Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2015 Milne Point UnitHilcorp Alaska, LLC
March 30th, 2016
Cathy Foerster, Chairman
Alaska Oil & Gas Conservation Commission
333 W. 7th Avenue, Suite 100
Anchorage, Alaska 99501-3539
RECEIVED
APR 0 12016
GCC
Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 100
Anchorage, AK 99503
Phone: 907/777-8414
Fax: 907/777-8580
dduffy@hilcorp.com
RE: MILNE POINT UNIT, MILNE POINT FIELD, KUPARUK RIVER OIL POOL, SCHRADER BLUFF OIL POOL, SAG
RIVER OIL POOL, STATE OF ALASKA, 2015 ANNUAL RESERVOIR REVIEW
Dear Commissioner Foerster:
In accordance with Conservation Order No. 205, 477, 423, 550.007, and 550.006, Hilcorp Alaska, LLC ("Hilcorp"),
as Operator, hereby submits for your review the following Annual Reservoir Review for the Milne Point Field.
This is the 15th Annual Reservoir Review and corresponds to events during the 2015 calendar year.
2Sincer
ony McConkey
Reservoir Engineer— Milne Point
Milne Point Unit
Waterflood and Reservoir Surveillance Report
for
Kuparuk River Oil Pool
Schrader Bluff Oil Pool
Sag River Oil Pool
January through December, 2015
Issued: March 30th, 2016
Sections and Exhibits
Introduction
Kuparuk River Oil Pool 1
Section 1: Kuparuk River Oil Pool Exhibits 1A —113
Schrader Bluff Oil Pool 2
Section 2: Schrader Bluff Oil Pool Exhibits 2A — 2B
Sag River Oil Pool
3
Section 3: Sag River Oil Pool Exhibits
3A — 3B
Production/Injection Surveillance Logs
4
Section 4: Production/Injection Well Surveillance Exhibits
4A — 4B
Shut in Well Exhibit
5
Section 5: Shut in Well Statuses
5A
Milne Point Well Testing
6
Section 6: Well Test Exhibits
6A — 6C
Milne Point Plan of Operations and Development
7
Section 7: Review of Annual Plans of Operations
7A
ANNUAL RESERVOIR SURVEILLANCE REPORTS
MILNE POINT UNIT
KUPARUK RIVER OIL POOL
SCHRADER BLUFF OIL POOL
SAG RIVER OIL POOL
JANUARY - DECEMBER 52015
Introduction
As required by Conservation Order 205 for the Kuparuk River Oil Pool, approved October 4,
1984, Conservation Order 477, approved August 23, 2002 for the Schrader Bluff Oil Pool,
Conservation Order 423 for the Sag River Oil Pool, approved May 6, 1998, and Conservation
Order 550.007 for all Milne Point Pools, approved January 6, 2009, and Conservation Order
550.006 for all Milne Point Pools, amended February 14, 2014, this report provides a
consolidated summary of surveillance activities within the Milne Point Unit. The report includes
surveillance data associated with waterflood projects and development activities. The time period
covered is January through December 20155.
Order 205 for the Kuparuk River Oil Pool requires the Operator to submit the following for the
previous calendar year:
• A tabulation of reservoir pressure and injection pressure data on wells in the waterflood
permit area.
• A tabulation of all production logs, injection well surveys, and injection well performance
data.
• Produced fluid volumes (oil, gas, and water) and injected fluid volumes reported by month
and on a cumulative basis.
Order 477 for the Schrader Bluff Oil Pool requires the Operator to submit the following for the
previous calendar year:
• Progress of enhanced recovery project(s) implementation and reservoir management
summary.
• Voidage balance by month of produced fluids (oil, gas, and water) and injected fluids and
cumulative status for each producing interval.
0 Summary and analysis of reservoir pressure surveys within the pool.
• Results, and, where appropriate, analysis of production and injection logging surveys, tracer
surveys and observation well surveys, and any other special monitoring.
• Review of well testing and pool production allocation factors over the prior year.
• Future development plans.
• Review of Annual Plan of Operations and Development. Note: A separate Plan of
Development is sent annually by October 1 as part of DNR reporting.
Order 423 for the Sag River Oil Pool requires the Operator to submit the following for the
previous calendar year:
• Progress of enhanced recovery project implementation and reservoir management summary
including engineering and geotechnical parameters.
• Voidage balance by month of produced fluids and injected fluids and cumulative status.
• Analysis of reservoir pressure within the pool.
• Results, and, where appropriate, analysis of production logging surveys, tracer surveys and
observation well surveys.
• Review of pool allocation factors over the prior year.
• Future development plans.
Order 550.007 for All Milne Point Pools requires the Operator to submit the following for the
previous calendar year:
• A summary of the performance and operational issues relating to the Unit 5 MPFM.
• The monthly oil, gas and water allocation factors for each Milne Point Field pool.
