Advanced Recovery Processes for Conventional Reservoirs and … · 2019. 12. 5. · CO2 injection Solvent Injection WAG 0.01 PV - CO2 WAG 0.01 PV - solvent GAW - CO2 GAW - solvent

Advanced Recovery Processes for

Conventional Reservoirs and Shale

Tony Kovscek

Energy Resources Engineering

School of Earth, Energy, and Environmental

Sciences

Outline

Shale and CO2 Cooptimized EOR & Storage

CO2

zero-entry capillary pressure barrier

oil

zero capillary entry pressure barrier 0

0.1

0.2

0.3

0.4

0.5

0.6

0 2000 4000 6000 8000 10000 12000 14000 16000days

CO2 injectionSolvent InjectionWAG 0.01 PV - CO2WAG 0.01 PV - solventGAW - CO2GAW - solventWC - CO2WC - solvent

Shale EOR and CO2

CO2


oil

What could we do with abundant CO2?

• enhance gas recovery

• enhance oil recovery

• replace fracturing fluids

• store CO2

https://www.acs.org/content/acs/en/pressroom/presspacs/2015/acs-presspac-november-18-2015/profit-from-co2.html

U.S. Oil Production

(million barrels per day)

2

4

6

8

10

1949

1957

1965

1973

1981

1989

1997

2005

2013

Conventional

Decline Curve

Source: U.S. Department of Energy, Energy Information Administration (EIA)

Recovery factor ~ 5%

U.S. Natural Gas Production

(billions of cubic feet per day)

Shale Gas

Non-Shale Gas

20

30

40

50

60

70

2000

2003

2006

2009

2012

Unconventional

Conventional

Recovery factor ~ 25%

Small Recovery Factors From Shale

5

! = #$ ⁄& ' − #$ ⁄) '#$&)* − #$+),--.

Storage Capacity (/) =Adsorbed Gas + Free Gas

(ф)

Aljamaan, H. C. M. Ross, and A. R. Kovscek, Society of Petroleum Engineers Journal, 22(6), 1760-1777 (2017).

6

Study Samples

Barnett 26-Ha Eagle Ford EF-4 Haynesville TWG3-2 Permian P-2

Source Sample Depth (ft) Ro TOC Clays Carbonates Quartz Feldspar Pyrite

Barnett 26-Ha 8620.1 - 11.7 25.2 10.4 45.1 5.8 1.7

Eagle Ford EF-4 11184.8 1.39 5.1 20.3 48.9 18 3.8 3.9

Haynesville TWG3-2 11134.05 1.37 1.9 22.8 49.5 16.8 6.9 2.0

Permian+ P-2 10134.25 1.28 0.5 5.5 68.8 17.5 7.3 1.0

clay—QFP—carbonate


7

Kr vs CO2 Storage Capacity

Kr

CO2

Barnett Eagle Ford Haynesville Permian

5.6

10.2

x = 9.9

x= 12.8 17.5

11.0

14.4

7.8


Kr CO2

• CO2 and Kr storage distribution slices aligned with

SEM mosaic

20 40 60 80 100

10

20

30

40

50

60

70

80

90

100

0

0.05

0.1

0.15

0.2

0.25

Low /High //

8

Eagle FordCT/SEM Registration


0

0.2Top down imaging: whole core images (2.5 cm diameter) with CO2, Kr, or Xe in pore space and adsorbed• transient, • different gas types, • including stress

Top Down ImagingExample – Shale, CO2 Storage Capacity (/)

CT voxel: 250 x 250 x 1000 µm

300 µm 30 µm

P

OM

P – Pyrite; OM – Organic Matter; Matrix – mixture of clay and carbonate

1 inch diameter

Pixel Size: 1.45 µm

Pixel Size: 366 nm Pixel Size: 74 nm

20 40 60 80 100

10

20

30

40

50

60

70

80

90

100

0

0.05

0.1

0.15

0.2

0.25

/

Aljamaan, H. C. M. Ross, and A. R. Kovscek, Society of Petroleum Engineers Journal, 22(6), 1760-1777 (2017).Vega, B., C. M. Ross, and A.R. Kovscek, Society of Petroleum Engineers Journal, 20(4) 810-823 (2015Foute, L., Nanoimaging of Shale Using Electron Microscopy Techniques, Stanford University (2019).

SEM MosaicSEM Multiscale Images TEM Multiscale Images

Pixel Size: 2 nm

100 nm

Segmented TXM voxel: 30 x 30 x 30 nm

9

Toward CO2 Miscible Injection

2

@ P > MMP

CO2zero-entry capillary pressure barrier

oil

• Questions

• Does CO2 penetrate matrix at small pressure

gradients?

• Are miscible recovery mechanisms similar to

conventional EOR?

• Does repressurization hinder recovery?

(Actually) Nitrogen Displacing KryptonEagle Ford Shale

Elkady, Youssef, Imaging of Enhanced Gas Recovery from Eagle Ford Shale, Stanford University (2019).

