2011 what's new at cmg event in perth - chemical eor modelling

7/27/2019 2011 What's New at CMG Event in Perth - Chemical EOR Modelling

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AdvancedChemical Flood

Simulation

Perth December 6, 2011


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Background

STARS is CMGs Advanced EOR Processes reservoir

simulator with a long l ist of available physics/features: Momentum, Mass and Heat Transfer

Radial, Cartesian and Corner Point Grids with Faults

Multi-level LGR & Dynamic Gridding

Naturally Fractured Grids (DP, SD-DP, MINC-DP, DK and SDDK)

Nonisothermal Analytical Aquifer

Arbi trary number of components Three Mobile Fluid Phases (O,G & W) each with multiple components, and Multiple Solid Components

Phase behavior using K-values dependence on pressure, temperature and key component compos ition

Solubility of all Components in All Fluid Phases with Nonideal Mixing

Water-wet, Oil-Wet & Mixed-wet Relative Permeability & Capillary Pressure with hysteresis, and end-point

scaling (by region or by gridblock)

Composition or Capillary Number Dependent Relative Permeability and Capillary Pressure

Reactions using all Solid and Fluid Components

Adsorption, dif fusion & d ispersion by component and phase (latter 2 are direction-dependent)

Source-Sink wells, Discretized wells and FlexWells (the latter two for modelling of t ransient segregated fluid

and heat flow in horizontal injection and product ion wells)

Heat injection wells and Electrical Current injection wells (for heating via resistance)

Pressure-dependent Permeability and Porosity with hystersis

Stress-dependent Geomechanical Stress Calculation and Compaction (Subsidence)

Capillary-Gravity Initialization


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Background

STARS has been used to model chemical EOR processes for many

years

The main features used for ASP are described by Pandey, et al of

Cairn India Ltd. in SPE 113347 (2008 IOR Conference in Tulsa):

IFT reduction from up to 2 chemical components (eg. Surfactant & Alkaline)

Modification of Relative Permeability resulting from Capillary Number changesWater viscosi ty increase by polymer addition

Shear-thinning (and thickening) behavior of polymer solution

Adsorpt ion of chemical components

Residual resistance factor due to chemical adsorpt ion

Type II- or Type II+ phase behavior for modelling surfactant partioning into oil or

water phases as a function of Alkali concentration

Reactions for modelling sur factant degradation into oil using Alkali as the

catalyst and Polymer degradation into water

Type III Phase behavior is not in STARS currently


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Background

Typically 5 or 6 components are used to model ASPprocesses in STARS

Water, surfactant, alkali, dead oi l, polymer1 (and polymer2 if salinity effects on

polymer viscosity are important)

Additional components & reactions can be added to

more mechanist ically model consumption of alkali andsurfactant via:

Mixing with formation brine

Cation exchange

Hydrogen ion exchange

Reaction with petroleum acids

Silica disolution

Kaolinite transformation

BUT, at considerable run time cost


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Background

STARS_ME has been developed to address currentlimitations of STARS and serve as transition platform

for eventual full integration into STARS

Addition of Type III phase behavior using UT-CHEM approach (July

2009)

STARS gas phase slot is used for ME phase in STARS_ME

Addition of 3-liquid phase relative permeabi lity using UT_CHEM

approach (July 2009)

Addition of efficient water chemistry (September 2011)

Remainder of this presentation deals with integration of

water chemistry into STARS_ME and chemical EOR

processes that can now be modelled more

mechanistically


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Objectives

Mechanistic modeling of chemical flood processes

Micellar-Polymer or Microemulsion (ME)

Alkaline-Surfactant-Polymer

Low-Salinity Water Flood


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Physics

Oil/Brine/Microemulsion phases

Chemical equilibrium reactions

Mineral precipitation/dissolution

Ion exchange

Incorporated in a special version (STARS_ME)

Work performed in collaboration with UT Austin


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Outline of Presentation

Modeling techniques

Laboratory Test Examples

Mechanistic ASP modeling

Field Examples

Mechanistic ASP at field scale

Low Salinity waterflood modeling concepts

Summary


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Modeling Techniques

Focus on surfactant effects on water-oil phase

behavior and flow

Injected surfactants include alkyl-benzene

surfactants (ABS), internal olefin surfactants (IOS),ethoxy/propoxy (EO/PO) sulfonates, etc.

