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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2007 Kenai Gas FieldM Marathon
MARATHON Oil Company
March 1, 2008
Commissioners: John Norman, Dan Seamount, Cathy Foerster
Alaska Oil and Gas Conservation Commission
333 W. 7t" Avenue Suite 100
Anchorage, AK 99501-3539
Re: Storage Injection Order 7
aAnnual Gas Storage Performance Evaluation
Dear Commissioners:
Alaska Asset Team
P.O. Box 196168
Anchorage, AK 99519-6168
Telephone 907/561-5311
Fax 907/565.3076
RECEIVED
FEB 2 9 2008
Marathon Oil Company (Marathon) respectfully submits the attached information to fulfill the
requirements of Rule 5 of Storage Injection Order #7, dated April 19, 2006. Rule 5 requires,
in part:
"An annual report evaluating the performance of the storage injection
operation must be provided to the Commission no later than March 15. The
report shall include material balance calculations of the gas production and
injection volumes and a summary of well performance data to provide
assurance of continued reservoir confinement of the gas storage volumes."
After almost 47 years of continuous production, the Sterling Pool 6 continues to exhibit tank -
like behavior. Marathon has not observed, and has no information indicating, any change to
this behavior as a result of gas injection and storage operations which began on May 8,
2006. Marathon has conducted gas storage operations in compliance with the rules and
conditions of SIO #7. All required data, other than form 10-413 as explained below, have
been submitted to the AOGCC.
From the time of first injection through the period ending December 31, 2007, the total
volume of gas injected into Pool 6 was 3,707,202 mscf. The total volume of stored gas
withdrawn was 903,541 mscf. The total volume of native gas withdrawn was 5,874,972
mscf. The maximum calculated reservoir bottom -hole pressure during the injection cycle
was 175.3 psia, far below the maximum of 300 PSI permitted under Rule 4 of SIO -7.
Attached, please find Exhibit #1, a summary of the results of a recent update to the Sterling
Pool 6 reservoir model, which is submitted to satisfy the annual performance evaluation
requirements for material balance calculations. The reservoir pressures used in the model
were shut-in tubing pressures obtained from our SCADA system which were converted to
bottom -hole pressures at mid -perforation. Additionally, the field was shut in on April 10, 2007
and October 12, 2007 to obtain the pressures.
Modeling work shows an expected direct response to injection and withdrawals from the
reservoir. Each observed shut-in well pressure correlated very well with the model
prediction.
The observed static pressures gathered do vary somewhat from the expected P/Z line
(Exhibit 4). Both values were lower than the values predicted on the P/Z line. This
variation can be explained by examining the pressure distributions predicted by the
simulation model (Exhibit 1 N). As can be seen in this exhibit, the model suggests more
pressure variation within the pool during April than during October. This is consistent with
the observed departures from the P/Z values in Exhibit 4.
The average measured pressure on October 12th, 2007 is approximately 1 psi less than the
model prediction. In summary, the model predication is consistent with observed pressures
and injection/withdrawal volumes.
Exhibit #2 is a plot showing the performance of the injection wells (KU 31-07X and 23X-06)
during 2007.
Exhibit #3 is a table showing monthly injection and withdrawal volumes plus allocated
balances between Native and Stored gas.
Exhibit #4 is the original P/Z plot contained in the application for gas storage.
Although Form 10-413 appears to be required by statute, the form has not been submitted
because we interpret it to be applicable only to enhanced recovery projects rather than gas
storage projects. Additional guidance is requested regarding the applicability and necessity
of Form 10-413 for this gas storage project.
If you have any questions, please do not hesitate to contact me at (713) 296-3302 or
domartens@marathonoil.com.
