Annual GCEP Symposium 2007 Contact: Amie Lucier at [email protected]
Amie Lucier and Mark Zoback, Department of Geophysics, Stanford University
Assessing the economic feasibility of regional deep saline aquifer CO2 injection and sequestration:
A geomechanics-based workflow applied to the Rose Run Sandstone in Eastern Ohio - Typical top-down regional assessments of CO2 sequestration feasibility
determine the maximum volumetric capacity of deep saline aquifers, but do not reflect the economic feasibility of sequestration of a region
- The CO2 sequestration capacity of an aquifer is a function of its porous
volume as well as its CO2 injectivity.
- Economic feasibility is controlled, in part, by the number and type of injection wells necessary to achieve regional CO
2 sequestration goals
- Economic feasibility is also affected by the cost of transporting CO2.
Transportation costs can be minimized by identifying injection sites near to large point sources.
- Injection sites closest to large point sources may not be the most “ideal” injection reservoirs
- In this study, we present a methodology to evaluate the economic feasibility of CO
2 sequestration in regions with many large point sources,
but less than ideal injection reservoirs
- The geomechanics-based assessment workflow that we present in this poster follows a bottom-up approach for evaluating regional deep saline aquifer CO
2 sequestration feasibility
- A site is considered feasible CO2 can be injected at a reasonable cost per
ton of CO2, as defined by injection rate and well costs
- A region is considered feasible if it has enough sites to store a specified amount of CO
2 at reasonable cost per ton of CO
2, as defined by the
number and costs of wells needed to met the CO2 project goals
Introduction Injectivity and Economics
Rose Run Sandstone Case Study
1. Define CO2 Sequestration Project and Goals - Study location area - Amount of CO2 to be sequestered - Economic controls/limitations
2. Regional Characterization
3. Construct 3D Reservoir Model Using Geostatistics - Build 3D grid with geometry consistent with regional structure - Use geostatistics to populated models with all possible combinations of hydrogeologic property distributions
4. Simulate CO2 Injection - Injection rates are limited by fracture pressure and/or critical fault slip pressure of caprock - Project goals define the time period over which simulations are run
5. Evaluate CO2 injection and Sequestration Feasibility - Categorize each model by likelihood of occurring in the region - Calculate cost/ton of CO2 for each injection model - Determine feasibility of achieving sequestration goals within the defined spatial and economic controls
a. Characterize the Geology - Characterize structure, rock and hydrogeologic properties of aquifer and caprock - Define reasonable regional distributions of hydro- geologic properties
b. Characterize the Geomechanics - Build regional geomechanical model of in situ stress state - Assess feasibility of incorporating injectivity/ permeability enhancement techniques
6. Evaluate Injectivity Enhancement Techniques for Improved CO2 Sequestration Feasibility
a. Vertical Well with Hydraulic Fracture
b. Vertical Well with Induced Micro- Seismicity
c. Horizontal Well with Hydraulic Fractures
d. Horizontal Well with Induced Micro- Seismicity
a. Proceed with Sequestration Assessment - Update regional results by screening more local sites - Refine assessment with new data
b. Abandon regional plans for sequestration
7. Regional Sequestration Assessment
Geomechanics-Based Workflow Discussion
Likelihood of Fault Slipas a function of fracture pole orientation
(lower hemisphere projection)
