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Special Core Analysis

CORE ANALYSIS CORE KNOWLEDGE

LEARNING OBJECTIVES

By the end of this lesson, you will be able to:

Define a typical workflow for SCAL

Describe the measurements obtained including the keypetrophysical properties for comparison and calibrating log data

Review the more detailed tests for information pertinent toreservoir engineering (covered in later sections)

Core Analysis Core Knowledge

© PetroSkills, LLC., 2016. All rights reserved._____________________________________________________________________________________________

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SPECIAL CORE ANALYSIS WORKFLOW

SCAL MEASUREMENTS

Formation Resistivity Factor (and cementation exponent)

I (and saturation exponent, n)

Cation Exchange Capacity

Capillary pressure

Wettability

Relative permeability

Residual oil saturation (on pressure or foam cores)

Rock mechanics

Acid response


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ARCHIE I AND II EXPERIMENTS

m

W

o

R

RF F = Formation resistivity

factor (FRF)

Ro = Resistivity of 100% brine saturation rock

RW = Brine resistivity (Ωm)

ϕ = Porosity

m = Cementation exponent

ARCHIE III

nW

o

t SR

RI I = Resistivity index

Rt = Resistivity of partly brine saturated rock

Ro = Resistivity of fully brine saturated rock

SW = Water saturation

n = Saturation exponent



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MODIFIED ARCHIE EQUATION

n

tm

WW R

RaS

Sw = Water Saturation

a = Lithology factor

RW = Brine resistivity (Ωm)

Rt = Resistivity of partly brine saturated rock

ϕ = Porosity

m = Cementation exponent

n = Saturation exponent

RESISTIVITY INDEX


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LAB RESISTIVITY MEASUREMENTS

Remember…

I = Rt/Ro

Rt= resistivity of partly brine-saturated rock

Ro= resistivity of fully brine saturated rock

EXAMPLE OF I MEASUREMENTS IN COMPOSITE PLOT –SANDSTONES



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LEARNING OBJECTIVES

You have now learned how to:

Define a typical workflow for SCALDescribe the measurements obtained including the key

petrophysical properties for comparison and calibrating log dataReview the more detailed tests for information pertinent to

reservoir engineering (covered in later sections)


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CAPILLARY PRESSURE AND WETTABILITY

LEARNING OBJECTIVES


Describe the concepts of capillary pressure and wettabilityDiscuss how they are measured in the labDiscuss the significance of these measurements, and how they

relate to reservoir behavior



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DEFINITIONS AND ASSUMPTIONS

Capillary pressure:

Pressure difference between wetting phase, non-wetting phase acrossmeniscus in capillary tube

Pressure needed to force non-wetting phase to displace wetting phase

Wettability:

Relative adhesion of two fluids to a solid surface

Preferential tendency of a fluid to wet or spread over a solid in presenceof one or more other fluids

Assumptions for capillary pressure tests:

Pores are bundles of tubes

System is 100% water-wet

Uses mercury as non-wetting phase

Porosity, permeability measured before testing

WETTABILITY

Water

Oil

Capillary Pressure and Wettability

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SCAL: WETTABILITY – LINK TO CAPILLARITY

In the water wet system, the water preferentially wets the surface of the capillary tube. The water capillary tube “crawls up” above the free water level.

In the oil-wet system, the oil preferentially wets the capillary tube. The oil within the capillary tube is below the free water level.

Water Wet

Oil Wet

(Note: theta always measured through wetting phase)

CAPILLARY PRESSURE – WHY IT WORKS

In the water-wet system, the water preferentially wets the surfaceof the capillary tube. The water within the capillary tube “crawlsup” above the free water level.

Pc=Pb at equilibrium



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INFLUENCE OF PORE THROAT SIZE ON CAPILLARY PRESSURE, HEIGHT AND SW

FWL = Free Water Level

H = Height above Free Water Level

Sw = Water saturation, % pore space

A B

SwHei

gh

t ab

ove

FW

LC

apill

ary

Pre

ssu

re

FWL

H

Cap

illar

y P

ress

ure

H

FWL

A B

Note: Free Water Level – water surface at zero capillary pressure

SCAL: CAPILLARY PRESSURE

If you consider the reservoir to be a bundle of variably sized capillaries, we can see why a capillary transition zone exists

The 100% water saturation occurs to a height dictated by the largest pore

Connate water saturation occurs at and above the capillary rise in the smallest pore

The shape of the curve in between is a function of the pore size distribution in the reservoir

Pc, h, Swirr, and Sw

ALL ARE RELATED!