• Breakthrough of CO2 between 0.45

and 1.2 PVI (2nd sample bag)

• 90% of gas recovery after 17 PVI

• CO2 gas fully displaces Kr –

confirmed by degassing core to

atmospheric

CO2 versus N2 Displacing Kr Results

12

Sorption Isotherms

Elkady, Youssef, Imaging of Enhanced Gas Recovery from Eagle Ford Shale, Stanford University (2019).

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10

Kryp

ton

Rec

over

y %

PVI

N2 Displacing Kr CO2 Displacing Kr

Chattanooga

Eagle Ford

Western Gulf

TX-LA-MSSalt Basin

Uinta Basin

Devonian (Ohio)Marcellus

Utica

Bakken***

Avalon-Bone Spring

San JoaquinBasin

MontereySanta Maria,Ventura, Los

AngelesBasins

Monterey-Temblor

Pearsall

Tuscaloosa

Big HornBasin

DenverBasin

Powder RiverBasin

ParkBasin

Niobrara*

Mowry

Niobrara*

Heath**

ManningCanyon

AppalachianBasin

Antrim

Barnett

Bend

New Albany

Woodford

Barnett-Woodford

Lewis

Hilliard-Baxter-Mancos

Excello-Mulky

Fayetteville

Floyd-Neal

Gammon

Cody

Haynesville-Bossier

HermosaMancos

Pierre

Conasauga

MichiganBasin

Ft. Worth Basin

Palo DuroBasin

PermianBasin

IllinoisBasin

AnadarkoBasin

Greater Green River Basin

Cherokee Platform

San JuanBasin

WillistonBasin

Black WarriorBasin

Ardmore Basin

Paradox Basin

RatonBasin

Montana Thrust

Belt

Marfa Basin

Valley & Ridge Province

Arkoma Basin

Forest City Basin

PiceanceBasin

Lower 48 states shale plays

0 200 400100 300

Miles

±

Source: Energy Information Administration based on data from various published studies. Updated: May 9, 2011

BasinsShale plays

Stacked plays

BasinsCurrent playsProspective plays

* Mixed shale & chalk play

** Mixed shale & limestone play

***Mixed shale &tight dolostone-

siltstone-sandstoneIntermediate depth/ ageShallowest/ youngest

Deepest/ oldest

Apparatus: For huff-n-puff and CO2 Flood

8

Confining pressure

Collection system

BPR

Bottom Top

N2

N2

Port 1

Port 2

Port 3

Heating tape

Temperature controller

Collection system

BPR

N2

CO2

Huff-n-Puff

Countercurrent

9

Confining pressure

Collection system

BPR

Bottom Top

N2

N2

Port 1

Port 2

Port 3


Heating tape

CO2

Cocurrent

9


Confining pressure

Collection system

BPR

Bottom Top

N2

N2

Port 1

Port 2

Port 3

Heating tape

CO2

45 oC10

Huff-n-Puff CO2 Injection

injection

injection

Vega, B. W. J. O’Brien, and A. R. Kovscek, Proceedings of the 2010 SPE Annual TechnicalConference and Exhibition, Florence, Italy, 19–22 September 2010.

45 oC11

Cocurrent CO2 Injection

injection

production

injection

production


Summary of Test Results

12

TEST 1 2 3 4

Flow conditions Immiscible Immiscible Near Miscible Miscible

kr to decane, mD 0.023 1.32 1.32 1.32

Sg after depletion 0.11 0.38 N/A N/A

CO2 after countercurrent 0.21 0.47 0.25 0.54

CO2 after cocurrent 0.32 0.66 0.36 0.93

Oil recovery (depletion) 0.11 0.37 N/A N/A

Oil recovery

(countercurrent)0.0 0.09 0.25 0.45

Oil recovery (cocurrent) 0.25 0.19 0.10 0.48

Total recovery for CO2

flow0.25 0.28 0.35 0.93


CO2 Distribution Observations

• Multiscale (cm to nm) imaging

• Gas accessibility and storage capacity in intact shale cores

• SEM mosaics of either core face or interior slices

• Elemental mapping and interpretation

• Image registration methods (same resolution and

multiscale)

• Gas storage and its distribution is controlled by

• porosity

• accessibility

• sorption capacity of minerals and organic matter

20

Outline

Shale and CO2 Cooptimized EOR & Storage

CO2


oil

zero capillary entry pressure barrier 0

0.1

0.2

0.3

0.4

0.5

0.6

0 2000 4000 6000 8000 10000 12000 14000 16000days


Shale EOR and CO2

CO2


oil

Main Points

• We know a lot about …

• miscibility

• unstable flow

• role of heterogeneity

• WAG

• optimization

• EOR using anthropogenic

CO2

• But, challenges remain …

• cooptimization of EOR and

storage

• phase behavior and

transport in tight media

• coupled transport, reaction,

and geomechanics

• unstable flow

https://www.acs.org/content/acs/en/pressroom/presspacs/2015/acs-presspac-november-18-2015/profit-from-co2.html

