Midwest Regional Carbon Sequestration Partnership...Carbon Storage R&D Review Meeting, Pittsburgh,...

Carbon Storage R&D Review Meeting, Pittsburgh, PA

August 12-14, 2014

DOE/NETL Cooperative Agreement # DE-FC26-0NT42589

Darrell Paul, Program MgrNeeraj Gupta, Technical MgrSrikanta Mishra, Modeling

Midwest Regional Carbon Sequestration Partnership

MRCSP Presentation Outline

• Program Overview • Technical Discussion Injection operations Site characterization Baseline monitoring Reservoir pressure analysis Static modeling Dynamic modeling

2

MRCSP: 10 Years of Achievements... and Going Strong

3

Contributions From Partners Have Helped Make MRCSP Successful

4

MRCSP Region - Economic Drivers•Population: 80.4 million (26% of the U.S. population) •Gross Regional Product: $3.1 trillion (27% of the U.S. economy) •26.3% of all electricity generated in the US •75% of electricity generated in the region is generated by coal

MI

OH

NY

KY

IN

PA

MDNJ

WV

MRCSP Field Test Sites

5

Regional Characterization Critical for Developing Implementation Plans

Nine State Geo Teams assist in identifying and characterizing reservoirs across state lines

Piggyback wireline logging, coring, etc. fills gaps in knowledge base, and stretches research funds

Ohio Coal Development Office strong supporter of geological characterization efforts through cofunding of activities.

6

Large Scale Demonstration Site

Location: Otsego County, Michigan

Source of CO2: Local Natural Gas Processing Plant (Antrim Shale Gas ~15% CO2 content)

Reservoir Type: Closely-spaced, highly compartmentalized oil & gas fields located in the Northern Michigan’s Niagaran Reef Trend

7

Outreach and Education Critical to Success of the Program

Proactive Approach- Communication Plan- Annual Partner’s Meetings- Site Visits - Community Relations- Outreach Materials- Website

8

- DOE/NETL Best Practices Manuals- NATCARB Database and Publications- EPA Guidelines Requests for Comments- Industry Mtgs & Conferences- Trade Associations

8

AcknowledgementsDOE/NETL has worked with us and our partners to structure a program that adds to the knowledge base and extends the state-of-the-art.

Core Energy, LLC our host site and CO2 supplier for 10 years of collaboration

The Ohio Coal Development Office has provided consistent and significant cofunding for the regional characterization efforts of the MRCSP.

The nine state Geology Surveys and Universities have been essential in expanding the results into regional implementation plans.

Battelle’s MRCSP team members for work shown here

9

EOR Field Evaluation Across Life Cycle Stages

Oil fields in various production stages

• Late-Stage EOR Reefs (Task 3)Highly depleted with extensive primary and secondary oil recovery.

• Active EOR Reefs (Task 4)Completed primary oil recovery and secondary oil recovery is under way

• Pre-EOR Reefs (Task 5)Undergone primary oil recovery but no secondary oil recovery is attempted

Reef Surface

10

Summary of Progress

• Completed baseline monitoring and site preparation• ~240,000 metric tonnes injected in late state reef• >25,000 metric tonnes net CO2 in active EOR reefs• Operational and subsurface monitoring underway• Reservoir analysis shows closed reservoir conditions• Phase chance and compressibility affect pressure• Initial static and reservoir models prepared• Injection in new EOR reefs likely to start in early 2015• Regional mapping/characterization across nine states

11

Many Operational and geological factors affect CO2 injection and storage in EOR Fields

• Production history for each reef needs to be known, including: Original estimates of fluids (oil, gas, brine)

Primary production history

Secondary recovery, CO2 injection and retention

• Current operational constraints determine how much CO2 is stored within each reef at a given time

• Geologic factors such as: Size of the reservoir

Configuration of the wells

Relative permeability

Solubility of CO2 in brine and oil

Reservoir temperature and pressure

12

Core Energy’s EOR Infrastructure used for Testing CO2 Storage

Core Energy Compressor

Core Energy Existing Pipeline

Charlton 6

Charlton 30/31

Dover 33Dover 35

Chester 5

Dover 36

Chester 2

Dover 33 is the main test bed

Active reefs also being monitored

Natural gas processing provides the CO2

Pre-EOR reef TBD

13

CO2 Flow System

Fluid production

Fluid Injection

Pure CO2compressed at Chester 10

Produced and Recycled CO2

Compositional Analysis

All produced CO2 is recycled back into system.

