Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2016 Schrader Bluff Oil PoolMarch 29, 2017
VIA HAND DELIVERY
Commissioner Cathy Foerster
Alaska Oil and Gas Conservation Commission
333 West 7"' Avenue, Suite 100
Anchorage, Alaska 99501
Re: 2016 Annual Reservoir Surveillance Report
Nikdtchuq Schrader Bluff Oil Pool
Nikaitchuq Unit, North Slope Alaska
Dear Commissioner Foerster:
J
eni us operating co. Inc.
3800 Centerpoint Dr., Suite 300
Anchorage, AK 99503 - U.S.A.
Tel. 907-865-3300 Fax 907-865-3380
RECEIVED
MAR S 9 2017
AOGCC
The Alaska Oil and Gas Conservation Commission approved pool rules for the Schrader Bluff oil pool
within the Nikaitchuq Unit as Conservation Order 639. Rule number 12 of the order requires the filing
of annual surveillance report, which is enclosed hereto.
Should you have any questions, require additional information or wish to schedule a meeting to discuss
the report, please contact me.
Sincerely,
1��ijtiv�
Robert Province
Land Manager - Alaska
Enclosures
us operatp*ng
2016 Annual Reservoir Surveillance Report
Schrader Bluff Pool
Nikaitchuq Field
Page I i
En! Petroleum — Alaska Development
Table of Contents
1. 2016 Development Activity Summary ...................................................................................................3
2. Reservoir Pressure Surveys at the Nikaitchuq Schrader Bluff Pool.......................................................6
3. Pool Allocation Factors and Issues over the Year 2016......................................................................12
4. Reservoir Management Summary .......................................................................................................13
4.1 2016 Fall PFO and DTS Data Acquisition Campaign....................................................................15
4.2 Voidage Balance by Month of Produced Fluids and Injected Fluids on a Standard and Reservoir
Volume Basis with Yearly and Cumulative Volumes...................................................................19
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Eni Petroleum —Alaska Development
1. 2016 Development Activity Summary
The development map submitted remains unchanged with respect to 2015. Due to the current
oil price environment and the global economy markets drilling activity was put on hold in
October 2015, aiming to return to drilling activities in early 2018.
For the year 2016, well intervention/workover activities were conducted for three wells where
ESP failed to restart operation and to repair a tubing leak detected is OP26 ( Table 1).
Well Name
Well Type
WO Completion Date
Drilling Path
OP23-WW02
Water Well
4/2/2015
Oliktok Point
OP22-WW03
Water Well
4/13/2015
Oliktok Point
OP16-03
Oil Producer
7/22/2015
Oliktok Point
OPO4-07
Oil Producer
8/4/2015
Oliktok Point
OP26-DSP02
Disposal Well
10/14/2015
Oliktok Point
Table 1. 2016 Workover Job summary for Nikaitchuq Field
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Eni Petroleum—Alaska Development
The Figure 1 below shows the completed well paths and its reservoir units up to January 2017:
Figure 1. Nikaitchuq Development map. Green = producer, Blue = injector, = Dual lateral
producer, "_,,, N Sand Appraisal well, dashed lines (----) planned development wells.
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Eni Petroleum —Alaska Development
Nikaitchuq Development Pattern - Jan 2017
s
�
o�
em
ens.n
I
4
\
\ u
b
`
I
I
I
I
9
o�
Nlkeltchuk 6evel_opmenl
�x
ORlllfhlll
a°B
�hOp �xx000
Alaaloa rev. Teem
eni
Figure 1. Nikaitchuq Development map. Green = producer, Blue = injector, = Dual lateral
producer, "_,,, N Sand Appraisal well, dashed lines (----) planned development wells.
Page 14
Eni Petroleum —Alaska Development
The well plan activity in 2009 had a total well count of 51 wells. The well pattern and summary
of the activity to the end of 2016 was 55 wells (not including the dual lateral well paths) and is
summarized in Table 2 below:
OPP = Oliktok point development path (onshore)
SID = Spy Island Development path (offshore)
Table 2. Total planned well count for Nikaitchuq Development
viI production di Nikaitchuq field continues to respond positively to waterflood. The positive
waterflood response to date indicates that waterflood technology chosen as the main oil
recovery strategy for this field continues to be working well. Figure 2 below shows Nikaitchuq
field's oil production and water injection history from January 2014 through December 2016.
