Advanced methodologies for fluid characterization and ... · Water Line - B/HOil 0.8 g/cc Gas Line - B/H: Oil 0.8 g/cc Water Line - B/H: Gas 0.3 g/cc Gas Line - B/H: Gas 0.3 g/cc

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Advanced methodologies for fluidcharacterization and saturationevaluation behind Casing

[email protected] Petrophysical Society – Resistivity Free Saturation Seminar13 December 2018

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Agenda

￭ Cased Hole Formation Evaluation

– Standard Conventional PN logging

– Sigma

– C/O

– Monte Carlo Emulation approach: Reservoir Characterization

– Advanced pulsed neutron technologies

– Gas quantification

– Variables in modelling

– Pressure depletion evaluation

– Oil quantification from PNC data (by pass C/O)

– Three-phases Saturation analysis

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Application

Water saturation in wellswhere water salinity ishigh and known

PNC Sigma Logging

)(

)1(

hw

hshshshmw

VVS

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Range of Application (Salt water vs Oil)

Water Salinity(Kppm)

Sigma water Sigma Oil Porosity Delta

(Sigma)

205 100 20 0.20 16

205 100 20 0.05 4

22 30 20 0.20 2

22 30 20 0.05 0.5

)(

)1(

hw

hshshshmw

VVS

Relative error in single pass of Sigma ~ 0.5 capture units

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Range of Application (Fresh Water vs Oil vs Gas)

Sigma water oroil

Sigma gas Porosity Delta

(Sigma)

20 10 0.20 2

20 10 0.10 1

20 10 0.05 0.5

)(

)1(

hw

hshshshmw

VVS

Relative error in single pass of Sigma ~ 0.5 capture units

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Application

Oil saturation informations with fresh orunknown water salinity

Carbon/Oxygen (C/O) Logging

0

2000

4000

6000

8000

10000

12000

14000

16000

1 2 3 4 5 6 7 8 9

Co

un

ts

Energy (MeV)

Carbon

Oxygen

1

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

1.9

0 5 10 15 20 25 30 35 40 45

C/O

Porosity (p.u.)

6" Openhole, LimestoneFormation

Oil Borehole

Water Borehole

X

DC/OSO = X / DC/O

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Monte Carlo emulation approach: Inputs Required for Modeling

Lithology:Sandstone, limestone ordolomite

Borehole/ CompletionConfiguration:Bit sizeCasing sizeTubing sizeCement typeBorehole fluid

Formation Fluids:Water salinityOil densityGas compositionGas density

PN Tool1.7 in

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Fast Neutron@ 14.2 MeV

Monte Carlo Modelingpredicts the life cycle ofan individual neutron

During its life a neutronmay have hundreds ofcollisions with differentpossible results(elastic, inelastic,capture, activation)

Repeated for 100 MillionNeutrons (or more) for 18data points

1.8 Billion histories

Each model requires ~ 4days of computation

Monte Carlo emulation approach: Modeling Methodology

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Agenda



– Sigma

– C/O








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Response Comparison in Gas

0

10

20

30

40

50

60

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45

SIG

MA

,c.u

.

Porosity

250 kppm

0 kppm

GasOil

0

10

20

30

40

50

60

70

80

90

100

0 0.1 0.2 0.3 0.4

INE

LA

ST

ICR

AT

IO

Porosity

0

30

60

90

120

150

0 0.1 0.2 0.3 0.4

CA

PT

UR

ER

AT

IO

Porosity

Sigma

Oil

Oil

Water Water

Gas

Gas

20+ ft/min

10 ft/min

10 ft/min

1.50

1.60

1.70

1.80

1.90

2.00

0.00 0.10 0.20 0.30 0.40

Ca

rbo

n/O

xyg

en

Ra

tio

Porosity

Gas

Oil

Water

C/O

2 ft/min*

Det 1 & 3 inelastic count ratio Det 1 & 3 pulsed neutron count ratio

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Salinity-independent gassaturation

Detector count rate ratios

New standard for gassaturation measurement

Multiple examples of directOH/CH comparisons todemonstrate accuracy

Best technology for freshwater / tight gas / low porositygas saturation applications

US Patent 2008

Gas Quantification Evaluation

30

40

50

60

70

80

0 0.1 0.2 0.3 0.4 0.5

RIN13 Response

PNC

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Variables in modelling: Lithology

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RIN

13

Water Line - Dolomite Gas Line - DolomiteWater Line - Limestone Gas Line - LimestoneWater Line - Sandstone Gas Line - SandstoneWater Line - K-Feldspar Gas Line - K-Feldspar

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RA

TO

13

Water Line - Dolomite Gas Line - DolomiteWater Line - Limestone Gas Line - LimestoneWater Line - Sandstone Gas Line - SandstoneWater Line - K-Feldspar Gas Line - K-Feldspar