Order 550.006 for All Milne Point Pools requires the Operator to submit the following for the
previous calendar year:
• A summary of all installations to date and the performance of each Gen 2 (VSRD meter).
• All operational issues and any additional Gen 2 test results.
Each of the three producing reservoirs is reported in a separate section.
Section I
Kuparuk River Oil Pool
List of Exhibits
Reservoir Injection Report (Form 10-413) 1-A
Reservoir Voidage Balance 1-B
Static Pressure Data (Form 10-412) 1-C
Kuparuk River Oil Pool Waterflood
Project Summary
The Kuparuk River Oil Pool is split up in Hydraulic Units which represent regions of the reservoir
that are believed to be hydraulically isolated due to faulting and/or lithologic controls. There were
81 producing wells and 54 injection wells active through 2015.
The increase in producer well count is likely a result of reactivating long term shut-in producers
previously thought as uneconomic under the previous operator. Hilcorp also utilized the smaller
ASR rig which allowed for RWO's into the summer, which was a limitation under BP's
operatorship due to the thawing/softening of pad roads during the warmer summer months.
Exhibit 1-A shows annual injection/production for the Kuparuk River reservoir for the entire
project history through December 2015. Water and gas injection rates averaged 71.6 MBWD and
3.5 MMSCFD for 2015. Injection rates in 2014 averaged 67.7 MBWD and 1.6 MMSCFD. This
represents an increase in water injection of 5.5% and an increase in gas injection of 54.3%. The
large increase in gas injection was likely due to the reactivation of high GOR well B-09. In order
to inject the excess gas produced, WAG injection (Water -Alternating -Gas) was reactivated at C -
pad which restarted in February 2015 and continued through the rest of the year. Cumulative
water injection since waterflood startup through the end of 2015 is 544.2 MMSTB and
cumulative gas injection is 99.3 BSCF.
Exhibit 1-B shows a monthly breakdown of production and injection data for the report period.
This data shows that the voidage replacement ratio averaged 0.88 RB/RB in 2015. The VRR in
2014 averaged 0.80 RB/RB. This represents an increase of 9.1%. However, the VRR still
remained under 1.0 BBL/BBL in order to reduce reservoir pressures in areas where pressure
gradient exceeds that of standard saltwater brine (-0.46 psi/ft).
Exhibit 1-C presents the reservoir pressure data taken during 2015 for the Kuparuk River wells.
In 2015, 28 static pressure readings were obtained in the Kuparuk River reservoir.
Exhibit 1-A Reservoir Voidage Balance Summary Kuparuk Pool
January - December 2015
Daily Production Rate Averages By Month:
Daily Injection Rate Averages By Month:
Oil
Water °
Gas
Reservoir
Water
Gas
Voidage
Voidage
Voidage
Month
Prod Rate
Prod Rate
Prod Rate
Voidage
Inj Rate
Inj Rate
Replacement
Replacement
Balance
(stb/day)
(stb/day)
(mscf/day)
(rbbl/day)
(stb/day)
(mscf/day)
(rbbl/day)
Ratio
(rbbl/day)
1/31/2015
13, 225
62,679
7,342
82,157
76,971
779
78,768
0.96
-3,390
2/28/2015
13,312
60,275
11,798
83,476
69,911
4,176
74,405
0.89
-9,071
3/31/2015
13,234
63,192
10,992
85,698
70,631
3,497
74,576
0.87
-11,123
4/30/2015
13,829
68,338
11,097
91,571
69,416
3,838
73,624
0.80
-17,947
5/31/2015
12,791
68,371
11,543
90,991
72,348
4,466
77,118
0.85
-13,873
6/30/2015
12,179
64,329
10,312 '
85,296
64,701
4,280
69,203
0.81
-16,093
7/31/2015
13,130
67,265
11,441 '
90,104
69,999
4,759
74,976
0.83
-15,128
8/31/2015
12,918
53,541
10,222
74,968
73,119
3,565
77,158
1.03
2,190
9/30/2015
12,331
65,649
11,277"
87,576
75,921
4,346
80,645
0.92
-6,930
10/31/2015
12,936
66,898
10,274
88,587
73,741
3,273
77,548
0.88
-11,039
11/30/2015
12,788
67,498
9,809 '
88,671
73,722
2,589
76,964