10 15 20 25 Critical Pp gradient, MPa/km
SHmax
N
Pp
high lowShmin caprock
16 21 260
2
4
6
Normal stress gradient, MPa/km
She
ar s
tress
gra
dien
t,M
Pa/
km
µ=0.6
SHmax Sv
Critically stressed fractures in the Rose Run
Not critically stressed fractures in the Rose Run
Critically stressed fractures in the Rose Run at Pp=Shmincaprock
Pp Shmincaprock
In situ P p
Critically stressed fractures in the Rose Run at Pp=ShminRose Run
P p=S hmin
Rose Run
P p=S hmin
caprock
ShminRose Run
Pp increasing with injection
CO2 Saturation0.1 0.30.2 0.4 0.5 0.6
Vertical Injection Wells Horizontal Injection Wells
32 MPa BHP
40 MPa BHP
Hydraulic Fracture
0
2
4
6
8
10
12
14
16
18
0 10 20 30
Cum
ulat
ive
Inje
ctio
n, M
t CO
2
Time, years
32 MPa BHP
40 M
Pa B
HP
Hyd
raul
ic F
ract
ure
32 MPa BHP
40 MPa BHP
Hydraulic Fracture
A. B.
Summary of CO2 Injection Simulation Results after 30 Years for Model T60_K20_P8
N10 X Vertical Exaggeration
BHP32 MPa
BHP40 MPa
Mean Thickness30 m (T30) [1]
Mean Thickness60 m (T60) [3]
Mean Perm.4 md (K4) [1]
Mean Perm.20 md (K20) [2]
Mean Perm.40 md (K40) [3]
Mean Porosity4 % (P4) [2]
Mean Porosity8 % (P8) [1]
Mean Porosity12 % (P12) [3]
Subtotal: 36 Injection Simulations
Stru
ctu
ral
Vari
abili
tyPr
op
erty
Var
iab
ility
Vertical Injection Well
BHP32 MPa
BHP40 MPa
Mean Thickness30 m (T30) [1]
Mean Thickness60 m (T60) [3]
Mean Perm.4 md (K4) [1]
Mean Perm.20 md (K20) [2]
Mean Perm.40 md (K40) [3]
Mean Porosity4 % (P4) [2]
Mean Porosity8 % (P8) [1]
Mean Porosity12 % (P12) [3]
Subtotal: 36 Injection Simulations
Horizontal Injection Well
Total: 108 Injection Simulations
BHP42 MPa
Mean Thickness30 m (T30) [1]
Mean Thickness60 m (T60) [3]
Mean Perm.4 md (K4) [1]
Mean Perm.20 md (K20) [2]
Mean Perm.40 md (K40) [3]
Mean Porosity4 % (P4) [2]
Mean Porosity8 % (P8) [1]
Mean Porosity12 % (P12) [3]
Subtotal: 18 Injection Simulations
Stru
ctu
ral
Vari
abili
tyPr
op
erty
Var
iab
ility
Vertical Injection Wellwith Single Hydraulic Fracture
BHP42 MPa
Mean Thickness30 m (T30) [1]
Mean Thickness60 m (T60) [3]
Mean Perm.4 md (K4) [1]
Mean Perm.20 md (K20) [2]
Mean Perm.40 md (K40) [3]
Mean Porosity4 % (P4) [2]
Mean Porosity8 % (P8) [1]
Mean Porosity12 % (P12) [3]
Subtotal: 18 Injection Simulations
Horizontal Injection Well with Four Hydraulic Fractures
0
0.3
0.6
0.9
1.2
1.5
T30_K
4_P4
T30_K
4_P8
T30_K
4_P12
T30_K
20_P
4
T30_K
20_P
8
T30_K
20_P
12
T30_K
40_P
4
T30_K
40_P
8
T30_K
40_P
12
T60_K
4_P4
T60_K
4_P8
T60_K
4_P12
T60_K
20_P
4
T60_K
20_P
8
T60_K
20_P
12
T60_K
40_P
4
T60_K
40_P
8
T60_K
40_P
12
Mt C
O2/
yr
0
0.3
0.6
0.9
1.2
1.5
T30_K
4_P4
T30_K
4_P8
T30_K
4_P12
T30_K
20_P
4
T30_K
20_P
8
T30_K
20_P
12
T30_K
40_P
4
T30_K
40_P
8
T30_K
40_P
12
T60_K
4_P4
T60_K
4_P8
T60_K
4_P12