In-situ surfactants in oil


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Modeling Techniques

Water chemistry affects the performance ofsurfactants

Inorganic aqueous species (Na+, Ca++ , Cl-, H+, OH-)

Solid species (CaCO3, Ca(OH)2)

Ion exchange with reactive clays (kaolini te, smectite, etc.) These effects are incorporated with the use of

chemical equilibrium concepts

Typical reactions

H2O H+ + OH-

HAc H+ + Ac-


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Mechanistic Modeling of ASP

Oil is characterized by its acid number (acidcontent)

Generation of soap with high pH (injection of

NaOH or NaCO3)HAo(oil phase) HAw(water phase)

HAw H+ + Aw-Anionic surfactant Aw

- (soap) affects ME phase

behaviorSalinity affects parti tioning of both injected and

acid surfactants


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ASP Effects on Phase Equilibrium

0 0,05 0,2 0,4 0,6 0,8 1,0

Alkali concentration(%)

Crude oil solubilization in water with NaOHbased on oil acid number of 0.56 mg KOH/g oil

Indication of ultralow

interfacial tension


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Activity Map for ASP Process

From Mohammadi et. al. (2009)


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ASP Coreflood Match

Based on UTCHEM laboratory history match

(Mohammadi et al., SPE Res. Eng., August 2009)

Core Dimensions: L = 30.48 cm ; D = 5.0 cm

Porosity: 0.17

Permeability: 683 md

Water viscosity: 0.5 cp

Oil viscosity: 19 cp


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ASP Coreflood Match

Chemical slug (0.3 PV, 4 hours)

3000 ppm polymer, 0.2 wt% surfactant, 2.75 wt% alkaline

(Na2CO3)

slug viscosity = 28 cp

Polymer drive (2 PV, 24 hours)

2000 ppm polymer, 0.6 wt% salt (NaCl)

slug viscosity = 33 cp


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ASP Coreflood Match


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ASP Coreflood Match


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STFLU20 Field Model Details

One-half inverted 7 spot pattern Heterogeneous porosity distribution

Heterogeneous permeabili ty dis tribution

Initial conditions (assumes end of waterflood)

Sw = 0.65

So = 0.35

Constant Q injector / four constant p producers

One year ASP chemical slug

Two year polymer dr ive

One year polymer taper Ten year post-flush


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Heterogeneous Permeability

Dissociated Acid Surfactant


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Dissociated Acid SurfactantDistribution


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Low Salinity Phenomena

Improved oil recovery with Low Salinity Waterflood

Multicomponent ion exchange

Clay content

Composition formation water (Ca++ , Mg++)

Oil composition

pH increase

Low Salinity Field Example


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Low Salinity Field ExampleInterbedded Clay Model

Two horizontal well line-drive pattern for l ight oil

reservoir

Heterogeneous porosity/permeabili ty distribut ion

Variability due to interbedded clay distribut ion Initial conditions

Average pore volume 1.667E+6 m3

Average clay content = 3.4% PV

Average Sw = 0.226

Average So = 0.784



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Well operations

Constant rate injector

Constant p producer

Water injection rate 1000 m3

/day High salinity Na/Ca/Cl (mol/l) = 1.54 / 0.09 / 1.72

Low salini ty Na/Ca/Cl (mol/l) = 0.003 / 0.005 / 0.013

Permeability Distribution


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Permeability DistributionInterbedded Clay



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Heterogeneous porosity distribution assumed dueto variable clay deposition levels

Clay-free constant porosi ty of = 0.343

Variability due to interbedded clay distribution

Relation between fluid porosity and free porosity

determines clay level

f = v * (1 Cc / ) with = 2650 kg/m3

Variable cation exchange capacity (CEC)dependent on clay type

Kaolinite CEC = 0.04 meq/g

Smectite CEC = 1.00 meq/g

Init ial Adsorbed Calcium from


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Init ial Adsorbed Calcium from

Interbedded Clay

INJ PROD

0 10 20 30 40 50 60 70 80 90 100

0 10 20 30 40 50 60 70 80 90 100

17

0

180

190

200

210

220

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240

160

1

70

180

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0.00 40.00 80.00 feet

0.00 15.00 30.00 meters

File:BASE_LAYERS_3User: dennisDate:6/25/2010

Scale:1:618Z/X:1.00:1Axis Units:m

0

LOWSALAdsorption(CALCIUM) (gmole/m3) 2007-01-01 J layer: 18



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Wettability is determined by adsorbed petroleum

acids on clay

Oil wettability determined by clay content

Classified 4 relative permeability rock types withincreasing oil-wetness depending range of clay

content



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Ion-exchange triggers petroleum acid desorption

from clays and shift of wettability to increased

water wetness

Interpolation of each class of relative permeabilityrock types between original curves and induced

wettability change depending on desorbed acid

levels

Relative Permeability Set number


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Relative Permeability Set-numberDistribution from Interbedded Clay

INJ PROD

0 10 20 30 40 50 60 70 80 90 100

0 10 20 30 40 50 60 70 80 90 100

170

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230

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0.00 40.00 80.00 feet

0.00 15.00 30.00 meters

File: BASE_LAYERS_3User:dennisDate: 6/25/2010

Scale:1:618

Z/X:1.00:1Axis Units:m

0.0

LOWSALRel Perm Set Number 2007-01-01 J layer: 17

Cumulative Oil from Original (oil wet) and


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Cumulative Oil from Original (oil wet) and

Low Salinity-shifted (water wet) Scenarios


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Summary

STARS_ME: Advanced Simulation of Chemical

Flood

Mechanistic modeling of ASP, micro-emulsion

flooding and Low Salinity water injection Representation of 3 liquid phases: aqueous, oil

and micro-emulsion

Comprehensive water chemistry

2011 what's new at cmg event in perth - chemical eor modelling

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