14

Injected CO2 (includes pure CO2 from Chester 10 + produced/recycled CO2)

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2/3/

13

2/18

/13

3/5/

13

3/20

/13

4/4/

13

4/19

/13

5/4/

13

5/19

/13

6/3/

13

6/18

/13

7/3/

13

7/18

/13

8/2/

13

8/17

/13

9/1/

13

9/16

/13

10/1

/13

10/1

6/13

10/3

1/13

11/1

5/13

11/3

0/13

12/1

5/13

12/3

0/13

1/14

/14

1/29

/14

2/13

/14

2/28

/14

3/15

/14

3/30

/14

4/14

/14

4/29

/14

5/14

/14

5/29

/14

6/13

/14

6/28

/14

Cum

ulat

ive

CO

2 (M

T)

CO

2 (M

T)

2013/2014 - Total CO2 Injected , Active Reefs + Dover 33 Reef

Total CO2 (MT) Cumulative Total CO2 (MT)

15

Dover 33 Reef EOR Operations

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,0004/

1/96

10/1

/96

4/1/

9710

/1/9

74/

1/98

10/1

/98

4/1/

9910

/1/9

94/

1/00

10/1

/00

4/1/

0110

/1/0

14/

1/02

10/1

/02

4/1/

0310

/1/0

34/

1/04

10/1

/04

4/1/

0510

/1/0

54/

1/06

10/1

/06

4/1/

0710

/1/0

74/

1/08

10/1

/08

4/1/

0910

/1/0

94/

1/10

10/1

/10

4/1/

1110

/1/1

14/

1/12

10/1

/12

4/1/

1310

/1/1

34/

1/14

Cum

ulat

ive

CO

2 (M

T)

Cum

ulat

ive

Oil

(BB

L)

Dover 33 - Cumulative Production/Injection

Cumulative Oil (BBL) Cumulative CO2 Injected (MT) Cumulative CO2 Produced (MT) Net CO2 in Reef (MT)

MRCSP Phase III Injection

16

139,037

236,063

334,826340,767356,027356,015356,680368,265372,994374,494462,256476,335

596,930653,435

807,672

974,134

1,133,991

1,321,633

1,378,224

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Net

in R

eef C

O2

(MT)

Net in Reef CO2 (MT)

Dover 33 EOR Unit Dover 36 EOR Unit Dover 35 EOR Unit

Charlton 30/31 EOR Unit Charlton 6 EOR Unit Chester 2 EOR Unit

Chester 5 EOR Unit Total EOR Net In Reef CO2 (MT)

Net CO2 in reefs increases over time

17

Dover 33 Reef Wells• 3 active wells

• Well 1-33 (vertical well) is the CO2 Injection well.

• Well 2-33 (horizontal well) is a former production well that was used as a monitoring well. This well is an open borehole.

• Well 5-33 (high angle well) is a former production well that was used as a monitoring well.

1-33 injection well

5-33

2-33

1-33

18

Dover 33 Reef Showing Well Traces

Injection Well (1-33)Surface of A-1 Carbonate Showing Reef Structure

19

A portfolio of technologies is being tested at the Dover 33 late stage reef

Lessons learned will be applied to design the MVA plan for the newly targeted field

Activity BeforeInjection

Early Injection

Mid Injection

Late Injection

After Injection

CO2 flow X X XPressure and temperature X X X X X

Wireline logging X X XBorehole gravity X XFluid sampling X X XVSP X XMicroseismic X MaybeSatellite radar X X X X X