T60_K
20_P
4
T60_K
20_P
8
T60_K
20_P
12
T60_K
40_P
4
T60_K
40_P
8
T60_K
40_P
12
Mt C
O2/
yr
CO2 Injection Rate Averaged over 30 Years of Injection
Vertical Well (BHP=32 MPa)
Horizontal Well (BHP=32 MPa)Vertical Well Hydraulic Fracture (BHP=42)
Horizontal Well Hydraulic Fracture (BHP=42)
Vertical Well (BHP=40 MPa)
Horizontal Well (BHP=40 MPa)Vertical Well Hydraulic Fracture (BHP=42)
Horizontal Well Hydraulic Fracture (BHP=42)
0.00
2.50
5.00
7.50
10.00
12.50
15.00
17.50
20.00
22.50
25.00Vertical Well 32 MPa BHPVertical Well 40 MPa BHP
1.31
More Likely Less Likely
Ass
ocia
ted
Wel
l Cos
t US
$/t C
O2
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
3_T30
_K4_
P8
4_T30
_K4_
P4
4_T30
_K20
_P8
5_T30
_K4_
P12
5_T60
_K4_
P8
5_T30
_K20
_P4
5_T30
_K40
_P8
6_T60
_K4_
P4
6_T30
_K20
_P12
6_T60
_K20
_P8
6_T30
_K40
_P4
7_T60
_K4_
P12
7_T60
_K20
_P4
7_T30
_K40
_P12
7_T60
_K40
_P8
8_T60
_K20
_P12
8_T60
_K40
_P4
9_T60
_K40
_P12
Vertical Well 32 MPa BHPVertical Well 40 MPa BHP
Reg
iona
l Are
a R
equi
red
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000Vertical Well 32 MPa BHPVertical Well 40 MPa BHP
Num
ber o
f Wel
ls R
equi
red
522
3_T30
_K4_
P8
4_T30
_K4_
P4
4_T30
_K20
_P8
5_T30
_K4_
P12
5_T60
_K4_
P8
5_T30
_K20
_P4
5_T30
_K40
_P8
6_T60
_K4_
P4
6_T30
_K20
_P12
6_T60
_K20
_P8
6_T30
_K40
_P4
7_T60
_K4_
P12
7_T60
_K20
_P4
7_T30
_K40
_P12
7_T60
_K40
_P8
8_T60
_K20
_P12
8_T60
_K40
_P4
9_T60
_K40
_P12
3_T30
_K4_
P8
4_T30
_K4_
P4
4_T30
_K20
_P8
5_T30
_K4_
P12
5_T60
_K4_
P8
5_T30
_K20
_P4
5_T30
_K40
_P8
6_T60
_K4_
P4
6_T30
_K20
_P12
6_T60
_K20
_P8
6_T30
_K40
_P4
7_T60
_K4_
P12
7_T60
_K20
_P4
7_T30
_K40
_P12
7_T60
_K40
_P8
8_T60
_K20
_P12
8_T60
_K40
_P4
9_T60
_K40
_P12
A.
B.
C.
0
2
4
6
8
10
12
14
16
18
20
0
650
1300
1950
2600
3250
3900
4550
5200
5850
6500
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
3_T30
_K4_
P8
4_T30
_K4_
P4
4_T30
_K20
_P8
5_T30
_K4_
P12
5_T60
_K4_
P8
5_T30
_K20
_P4
5_T30
_K40
_P8
6_T60
_K4_
P4
6_T30
_K20
_P12
6_T60
_K20
_P8
6_T30
_K40
_P4
7_T60
_K4_
P12
7_T60
_K20
_P4
7_T30
_K40
_P12
7_T60
_K40
_P8
8_T60
_K20
_P12
8_T60
_K40
_P4
9_T60
_K40
_P12
More Likely Less Likely
Ass
ocia
ted
Wel
l Cos
ts U
S$/
t CO
2R
egio
nal A
rea
Req
uire
dN
umbe
r of W
ells
Req
uire
d
1.31
Vertical Well Hydraulic FractureEstimated VW Micro-seismicityHorizontal Well (32 MPa BHP)Horizontal Well (40 MPa BHP)Horizontal Well Hydraulic FractureEstimated HW Micro-seismicity
Vertical Well Hydraulic FractureHorizontal Well (32 MPa BHP)Horizontal Well (40 MPa BHP)Horizontal Well Hydraulic Fracture
Vertical Well Hydraulic FractureEstimated VW Micro-seismicityHorizontal Well (32 MPa BHP)Horizontal Well (40 MPa BHP)Horizontal Well Hydraulic FractureEstimated HW Micro-seismicity
A.
B.