Sincerely,
Dave Martens
SUBSURFACE MANAGER
MARATHON OIL COMPANY
Enclosures
Via Certified Mail
cc: Greg Noble, BLM
Kevin Banks, Alaska DNR, Dept of Oil & Gas
Lyndon (bele, Marathon
File
2
Exhibit #1 (IA - 1L)
Comparisons of Observed Pressures vs. Expected Pressures from Eclipse Model
• KDU-5
• Well 43-06RD
• Well 34-32
• Well 34-31
• Well 33-07
• Well 33-06
• Well 31-07X
• Well 23X-06
• Well 21-06RD
• Well 14X-06
• Well 14-32
• Well 13-06
For each of the wells listed above, two plots are presented showing historical observed
shut-in pressures against those predicted by the Eclipse simulation model. The upper
plot encompasses the entire historical life of the Pool 6 reservoir. The lower plot shows
the same data beginning in the Year 2001.
As can be seen for each of the wells, there is, in general good agreement between the
pressures predicted by the simulation model and those observed at the individual wells.
There do appear to be some minor differences for the historical pressures during 2001-
2007 when plotted on an expanded scale. This is a result of the fact that the simulation
model uses average monthly production rates and assumes that a well produces each
and every day during a month at a particular rate. Therefore, during months where an
individual well has production, the simulation model will tend to under predict the
pressure at that well because the model assumes the well is producing rather than shut-
in.
As can be seen on the plots, there is very good agreement between the simulation model
and the pressures observed during the 2007 injection cycle season.
3
—Simulated SBHP - Eclipse - Observed SBHP for 2007
•• Observed SBHP till 2006
' I
i
2000 - - -
j
I
t
I
O
N 1000
a
m i
O) '
1
i
0
1/1960 1/1965 111970 1/1975 1/1980 111985 1/1990 1/1995 112000 1/2005
Dote
Exhibit 1 A: Well KDU-5
4
—Simulated SBHP- Eclipse
•• Observed SBHP till 2006
1
2000
_O
N 1000
Q
N
m
N
a
Observed SBHP for 2007
0
111960 1/1965 1/1970 1/1975 111980 1/1985 111990 111
Date
Exhibit 1 B: Well 43-06RD
v
—Simulated SBHP- Eclipse Observed SBHP for 2007
•• Observed SBHP till 2006
2000—
(D
000
O
N
1000
C)
Cn
V)
Q
n
0
111960 1/1965 1111
975 111980 1/1985 1/1990 1/15
Date
Exhibit 1C: Well 34-32
i
Simulated SBHP - Eclipse
•• Observed SBHP till 2006
2000
Observed SBHP for 2007
D
N
1000—
U)
000N
N
i
0
1/1960 1/1965 111970 1/1975 111980 111985 1/1990 1/1995 1/2(
Dote
Exhibit 1 D: Well 34-31
7
Simulated SBHP - Eclipse - Observed SBHP for 2007
•• Observed SBHP till 2006
2000
f
f
Q 1000
I
N
rn
m
N I
a
0
1/1960 1/1965 111970 111975 111980 1/1985 111990 111995 112000 112005
Date
Exhibit 1 E: Well 33-07
I
Simulated SBHP - Eclipse Observed SBHP for 2007
• • Observed SBHP till 2006
2000
I
I
I
1000
Q
i
0-
111960 1/1965 111970 1/1975 111980 1/1985 1/1990 111995 1
Dote
Exhibit 1 F: Well 33-06
i
—Simulated SBHP- Eclipse Observed SBHP for 2007
•• Observed SBHP till 2006
1
2000 (.._... -- ! ......
I
i
I
:
_a
m 1000—
C)_
N
N ?