Dolomite CaMg(CO3)2 2.87 g/cc Calcite CaCO3 2.71 g/cc Quartz SiO2 2.65 g/cc Feldspar KAlSi3O8 2.56 g/cc

Inel

astic

ratio

Cap

ture

ratio

Effective Porosity Effective Porosity

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Variables in modelling: Borehole Size

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RIN

13

Water Line - 6 '' / 4.5'' Gas Line - 6 '' / 4.5'

Water Line - 8.5 '' / 7' Gas Line - 8.5 '' / 7'

Water Line - 12 '' / 9.625' Gas Line - 12 '' / 9.625'

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RA

TO

13

Water Line - 6 '' / 4.5'' Gas Line - 6 '' / 4.5'

Water Line - 8.5 '' / 7' Gas Line - 8.5 '' / 7'

Water Line - 12 '' / 9.625' Gas Line - 12 '' / 9.625'

Bit: 6 in, Casing: 4.5 in Bit: 8.5 in, Casing: 7 in Bit: 12 in, Casing: 9.625 in

Inel

astic

ratio

Cap

ture

ratio


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Variables in modelling: Borehole Fluids

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RIN

13

Water Line - B/H: Fresh Water'' Gas Line - B/H: Fresh Water'Water Line - B/H: 100 kppm Gas Line - B/H: 100 kppmWater Line - B/HOil 0.8 g/cc Gas Line - B/H: Oil 0.8 g/ccWater Line - B/H: Gas 0.3 g/cc Gas Line - B/H: Gas 0.3 g/ccWater Line - B/H: Gas 0.1 g/cc Gas Line - B/H: Gas 0.1 g/cc

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RA

TO

13

Water Line - B/H: Fresh Water'' Gas Line - B/H: Fresh Water'Water Line - B/H: 100 kppm Gas Line - B/H: 100 kppmWater Line - B/HOil 0.8 g/cc Gas Line - B/H: Oil 0.8 g/ccWater Line - B/H: Gas 0.3 g/cc Gas Line - B/H: Gas 0.3 g/ccWater Line - B/H: Gas 0.1 g/cc Gas Line - B/H: Gas 0.1 g/cc

Fresh Water – 1.0 g/cc Saline Water – 100 kppm ~ 1.1 g/cc Oil – 0.8 g/cc Methane Gas – 0.3 g/cc Methane Gas – 0.1 g/cc

Inel

astic

ratio

Cap

ture

ratio


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Variables in modelling: Gas Density

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RIN

13

Water Line Gas Line - 0.3 g/cc Gas Line - 0.1 g/cc

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RA

TO

13

Water Line Gas Line - 0.3 g/cc Gas Line - 0.1 g/cc

Methane Gas – CH4 – 0.3 g/cc Methane Gas – CH4 – 0.1 g/cc

Inel

astic

ratio

Cap

ture

ratio


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Variables in modelling: Water Salinity

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

0 5 10 15 20 25 30 35 40 45

Porosity

RA

TO

13

250 kppm Water

200 kppm Water

150 kppm Water

100 kppm Water

50 kppm Water

Fresh Water

Gas Line

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RIN

13

250 kppm Water

200 kppm Water

150 kppm Water

100 kppm Water

50 kppm Water

Fresh Water

Gas Line

Fresh Water 50 kppm NaCl 100 kppm NaCl 150 kppm NaCl 200 kppm NaCl 250 kppm NaCl


Inel

astic

ratio

Cap

ture

ratio

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Variables in modelling: Oil Density

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RIN

13

0.80 g/cc Oil

0.75 g/cc Oil

0.70 g/cc Oil

0.65 g/cc Oil

0.60 g/cc Oil

0.55 g/cc Oil

Gas Line0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45

Porosity

RA

TO

13

0.80 g/cc Oil

0.75 g/cc Oil

0.70 g/cc Oil

0.65 g/cc Oil

0.60 g/cc Oil

0.55 g/cc Oil

Gas Line

Oil – 0.80 g/cc Oil – 0.75 g/cc Oil – 0.70 g/cc Oil – 0.65 g/cc Oil – 0.60 g/cc Oil – 0.55 g/cc

Inel

astic

ratio

Cap

ture

ratio

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Variables in modelling: Gas Composition

0

10

20

30

40

50

60

70

80

90

100

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45

Porosity

RA

TO

13

Water

OilMethane - 0.10 g/cc

Methane - 0.04 g/ccCO2 - 0.68 g/cc

CO2 - 0.12 g/cc

0

10

20

30

40

50

60

70

80

90

100

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45

Porosity

RIN

13

Water

OilMethane - 0.10 g/cc

Methane - 0.04 g/ccCO2 - 0.68 g/cc

CO2 - 0.12 g/cc

Methane – 0.10 g/cc Methane – 0.04 g/cc Carbon Dioxide – 0.68 g/cc Carbon Dioxide – 0.12 g/cc