0.87
-11,708
12/31/2015
11,916
65,326
8,860 '
84,862
68,795
2,307
71,731
0.85
-13,131
Cumulative Production By Month:
Cumulative Injection By Month:
Oil
Water
Gas
Reservoir
Water
Gas
Voidage
Voidage
Voidage
Month
Cumulative
Cumulative
Cumulative
Voidage
Cumulative
Cumulative
Replacement
Replacement
Balance
(stb)
(stb)
(mscf)
(rbbl)
(stb/day)
(mscf/day)
(rbbl)
Ratio
(rbbl)
1/31/2015
409,987
1,943,035
227,593
2,546,882
2,386,097
24,140
2,441,806
0.96
-105,076
2/28/2015
372,735
1,687,688
330,334
2,337,321
1,957,508
116,918
2,083,339
0.89
-253,981
3/31/2015
410,241
1,958,962
340,744
2,656,648
2,189,562
108,404
2,311,849
0.87
-344,799
4/30/2015
414,877
2,050,152
332,911
2,747,118
2,082,474
115,149
2,208,720
0.80
-538,398
5/31/2015
396,506
2,119,490
357,821
2,820,712
2,242,798
138,437
2,390,664
0.85
-430,048
6/30/2015
365,373
1,929,880
309,360
2,558,892
1,941,020
128,412
2,076,088
0.81
-482,805
7/31/2015
407,017
2,085,200
354,667
2,793,225
2,169,982
147,526
2,324,255
0.83
-468,970
8/31/2015
400,448
1,659,758
316,870
2,324,016
2,266,702
110,526
2,391,897
1.03
67,881
9/30/2015
369,940
1,969,474
338,299
2,627,268
2,277,618
130,377
2,419,356
0.92
-207,912
10/31/2015
401,019
2,073,841
318,488
2,746,184
2,285,978
101,470
2,403,990
0.88
-342,194
11/30/2015
383,631
2,024,933
294,255
2,660,138
2,211,648
77,673
2,308,911
0.87
-351,228
12/31/2015
369,396
2,025,113
274,662
2,630,721
2,132,643
71,523
2,223,646
0.85
-407,075
Average:
2015
12,882
64,447
10,414
86,163
71,606
3,490
2,298,710
0.88
-322,050
Cumulative:
stb
stb
mscf
rb
stb
mscf
rb
rb
31 -Dec -15
4,701,170
23,527,526
3,796,004 '31,449,239
26,144,030
1,270,555 °
28,650,856
0.91
-2,798,383
Exhibit 1-R Fnrm 10-117 V.,.. -.i, n 1
FL Fluid Level
PBU
Pressure Build Up
PFO
Pressure Fall Off
PP
Pump Pressure
STATE OF ALASKA
Shut -In Bottom Hole Pressure
ALASKA OIL AND GAS CONSERVATION COMMISSION
RESERVOIR PRESSURE REPORT
1. Operator: Hilcorp Alaska, LLC.
2. Address: 3800 Genterpoint Dr. Anchorage, AK99516
3. Un@ or Lease Name: Mine Point
4. Field and Pool: Kuparuk River Fool
5. Datum Reference: 7000' SS
Oil Gravity: AR - 23 7. Gas Gravity: Air = 1.0
8. Well Name and
Number:
9. AR Number
50-XXX-XXXXX-XX-XX
10. Oil (0)
or Gas
(G)
11. AOGCC Pool
Code
12. Final Test
Date
13. Shut -In
Time, Hours
14. Press.
Surv. Type
(see
instructions
for codes)
15. B.H.
Tenp.
16. Depth
Tool TVDss
17. Final
Pressure at
Tool Depth
18. Datum
iV Dss
(input)
19. Pressure20.
Gradient, psi/ft.
Pressure Comments
at Datum
(cal)
Zone
MPL-28A
50-029-22859-01-00
PROD
525100
1/11/2015
296
SBHP
174
6,793
1,840
7000
0.271
1,928 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3
MPF -01
50-029-22552-00-00
PROD
525100
2/1/2015
1 6,888
SBHP
167
6,753
3,312
7000
0.490
3,419 Used Grad = 0.43psi/ft for Datum Corr.
Al+A2+A3
MPC -13
50-029-21328-00-00
PROD
525100
2/4/2015
1,817
SBHP
1 169
6,241
2,101
7000
0.337
2,352 Used Grad = 0.33 psi/ft for Datum Corr.
A2+A3+8+C
MPL-28A
50-029-22859-01-00
PROD
525100
2/7/2015
951
PP
168
6,870
2,440
7000
0.355
2,495 Used Grad = 0.42psi/ft for Datum Corr.
Al+A2+A3
MPF -05
50-029-22762-00-00
PROD
525100
2/8/2015
658
SBHP
172
6,763
4,301
7000
0.636
4,402 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3
MPL-12
50-029-22334-00-00
PROD
525100
2/22/2015
506
SBHP
184
6,850
1,948
7000
0.284
2,013 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3+B
MPF -81
50-029-22959-00-00
PROD
525100
2/26/2015
2,900
PP
168
6,531
3,292
7000
0.504
3,492 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3
MPJ -10
50-029-22500-00-00
PROD
525100
3/6/2015
470
PP
176
6,785
2,852
7000
0.420
2,944 Used Grad = 0.43psi/ft for Datum Corr.
A2+A3+B
MPC -25
50-029-22638-01-00
INJ
525100
3/28/2015
1 13,908
SBHP
168
7,169
4,798
7000
0.669
4,723 Used Grad = 0.44 psi/ft for Datum Corr.