The drop in injection during 4Q16 is due to a water source well ESP failure. In August 2016
SP12 ESP failed and in December 2016 SP28 ESP failed. These two workovers are scheduled for
March 2017
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Eni Petroleum —Alaska Development
Planned Activity (2009)
Activity up to date
(December 2016)
OPP
SID
Total
OPP
SID
Total
IV
Injector
8
12
20
8
13
21
CL
Producer
11
1s
26
11
18
29
Disposal
1
1
2
1
1
2
3
Water Source
3
0
3
3
0
3
Total
23
28
51
23
32
SS
Dual Lateral Well Paths
8
9 17
OPP = Oliktok point development path (onshore)
SID = Spy Island Development path (offshore)
Table 2. Total planned well count for Nikaitchuq Development
viI production di Nikaitchuq field continues to respond positively to waterflood. The positive
waterflood response to date indicates that waterflood technology chosen as the main oil
recovery strategy for this field continues to be working well. Figure 2 below shows Nikaitchuq
field's oil production and water injection history from January 2014 through December 2016.
The drop in injection during 4Q16 is due to a water source well ESP failure. In August 2016
SP12 ESP failed and in December 2016 SP28 ESP failed. These two workovers are scheduled for
March 2017
Page 15
Eni Petroleum —Alaska Development
Figure 2. Nikaitchuq Field Production and Events summary 2014-2016
2. Reservoir Pressure Surveys at the Nikaitchuq Schrader Bluff Pool
Similar to previous years, reservoir pressure monitoring activities were executed by controlling
intake BHP's as shown in Figures 2a & 2b for OPP and SID, respectively. These plots show how
intake pressures have been gradually stepped down while the team monitored signs of sand
production, rising water cuts (WC), gas -oil ratios (GOR) and balancing voidage across all sectors
in the field.
Intake pressure at OPP is around 450 psi (See Figure 2a). However, the pressure spread is larger
at SID where ESP's have reached lift capacity (See Figure 2c). Larger capacity ESP's are planned
for future workover opportunities.
Monthly and cumulative Voidage Replacement Ratio's are monitored to give an idea of whether
or not enough water is being injected in the field (See section 4.2). Maps of dynamic pressures
are extremely helpful for monitoring activities (see Figure 3). In addition, a planned opportunity
in 2016 made it possible to measure reservoir pressures during Pressure Fall -Off (PFO) and
Page 16
Eni Petroleum —Alaska Development
"me
_.�._.��._.
46AOO
42 Ao
pp
40,0°0
4000
36AOo6
98M
36A00
36,060
34000
34000
32000
3200
90,000
r
SA12
.. 30,000
e
26,000
2a 00o
Z
26,000
UN:
_
ti.
—'
_
- M
26000
24 0
`
22000,
,°°
3
20.00,'
- �.,..
20,000
Q
16,000
. ,�
"
...
.. .. ..
- ..
..,.. _ ..
........... .. .. _
.-
16,000
o.
16,000
16.0°0
14,000
14,000
12000
12 000
10000
♦ Oil Producers
70 000
8,000
.
... , - ..
.-.......
• Water Injectors
6,000
6a0po
-
t Water Injection Rate
6,000
4.000
f
--o-Oil Production Rate
4,000
}
■ ■ ■
; 2,0°0
i kA�
o
'F O
LL
= O
Figure 2. Nikaitchuq Field Production and Events summary 2014-2016
2. Reservoir Pressure Surveys at the Nikaitchuq Schrader Bluff Pool
Similar to previous years, reservoir pressure monitoring activities were executed by controlling
intake BHP's as shown in Figures 2a & 2b for OPP and SID, respectively. These plots show how
intake pressures have been gradually stepped down while the team monitored signs of sand
production, rising water cuts (WC), gas -oil ratios (GOR) and balancing voidage across all sectors
in the field.
Intake pressure at OPP is around 450 psi (See Figure 2a). However, the pressure spread is larger
at SID where ESP's have reached lift capacity (See Figure 2c). Larger capacity ESP's are planned
for future workover opportunities.
Monthly and cumulative Voidage Replacement Ratio's are monitored to give an idea of whether
or not enough water is being injected in the field (See section 4.2). Maps of dynamic pressures
are extremely helpful for monitoring activities (see Figure 3). In addition, a planned opportunity
in 2016 made it possible to measure reservoir pressures during Pressure Fall -Off (PFO) and
Page 16
Eni Petroleum —Alaska Development
distributed temperature surveys (DTS) campaign. The reservoir pressure measurements in the
foregoing campaign were used to support the Nikaitchuq reservoir model pressure map of 2016
as shown in Figure 3.