21

Baseline monitoring activities

22

Safety Considerations for MRCSP Fieldwork

• Wide variety of work -- wide range of safety considerations

• All work completed safely to date!Well Workovers –well control, overhead hazards, heavy equipment

Seismic Activities –well work, explosive hazards

Fluid Sampling and Reservoir Testing –high pressure fluids, well work

InSar ACRs – heavy equipment operation

Wireline Logging –well work, radiologic hazards

23

Vertical Seismic Profile• Five walk-away lines centered around 1-33 injection well

• Processed data shows increase in resolution, though questions remain regarding potential migration errors

• VSP will be repeated after injection is completed

Receiver Locations North-South Line

24

Comparison of Surface and Borehole Seismic Data

• The two images show nearly the same geologic slice

• The VSP shows higher resolution and more internal reef character

• Curvature seen on the edges of the image is a processing artifact

• 3D Data • VSP

25

East-West VSP Line Detail

A2 Carbonate

A1 Carbonate

26

Microseismic Monitoring• Monitoring in Dover 33 well 5-33 from 3/20/13 - 4/1/13, during

and after a short injection test

• Data quality was good for confidence in event picks

• 34 events recorded, but none in the reef Detectable events verify the ability of the array to detect events

Events were located using a velocity model created from the available sonic logs in and around the reef

• Maybe repeated after injection

27

Microseismic Event Locations

Simplified Reef Location

Borehole Events

Small Seismic Events

28

Pulsed Neutron Capture

• Completed baseline and repeat logs in two wells (2-33 and 5-33)

• Processing to distinguish liquid (oil/brine) from gas (CO2/methane) phase

• Additional processing may distinguish between oil and brine

• Initial results show increase in fluid phase constituents and a decrease in gas phase constituents – CH4dissolving in oil and CO2 phase change to supercritical?

• Further logging events may also help distinguish phase behavior from fluid saturations

Well 5-33 repeated data, showing data from 2012 to 2013

LithologyGas/Fluid Saturation

Porosity Percent change in Sigma

29

• Gravity meter takes point measurements along the injection wellbore

• Data is then converted to density

• Repeat surveys indirectly measure the change in CO2 saturation

Borehole gravity surveys conducted to measure CO2 saturation

30

Geochemical sampling and analysis

31

• Major and trace element in fluids• Isotopic composition of gas,

water, carbon compounds• Seeking regional core samples

to analyze mineralogy, porosity, pore networks

• Integrating results into predictive models to better understand geochemical processes

• In collaboration with Ohio State

31

High precision measurements of the ground surface using satellite radar (InSAR)

• Installed reference points (ACRs)

• Completed historic analysis and >one year of operational monitoring

• No significant elevation change detected so far

Source: TRE Canada, Inc.

32

16 weekTest

11 weekTest

30 week Test

9 DayTest

1 DayTest

*Pressure in 1-33 injection well available only thru 12-26-13

CO2 Injection and Pressure Response

33

History Matching Method Was Used for Analyzing Injection-Fall-Off Tests

• History matching was implemented using analytical reservoir model (WellTest™)

• History matching process:

• Using measured injection record for each CO2 injection test, simulate pressure response in the injection well and monitoring wells;

• Adjust model parameters to match the measured pressure response during the injection-falloff sequence

Simulated pressure

Measured pressurePr

essu

re (p

si)

Elapsed Time (hr)

Example History Match Plot for a Single Injection Fall-Off Event

---------- Injection ------------ ----Fall-Off ---

Modeled

Measured

34

9-Day Injection+3-Week Fall-Off Test

800

850

900

950

1000

1050

1100

Pres

sure

(psi

(a))

-20

-16

-12

-8

-4

0

Gas R

ate (MM

scfd)

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700

Time (h)

pdatapmodelqgas

pi (syn) 876.9 psi(a)pav g 919.1 psi(a)Cumgas -175.718 MMscfGIPmodel 2161.719 MMscf

9-Day Injection+3-Week Fall-Off Test

10-3

10-2

10-1

1.0

101

102

3

3

3

3

3

∆ψ

/q, D

eriv

ativ

e ((1

06ps

i2 /cP

)/MM

scfd

)