A2+A3+B+C
MPL-04
50-029-22029-00-00
PROD
525100
3/28/2015
533
PP
1 183
7,072
3,196
7000
0.452
3,165 Used Grad = 0.42psi/ft for Datum Corr.
Al+A2+A3+B+C
MPL-29
50-029-22543-00-00
PROD
525100
3/28/2015
433
PP
193
7,109
2,322
7000
0.327
2,276 Used Grad = 0.42 psi/ft for Datum Corr.
Al+A2+A3+B+C
MPF -09
50-029-22773-00-00
PROD
525100
4/6/2015
75
SBHP
180
6,849
2,508
7000
0.366
2,573 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3
MPE-22
50-029-22567-00-00
PROD
525100
5/17/2015
208
PP
177
6,871
2,240
7000
0.326
2,296 Used Grad = 0.43 psi/ft for Datum Corr.
B+C
MPF -93
50-029-23266-00-00
PROD
525100
5/17/2015
221
PP
173
5,801
2,825
7000
0.487
3,338 Used Grad = 0.43 psi/ft for Datum Corr.
A1+A2+A3
MPL-25
50-029-22621-00-00
PROD
525100
5/17/2015
192
PP
185
7,183
3,556
7000
0.495
3,478 Used Grad = 0.42 si/ft for Datum Corr.
Al+A2+A3+B
MPF -96
50-029-23406-00-00
PROD
525100
6/7/2015
777
PP
N/A
5,520
2,387
7000
0.432
Used Grad = 0.41 psi/ft for Datum Corr.,
2,996 Temp Gauge not working
Al+A2+A3
MPF -87A
50-029-23184-01-00
PROD
525100
6/14/2015
173
PP
183
7,063
2,740
7000
0.388
2,713 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3
MPF -57A
50-029-22747-00-00
PROD
525100
6/14/2015
161
PP
178
6,350
2,699
7000
0.425
2,974 Used Grad = 0.42psi/ft for Datum Corr.
A3
MPF -22
50-029-22632-00-00
PROD 1
525100
6/14/2015
162
PP
176
6,684
2,652
7000
0.397
2,788 Used Grad = 0.43 si/ft for Datum Corr.
Al+A2+A3
MPK-30
50-029-22711-00-00
PROD
525100
8/7/2015
1,015
PP
N/A
6,905
2,834
7000
0.410
2,875 Used Grad = 0.43 si/ft for Datum Corr.
B+C
MPL-33
50-029-22774-00-00
INJ
525100
8/21/2015
5,064
SBHP
140
7,200
3,811
7000
0.529
3,725 Used Grad = 0.43 psi/ft for Datum Corr.
Al+A2+A3+C
MPC -14
50-029-21344-00-00
PROD
525100
11/1/2015
174
SBHP
166
6,686
1,867
7000
0.279
2,001 Used Grad = 0.43 psi/ft for Datum Corr.
A2+A3+6+C
MPF -96
50-029-23406-00-00
PROD
525100
11/16/2015
4,637
SBHP
160
5,499
1,908
7000
0.347
Used Grad = 0.37 psi/ft for Datum Corr.,
2,470 lTemp Grad = 0.018°F/ft
Al+A2+A3
MPL-03
50-029-21999-00-00
PROD
525100
12/11/2015
102
SBHP
174
6,778
2,428
7000
0.358
2,513 jUsed Grad = 0.38 psi/ft for Datum Corr.
Al+A2+A3+B
MPE-11
50-029-22541-00-00
PROD 1
525100
12/15/2015
597
SBHP
171
6,586
2,120
7000
0.322
2,295 Used Grad = 0.42 psi/ft for Datum Corr.
C
MPE-19
50-029-22746-00-00
PROD
525100
12/19/2015
2,195
SBHP
179
6,701
1,320
7000
0.197
1,334 Used Grad = 0.05psi/ft for Datum Corr.
C+B
MPL-39
50-029-22786-00-00
PROD
525100
12/21/2015
5,208
SBHP
164
6,914
3,688
7000
0.533
3,725 Used Grad = 0.43 psi/ft for Datum Corr.
A2+A3+C
MPF -45
50-029-22556-00-00
PROD
525100
12/22/2015
216
SBHP
177
6,951
1,645
7000
0.237
1,666 Used Grad = 0.42psi/ft for Datum Corr.
Al+A2+A3
Avera a
2,820
21. All tests reported herein w erq made
in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Conrriss ion.
I hereby certify that the foregoing is true and correct to the best of my know ledge.
