The Allison Unit CO â ECBM Pilot: A Reservoir Modeling ... - Coal-Seq
The Allison Unit CO â ECBM Pilot: A Reservoir Modeling ... - Coal-Seq
The Allison Unit CO â ECBM Pilot: A Reservoir Modeling ... - Coal-Seq
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<strong>The</strong> <strong>Allison</strong> <strong>Unit</strong> <strong>CO</strong> 2 – <strong>ECBM</strong> <strong>Pilot</strong>:<br />
A <strong>Reservoir</strong> <strong>Modeling</strong> Study to Understand<br />
<strong>CO</strong> 2 <strong>Seq</strong>uestration in <strong>Coal</strong> Seams<br />
Second International Forum on Geologic <strong>Seq</strong>uestration of <strong>CO</strong> 2 in Deep,<br />
Unmineable <strong>Coal</strong>seams<br />
(<strong>Coal</strong>-<strong>Seq</strong> II)<br />
March 6 & 7, 2003<br />
Washington, DC<br />
Sponsored by:<br />
U.S. Department of Energy<br />
Contract No.: DE-FC26-00NT40924<br />
Performed by:<br />
Advanced Resources International<br />
Houston, Texas<br />
LLM022403.ppt<br />
LLM022403.ppt
Presentation Outline<br />
• Field Background<br />
• <strong>Reservoir</strong> & Model Description<br />
• Model Results<br />
• What-if Scenarios<br />
• Economics<br />
• Closing Remarks<br />
LLM022403.ppt
<strong>Coal</strong>-<strong>Seq</strong> Project Study Sites,<br />
San Juan Basin<br />
LA PLATA <strong>CO</strong>.<br />
ARCHULETA<br />
<strong>CO</strong>LORADO<br />
NEW MEXI<strong>CO</strong><br />
Durango<br />
Florida River<br />
Plant<br />
F A I R WA<br />
Y<br />
N2 Pipeline<br />
Tiffany <strong>Unit</strong><br />
Pagosa<br />
Springs<br />
San Juan<br />
Basin Outline<br />
Dulce<br />
<strong>Allison</strong> <strong>Unit</strong><br />
Aztec<br />
Farmington<br />
Bloomfield<br />
R<br />
LLM022403.ppt
<strong>Allison</strong> <strong>Pilot</strong> Base Map<br />
61<br />
LLM022403.ppt
<strong>Pilot</strong> Area Production History<br />
Rates, Mcf/mo<br />
2,000,000<br />
1,800,000<br />
1,600,000<br />
1,400,000<br />
1,200,000<br />
1,000,000<br />
800,000<br />
600,000<br />
400,000<br />
200,000<br />
16 producers, 4 injectors, 1 POW<br />
Injection suspended, five wells<br />
reopened<br />
Five wells shutin<br />
during initial injection<br />
period<br />
Gas Rate, Mcf/mo<br />
<strong>CO</strong>2 Injection Rate, Mcf/mo<br />
Well Gas Rate, Mcf/d<br />
Line pressures reduced, wells recavitated, wells<br />
reconfigured, onsite compression installed<br />
Injection resumed<br />
Peak @ +/- 57 MMcfd<br />
+/- 3 1/2 Mcfd<br />
4,000<br />
3,500<br />
3,000<br />
2,500<br />
2,000<br />
1,500<br />
1,000<br />
500<br />
Individual Well Gas Rate, Mcf/d<br />
0<br />
0<br />
Jan-89<br />
Jul-89<br />
Jan-90<br />
Jul-90<br />
Jan-91<br />
Jul-91<br />
Jan-92<br />
Jul-92<br />
Jan-93<br />
Jul-93<br />
Jan-94<br />
Jul-94<br />
Jan-95<br />
Jul-95<br />
Jan-96<br />
Jul-96<br />
Jan-97<br />
Jul-97<br />
Jan-98<br />
Jul-98<br />
Jan-99<br />
Jul-99<br />
Jan-00<br />
Jul-00<br />
Jan-01<br />
Jul-01<br />
Date<br />
LLM022403.ppt
Example Well<br />
160000<br />
140000<br />
120000<br />
100000<br />
80000<br />
60000<br />
40000<br />
20000<br />
0<br />
Jan-89<br />
Jul-89<br />
Jan-90<br />
Jul-90<br />
Jan-91<br />
Jul-91<br />
Jan-92<br />
Jul-92<br />
Jan-93<br />
Jul-93<br />
Jan-94<br />
Jul-94<br />