23

LaBarge, WY

Rangely Colorado

Gas ProcessingPlant

Gas Injection Well

Mixture of MethaneCarbon DioxideHeliumHydrogen Sulfide

Utah

Driven solely by economics

Ca

n w

e u

se

an

thro

po

ge

nic

CO

2fo

r E

OR

?S

eq

ue

str

ati

on

to

da

y

Can we use anthropogenic CO2 for EOR?Rangely Field, CO Performance

• separate CO2 from produced

natural gas

• use CO2 for enhanced oil

recovery (EOR)

• 114 million bbl incremental

production (about $5.5 billion

at $50/bbl)

• extended significantly the life

of the fieldIncremental

Production

Masoner and Wackowski, SPERE, Aug 1995

EOR vs Sequestration

• EOR design: max{recovery} U min{CO2 injection}

• Cooptimization EOR and CCS: max{recovery and Sg} U min{CO2 cycling}

• Breakthrough of injected gas and gas cycling limits EOR processes:

Np* = oil recovery - energy to recompress cycled gas

Synthetic reservoir (PUNQ S3)

permeability, kx (md)1 1000 log 10

truth model

• dome with gas cap

• bounded by faults and

aquifer

• PV = 30 Mm3 = 0.2 Bbbl

• depth to top = 2340 m

• ~24°API

• sand & shale

sequences

19 x 28 x 5 blocks, 1761 active

Kovscek, A. R. and M. D. Cakici, Energy Conversion and Management, 2005.

Solvent Immiscible

Name pure CO2

N2 0 0CO2 0.6667 1H2S 0 0Methane 0 0Ethane 0.1250 0Propane 0.1250 0i-Butane 0.0833 0

Gas injection


• Water Alternating Gas Drive

(WAG)

• Gas Injection after Water

Flooding (GAW)

• GOR Controlled Production

Wells with Injection Well

BHP constraints (no water)

• Np* = Np - oil energy to compress

produced gas

0.0E+00

5.0E+07

1.0E+08

1.5E+08

2.0E+08

2.5E+08

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5PVs injected

kg-m

of C

O2

wag 0.01 PV - CO2wag 0.1 PV - CO2wag 1 PV - CO2wag 0.01 PV - solventwag 0.1 PV - solventwag 1 PV - solventCO2 injectionsolvent injection

kg o

f CO

2 in

rese

rvoi

r

The Problem With WAG and CCSFill your reservoir with water not CO2


Well Control: Active Injection and Production

Constraints


Average Pressure and GOR

0

50

100

150

200

250

300

350

400

0 2000 4000 6000 8000 10000 12000 14000 16000days

0

2000

4000

6000

8000

10000

12000WC1 - FPR WC2 - FPR WC3 - FPR WC0 - FPR

WC1 - GOR WC2 - GOR WC3 - GOR WC0 - GOR


0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 2000 4000 6000 8000 10000 12000 14000 16000days


fracti

on

al o

il r

eco

very

(N

p* /O

OIP

)

CO2

solvent

Oil Recovery

0

0.1

0.2

0.3

0.4

0.5

0.6

0 2000 4000 6000 8000 10000 12000 14000 16000days


reserv

oir

uti

lizati

on

(V

CO

2/P

V)

Storage Utilization


Geomechanics and Seal Capacity

• How will CO2

injection affect the

reservoir seal?

• Did production and

depletion affect the

seal?

• What are the

geomechanical

mechanisms

governing capacity?

Trap and Seal Framework

Cooptimization Summary

• Well control (GOR and pinj as control parameters)

– same oil recovery as WAG process

– 2.5 times more CO2 utilization wrt WAG

– significant effect on recovery for solvent injection

• Results show little sensitivity to the reservoir

model (i.e., distribution of permeability)

• Some sensitivity wrt values of GOR and pinj

• Sensitive to constitutive relationships

35

Our approach to CO2 Enhanced RecoveryMulti* = multiscale, multiphysics, multiphase

Pore Scale• Capillary forces

• Stokes flow

• Viscous dissipation

• Rock/fluid interaction & reaction

• DLA, Anti-DLA

• Pore network simulation

• Direct numerical simulation

• Microfluidics

• MicroCT

Darcy Scale • Viscous & gravity forces

• Darcy’s law

• Coupled flow and mechanics

• Mobility control

• Reduction of gas production and recycle

Relative Permeability

StatisticalInformation

Small Scale Large Scale

Acknowledgements

• SCCS

• Stanford Synchrotron Radiation Lightsource, SLAC

• Stanford Nano Shared Facilities, SNSF

• Collaborators

36

KhalidAlnoaimi

HamzaAljamaan

Cindy Ross

BeibeiWang

BoliviaVega

YoussefElkady

DenizCakici

Questions?

Documents

Advanced Recovery Processes for Conventional Reservoirs and … · 2019. 12. 5. · CO2 injection Solvent Injection WAG 0.01 PV - CO2 WAG 0.01 PV - solvent GAW - CO2 GAW - solvent