Signature
Title
Reserwir Engineer
Printed Name
Anthony McConkey
Date
3/29/2016
FL Fluid Level
PBU
Pressure Build Up
PFO
Pressure Fall Off
PP
Pump Pressure
SBHP
Shut -In Bottom Hole Pressure
Section 2
Schrader Bluff Oil Pool
List of Exhibits
Reservoir Injection Report (Form 10-413) 2-A
Reservoir Voidage Balance
Static Pressure Data (Form 10-412) 2-C
Schrader Bluff Oil Pool Waterflood
Project Summary
The Schrader Bluff Oil Pool oil production averaged 5.6 MSTBD for 2015 compared to 6.3
MSTBD in 2014. This represents an oil production decrease of 12.5% in 2015. Gas production
averaged at 2.0 MMSCFD in 2015 compared to 2.6 MMSCFD in 2014, representing a gas
production decrease of 30% in 2015. The decrease in oil and gas production is likely a result of
several Matrix Bypass Events, or MBE's, developing throughout the year of 2015. An MBE is a
formation `wormhole' of sorts in which a high permeability streak is established between a
producer and injector that causes watercut to dramatically increase, with a sharp decline in oil
production. Hilcorp ran two MBE treatments in 2015; however, additional treatments are planned
for the 2016 year.
Water production averaged 11.9 MBWD in 2015 compared to 10.9 MBWD in 2014. Cumulative
production since waterflood startup through the end of 2015 is 74.8 MMSTB of oil, 43.1 BSCF
of gas, and 69.9 MMSTB of water.
The water injection rate averaged 25.9 MBWD for 2015 compared to 22.1 MBWD in 2014. The
increase is partially attributed to four producer -to -injector conversions performed through the
2015 year in the Schrader reservoir. Cumulative water injection since waterflood startup through
the end of 2015 is 167.4 MMSTB. Gas injection in the Schrader began in 2006 and continued
through December 2008. Of the two patterns utilized for the WAG pilot, only the MPE-29
(injector) to MPE-24A (producer) pattern demonstrated signs of WAG interactions as
characterized by the GOR response at the producer. No gas was injected in 2009 to 2015.
Cumulative gas injection through the end of 2015 remains as it was at year-end 2008: 220
MMSCF.
As of December 2015 the cumulative under -injection is 26.0 MMRB.
In the supported waterflood patterns, under -injection is minimal. The average voidage
replacement ratio, or VRR, for 2015 was 1.36, an increase compared to the 2014 VRR of 1.26.
Future development plans for the Schrader Bluff oil pool include expansion into undeveloped
areas in the North West area of the pool, and the evaluation of EOR techniques suitable for
Viscous Oil application. Northwest expansion in the Schrader Bluff reservoir began with L -pad
drilling towards the end of 2015 which targeted Schrader OA sands. Additional development is
planned in the F&L pad areas as well as N -sand drilling at B -pad and J -pads within the Schrader
Bluff reservoir. Additional development info can be found in the attached Plan of Development
Review slides in Section 7.
Exhibit 2-C presents the reservoir pressure data for the Schrader Bluff wells taken during 2015. In
2015, 24 static pressures were obtained.
Exhibit 2-A Reservoir Voidage Balance Summary Schrader Bluff Pool
January - December 2015
Production Rate Averages:
Injection Rate Averages:
Oil
Water ,
Gas
Reservoir
Water
Gas
Voidage
Voidage
Voidage
Month
Prod Rate
Prod Rate
Prod Rate
Voidage
Inj Rate
Inj Rate
Replacement
Replacement
Balance
(stb/day)
(stb/day)
(mscf/day)
(rbbl/day)
(stb/day)
(mscf/day)
(rbbl/day)
Ratio
(rbbl/day)
1/31/2015
5, 780
10,541
2,756
19,138
25,836
0
26,095
1.36
6,956
2/28/2015
5,133
8,954
1,612
15,405
25,701
0
25,958
1.69
10,553
3/31/2015
4,991
9,758
1,658
16,169
25,143
0
25,395
1.57
9,226
4/30/2015
5,528
11,780
1,917
19,004
25,156
0
25,407
1.34
6,404
5/31/2015
5,012
11,948