Jan-95<br />
Jul-95<br />
Jan-96<br />
Jul-96<br />
Jan-97<br />
Jul-97<br />
Jan-98<br />
Jul-98<br />
Jan-99<br />
Jul-99<br />
Jan-00<br />
Jul-00<br />
Jan-01<br />
Rate<br />
Gas, Mcf/mo<br />
Csg Press, psi<br />
Line Press, psi<br />
<strong>CO</strong>2 injection commenced<br />
Line pressures<br />
reduced<br />
Recavitate (5/95)<br />
1000<br />
900<br />
Well reconfigured, pump<br />
800<br />
installed (3/99)<br />
700<br />
Onsite<br />
600<br />
compression<br />
Onsite compression<br />
500<br />
installed<br />
installed<br />
400<br />
300<br />
200<br />
100<br />
Pressure<br />
0<br />
Date<br />
LLM022403.ppt
Injector Well Configurations<br />
Well Head Flow Meter Heating <strong>Unit</strong><br />
Corrosion<br />
Inhibitor<br />
2-7/8 inch production tubing<br />
(internally lined with fiberglass)<br />
5-1/2 inch production casing<br />
Packer<br />
Yellow <strong>Coal</strong><br />
<strong>CO</strong> 2<br />
Supply<br />
Blue <strong>Coal</strong><br />
Purple <strong>Coal</strong><br />
Packer Fluid<br />
<strong>Reservoir</strong><br />
Power System<br />
Control/SCADA<br />
Pressure<br />
Regulator<br />
7-7/8 inch hole to total depth<br />
LLM022403.ppt
Producer Well Configurations<br />
9-5/8 inch surface casing<br />
2-3/8 inch production tubing<br />
7 inch production casing<br />
Liner hanger<br />
Sucker rods<br />
Yellow <strong>Coal</strong><br />
Rod pump<br />
Blue <strong>Coal</strong><br />
5-1/2 inch pre-perforated<br />
liner (not cemented)<br />
Purple <strong>Coal</strong><br />
6-1/2 inch hole to total depth<br />
LLM022403.ppt
Presentation Outline<br />
• Field Background<br />
• <strong>Reservoir</strong> & Model Description<br />
• Model Results<br />
• What-if Scenarios<br />
• Economics<br />
• Closing Remarks<br />
LLM022403.ppt
Basic <strong>Reservoir</strong> Description<br />
Property<br />
Value<br />
Average Depth to Top <strong>Coal</strong><br />
3100 feet<br />
No. <strong>Coal</strong> Intervals<br />
3 (Yellow, Blue, Purple)<br />
Average Total Net Thickness<br />
43 feet<br />
Yellow – 22 ft<br />
Blue – 10 ft<br />
Purple – 11 ft<br />
Initial Pressure<br />
1650 psi<br />
Temperature<br />
120°F<br />
LLM022403.ppt
Available Model Input Data<br />
• Maps:<br />
– Structure, by layer<br />
– Thickness, by layer<br />
– Permeability<br />
– Porosity<br />
• Isotherms, by gas and by layer<br />
• Permeability Functions (Cp, Cm, Ck)<br />
• Relative Permeability<br />
LLM022403.ppt
Impact of Recavitation<br />
Operations<br />
Note: Maximum value of +10 imposed.<br />
LLM022403.ppt
Model Grid – Map View<br />
Face<br />
cleat<br />
Butt cleat<br />
No-flow<br />
boundaries<br />
• 16 producers<br />
• 4<br />
• 1<br />
injectors<br />
POW<br />
• 33 x 32 x 3<br />
• 3168 gridlocks<br />
(2646 active)<br />
N<br />
LLM022403.ppt
Model Grid – Cross Section<br />
N-S Cross-Section<br />
W-E Cross Section<br />
LLM022403.ppt
Presentation Outline<br />
• Field Background<br />
• <strong>Reservoir</strong> & Model Description<br />
• Model Results<br />
• What-if Scenarios<br />
• Economics<br />
• Closing Remarks<br />
LLM022403.ppt
Guiding Principle<br />
• Only make changes to reservoir<br />
description that are:<br />
» “global”, not regional<br />
» independently justifiable<br />