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GRAIN SIZE AND IRREDUCIBLE SATURATION

SCAL: CAPILLARY PRESSURE – CURVE SHAPES

Indicative of permeability by: Entry pressure Irreducible saturation



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CAPILLARY – CURVE SHAPES

Sandstones, Facies Dependent Air/Brine Capcurves

SCAL: CAPILLARY PRESSURE – CURVES – CARBONATE EXAMPLE

ME Carbonate: Air/Hg CP data

Wetting Phase Saturation, %


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SCAL: CAPILLARY PRESSURE CURVES – CORE – LOG MATCHES

Capillary Pressure Data and Swirr from LogMiddle EastCarbonateExample

FWL = 7920' tvd-ss

FORMATION WATER SATURATION LAB - LPSA-DERIVED PC-SW

LPSA data have been related to PORE SIZE DISTRIBUTION of mercury injection tests (at stress) for hundreds of unconsolidated sand samples.

CapSimsm Model permits estimate of capillary retention of water, or Pc-Sw, for each LPSA sample.

Better estimation of hydrocarbons in place when log responses are effected by bed thickness

Image: Courtesy of Core Laboratories



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SCAL: CAPILLARY AND WETTABILITY SUMMARY

Capillarity: rock sucks up liquid against gravity

Depends on:

• Keeps bubble in shape

Interfacial tension

• Fluid that is wetting the rock

Wettability

• Small pores suck fluid higher

Pore size distribution

SCAL: CAPILLARY AND WETTABILITY SUMMARY

• Describes how much wetting fluid can be pulled up, against gravity.

Capillary pressure curve

• Capillarity leads to transition zone above hydrocarbon/ water contact.

In reservoir

• OWC (logs) is above FWL (from RFT/MDT)• Capillary pressure curve can be measured in the lab,

and converted to field conditions.• From this: saturation / height curve; compare with log

derived saturations.

Entry pressure


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LEARNING OBJECTIVES


Describe the concepts of capillary pressure and wettabilityDiscuss how they are measured in the labDiscuss the significance of these measurements, and how they

relate to reservoir behavior



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RELATIVE PERMEABILITY

LEARNING OBJECTIVES


Understand the concept of relative permeability and itsmeasurement in the lab and how it relates to effectivepermeability

Describe the sequence of saturation changes in reservoir duringthe drainage and imbibition phases of a reservoir; that is thedisplacement of oil into the reservoir and out of the reservoir(production)


© PetroSkills, LLC., 2016. All rights reserved.1_____________________________________________________________________________________________

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WHAT ABOUT RELATIVE PERMEABILITY?

Measured in the labfrom core sample

Uses plug orfull-diametercore sample

EFFECTIVE PERMEABILITY Ke

Flow of one fluid hinders the flow of another

Relative Permeability

k

kk e

r

1 KrwKro

But,


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DRAINAGE (OIL DISPLACES WATER)

Reservoir Begins to Fill up with Oil

Sw 50 22

Krw 5 0

So 50 78

Kro 40 100

DRAINAGE (OIL DISPLACES WATER)

Reservoir Begins to Fill up with Oil

Sw 100 50 22

Krw 100 5 0

So 0 50 78

Kro 0 40 100



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OIL HAS DISPLACED ½ THE WATER

Perm to Oil RisesPerm to Water Falls

Time Start Middle End

Sw 100 22

Krw 100 0

So 0 78

Kro 0 100

OIL HAS DISPLACED ½ THE WATER


Sw 100 50 22

Krw 100 5 0

So 0 50 78

Kro 0 40 100

Perm to Oil RisesPerm to Water Falls


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DRAINAGE COMPLETE – SWIRR REACHED

At IrreduciblePerm to Oil 100%Perm to Water 0%


Sw 100 50

Krw 100 5

So 0 50

Kro 0 40

DRAINAGE COMPLETE – SWIRR REACHED

At IrreduciblePerm to Oil 100%Perm to Water 0%


Sw 100 50 22

Krw 100 5 0

So 0 50 78

Kro 0 40 100



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IMBIBITION – WATER DRIVES OUT OIL

Reservoir placed on production

Initial Watercut 0%


Sw 50 85

Krw 5 30

So 50 15

Kro 40 0

IMBIBITION – WATER DRIVES OUT OIL

Reservoir placed on production

Initial Watercut 0%


Sw 22 50 85

Krw 0 5 30

So 78 50 15

Kro 100 40 0


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RESERVOIR FLOODED OUT

Reservoir Left at Residual Oil

Saturation ROS


Sw 22 50

Krw 0 5

So 78 50

Kro 100 25

WATER ENCROACHING RESERVOIR

Reservoir in Production Active Water Drive


Sw 22 50 85

Krw 0 5 30

So 78 50 15

Kro 100 25 0



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Saturation ROS


Sw 22 50

Krw 0 5

So 78 50

Kro 100 25



Saturation ROS


Sw 22 50 85

Krw 0 5 30

So 78 50 15

Kro 100 25 0


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POSSIBLE FACTORS INFLUENCING PERMEABILITY

Cleaning/drying Solid hydrocarbon not removed Clay mineral damage

Confining stress Pore volume compression Combining data from different stresses

Pore geometry Vugs Microporosity in grains (e.g. chalk, chert) Clay minerals

Gas slippage (low perm. rocks)

Turbulence (high perm. rocks)

KGAS KLIQUID – GAS SLIPPAGE

Function of gas composition and mean pressure.