1,928
18,779
25,034
0
25,284
1.35
6,505
6/30/2015
5,313
13,707
2,415
21,482
21,780
0
21,998
1.02
515
7/31/2015
5,675
13,387
2,101
21,004
25,377
0
25,631
1.22
4,627
8/31/2015
5,894
11,079
1,914
18,583
27,495
0
27,770
1.49
9,187
9/30/2015
5,741
12,065
1, 764
19,245
26,508
0
26,773
1.39
7,528
10/31/2015
5,831
13,502
1,563
20,484
27,571
0
27,847
1.36
7,363
11/30/2015
6,091
12,539
1,645
19,835
28,129
0
28,410
1.43
8,575
12/31/2015
6,720
13,258
2,457
22,208
27,182
0
27,454
1.24
5,246
Cumulative Production:
Cumulative Injection:
Oil
Water
Gas
Reservoir
Water
Gas
Voidage
Voidage
Voidage
Month
Cumulative
Cumulative
Cumulative
Voidage
Cumulative
Cumulative
Replacement
Replacement
Balance
(stb)
(stb)
(msci)
(rbbl)
(stb/day)
(mscf/day)
(rbbl)
Ratio
(rbbl)
1/31/2015
179,189
326,764
85,438
593,292
800,924
0
808,933
1.36
215,641
2/28/2015
143,711
250,701
45,148
431,334
719,627
0
726,823
1.69
295,489
3/31/2015
154,717
302,494
51,398
501,230
779,447
0
787,241
1.57
286,011
4/30/2015
165,830
353,388
57,512
570,112
754,673
0
762,220
1.34
192,108
5/31/2015
155,382
370,386
59,775
582,161
776,055
0
783,816
1.35
201,654
6/30/2015
159,384
411,216
72,442
644,474
653,398
0
659,932
1.02
15,458
7/31/2015
175,938
414,985
65,123
651,117
786,681
0
794,548
1.22
143,430
8/31/2015
182,724
343,441
59,336
576,085
852,349
0
860,872
1.49
284,787
9/30/2015
172,217
361,961
52,906
577,348
795,248
0
803,200
1.39
225,853
10/31/2015
180,763
418,551
48,447
635,007
854,698
0
863,245
1.36
228,238
11/30/2015
182,737
376,178
49,351
595,058
843,859
0
852,298
1.43
257,240
12/31/2015
208,319
410,995
76,159
688,442
842,645
0
851,071
1.24
162,629
Average:
2015
5,642
11,876
1,977
19,278
25,909
0
26,168
1.36
6,890
Cumulative:
stb
stb
mscf
rb
stb
mscf
rb
rb
31 -Dec -15
2,060,911
4,341,060
723,035 '
6,947,694
9,459,604
0
9,648,796
1.39
2,701,102
Exhibit 2-B Form 10-412 Rrhrn Al PI„PFT). I
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
RESERVOIR PRESSURE REPORT
1. Operator: Hlcorp
Alaska, LLC.
2. Address: 3800 Centerpoint Dr. Anchorage, AK 99516
3. Unit or Lease Nam, Mlne Point
4. Feld and Pool: Schrader Bluff Pool
1 5. Datum Reference:
4000' SS
6. Oil Gravity:
API = 14 -22
7. Gas Gravity: Air = 0.65
8. Well Name and
Number:
9. AF Number 50- 10. Oil (0) or Gas 11. AOGCC 12. Final Test
XXX-XXXXX-XX-XX (G) Pool Code Date
13. Shut -In
Tina, Flours
14. Press.
Surv. Type
(see
instructions
15. B.H
Tenp.
16. Depth
Tool TVDss
17. Final
Pressure at
Tool Depth
18. Datum 19. Pressure Gradient,
NDss
(input)
psVft. 20.
Pressure
at Datum
(cal)
Comments
Zone
MPS-16LS
50-029-23151-00-00
INJ
525140
9/12/2015
6,202
SBHP
86
4,117
1,301
4,000
0.316
1,258
Used Grad = 0.37 si/ft
OA
MPS -34
50-029-23171-00-00
PROD
525140
11/15/2015
19,704
PP
UNK
3,996
1,423
4,000
0.356
1,425
Jet Pump Gauge
NE+OA
MPE-24A
50-029-22867-01-00
PROD
525140
5/13/2015 1
144
PP
83
4,132
1,683
4,000
0.407
1,634
Jet Pump Gauge
OA+OB
MPS -05
50-029-23100-00-00
PROD
525140
12/24/2015
342
PP
UNK
3,992
1,926
4,000
0.482
1,929
Jet Pump Gauge
OA+OB
MPS-09LS
50-029-23067-00-00
INJ
525140
9/13/2015
61,776
SBHP
83
4,304
2,881
4,000
0.669
2,768
1 Used Grad = 0.37 si/ft
OB
MPS -32
50-029-23157-00-00
PROD
525140
12/31/2015
41,832
PP
UNK
3,754
1,575
4,000
0.420
1,666
Jet Pump Gauge
NB
MPS -24
50-029-23142-00-00
PROD
525140
12/31/2015
23,184
PP
UNK
3,882
1,533
4,000
0.395
1,577
Jet Pump Gauge
NB
MPL-46
50-029-23551-00-00
PROD
525140
9/21/2015
New Well
PP
71
3,344
1,494
4,000
0.447
1,737
ESP Gauge
OA
MPL-49
50-029-23545-00-00
INJ
525140
9/9/2015
New Well
SBHP
81
4,071
1,830
4,000
0.450
1,804
Used Grad = 0.37psi/ft
OA
MPL-45
50-029-22913-00-00
PROD
525140
9/2/2015
127,008
SBHP
56
2,967
1,364
4,000
0.460
1,746
Used Grad = 0.37psi/ft
OA
MPB-27LS
50-029-23233-00-00
INJ
525140