C.3_
T30_K
4_P8
4_T30
_K4_
P4
4_T30
_K20
_P8
5_T30
_K4_
P12
5_T60
_K4_
P8
5_T30
_K20
_P4
5_T30
_K40
_P8
6_T60
_K4_
P4
6_T30
_K20
_P12
6_T60
_K20
_P8
6_T30
_K40
_P4
7_T60
_K4_
P12
7_T60
_K20
_P4
7_T30
_K40
_P12
7_T60
_K40
_P8
8_T60
_K20
_P12
8_T60
_K40
_P4
9_T60
_K40
_P12
3_T30
_K4_
P8
4_T30
_K4_
P4
4_T30
_K20
_P8
5_T30
_K4_
P12
5_T60
_K4_
P8
5_T30
_K20
_P4
5_T30
_K40
_P8
6_T60
_K4_
P4
6_T30
_K20
_P12
6_T60
_K20
_P8
6_T30
_K40
_P4
7_T60
_K4_
P12
7_T60
_K20
_P4
7_T30
_K40
_P12
7_T60
_K40
_P8
8_T60
_K20
_P12
8_T60
_K40
_P4
9_T60
_K40
_P12
Average kH (permeability thickness), m3 X10-9
Not Feasible: Costs > Maximum Economic Threshold of 1.31 US$/t CO2
Likely Feasible: Costs Within the Range of Economic Thresholds of 0.875-1.31 US$/t CO2
Feasible: Costs < Minimum Economic Threshold of 0.875 US$/t CO2
Inje
ctio
n S
cena
rio
0.1 1 10
Vertical Well: 32 MPa BHP
Vertical Well: 40 MPa BHP
Horizontal Well: 32 MPa BHP
Horizontal Well: 40 MPa BHP
Vertical Well: Hydraulic Fracture
Horizontal Well: Hydraulic Fractures
Vertical Well: Induced Micro-seismicity
Horizontal Well: Induced Micro-seismicity
Econo
mic Tr
ansit
ion fo
r Thr
esho
ld of
1.31 U
S$/t C
O 2
Inje
ctio
n S
cena
rio
0.1 1 10
Vertical Well: 32 MPa BHP
Vertical Well: 40 MPa BHP
Horizontal Well: 32 MPa BHP
Horizontal Well: 40 MPa BHP
Vertical Well: Hydraulic Fracture
Horizontal Well: Hydraulic Fractures
Vertical Well: Induced Micro-seismicity
Horizontal Well: Induced Micro-seismicity
Econo
mic Tr
ansit
ion fo
r Thr
esho
ld of
1.31 U
S$/t C
O 2
Econo
mic Tr
ansit
ion fo
r Thr
esho
ld of
2.62 U
S$/t C
O 2
Econo
mic Tr
ansit
ion fo
r Thr
esho
ld of
3.93 U
S$/t C
O 2
EconomicallyFeasible
Not Economically Feasible
A.
B.
Average kH (permeability thickness), m3 X10-9
1900
2050
2200
2350
2500
2650
2800
0 20 40 60 80 100
Dep
th [m
]
Pressure [MPa]
Pp SvShmin SHmax
minifrac
Strike-SlipFrictionalFaulting
Equilibrium
TrentonLimestone
BeekmantownDolomite
Rose Run Ss.