950
850
750
in
CL
a
m 650
550
BHP at Depth of Heel
450 4%..4-.r _'• �lwAw..o'}�+l . k_
350 — —
W LD W LD LD to to to to lD LD W h
C ? C tW d i cJ C
O P 12-01
O P 17-02
OP16-03
OP05-06
OP8-04
O P3-05
— O P4-07
O P 18-08
O P 10-09
0P9 -S1
OP14-53
Figure 2a. Intake BHP measurements in year 2016 for active wells at OPP
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Eni Petroleum—Alaska Development
BHP at Depth of Heel
1400
1300
1200
1100-` -
1000
Cc: 900 a r
800—"
700
600
500
400 '�--' T ` k , E�
i r°LD
C C T C
N fp 2 Q 2
Figure 2b. Intake BHP measurements in year 2016 for active wells at SID
On the injector side, wellhead pressures have been capped at an equivalent of 0.60 psi/ft. to
avoid injection at pressures that can fracture the reservoir
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Eni Petroleum —Alaska Development
SP16-FN3
!
SP10-FNS
SP08-N7
—SP31-W7
—
SP21-NW1
SP04-SE5
SP01-SE7
r—JSP36-W5
SP28-NW3
SP24-SE1
c
�SP05-FN7
T. ..
—SP27-N1
-' ' — .'
-----
—
SP23-N3
.� 1
,�,,��,
lSP22-FN1
uSP12-SE3
—
r
SP18-N5
SP30-W1
SP33-W3
W tD
LD �
�0 r�
H
O °Z
❑
Figure 2b. Intake BHP measurements in year 2016 for active wells at SID
On the injector side, wellhead pressures have been capped at an equivalent of 0.60 psi/ft. to
avoid injection at pressures that can fracture the reservoir
Page 18
Eni Petroleum —Alaska Development
600
500
400
'M 300
dL
CL
x
3
200
100
0
ti� ti� �� ti� �� ti� �( tir ti( ti(0 tib tib ti�
,ti\moo tiltio ,�\tio ti_\tio \,yo \,yo a\yo a\,yo 4,\,yo \,yo ^\tio 0, V r0T
N" 4\ 1 `b`* 14\� a\7 4" ql�v AVI, b y �\v ,o\v yti\,:
Wellhead Pressure
—0106-05
—0107-04
0111-01
—0113-03
0115-S4
0120-07
0124-08
OP -12 (inj)
Figure 2c. Wellhead pressure measurements in year 2015 for injectors at OPP
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Eni Petroleum —Alaska Development
r
i
i
—0106-05
—0107-04
0111-01
—0113-03
0115-S4
0120-07
0124-08
OP -12 (inj)
Figure 2c. Wellhead pressure measurements in year 2015 for injectors at OPP
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Eni Petroleum —Alaska Development
600
500
400
'v, 300
CL
CL:
x
3
200
100
Wellhead Pressure
ti`0 ti`0 ti`O ti`0 ti`0 ti`0 ti`0 ti`0 ti`0 ti`0 ti( ti( ti(0
5107-S E4
---SI11-FN6
S113-FN4
_S114 -N6
— SI17-SE2
S119-FN2
—S120 -N4
_S125 -N2
S126 -N W2
5129-S2
S132 -W2
S134 -W6
S135 -W4
Figure 2d. Wellhead pressure measurements in year 2016 for injectors at SID
Injection deficit, due to an ESP failure on a source water well, is reflected in the declining THPs
of the fourth quarter 2016. After the workover on the source well, injection THPs are stabilized
to target.
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Eni Petroleum—Alaska Development
L
Nikaitchuq Pressure Map Up to December -2016
Figure 3. Pressure map of Nikaitchuq Field @ YE 2016
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Eni Petroleum —Alaska Development
3. Pool Allocation Factors and Issues over the Year 2016
Production from all wells producing from the Schrader Bluff pool is commingled at the surface
into a common production line. Theoretical production for individual wells from the pool is
calculated on a daily basis by using well test allocation. Wells are tested, at minimum, twice per
month for a total of 24 times per year per well. During 2016, 1,276 welltests were performed.
Measurements are performed on a multiphase meter.
Daily theoretical production for a well was calculated using the last valid well test and the
amount of time a well was on production for a given day. For example, if there was a valid well
test on the first of the month and another on the fifth of the month, the allocation factor for
that well would be calculated on the first through the fourth of the month using the test on the
first of the month. Subsequently, the allocation factor will be recalculated on the fifth of the
month using the new valid test measured on the fifth. On the monthly level, our AVOCET
Manager Production software sums up the allocated volumes from each time period between
valid well tests.
(Minutes on production/1440 minutes/day)*Daily Rate (stb/d) well test=Theoretical Daily
Production
The daily allocation factor for the field is calculated by dividing the actual total production for
the day by the sum of the theoretical daily production for each individual well. Daily allocated
production is assigned to each well by multiplying its theoretical daily production by the daily
allocation factor.