10-2 10-1 1.0 101 102 1032 3 4 5 6 2 3 4 5 6 7 2 3 4 5 6 7 2 3 4 5 6 7 2 3 4 5 6 8

Pseudo-Time (h)

∆ψ/qdata∆ψ/qmodelExt. ∆ψ/qmodelDerivativedata

Derivativemodel

Ext. Derivativemodel

pi (syn) 876.9 psi(a)pavg 919.1 psi(a)Cumgas -175.718 MMscfGIPmodel 2161.688 MMscf

h1 150.000 ft(k/µ)t1 1346.00 md/cPµ1 0.0200 cPk1 26.9200 mdct1 1.5225e-03 1/psir1 250.000 fts' -4.500

h2 150.000 ft(k/µ)t2 200.00 md/cPµ2 0.0200 cPk2 4.0000 mdct2 5.0000e-04 1/psir2 515.000 ftCD 100.00

h3 150.000 ft(k/µ)t3 700.00 md/cPµ3 0.0200 cPk3 14.0000 mdct3 2.0000e-02 1/psir3 1500.000 ft

9-Day Injection + 3-Week Fall-Off Test (5-33 Well)

820

840

860

880

900

Pres

sure

(psi

(a))

-20

-15

-10

-5

0

Gas R

ate (MM

scfd)

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700

Time (h)

pdatapmodelqgas


h1 150.000 ft(k/µ)t1 222.00 md/cPµ1 0.0200 cPk1 4.4400 mdct1 1.4873e-03 1/psir1 250.000 fts' 0.000


9-Day Injection +3-Week Fall-Off Test (2-33 Well)

460

480

500

520

540

Pres

sure

(psi

(a))

-20

-15

-10

-5

0

Gas R

ate (MM

scfd)

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750

Time (h)

pdatapmodelqgas




Injection WellPressure Match

Injection WellDerivative Match

Monitoring Well 5-33 Monitoring Well 2-33

9-Day Test

35

Injection WellPressure Match

Injection WellDerivative Match

Monitoring Well 5-33 Monitoring Well 2-33

16-Week Test

Could not match Could not match

16-Week Injection + 3-Week Fall-Off Test

1150

1200

1250

1300

1350

1400

1450

1500

1550

Pres

sure

(psi

(a))

-20

-16

-12

-8

-4

0

Gas R

ate (MM

scfd)

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

Time (h)

pdatapmodelqgas


16-Week Injection + 3-Week Fall-Off Test

10-2

10-1

1.0

101

2

4

2

4

2

4

∆ψ

/q, D

eriv

ativ

e ((1

06ps

i2 /cP

)/MM

scfd

)

10-2 10-1 1.0 101 102 103 1042 3 4 5 7 2 3 4 5 7 2 3 4 5 7 2 3 4 5 6 2 3 4 5 6 2 3 4 5 6

Real Time (h)


h1 150.000 ft(k/µ)t1 250.00 md/cPµ1 0.0500 cPk1 12.5000 mdct1 1.0000e-03 1/psir1 85.000 fts' -4.500

h2 150.000 ft(k/µ)t2 832.00 md/cPµ2 0.0500 cPk2 41.6000 mdct2 3.0000e-04 1/psir2 600.000 ftCD 100.00


16-Week Injection + 3-Week Fall-Off Test (2-33)

850

900

950

1000

1050

1100

1150Pr

essu

re (p

si(a

))

-20

-16

-12

-8

-4

0

Gas R

ate (MM

scfd)

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200

Time (h)

pdatapmodelqgas




16-Week Injection + 3-Week Fall-Off Test (5-33)

1100

1200

1300

1400

1500

Pres

sure

(psi

(a))

-40

-30

-20

-10

0

Gas R

ate (MM

scfd)

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200

Time (h)

pdatapmodelqgas




36

Results

Mobility (2-33 and 5-33)Mobility (1-33)

1400

1200

1000

800

600

400

200

0

Mob

ility

(m

d/cP

)