Copper RidgeDolomite
Nolichucky Shale
Upper MaryvilleDolomite
Lower MaryvilleSandstone
1. Define the CO2 Sequestration Project and Goals
a. Characterize the Geology
b. Characterize the Geomechanics
3. Construct 3D Reservoir Model Using Geostatistics
4. Simulate CO2 Injection
5. Evaluate CO2 Injection and Sequestration Feasibility
7. Regional Sequestration Assessment
2. Regional Characterization
6. Evaluate Injectivity Enhancement Techniques for ImprovedCO
2 Sequestration Feasibility
- This assessment methodology is a tool for estimating regional effective CO2
sequestration capacity
- It considers: 1. Available aquifer storage volumes 2. Realistic well injection rates 3. The costs associated with drilling and maintaining injection wells
- It utilizes: 1. Geological Characterization 2. Geomechanical Characterization 3. Aquifer Modeling 4. CO
2 injection simulation
- Regions are evaluated at the scale of individual injection intervals that represent the heterogeneity and uncertainty of regional aquifer properties
- In regions with low-to-moderate permeability and aquifer thickness, the injectivity of an aquifer may severely limit its effective storage potential
- Aquifer stimulation techniques can increase injectivity and decrease costs
- Carrying out a geomechanical analysis at a proposed injection site is necessary for: 1. Controlling injection pressures 2. Formulating stable deviated well trajectories 3. Developing hydraulic fracture treatments 4. Characterizing existing hydraulically conductive fractures 5. Planning induced micro-seismicity treatments
- For CO2 sequestration to be practical in a large portion of the Midwestern
United States, stimulation techniques will need to be employed
- The permeability, k, and the thickness, H, are the primary properties controlling the injection rate
- Models are more likely to be economically feasible if they have large kH values and are stimulated with hydraulic fractures or induced micro-seismicity
- At a higher cost per ton of CO2, some
models with smaller kH values and less stimulation become economically feasible
- With simple vertical or even horizontal injection wells, the region is unlikely to have enough injection capacity to make CO
2 sequestration feasible
- The Rose Run region meets the spatial requirements for sequestering 113 Mt CO
2/yr for 30 years.
- The Rose Run region is likely a feasible location for CO2 sequestration
- Several areas of investigation will lead to a more complete assessment 1. Characterize the stress state at more locations 2. Find trends in aquifer thickness and permeability to optimize kH values 3. Injection induced micro-seismicity experiments to determine the potential for increasing injectivity in the region
The goal of this project is to sequester 90% of the emissions from the 23 power plants near the case study area for 30 years at the current emissions rate of 126 Mt CO
2/yr (i.e.
113 Mt CO2/yr or 3.39 Gt CO2 over 30 years)
The economic constraints limit the costs associated with drilling and maintaining the injection wells in the region to ideally less than 0.875 US$/t CO
2 but up to 1.31 US$/t
CO2 (based on regional cost of energy and emissions rates)
The associated well costs are estimated by the type of well, stimulation techniques, and maintenance costs for the lifetime of the well
Study Area:- Rose Run is 2350±100 m deep (36 km X 360 km) - Corresponds to the depth of the Rose Run at the Mountaineer power plant - Near 23 large point sources, which emit approximately 126 Mt CO
2/yr
Well Type Initial Cost
(M US$)
Lifespan (years)
Annual Maintenance Cost (M US$)
Total Well Cost
(M US$)
Maximum # of Wells
Vertical well 4.0 30 0.15 8.5 522
Vertical well with hydraulic fracture 4.5 30 0.15 9.0 493
Vertical well with induced micro-seismicity 5.5 30 0.15 10.0 444
Horizontal well 6.0 30 0.15 10.5 423
Horizontal well with 4 hydraulic fractures 7.5 30 0.15 12.0 370
Horizontal well with induced micro-seismicity 8.5 30 0.15 13.0 342
The mean thickness of the Rose Run is about 30 m, but in some areas it can be more than 60 m thick
We defined three lognormal porosity distributions to evaluate with mean porosity values of 4%, 8%, and 12%.
We modeled three multigaussian log permeability distributions: (1) ranging from 1.6-25 md and a mean of about 4 md, (2) ranging from 8-125 md with a mean of about 20 md, and (3) ranging from 16-250 with a mean of about 40 md.
5 10 15 20 25 30
Porosity [%]
1 10 100 1000
Permeability [mD]
NWe modeled two aquifer thicknesses 1. Averaging 30 m (varying from 15 to 50 m) 2. Averaging 60 m (varying from 45 to 80 m)
We modeled each aquifer thickness three times: 1. Without a hydraulic fracture 2. With a single hydraulic fracture 3. With four, smaller, staggered hydraulic fractures that represent hydraulic fracturing along a horizontal well.
We populated the models with porosity and permeability values using sequential Gaussian simulation with 9 possible property combinations 1. Mean porosity = 4%, 8%, or 12% 2. Mean permeability = 4 md, 20 md, or 40 md
A. CO2 saturation after 30 year of injection for the six
injection scenarios that are simulated
B. Cumulative CO2 injection over 30 years for the six
scenarios
Stress magnitudes at the Mountaineer Site. The minifrac tests (red) indicate that the S
hmin magnitude
has two trends. It is significantly less in the Rose Run than that above and below. This means hydraulic fracturing is feasible.