• Objective is to understand processes at<br />
work, not necessarily achieve a match<br />
for its own sake.<br />
• “Known” reservoir description was<br />
strictly honored.<br />
LLM022403.ppt
Field Total Gas Rate<br />
LLM022403.ppt
POW #2 Pressure<br />
No field data<br />
Material balance during<br />
primary production appears ok<br />
Difference appears to exist only<br />
after <strong>CO</strong> 2<br />
injection<br />
300 psi<br />
Approximate POW#2 pressure based<br />
on May 2000 PTA (+/- 525 psi)<br />
LLM022403.ppt
Well #113<br />
Water Rate<br />
Bottomhole Pressure<br />
61<br />
104<br />
111<br />
12M<br />
106<br />
112<br />
101<br />
114<br />
130<br />
142<br />
Gas Composition<br />
108<br />
131<br />
141<br />
132<br />
113<br />
143<br />
POW#2<br />
140<br />
120<br />
115<br />
102<br />
Pressure<br />
121<br />
119<br />
62<br />
LLM022403.ppt
Well #140<br />
Injection Pressure<br />
LLM022403.ppt
“Systematic” Discrepancies<br />
• Flowing bottomhole pressures too high.<br />
• Injecting bottomhole pressures too low.<br />
• <strong>CO</strong> 2 breakthrough profiles too steep.<br />
• POW #2 pressure response.<br />
• <strong>Reservoir</strong> pressures too low.<br />
LLM022403.ppt
Current Findings<br />
• Permeability not the answer; cannot be<br />
lowered enough to match producing/injecting<br />
pressures and still maintain required gas<br />
production.<br />
• <strong>CO</strong> 2 breakthrough profiles cannot be<br />
explained with permeability variations (i.e.,<br />
vertical heterogeniety, compressibilties).<br />
• A change in coal sorption/diffusion<br />
characteristics with <strong>CO</strong> 2 injection must also<br />
be occurring to explain pressure/composition<br />
behavior.<br />
LLM022403.ppt
Current Findings (cont’d)<br />
• Observed pressure response in POW<br />
#2 believed to be a wellbore problem –<br />
May, 2000 datapoint more valid.<br />
• <strong>Reservoir</strong> pressure discrepancies not<br />
valid – difficulty lies in selecting correct<br />
PTA time for comparing to gridblock<br />
pressure.<br />
Continues to be a work-in-progress.<br />
LLM022403.ppt
Progression of <strong>CO</strong> 2 Displacement<br />
(@ mid-2002)<br />
N<br />
LLM022403.ppt
Forecast Results<br />
Case<br />
Total Methane<br />
Recovery (Bcf)<br />
Incremental<br />
Recovery<br />
(Bcf)<br />
Total <strong>CO</strong> 2<br />
Injection<br />
(Bcf)<br />
<strong>CO</strong> 2<br />
Production<br />
(Bcf)<br />
<strong>CO</strong> 2<br />
/CH 4<br />
Ratio<br />
W/o <strong>CO</strong> 2<br />
injection<br />
100.5*<br />
n/a<br />
n/a<br />
n/a<br />
n/a<br />
W/<strong>CO</strong> 2<br />
injection<br />
102.1<br />
1.6<br />
6.4**<br />
1.2<br />
3.2<br />
*6.3 Bcf/well<br />
** 20 Mcfd/ft<br />
Small incremental recovery due to limited injection volumes.<br />
INJECTIVITY IS KEY!<br />
Note: OGIP for model = 152 Bcf.<br />
Recoveries understated due to more rapid<br />
<strong>CO</strong> 2 breakthrough in model than observed.<br />
LLM022403.ppt
LLM022403.ppt<br />
Typical Injection Pressure<br />
History<br />
Well #143<br />
0<br />
10000<br />
20000<br />
30000<br />
40000<br />
50000<br />
60000<br />
Jan-89<br />
Jul-89<br />
Jan-90<br />
Jul-90<br />
Jan-91<br />
Jul-91<br />
Jan-92<br />
Jul-92<br />
Jan-93<br />
Jul-93<br />