Mobility from Injection Well (1-33) and Monitoring Wells (2-33, 5-33)

Permeability (2-33 and 5-33)Permeability (1-33)

50

40

30

20

10

0

Per

mea

bilit

y (m

d)

Permeability from Injection Well (1-33) and Monitoring Wells (2-33, 5-33)

Comparison of Mobility Values fromInjection Well Data (left) and Monitoring Well Data (right)

Comparison of Permeability Values fromInjection Well Data (left) and Monitoring Well Data (right)

37

CO2 Phase Behavior During Tests Based on P&T at Injection Well

|--1 day--|---9 day test--|----------------11 week test-------------------|--------------------16 week test-------------------------------------|

V

LS

VaporLiquidSupercritical

V

L SL

V

38

CO2 Compressibility During Tests Based on P&T at Injection Well

|--1 day--|---9 day test--|----------------11 week test-------------------|--------------------16 week test----------------------------------|

Summary of Fall-Off Testing (cont’d)

• It was not possible to match all injection/fall-off events• Despite limitations of analytical modeling approach, the

following conclusions can be made: The Dover 33 reef behaves as a closed system, as evidenced by

pressure build up over time

It can be modeled as a circular reservoir with radius of ~1,000 to 2,000 ft (most scenarios suggested radius <1,500 ft)

Permeability ranges from ~ 1 to 42 md based on injection well results and ~ 2 to 23 md based on monitoring well results

• EPA Class VI UIC Regulation requires periodic Fall-Off Testing; existing analytical methods may not be adequate for EOR reservoirs.

40

Field data has been integrated into geologic models of the reef

Log and core correlationSeismic Interpretation Geologic Framework Model

Final Geologic Model

Porosity

41

Sensitivity of dynamic reservoir behavior to alternate geologic models

Static Earth Model (SEM) Level 1

Property distributions constrained by geologic formation surfaces.

Property distributions constrained by lithofacies.

Static Earth Model (SEM) Level 2

Geologic surfaces based on 3D seismic and well data.

42

Dover-33 (carbonate reef) represented in various levels of geologic detail

SEM1 Porosity Model

SEM2 Porosity Model

43

Initialization of SEM1 in black oil simulator

1-3329565 55942

2 011 000 2 012 000 2 013 000

04,200

4,3004,400

4,5004,600

44,

200

4,30

04,

400

4,50

04,

600

4,70

00.00 355.00 710.00 feet

0.00 110.00 220.00 meters

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

Initial water saturation

44

Goals of Reservoir Modeling

• Scientific – process understanding (e.g., how does CO2move through the formation and interact with oil/brine)

• Engineering – system design (e.g., well rates/location needed to maximize recovery and optimize storage)

• Calibration – history matching (e.g., update description of subsurface by comparing model predictions to observations)

• Regulatory – compliance demonstration (e.g., what is the risk of CO2 leakage)

• Outreach – visualization (e.g., animation of system evolution)

46

Phase-III Modeling Tasks

• Task 1.11 – Assessment and Modeling of Niagaran Reefs CO2 storage potential in Niagaran reef trend

• Task 3.4 – Reservoir Modeling & Analysis (Late Stage Reefs) Prediction/history matching of CO2 injection response

• Task 4.3 – Reservoir Modeling & Analysis (Active Reefs) Prediction/history matching of CO2 injection response

• Task 5.4 – Reservoir Modeling & Analysis (New Reefs) Design of optimal CO2 injection scenarios

Prediction/history matching of CO2 injection response

47

Time (Date)

Cum

ulat

ive

Oil

SC (M

BB

L)

Avg

rese

rvoi

r pre

ssur

e (p

si)

1980 1985 1990 19950

500

1,000

1,500

2,000

0

1,000

2,000

3,000

Task 3 (Dover 33) Dynamic Modeling

1. System / reservoir specificationBLACK OIL MODEL

COMPOSITIONAL MODEL

3. Model performance calibration to historical data

2. Fluids definition/ treatment

4. Injection response validation

48

Black-oil Model History Match

Time (Date)