Klinkenberg k is the permeability at infinite pressure.

Factor can range from ~.5 at low perms to ~.9 at high perms.

K is independent of fluid type and ∆P.

Kgas>Kliquid due to slippage of the gas along the rock wall:Effect high at -Low pressure

-Low K

b = Klinkenberg factor



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POROSITY – PERMEABILITY RELATIONSHIPS

Remember our previous discussion.

Porosity and permeability do not obey the same rules.

Porosity is a function of sorting

Permeability is a function of grain size, pore throat diameter

and connectivity

SUMMARY – WHY CUT CORE?

Core analyses provide:

Porosity

Fluid saturations

Permeability, Relative permeability

Capillary pressure

Pore throat and Grain size distributions

Grain density and Mineral composition

Electrical Properties (a, m, n)

Sensitivity to fluids

Hydrocarbon Analysis


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LEARNING OBJECTIVES


Understand the concept of relative permeability and its measurement in the lab and how it relates to effective permeability

Describe the sequence of saturation changes in reservoir during the drainage and imbibition phases of a reservoir; that is the displacement of oil into the reservoir and out of the reservoir (production)



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OTHER APPLICATIONS

LEARNING OBJECTIVES


Discuss the more detailed analytical techniques used in additionto RCA and SCAL for integrated reservoir description

Appreciate the range of additional tests that can be performedbeyond RCA and SCAL for information during the oilfield lifecycle



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FLOW LABORATORY PRODUCTION ENHANCEMENT, FORMATION DAMAGE, ENHANCED RECOVERY


Return-Regain Permeability

Critical Velocity

Rock/Fluid Interaction

Perm vs. Thruput

Steam Flood

Miscible Flood

WAG

GEOMECHANICS LABORATORY

Well bore Stability

Sand Production

Dynamic vs. Static Tests

Fracture Design Optimization

Log & Seismic Calibration

Vp/Vs

Acoustic Velocity

Reservoir Simulation

Pore Volume Compressibility

Compaction Studies

Production Optimization

Other Applications _____________________________________________________________________________________________

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GEOLOGICAL, PETROPHYSICAL INFORMATION

Reservoir Characterization Grain Size Distribution

Bed/Lamination Thickness

Grain Surface and Contacts

Integration of Routine / SCALAnalyses

“Enhanced” Core Photos

Geologic & Facies Models

Continuity & Connectivity

Petrography Thin Section

XRD

SEM/EDX

XRF

Cathodoluminescence

Epifluorescence

Sedimentology Core Description

Lamination Counts

(Net Sand)

Facies Interpretation

Data Integration/Statistics

Enhanced Core Photos

Log Response

Bed Dip Measurements

Fracture Analysis

Formation Sensitivity Migration of Fines -

Kaolinite & Illite

HF Acid Sensitivity -Carbonates & Zeolites

HCL Acid Sensitivity -Siderite, Pyrite, & Chlorite

Fresh Water Sensitivity -Smectite & Illite

Typical Distal & Proximal Levee Facies

= 23% K = 39 md = 32% K = 231 md

FACIES D - Laminated-to-Medium-Bedded Silty Shales

FACIES A - Thick-to-Very Thick-Bedded SILT/SAND Reservoirs

CORE DESCRIPTION



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LAMCOUNTsm ANALYSIS ACCURATE NET TO GROSS

G O M D e e p -w a te r P r o s p e c t

4 0 0

4 5 0

5 0 0

5 5 0

6 0 0

6 5 0

7 0 0

0 .1 1 1 0 1 0 0

R e s is t iv i ty

D e e p R e s it iv ityC o re

W e ll G a m m a R a y

0 5 0 1 0 0 1 5 0

G A P I

W e ll G a m m a R a y

D L

P L

M L

565.0 665.0

570.0 670.0

PL Proximal LeveeDL Distal Levee

Pay

?

Pay

Pay

?P

ay

A

B

A BHow much pay is there?

How would you model this reservoir?

FLOW ASSURANCE DETERMINATION OF ASPHALTENE ONSET

Pressurized Fluid Imaging (PFI) System:

Reservoir fluid is depressurized at a controlled rate and constant temperature

The fluid is observed via a microscope with digital camera and monitor

Onset is observed and digitally recorded


Other Applications _____________________________________________________________________________________________

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FLOW ASSURANCE DETERMINATION OF ASPHALTENE ONSET

Near Infra-Red (NIR):

Reservoir fluid is depressurized at a controlled rate and constant temperature

A beam of light is passed through the fluid

Onset blocks the light path

Onset is detected in the near-infrared region and recorded as a deviation from the baseline


LEARNING OBJECTIVES


Discuss the more detailed analytical techniques used in addition to RCA and SCAL for integrated reservoir description

Appreciate the range of additional tests that can be performed beyond RCA and SCAL for information during the oilfield life cycle



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