Jan-94<br />
Jul-94<br />
Jan-95<br />
Jul-95<br />
Jan-96<br />
Jul-96<br />
Jan-97<br />
Jul-97<br />
Jan-98<br />
Jul-98<br />
Jan-99<br />
Jul-99<br />
Jan-00<br />
Jul-00<br />
Date<br />
Rate<br />
500<br />
700<br />
900<br />
1100<br />
1300<br />
1500<br />
1700<br />
1900<br />
2100<br />
2300<br />
2500<br />
Pressure<br />
<strong>CO</strong>2, Mcf/mo<br />
BHP, psi
Permeability History for<br />
Injector Well<br />
250<br />
Start<br />
Permeability, md<br />
200<br />
150<br />
100<br />
50<br />
Continued<br />
Injection<br />
Depletion<br />
Displace w/ <strong>CO</strong>2<br />
0<br />
0 500 1000 1500 2000 2500 3000 3500<br />
Pressure, psi<br />
LLM022403.ppt
Remarks on Perm/Inj Loss<br />
• Matrix pressure-dependent perm and<br />
matrix swelling/shrinkage accounted for<br />
in model.<br />
• Other effects must also be occurring to<br />
explain permeability and injectivity loss.<br />
– Multi-component, bi-directional, microscale<br />
sorption/diffusion<br />
LLM022403.ppt
Presentation Outline<br />
• Field Background<br />
• <strong>Reservoir</strong> & Model Description<br />
• Model Results<br />
• What-if Scenarios<br />
• Economics<br />
• Closing Remarks<br />
LLM022403.ppt
What-if Scenarios<br />
Continuous<br />
Similar<br />
Rate<br />
ü<br />
Aggressive<br />
Rate<br />
ü<br />
Short-Term<br />
ü<br />
ü<br />
LLM022403.ppt
What-if Results<br />
Cont Inj,<br />
ST Inj,<br />
Cont Inj,<br />
ST Inj,<br />
Same Rate<br />
Same Rate<br />
Aggr Rate<br />
Aggr Rate<br />
<strong>CO</strong> 2 Inj,<br />
(Bcf)<br />
11.1<br />
1.3<br />
45.2<br />
5.4<br />
Incr CH 4 ,<br />
(Bcf)<br />
1.6<br />
0.4<br />
4.3<br />
1.3<br />
Net<br />
Ratio<br />
6.7:1<br />
2.7:1<br />
10.2:1<br />
3.8:1<br />
LLM022403.ppt
What-if Conclusions<br />
• To achieve equilibrium <strong>CO</strong> 2 /CH 4 ratios in the<br />
reservoir, at some point <strong>CO</strong> 2 injection must<br />
cease and the system allowed to equilibrate.<br />
• For <strong>ECBM</strong>, short-term, aggressive injection<br />
probably best economically.<br />
• For sequestration, care must be exercised<br />
not to exceed equilibrium <strong>CO</strong> 2 storage<br />
capacity at maximum pressure.<br />
LLM022403.ppt
Presentation Outline<br />
• Field Background<br />
• <strong>Reservoir</strong> & Model Description<br />
• Model Results<br />
• What-if Scenarios<br />
• Economics<br />
• Closing Remarks<br />
LLM022403.ppt
Economic Assumptions<br />
Capex<br />
<strong>CO</strong> 2<br />
Hot Tap:<br />
36 mi (4 inch) Pipeline:<br />
Field Distribution:<br />
Wells<br />
Opex<br />
Injector Well Operating:<br />
<strong>CO</strong> 2<br />
Cost<br />
Produced Gas Processing<br />
Financial<br />
Gas Price:<br />
Methane BTU Content<br />
Net Revenue Interest:<br />
Production Taxes:<br />
Discount Rate:<br />
Total<br />
$175,000<br />
$3.5 million ($24,000/in-mi)<br />
$80,000 ($20,000/in-mi)<br />
$1.6 million ($400,000/ea; fully equipped)<br />
$5.355 million<br />
$1,000/mo well (active only)<br />
$0.30/Mcf ($5.19/ton)<br />
$0.25/Mcf<br />
$2.20/MMBTU (ex-field)<br />
1.04 MMBTU/Mcf<br />
87.5%<br />
8%<br />
12%<br />
LLM022403.ppt
Current Economic Results<br />
@ 5 years<br />
@10 years<br />
Net Present Value<br />
($627k)*<br />
($1,809k)<br />
Breakeven Gas Price<br />