Sv=62SHmax=54Shmin=34Pp=Pm=26
TENDENCY FOR BREAKOUTS AT 2365 m DEPTH
Stress Magnitudes [MPa]
Rose Run:Normal Faulting Stress Regime
Rock Strength [MPa] to Prevent Breakouts with >30o Width
SHmax
65 70 75 80 85 90
N
Horizontal Wellin Shmin Direction
Vertical Well
Well trajectories with hot colors require higher rock strengths to prevent breakouts and are therefore less stable. The Rose Run rock strength is more than 200 MPa at the Mountaineer site, so all well trajectories are stable the Rose Run stress state.
Fractures in the Rose Run sandstone. The lower hemisphere stereonet plot indicates likelihood of fault slip as a function of pole to the fracture plane. Fractures are also plotted on a Mohr diagram. Critically stressed faults often act as conduits for flow and enhance permeability. The presence of critically stressed faults make induced microseismicity a feasible stimulation technique.
Outline of fluid flow simulations, organized by injection scenario. BHP is bottom hole pressure used to constrain injection rates, and is constrained by S
hmin. The
abbreviations in ( ) refer to the naming convention. The number in [ ] categorizes the likelihood of a property to be found in the region, [1] is most and [3] is least likely.
CO2 injection rate averaged over 30 years
of injection. Simulations are sorted in order by thickness (T30, T60), permeability (K4, K20, K40), and porosity (P4, P8, P12).
Injection interval models are ranked by their likelihood of occurring in the region basedon their hydrogeological property values 1. We added up the values (1-3) for the 3 properties to get a ranking value from 3 to 9 2. Models with lower values are more representative of the regional aquifers 3. The ranking values are appended to the beginning of the model names.
We examined whether the sequestration goals could be met honoring spatial constraints 1. We calculated the surface area of the top of the CO
2 plume after 30 years of injection
2. Determined how many injection wells would be necessary to inject 113 Mt CO2/yr 3. We calculated the percentage of the regional area required to reach the goal 4. All of the potential injection scenarios met the spatial feasibility constraint.
We determine if economic constraints could also be honored (i.e., the sequestration goal is met with fewer than 522 vertical wells or an associated well cost of less than $1.31/t CO2) 1. For a BHP of 32 MPa, 3 models with ranking values > 6 honor the constraint 2. For a BHP of 40 MPa, 10 models honor the constraint, 4 of these have a ranking value of 5 or 6 (moderately likely) 3. It is unlikely that the study area contains enough sites similar to these models to meet its sequestration goals using only vertical injection wells.
We showed that injection scenarios such as using horizontal wells, hydraulically fracturing vertical or horizontal wells, and induced micro-seismicity within the aquifer were all feasible ways to increase injection rates However, these potential increases in injection rates come with higher associated well costs.
All of the enhanced injectivity scenarios honor the regional spatial constraints
We determine if the economic constraints could also be honored 1. In induced micro-seismicity cases we assumed that the injection rate was five times that of the vertical or horizontal wells simulated with a 40 MPa BHP 2. The number of wells required to sequester 113 Mt CO
2/yr was estimated for
the 6 potential injectivity enhancement techniques 3. When the number of wells was translated into associated well costs per ton of CO
2, 15 of the 18 models had at least one injection scenario that was
within the feasibility threshold of 1.31 US$/t of CO2.
4. Horizontal wells alone do not reduce the costs enough to be economical 5. Injection wells with hydraulic fracturing and/or induced micro-seismicity increases the likelihood that Rose Run sequestration goals can be reached.
Pp is pore pressure, S
hmin is the minimum horizontal
compressive stress, SHmax
is the maximum horizontal compressive stress, S
v is the vertical stress
Ohio
Indiana
West Virginia
Kentucky
87° W 85° W 83° W 81° W 79° W 37° N
38° N
39° N
40° N
41° N
42° N
Earthquake Magnitude2 43 5
CO2 Emissions [Mt/yr]0.5 51 10
Ohio River