n
1
: I i
0
1/1960 1/1965 1/1970 1/1975 1/1980 1(1985 111990 111995 1/2000 112005
Date
Exhibit 1G: Well 31-07X
10
Simulated SBHP - Eclipse - Observed SBHP tot 2007
• • Observed SBHP till 2006
2000
I
I
1000
Q-
V)
a�
I
0
1/1960 111965 1/1970 1/1975 1/1980 1111985 1/1990 1/1995 1/2000 112005
Dote
Exhibit 1H: Well 23X-06
—Simtdated SBHP -Eclipse Observed SBHP for 2007
• • Observed SBHP till 2006
2000-
1000—
U)
000 1000 to
i,
0
1/1960 111965 1/1970 1/1975 1/1980 1/1985 1/1990 1/1995 1/2000 L/2005
Date
Exhibit 11: Well 21-06RD
12
--Simulated SBHP- Eclipse = Observed SBHP for 2007
•• Observed SBHP till 2006
2000—
C)
N 1000
Q
Co
rn
n
0
111960 1/1965 1 /1970 111975 111980 111985 '111990 111995 112000 1/2005
Date
Exhibit 1J: Well 14X-06
13
Simulated SBHP 'Eclipse Observed SBHP for 2007
Observed SBHP till 2006
2000—
V) 1000
0
1/1960 1/1965 IM
1/1980 1/1985 1M
Date
Exhibit 1 K: Well 14-32
14
Simulated SBHP - Edipse Observed SBHP for 2007
Observed SBHP till 2006
2000
1
1000
Q
U)
N
n
I
I
i
0 i
1/1960 1/1965 1/1970 1/1975 1/1980 1/1985 111990 1/1995 1/2000 1/2005
Dote
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7
Exhibit 1 M: Static Reservoir Pressures gathered before and after 2006 injection cycle
Pressure distribution per Eclipse Model on 30 -April -2007
For all arid cells where So > 0.01
Pressure distribution per Eclipse Model on 31 -October -2007
For all grid cells where Sg > 0.01
Exhibit 1 N: Reservoir pressure distribution predicted by Eclipse simulation model before
IN
50000
45000
40000
35000
U
E 30000
ti
25000
3
20000
15000
10000
5000
0
and after 2007 injection cycle.
31-7X
♦ t!
♦r
•
♦
Of
♦
0 100 200 300 400 500 600 700 800
Tubing pressure, psig
Exhibit #2: Performance of the injection wells (KU 31-07X and 23X-06) during 2007
19
Withdrawals
Date
Injection
(mscf)
Total
withdrwawl
mscf
Native gas
allocation %
Stored gas
allocation %
Native gas
(mscf)
Stored gas
(mscf)
1/1/2007
-
783,239
90
10
704,915
78,324
2/1/2007
9,315
593,204
90
10
533,884
59,320
3/1/2007
-
631,740
90
10
568,566
63,174
4/1/2007
200,796
21,688
90
10
19,520
2,168
5/1/2007
868,135
69,202
80
20
55,362
13,840
6/1/2007
4,301
110,126
80
20
88,100
22,026
7/1/2007
464,423
-
80
20
-
-
8/1/2007
327,487
-
80
20
-
-
9/1/2007
247,055
436,853
80
20
349,482
87,371
10/1/2007
52,133
277,220
80
20
221,777
55,443
11/1/2007
-
558,360
80
20
446,689
111,671
12/1/2007
4,402
805,130
80
20
644,105
161,025
2,178,047
4,286,762
3,632,400
654,362
Exhibit 3: Monthly injection and withdrawal volumes
20
300
250
200
N 150
100
PIZ for Pool - 6
5.100E+08 5.200E+08 5.300E+08 5.400E+08 5.500E+08 5.600E+08 5.700E+08
Cum withdrwwl (MSCF)
Exhibit # 4: P/Z Plot
21
*Apr -06 average static pressure
*Oct -06 average static pressure
*Apr -07 average static pressure
♦0ct-07 average static pressure
OtkcialPIZ
E dipse Model PFZ
•
+`4
t
.��44
•
5.100E+08 5.200E+08 5.300E+08 5.400E+08 5.500E+08 5.600E+08 5.700E+08
Cum withdrwwl (MSCF)
Exhibit # 4: P/Z Plot
21
Conclusions
• Eclipse Model was updated to include production and injection volumes through
December 31, 2007.
• The pressures predicted by the Eclipse model were compared to pressures
observed in the various wells in 2007.
• The pressures observed in the various wells compared favorably with those
predicted by the simulation model.
• The Storage Unit did not exceed maximum allowable pressure of 300 psia.
• There is no evidence of the loss of containment.
22