1.15
1.14
1.13
1.12
1.11
1.1
1.09
1.08
1.07
1.06
1.05
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
January
1.1032
February
1.0944
March
1.0996
April
1.0932
May
1.1092
June
1.1048
July
1.0999
August
1.0984
September
1.1203
October
1.1187
November
1.1144
December
1.1004
Figure 4. Average field allocation factor trend for 2016
The average allocation factor for 2016 has been 1.10.
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Eni Petroleum—Alaska Development
4. Reservoir Management Summary
For the year 2016, the Nikaitchuq OA reservoir monitoring activities focused on replenishing
reservoir energy by replacing the voidage created with water injection and optimizing the field
production performance through workover activities. Reservoir energy is monitored by
monitoring surface and bottom -hole pressures. In addition to surface meters measuring tubing
pressures, Nikaitchuq oil producers are equipped with downhole gauges which allow real-time
bottom -hole pressures to be monitored.
With respect to Resman tracer system described in 2015, only SP21-NW1 and SP31-W7 retain
useful life. However, application to multilateral (ML) well bores results in noisy data difficult to
be interpreted.
Eight injector wells (See Figure 5), four in Spy Island (5111-FN6, 5119-FN2, 5113-FN4, 5125-1\112)
and four in Oliktok Point (0111-01, OP -12, 0113-03, 0124-08) have been treated with unique
Tracerco tracers in 2015 in order to evaluate the water flow patterns, the breakthrough time
and the sweep efficiency of the water injection. During 2016 tracer concentration in 22
producers continued to be monitored.
Three OPP iniectors (0106-05, 0107-04 & 0111-01) and two SID iniectors (5114-N6 & 5120-1\14) are
equipped with DTS fiber optics which determines the level of injectivity along the horizontal
injection intervals of the injectors. Figure 5 below, shows the Nikaitchuq field map with
Resman, Tracerco tracers and the wells injector with DTS fiber optic.
Page 1 13
Eni Petroleum —Alaska Development
Nikaitchuq Development Pattern - December 2015
I
A
0, ftud—,,Ah ROMAN eaw. L.
WF.y 4pmMd woMTMLRf.0 DrAca
i�., M I:V acwtl$
Figure 5. Nikaitchuq map showing wells with Resman tracers and DTS Fibers
Page 1 14
Eni Petroleum — Alaska Development
4.12016 Fall PFO and DTS Data Acquisition Campaign
Pressure and temperature data acquisition were conducted during the 2016 Fall -Off (FO)
campaign in order to evaluate whether the update injection profiles confirm the ones evaluated
last year. During the approximately 48 hours that followed, Pressure Fall -Off data was recorded
by means of the BHP/T gauge. DTS acquisitions have been carried out during the FO test
executed on each well as part of the periodic reservoir management activity The main reason
for the DTS interpretation is to check if the actual injection profiles are comparable with the
previous ones or if the increase in the rate generated some distortions in the profile and the
possible activation of preferential zones.
The Table 4 below summarizes the acquisition dates for injector wells with DTS fiber optic
installed.
Well
PFO Start & End Dates
Duration
WH Pressure (PSI)
Injector
Start
End
Hours
Start
End
0106-05
11/01/2016
11/03/2016
48
499
329
0107-04
10/28/2016
10/30/2016
48
271
0
0111-01
10/30/2016
11/01/2016
48
441
59
5114-N6
11/23/2016
11/25/2016
48
464
101
5120-N4
11/15/2016
11/17/2016
48
366
263
Table 4.PFO/DTS Survey Date and Time during PFO 2016 Campaign
The following charts show the execution of the Fall -Off period well by well:
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En Petroleum—Alaska Development
0106-05
2,000
1,500
1,000
500
-injeueu vvai
bbl/d
- Tubing Head
Oct -25 Oct -27 Oct -29 Oct -31 Nov -02 Nov -04 Nov -06 Nov -08 Nov -10
Figure 6. Fall -Off period of well 0106-05 acquired in November 2016
(Blue= Rate; Red= Tubing Pressure)
Figure 7. Fall -Off period of well 0107-04 acquired in October 2016
(Blue= Rate; Red= Tubing Pressure)
Page 116
Eni Petroleum — Alaska Development
0107-04
3,500
350
3,000
300
-�Noon
Z—.