Inel

astic

ratio

Cap

ture

ratio

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Pressure Depletion – BP Alaska

Gas-liquid saturation

Gas pressure or density behind casing

In this BP Alaska example, computedgas densities of 0.26 g/cc in main gasinterval, 0.35 g/cc in isolated zone

US Patent 20080.35 g/cc

0.26 g/cc

Ine

las

tic

rati

o

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ReservoirInitialSBHP

(kg/cm2)

Lastmeasured

SBHP(kg/cm2)

Avg.estimatedby PN log(kg/cm2)

Sand A 337 54 55Sand B 336 52 62

Gas-liquid saturation

Gas pressure or density behindcasing

Original matrix assumed to be puresandstone, revised matrix includessandstone and muscovite

Pressure Depletion Evaluation – ENI Italy

SPWLA 58th Annual Technical Conference Oklahoma City, 17-21 June , 2017

Inela

stic

ratio

Inelastic ratio responses: Sandstone vs. Sandstone+Muscovitewith heavy elements

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Oil Quantification from PNC Data

￭ Oil saturation in light oilreservoirs

￭ Alternative to C/O logging infresh water / light oil reservoirs(density difference > 0.35 g/cc)

￭ Data acquired at 10 fpm and 3passes – C/O logged at 2 fpmand 5 passes

￭ Memory logging available

￭ US Patent 2009

0

20

40

60

80

100

120

0 0.1 0.2 0.3 0.4 0.5

RATO13 responseDet 1 & 3 pulsed neutron count ratio

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3-phase saturation monitoring

Light oil and/or high-salinity formation water

US Patent 2009

30

40

50

60

70

80

0 0.1 0.2 0.3 0.4 0.5

RIN13 Response

0

20

40

60

80

100

120

0 0.1 0.2 0.3 0.4 0.5

RATO13 responseDet 1 & 3 pulsed neutron count ratio

Det 1 & 3 inelastic count ratio

3-Phases Quantification from PNC Data

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RPM – Multi Detector Pulsed Neutron Measurements

1.50

1.60

1.70

1.80

1.90

2.00

0.00 0.10 0.20 0.30 0.40

Ca

rbo

n/O

xyg

en

Ra

tio

Porosity

Gas

Oil

Water

0

10

20

30

40

50

60

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45

SIG

MA

,c.u

.

Porosity

250 kppm

0 kppm

GasOil

0

10

20

30

40

50

60

70

80

90

100

0 0.1 0.2 0.3 0.4

INE

LA

ST

ICR

AT

IO

Porosity

0

30

60

90

120

150

0 0.1 0.2 0.3 0.4

PU

LS

ED

CA

PT

UR

ER

AT

IO

Porosity

C/OSigma

Oil

Oil

Water Water

Gas

Gas

20+ ft/min 2 ft/min*

10 ft/min

10 ft/min

Det 1 & 3 inelastic count ratio

Det 1 & 3 pulsed neutron count ratio

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3-phases Saturation: Triangulation Methods

￭Triangulation technique integrates two pulsed neutron log measurements andMonte Carlo modeling results to solve three-phase fluid saturations.

￭Options Available:

1. Crossplot of Det. 1&3 Inelastic ratio and Det. 1&3 pulsed neutron captureratio– salinity/oil density dependent, 10ft/min

2. Crossplot of Det. 1&3 pulsed neutron capture ratio and SGFC – salinity/oildensity dependent, less lithology sensitivity, 10ft/min

3. Crossplot of Det.1 &3 Inelastic ratio and C/O – salinity independent:requires C/O passes at 2ft/min and PNC passes at 10ft/min

￭Simultaneous 3 phase saturation solution

￭Computes gas, oil and water saturations using a triangle at each depth

￭Memory logging available except for C/O mode

￭Patent issued in 2013

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Triangulation Option 1: D13 INELASTIC vs. CAPTURE ratio

￭Monte Carlo models of INELASTICand CAPTURE ratio curves

￭Crossplot of curves modeledresponses at each depth

￭Normalize measured INELASTICand CAPTURE ratio curves on thecrossplot

￭ Factors that determine the size andshape of a triangle

– Hole and casing sizes, boreholefluid property

– Porosity, lithology, reservoir fluidproperties (i.e., salinity, HCdensity)

Triangle combiningInelastic and PNC

INELASTIC Monte Carlo Model

CA

PT

UR

EM

on

teC

arloM

od

el

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Triangulation: Variation of porosity, salinity

￭ The size of the triangle increases as porosityincreases.

￭ Porosity ranges from 0 pu to 40 pu.

￭ Other parameters are constant.

￭ The size of the triangle increases as water salinity increases.

