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DESIGN AND IMPLEMENTATION OF A CO2 FLOOD UTILIZING ADVANCED RESERVOIR
CHARACTERIZATION AND HORIZONTAL INJECTION WELLS IN A SHALLOW SHELF
CARBONATE APPROACHING WATERFLOOD DEPLETION
DESIGN AND IMPLEMENTATION OF A CO2 FLOOD UTILIZING ADVANCED RESERVOIR
CHARACTERIZATION AND HORIZONTAL INJECTION WELLS IN A SHALLOW SHELF
CARBONATE APPROACHING WATERFLOOD DEPLETION
•Based On DOE Report # DOE/BC/14991R36
•Presented by M. K. Moshell, P.E. 12/12/02
0
100
1stQtr
3rdQtr
EastWestNorth
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Cooperative Agreement Number: DE-FC22-94BC14991
Participant Organization: Phillips Petroleum Company
4001 Penbrook
Odessa, Texas 79762
(Now ConocoPhillips)
Date of Report: 09/01/2002
Award Date: 06/03/1994
Completion Date: 07/01/2001
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Special “Thanks” to
Michelle Navarette
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Project Purpose:
To economically design an optimum carbon dioxide (CO2) flood for a mature waterflood nearing
its economic abandonment.
The original project utilized advanced reservoir characterization and CO2 horizontal injection wells
as the primary methods to redevelop the South Cowden Unit (SCU), Ector County, Texas.
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The Unit was a mature waterflood with water cut exceeding 95%. Oil must be mobilized through the use of a miscible or near-miscible fluid to recover significant additional reserves. Also, because the unit is relatively small, it does not have the benefit of economies of scale inherent in normal larger scale projects. Thus, new and innovative methods are required to reduce investment and operating costs.
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Two primary methods planned to accomplish improved economics were use of :
1) Reservoir characterization to design and restrict the flood to the higher quality rock in the unit, and
2) Use of horizontal injection wells to cut investment and operating costs
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Property Details
Low permeability San Andres reservoir, 4,600’
At Eastern edge of San Andres productive trend on Central Basin Platform
~ 2200 Acres in Unit, ~500 Acres CO2 Flood area
20 Acres /wellbore on edges
10 Acres/wellbore in thicker pay area of Unit
Slow waterflood processing rate
Economic limit and abandonment was predicted for 1999
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Early ResultsEarly Results
•The first two lateral CO2 injectors were drilled in the thickest portion of the reservoir
•Oil production response to that injection was less than predicted
•Laterals were drilled from existing producers
•Additional injectors were drilled as vertical wells
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feet1000. 0. 1000. 2000. 3000. 4000. 5000.
Scale 1:8000.
LEGEND
Active Water Injection Well
Proposed Locations
Proposed WIW to Convert to POW
TA'd or SI Prod. Well
P & A Prod. Well
Wells To Be Shut In
Prop. CO2 Inj.(WAG)/Currently Active WI
TA'd WIW
Active Prod. Oil Well
P & A WIW
D&A or P&A - Oil
rowen 1/00
msb PRO97CGD.GPF
12
7
8
9
13
18
17
16
EMMONS UNIT
S. COWDEN UNIT
112
114
101A
103
104
105
106
108
109
110
201
203W
204
111
116W
122
102A
127
208
132
210
209
131
107
215W
135
136
202
140
142
213
217
218
4-02
3-03
3-01
3-04
3-05W
3-06
3-07
8-02
8-03
8-04W
8-05
8-06
8-08W
8-09W
7-01
7-02
7-03W
7-04W
7-05
1-01
1-02
1-03
1-04
2-01
2-02
2-03
2-04
2-05
2-07
2-08
2-09
2-10
2-11
2-12
2-13W
5-01W5-02
5-03
5-04W5-05
6-01
6-02
6-03W
6-05
6-06
6-07
6-08
6-10
6-11W
6-12W
6-09A7-06
7-085-07
7-09
2-15W
8-10
8-13
6-13
2-17
8-14
6-14
1-07
1-05
9-03
8-16
8-12
1-06
6-16W
8-18
6-178-17
6-18
2-202-19W
4-03W
6-19
2-22
2-212-23
5-08
3-02
8-15W
5-06W9-02W
6-20
2-24
8-19
2-25
6-23
6-21
7-10
2-18
8-02
9-01
6-227-12
6-24
7-13
7-15
6-04
205
123
128
211
143
146W
2-26W
2-27W
6-C25H7-C11H
6-26W
6-28W
6-27W
PHASE I - SHORT RADIUS DRILLING
Original TrajectoriesActual Trajectories
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Challenges – Phase 2Challenges – Phase 2
•Inject CO2 at higher rates to improve flood economics
•Keep CO2 injection within the target reservoir layers
•Increase total production rate without fracturing out of zone
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a
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South Cowden Unit
Cumulative CO2 Injection
0
2
4
6
8
10
12
14
16
Jul-9
6
Oct
-96
Jan-
97
Apr
-97
Jul-9
7
Oct
-97
Jan-
98
Apr
-98
Jul-9
8
Oct
-98
Jan-
99
Apr
-99
Jul-9
9
Oct
-99
Jan-
00
Apr
-00
Jul-0
0
Oct
-00
Jan-
01
Apr
-01
Jul-0
1
Oct
-01
Jan-
02
Apr
-02
BC
F
Purchased CO2 Total Injection Recycled CO2
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South Cowden Unit CO2 Utilization
01020304050607080
Jan-
97
May
-97
Sep
-97
Jan-
98
May
-98
Sep
-98
Jan-
99
May
-99
Sep
-99
Jan-
00
May
-00
Sep
-00
Jan-
01
May
-01
Sep
-01
Jan-
02
May
-02In
stan
tan
eou
s C
O2
Inje
ctio
n, M
CF
Per
Te
rtia
ry B
bl R
eco
vere
d
Gross, Total Injection Net, Purchase Only
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Tertiary Recovery vs. CO2 Injection
0.000
0.001
0.002
0.003
0.004
0.005
0.006
0.007
0.000 0.010 0.020 0.030 0.040 0.050 0.060 0.070
CO2 Injection, Fraction of HCPV
Tert
itar
y R
eco
very
, Fra
ctio
n o
f O
OIP
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Oil Recovery Summary MMSTBO % OOIP
PROJECT AREA
Estimated Original Oil in Place, Project Area 86.5
Most Likely Estimated Ultimate Tertiary recovery 3.7 4.3
UNIT
Estimated Original Oil in Place, Unit* 117 100
Estimated ultimate oil recovery, Primary + Secondary** 35.8 30.6
Cumulative recovery to 6/30/02 36.3 31.0
Cumulative Tertiary recovery to 6/30/02 0.6 0.5
Est. Ultimate Primary + Secondary + Tertiary 39.5 33.8
Most Likely Estimated Ultimate Tertiary recovery 3.7 3.2
High Side Estimated Ultimate Tertiary recovery 4.5 3.8
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12/11/02 Update
Current Production
680 BOPD
2,800 MCFD
5,500 BWPD
Oil production has been rising steadily since April 2002
(April 2002 = 600 BOPD)
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ConclusionsConclusions
•Reservoir characterization partially successful
•Simulation provided a forecast which was too optimistic on total liquid production and BOPD
•Ultimate Tertiary Oil recovery ~ 40% of predicted
•Liquid production rate still too low
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ConclusionsConclusions
•Oil response good where CO2 Injection rate is maintained at target injection rates
•Overall oil response is poor due to inability to maintain CO2 injection rate in-zone in most injectors
•Water injection for gas mobility control in the future will slow flood even more
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