2,500
250
M
C
Q
2,000
200
La
M
N
1,500
150
W
°J
a
1,000
100
-a
d
Injected Water
V
=
500
Rate, bbl/d
50
a�
•�
-Tubing Head
0
Pressure, psi
0
h
J
-500
-50
Oct -21
Oct -23 Oct -25 Oct -27 Oct -29 Oct -31 Nov -02 Nov -04 Nov -06
Figure 7. Fall -Off period of well 0107-04 acquired in October 2016
(Blue= Rate; Red= Tubing Pressure)
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Eni Petroleum — Alaska Development
3,500
3,000
2,500
2,000
1,500
1,000
500
0
Ort -23
0111-01
Oct -25 Oct -27 Oct -29 Oct -31 Nov -02 Nov -04 Nov -06 Nov -08
Figure 8. Fall -Off period of well 0121-01 acquired in October/November 2016
(Blue= Rate; Red= Tubing Pressure)
5114-N6
2,500
2,000
1,500
1,000
500
Injected Water
Rate, bbl/d
—Tubing Head
Pressure, psi
0 i ' - ,
Nov -16 Nov -18 Nov -20 Nov -22 Nov -24 Nov -26 Nov -28 Nov -30 Dec -02
Figure 9. Fall -Off period of well S114 -N6 acquired in November 2016
(Blue= Rate; Red= Tubing Pressure)
Page 1 17
Eni Petroleum —Alaska Development
S120 -N6
2,500
2,000
r
1,500
--Injected Water
Rate, bbI/d
1,000
--Tubing Head
Pressure, psi
500
0
Nov -08 Nov -10 Nov -12 Nov -14 Nov -16 Nov -18 Nov -20 Nov -22 Nov -24
Figure 10. Fall -Off period of well 5120-N6 acquired in November 2016
(Blue= Rate; Red= Tubing Pressure)
Main preliminary feedback of the ongoing DTS analysis with respect to foregoing year
interpretation can be summarized as follows:
• 0107-04: no evident changes have been detected on the injection profile respect to last
interpretation (Nov 2014);
# 5120-N4: the increase of rate permits now to reach the well TD whereas previously
injection stopped @12,130 ft. MD (about 300-400 ft. before TD);
5114-N6: the increase of the injection rate respect to the date of last DTS interpretation
(2014) provided an increasing injectivity in the first half of the drain, where before
injection was not so effective.
The profiles interpretation for all of the six wells tested during the campaign is still under
analysis at the time being.
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En! Petroleum —Alaska Development
4.2 Voidage Balance by Month of Produced Fluids and Injected Fluids on a Standard and
Reservoir Volume Basis with Yearly and Cumulative Volumes
A total of approximately 9.0 million barrels of oil was produced from the Nikaitchuq field during
the year 2016 at an average daily production of 23,700 bopd. Injected volumes of water during
year 2016 were about 15.3 million barrels at an average daily rate of 41,500 bwpd.
During the last quarter of the year there was an injection deficit, due to a source water well ESP
failure, which was normalized starting December.
Table 5 below summarizes the entire voidage replacement for the Nikaitchuq field in 2016. The
spikes in the graph are typically associated with Alyeska proration days.
0.75
0.5
0.25
0
Jan -16
Feb -16 Mar -16 Apr -16 May -16 Jun -16 Jul -16 Aug -16 Sep -16 Oct -16 Nov -16 Dec -16
Table 5. 2016 Nikaitchuq Field Monthly Production/Injection Volumes and Voidage Replacement Ratios
Page 1 19
Eni Petroleum —Alaska Development
—Monthly
Oil
KSTB
subsurface Production Voidage
Water Total
KSTB KSTB
Monthly subsurface Injection Voidage
Water Injection
KSTB
Voidage Replacement Ratio
Monthly
-
Jan -16
833
380
1,213
1,234
102
Feb -16
775
371
1,146
1,163
1.02
Mar -16
1 796
412
1208,
1,247
103
Apr -16
760
417
1,177
1,222
1.04
May -16
809
476
1,285
1,275
0.99
Jun -16
774
497
1,271
1,268
1.00
Jul -16
7^,4
530
1,J24
1,331
1.01
Aug -16
752
528
1,280
1,322
103
Sep -16
712
521
1,233
1,316
1.07
Oct -16
727
557
1,284
1,351
1.05
Nov -16
694
538
1,232
1,216
0.99
Dec -16
693
585
1,278
1,326
1.04
0.75
0.5
0.25
0
Jan -16
Feb -16 Mar -16 Apr -16 May -16 Jun -16 Jul -16 Aug -16 Sep -16 Oct -16 Nov -16 Dec -16
Table 5. 2016 Nikaitchuq Field Monthly Production/Injection Volumes and Voidage Replacement Ratios
Page 1 19
Eni Petroleum —Alaska Development