￭ Thermal neutron capture measurement effect

￭ Freshwater to 200 kppm salt water cases (50 kppm increment) at20 pu

INE

LA

ST

ICR

AT

IO

INE

LA

ST

ICR

AT

IO

CAPTURE RATIO CAPTURE RATIO

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Triangulation: Variation of oil density, salinity

￭ The shape of the triangle changes as oil densitychanges.

￭ CAPTURE Ratio is more responsive to oil densityvariation.

￭ Oil density from 0.8 g/cc to 0.6 g/cc at 20 pu.

￭ For INELASTIC and CAPTURE Ratio combination, the favorablereservoir conditions are high water salinity and low oil density.

￭ The size of the triangle increases as salinity increases and oildensity decreases.

INE

LA

ST

ICR

AT

IO

INE

LA

ST

ICR

AT

IO

CAPTURE RATIO CAPTURE RATIO

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• Example

• North Sea

• Bit size: 8.5”

• Casing size: 5”

• Oil density: 0.67 g/cc

• Gas density: 0.166 g/cc

• Salinity: 70~120 kppm

• Acquired PN tool data: Shut-in and Flowing passes

• Surface production: Gas, oil and water

• Logging Objective: To detect the source of gas production

Triangulation-Option 1: D13 INELASTIC vs. CAPTURE ratio

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25

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35

40

45

0 15 30 45 60 75

RATO13

RIN

13

D13

INEL

AST

IC

D13 CAPTURE


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25

30

35

40

45

0 15 30 45 60 75

RATO13

RIN

13

D13

INEL

AST

IC

D13 CAPTURE


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25

30

35

40

45

0 15 30 45 60 75

RATO13

RIN

13

D13

INEL

AST

IC

D13 CAPTURE


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25

30

35

40

45

50

55

60

65

70

0 10 20 30 40 50 60 70 80 90 100

RATO13

RIN

13

D13

INEL

AST

IC

D13 CAPTURE


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Triangulation-Option 2: SIGMA vs D13 CAPTURE CurveCO2 MONITORING example

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Sigma vs D13 CAPTURE (2012)

D13 CAPTURE RATIO D13 CAPTURE RATIO

Sigma vs D13 CAPTURE (2014)

Triangulation-Option 2: SIGMA vs D13 CAPTURE CurveCO2 MONITORING example

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Triangulation-Option 3: D13 INELASTIC vs C/O

￭ A combination of two inelasticscattering gamma ray measurements

– Water salinity independent

– Same depth of investigation

￭Monte Carlo models of Det. 1&3Inelastic ratio and C/O

￭Crossplot of Det. 1&3 Inelastic ratioand C/O modeled responses at eachdepth

￭Normalize measured Det. 1&3Inelastic ratio and C/O on thecrossplot

Triangle combining Inelastic and C/O INELASTIC Monte Carlo Model

Weig

ht

av

era

ged

C/O

Mo

nte

Carlo

Mo

del

D1

3IN

ELA

STIC

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￭ Prudhoe Bay field

– Relatively fresh water environment (~35kppm)

– In-situ oil density of 0.78 g/cc

– Mineralogy/ lithology includes quartz,conglomerate and siderite.

￭Challenges

– Could not obtain reliable three-phasesaturation using conventional PNCSigma, C/O, or cased hole resistivitylogs

– Gas in the borehole

– Post-waterflood recovery indicatedunpredictable and variable water salinity

Triangulation-Option 3: Field Example

Normalized INEL

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￭Objectives

– Current reservoir fluid identification

– Understanding of gas cap and fluidcontact movement

– Identification of intervals of bypassed oilfor additional perforations

￭ Approach

– PN tool data acquisition using PNC3Dand C/O modes

– Water injection into the wellbore duringlogging operation to avoid the presenceof gas in the wellbore

– Use Triangulation Technique of PNCInelastic D13 ratio and C/O

Normalized INEL


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￭ Salinity-independent 3-phase saturation

￭ Triangulation of D13 INELASTIC and C/O

￭US Patent 2013

INEL.

D1

3In

ela

sti

c

Normalized INEL


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￭ BP Alaska logging campaign in 2014 inPrudhoe Bay

￭ Identified bypassed pay zones in 14 wells,perforation jobs added ~7000 bopd to theexisting production

Presented at SPWLA 56th Symposium, California, 2015


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Summary

Confidential. Not to be copied, distributed, or reproduced without prior approval.© 2017 Baker Hughes, a GE company, LLC

- All rights reserved.

Advanced methodologies for fluidcharacterization and saturationevaluation behind Casing

London Petrophysical Society – Resistivity Free Saturation Seminar13 December 2018

Documents

Advanced methodologies for fluid characterization and ... · Water Line - B/HOil 0.8 g/cc Gas Line - B/H: Oil 0.8 g/cc Water Line - B/H: Gas 0.3 g/cc Gas Line - B/H: Gas 0.3 g/cc