Breakeven <strong>CO</strong> 2<br />
Cost<br />
$2.57/MMBTU<br />
$0.12/Mcf<br />
$3.60/MMBTU<br />
($0.12/Mcf)<br />
*Maximum (least negative) NPV occurs at ~ 5 years.<br />
Note: Assumes pipeline Capex assigned at 25%.<br />
LLM022403.ppt
Forecast Economic Results<br />
Versus Current Case<br />
Cont. Inj. @<br />
Similar Rate<br />
Short-Term Inj.<br />
@ Similar Rate<br />
Cont. Inj. @<br />
Aggressive Rate<br />
Short-Term Inj. @<br />
Aggressive Rate<br />
Net Present<br />
Value<br />
($1,040k)<br />
($38k)<br />
($5,063k)<br />
($301k)<br />
Breakeven Gas<br />
Price<br />
$3.67/MMBTU<br />
$2.38/MMBTU<br />
$4.82/MMBTU<br />
$2.64/MMBTU<br />
Breakeven <strong>CO</strong> 2<br />
Cost<br />
$0.15/Mcf<br />
$2.60/ton<br />
$0.26/Mcf<br />
$4.50/ton<br />
$0.12/Mcf<br />
$2.08/ton<br />
$0.24/Mcf<br />
$4.15/ton<br />
Breakeven<br />
<strong>CO</strong> 2<br />
Tax Credit*<br />
$0.15/Mcf<br />
$2.60/ton<br />
$0.04/Mcf<br />
$0.69/ton<br />
$0.18/Mcf<br />
$3.11/ton<br />
$0.06/Mcf<br />
$1.04/ton<br />
*Assumes $0.30/Mcf ($5.19/ton) <strong>CO</strong> 2<br />
cost.<br />
LLM022403.ppt
Case for <strong>CO</strong> 2 <strong>Seq</strong>uestration<br />
Methane Depletion<br />
and <strong>ECBM</strong> Period<br />
<strong>CO</strong> 2 <strong>Seq</strong>uestration Period<br />
Field on<br />
Production<br />
Begin Initial <strong>CO</strong> 2<br />
Injection <strong>Pilot</strong><br />
Proposed Stop<br />
of Injection<br />
(Pr = 0.75 Pi)<br />
End of Actual<br />
History<br />
Begin Aggressive<br />
<strong>CO</strong> 2 Injection<br />
End of<br />
Forecast<br />
Period<br />
• Recovers 9.8 Bcf of incremental methane.<br />
• <strong>Seq</strong>uesters 10 million tons of <strong>CO</strong> 2 .<br />
• Tax credit of $3.11/ton (over $5.19/ton) required to breakeven.<br />
LLM022403.ppt
Economics Summary<br />
• Short-term, designed-volume, <strong>CO</strong> 2<br />
injection provides best economics.<br />
• Even when maximizing <strong>CO</strong> 2 injection<br />
volumes, only modest gas price<br />
increases or tax incentives are required<br />
for breakeven conditions.<br />
LLM022403.ppt
Presentation Outline<br />
• Field Background<br />
• <strong>Reservoir</strong> & Model Description<br />
• Model Results<br />
• What-if Scenarios<br />
• Economics<br />
• Closing Remarks<br />
LLM022403.ppt
Closing Remarks<br />
• First instance of long-term <strong>CO</strong> 2 injection in<br />
coalseams documented and analyzed – an excellent<br />
start.<br />
• Incremental methane recovery achieved.<br />
• Observations generally consistent with current<br />
theoretical understanding, but critical process<br />
questions remain.<br />
– Need improved understanding of causes of permeability &<br />
injectivity loss (matrix swelling, multi-component sorption &<br />
diffusion behavior)<br />
• Stand-alone economic performance marginal –<br />
achieving high injectivity project maker/breaker.<br />
• Need more integrated laboratory and field data.<br />
– Permeability changes with <strong>CO</strong> 2 injection.<br />
– In-situ <strong>CO</strong> 2 /CH 4 exchange.<br />
– Maximizing injectivity.<br />
LLM022403.ppt
Advanced<br />
Resources<br />
International<br />
LLM022403.ppt
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