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
pi (syn) 814.1 psi(a)pavg 891.8 psi(a)Cumgas -175.836 MMscfGIPmodel 1145.367 MMscf
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
h2 150.000 ft(k/µ)t2 222.00 md/cPµ2 0.0200 cPk2 4.4400 mdct2 1.4873e-03 1/psir2 1000.000 ft
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
pi (syn) 450.4 psi(a)pavg 531.6 psi(a)Cumgas -193.411 MMscfGIPmodel 846.024 MMscf
h1 150.000 ft(k/µ)t1 265.00 md/cPµ1 0.0200 cPk1 5.3000 mdct1 2.1683e-03 1/psir1 250.000 fts' 0.000
h2 150.000 ft(k/µ)t2 265.00 md/cPµ2 0.0200 cPk2 5.3000 mdct2 2.1683e-03 1/psir2 1165.000 ft
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
pi (syn) 1419.9 psi(a)pavg 1618.2 psi(a)Cumgas -1644.539 MMscfGIPmodel 6566.704 MMscf
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)
pi (syn) 1419.9 psi(a)pavg 1618.1 psi(a)Cumgas -1644.539 MMscfGIPmodel 6566.313 MMscf
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
h3 150.000 ft(k/µ)t3 65.00 md/cPµ3 0.0500 cPk3 3.2500 mdct3 2.0000e-02 1/psir3 1100.000 ft
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
pi (syn) 813.0 psi(a)pavg 948.8 psi(a)Cumgas -1646.727 MMscfGIPmodel 5715.010 MMscf
h1 150.000 ft(k/µ)t1 535.00 md/cPµ1 0.0400 cPk1 21.4000 mdct1 5.0000e-03 1/psir1 250.000 fts' 0.000
h2 150.000 ft(k/µ)t2 535.00 md/cPµ2 0.0400 cPk2 21.4000 mdct2 5.0000e-03 1/psir2 2000.000 ft
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
pi (syn) 1144.6 psi(a)pavg 1309.7 psi(a)Cumgas -1646.620 MMscfGIPmodel 2971.734 MMscf
h1 150.000 ft(k/µ)t1 500.00 md/cPµ1 0.0400 cPk1 20.0000 mdct1 5.0000e-04 1/psir1 150.000 fts' 0.000
h2 150.000 ft(k/µ)t2 500.00 md/cPµ2 0.0400 cPk2 20.0000 mdct2 8.0000e-04 1/psir2 1050.000 ft
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