10/4/2015
30,336
SBHP
86
4,430
1,998
4,000
0.451
1,839
Used Grad = 0.37 psi/ft
OA
MPJ -09A
50-029-22495-01-00
PROD
525140
11/8/2015
2,002
1 PP
76
1 3,639
1,212
4,000
0.333
1,345
ESP Gauge
OA
MPJ -01A
50-029-22070-01-00
PROD
525140
8/5/2015
356
PP
73
3,279
1,064 1
4,000
0.324
1,333
ESP Gauge
OA+OB
MPG -13
50-029-22782-00-00
INJ
525140
9/17/2015
11,712
SBHP
76
3,892
2,493
4,000
0.641
2,533
l Used Grad = 0.37psi/ft
NB+OA+OB
MPE-13BLS
50-029-22536-02-00
INJ
525140
10/3/2015
12,312
SBHP
81
4,027
1,649
4,000
0.409
1,639
1 Used Grad = 0.37 psi/ft
OA
MPE-15
50-029-22528-00-00
PROD
525140
9/4/2015
418
SBHP
99
4,040
1,664
4,000
0.412
1,649
Used Grad = 0.37 psi/ft
N+oA
MPG -11
50-029-22781-00-00
INJ
525140
5/14/2015
120,913
SBHP
75
4,094
1,552
4,000
0.379
1,517
Used Grad = 0.37psi/ft
OA+OB
MPG -08A
50-029-22141-01-00
PROD
525140
10/25/2015
62,352
SBHP
63
3,310
1,605
4,000
0.485
1,860
Used Grad = 0.37psi/ft
N+OA+OB
MPH -18
50-029-23224-00-00
PROD
525140 1
6/30/2015
370
PP
75
3,756
1,539
4,000
0.410
1,629
Gauges
OA+OB
MPI -12
50-029-23038-00-00
PROD
525140
12/19/2015
7,968
SBHP
48
1 2,603
1,090
4,000
0.419
1,607
High AnIe Well
OA+OB
MPI -16
50-029-23221-00-00
INJ
525140
9/22/2015
264
SBHP
102
3,897
2,318
4,000
0.595
2,356
Used Grad = 0.37 psilft
NB+OA+OB
MPH -16
50-029-23227-00-00
PROD
525140
10/2/2015
308
PP
BO
3,863
1,134
4,000
0.294
1,184
ESP Gauge
OA+OB
MPH -19
50-029-23371-00-00
PROD
525140
12/31/2015
12,624
PP
80
3,917
1,843
4,000
0.471
1,874
lJet Pump Gauge
OA+OB
MPJ -26
50-029-22818-01-00
PROD
525140
3/6/2015
138
PP
76
3,850
1,335
4,000
0.347
1,400
Used Grad= 0.43 si/ft
NB+OA+OB
Average
1,721
21. All tests reported herein were Trade in accordance w ith the applicable rules, regulations and instructions of the Alaska Oland Gas Conservation Comrission.
I hereby certify that the foregoing is true and correct to the best of my knowledge.
Signature
Title
Reserwir Engineer
Printed Name
Anthony McConkey
Date
3/16/2016
FL Fluid Level
PBU Pressure Build Up
PFO Pressure Fall Off
PP Pump Pressure
SBHP Shut -In Bottom Hole Pressure
Section 3
Sag River Oil Pool
List of Exhibits
Reservoir Injection Report (Form 10-413) 3-A
Reservoir Voidage Balance 3-B
Static Pressure Data (Form 10-412) 3-C
Sag River Oil Pool Waterflood
Project Summary
A Participating Area for the Sag was approved in 2005. On December 31, 2008, the PA
contracted to a 160 acre area around the active wells, MPF -33A and MPF -73A. During 2015,
there were two active Sag production wells (MPK-33 and MPC -23) and no active injection wells.
There was no production from the reservoir in most of 1999 and the entire year of 2000 because
it was not economical to repair the failed ESPs. At the end of 2000, one well (MPC -23) was
converted to a jet pump completion. In 2001, one well (MPF -33A) was side-tracked and
completed with a jet pump completion and another well (MPF -73A) was deepened from an idle
Kuparuk well into the Sag River reservoir as an injector. One producing well (MPC -23) was shut
in for integrity reasons in 2002 and the injection well (MPF -73A) was changed to water service
only in 2006 due to tubing to inner annulus communication on gas injection.
MPK-33 was cycled between Kuparuk and Sag production throughout 2015, while MPC -23
remained on Sag production throughout 2015.
The Sag River Pool oil production averaged 198 STBD, gas production averaged 156 MSCFD
(average GOR of 788 SCF/BBL), and water production averaged 6 STBD in 2015. Cumulative
production through the end of 2015 is 3.8 MMSTB of oil, 2.77 BSCF of gas, and 2.41 MMSTB
of water. The average Sag production rate in 2014 was 410 STBD. The significant decrease in
2015 was likely due to flush production present in 2014 in MPK-33 that tapered off in 2015.