Cum

ulat

ive

Solv

ent S

C (M

MSC

F)

Solv

ent R

ate

SC (M

MSC

F/da

y)

1980 1985 1990 1995 2000 2005 20100

10,000

20,000

30,000

40,000

0.0

5.0

10.0

15.0

20.0

Time (Date)

Ave

rag

e re

serv

oir

pre

ssu

re (

psi

)

1980 1985 1990 1995 2000 2005 2010

500

1,000

1,500

2,000

2,500( )( )

Gas injection Avg. pressure

Time (Date)

Cum

ulat

ive

Oil

SC

(MB

BL)

Oil

Rat

e S

C (M

BB

L/da

y)

1980 1985 1990 1995 2000 2005 20100

500

1000

1500

2000

0.00

0.50

1.00

1.50

2.00

Time (Date)

Cum

ulat

ive

Sol

vent

SC

(MM

SC

F)

Sol

vent

Rat

e S

C (M

MS

CF/

day)

1980 1985 1990 1995 2000 2005 20100

5,000

10,000

15,000

20,000

25,000

0.0

5.0

10.0

15.0

20.0

Oil production Gas production

49

“Validation” with Phase III Injection Data

Time (Date)

Solv

ent R

ate

SC (f

t3/d

ay)

Ave

rage

Res

ervo

ir Pr

essu

re B

uild

up (p

si)

2013-4 2013-7 2013-10 2014-1 2014-4 2014-70.00e+0

5.00e+6

1.00e+7

1.50e+7

2.00e+7

0

500

1,000

1,500

2,000

Pressure under-predicted possibly due to

Reservoir dimensions

CO2Solubility

Compositional model

50

Time (Date)

Ave

rese

rvoi

r pre

s (p

si)

Cum

ulat

ive

Oil

SC (M

BB

L)

1980 1985 1990 19950

1,000

2,000

3,000

0

500

1,000

1,500

2,000

Compositional Model History MatchPrimary Production

Oil Production

Average reservoir pressure

51

Ongoing/Future Modeling Activities

• Complete compositional model history match for secondary recovery period

• Predict injection pressure response for Phase III injection, and adjust model parameters as needed to match field data

• Repeat exercise for Level 2 SEM (lithofacies model)

• Extract single-well simulation model for detailed analysis of transient pressure response from injection-falloff periods.

• Incorporate geochemical and geo/mechanical aspects

• Investigate applicability of material balance type models

52

Material Balance with CO2 InjectionFluids produced CO2 injected

Fluid expansion Formation expansion

Expansion of CO2contacted oil

Expansion of CO2contacted water

CO2 dissolved in oil CO2 dissolved in water

+

++

– –

gPgsoP BGBRBN +− )(

=

–22, COCOi BG

})({ gssioio BRRBBN −+− )}1/()({ wiwiwfoi SPSccBN −∆+

ooomom BBBV /)( ,, − wwwmwm BBBV /)( ,, −

,2

2

,

,)(

COo

COsop

BRBNN −

after Tian & Zhao, JCPT, 2008

22, COCOP BG+

woi

swwoi

BSRSNB

53

Injection Response in a Closed Volume

• If ct is known, we can predict pressure buildup from injection of known volume (or storage capacity upto discovery pressure)

• co ~10-5 psi-1; cw, cf ~10-6 psi-1

• cg ~10-4 psi-1 (pressure. dependent)

• [Q] Can we obtain insights on ct

versus p relation from field data?

fwwggoot

ti

cScScScccAh

QPP

+++=

=−φ

)(Dover 33 Data

54

What Can We Learn From Modeling?

• Workflow for building SEMs with limited data, and calibrating dynamic models to production history

• Impact of geologic uncertainty on reservoir behavior

• Factors affecting CO2 retention in closed systems

• Simplified models for predicting CO2 storage capacity in depleted reef reservoirs

• Significance of coupled processes in depleted reefs

55

Questions?

Please visit www.mrcsp.org56

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