Furthermore, some mechanical problems developed with MPC -23's artificial lift in the summer
months, which has since been resolved. In 2015, the average GOR was 788 SCF/STB, a decrease
over the 2014 average GOR of 1207 SCF/STB.
The only injector (MPF -73A) started water injection in July 2002. The water injection rate for
2012 averaged 790 BWD, with no gas injected. However, from 2013 onward, there was no water
or gas injection into MPF -73A as the offset producer, MPF -33A, was offline. Cumulative water
injection since waterflood startup through the end of 2015 remained the same as at the end of
2012 at 3.02 MMSTB and cumulative gas injection at the end of 2015 is 0.32 BSCF.
Exhibit 3-C presents the reservoir pressure data for the Sag River wells taken during 2015. Three
pressure surveys were obtained.
MPF -33A has been shut-in since 4/9/12 due to a stuck jet pump in the tubing string. During 2012
and 2014, options were pursued to remove the pump, all of which were unsuccessful. The stuck
jet pump is preventing access to the reservoir to obtain a SBHP survey.
Exhibit 3-A Reservoir Voidage Balance Summary Sag River Pool
January - December 2015
Production Rate Averages:
Injection Rate Averages:
Oil
Water '
Gas
Reservoir
Water
Gas
Voidage
Voidage
Voidage
Month
Prod Rate
Prod Rate
Prod Rate
Voidage
Inj Rate
Inj Rate
Replacement
Replacement
Balance
(stb/day)
(stb/day)
(mscf/day)
(rbbl/day)
(stb/day)
(mscf/day)
(rbbl/day)
Ratio
(rbbl/day)
1/31/2015
331
0
307
528
0 0
0
0.00
-528
2/28/2015
286
0
343
504
0 0
0
0.00
-504
3/31/2015
266
0
287
450
0 0
0
0.00
-450
4/30/2015
208
0
287
390
0 0
0
0.00
-390
5/31/2015
161
0
110
234
0 0
0
0.00
-234
6/30/2015
260
0
119
364
0 0
0
0.00
-364
7/31/2015
258
0
94
361
0 0
0
0.00
-361
8/31/2015
201
11
136
302
0 0
0
0.00
-302
9/30/2015
124
33
102
224
0 0
0
0.00
-224
10/31/2015
123
0
44
173
0 0
0
0.00
-173
11/30/2015
92
0
18
129
0 0
0
0.00
-129
12/31/2015
71
28
26
128
0 0
0
0.00
-128
Cumulative Production:
Cumulative Injection:
Oil
Water '
Gas
Reservoir
Water
Gas
Voidage
Voidage
Voidage
Month
Cumulative
Cumulative
Cumulative
Voidage
Cumulative
Cumulative
Replacement
Replacement
Balance
(stb)
(stb)
(mscf
(rbbl)
(stb/day)
(mscf/day)
(rbbl)
Ratio
(rbbl)
1/31/2015
10, 247
0
9,506
16,383
0 0
0
0.00
-16,383
2/28/2015
7,999
0
9,611
14,118
0 0
0
0.00
-14,118
3/31/2015
8,251
2
8,912
13,957
0 0
0
0.00
-13,957
4/30/2015
6,250
0
8,610
11,699
0 0
0
0.00
-11,699
5/31/2015
4,985
3
3,425
7,245
0 0
0
0.00
-7,245
6/30/2015
7,804
1
3,569
10,927
0 0
0
0.00
-10,927
7/31/2015
7,999
4
2,913
11,203
0 0
0
0.00
-11,203
8/31/2015
6,235
353
4,205
9,371
0 0
0
0.00
-9,371
9/30/2015
3,722
985
3,069
6,723
0 0
0
0.00
-6,723
10/31/2015
3,819
3
1,378
5,350
0 0
0
0.00
-5,350
11/30/2015
2,767
0
551
3,874
0 0
0
0.00
-3,874
12/31/2015
2,199
868
816
3,964
0 0
0
0.00
-3,964
Average:
2015
198
6
156
316
0
0
0
0.00
-316
Cumulative:
stb
stb
mscf
rb
stb
mscf
rb
rb
31 -Dec -15
72,277
2,219
56,565
117,135
0
0
0
0.00
-117,135
Exhibit 3-B Form 10-412 car. Vi* . T)__I
FL
Fluid Leel
PBU
STATE OF ALASKA
PFO
Pressure Fall Off
PP
Pump Pressure
SBHP
ALASKA OIL AND GAS CONSERVATION COMMISSION
RESERVOIR PRESSURE REPORT
1. Operator: Hilcorp Alaska, LLC.
12. Address: 3800 Centerpoint Dr. Anchorage, AK 99516
3. Unit or Lease
Name: Milne Point
4. Field and Fool: Sag River Oil Pool 5. Datum Reference: 8750' SS 6. Oil Gravity: AR - 34 7. Gas Gravity: Air =.65
8. Well Name
and Number:
9. AR Number 50-XXX-XXXXX-XX-
XX
10. Oil (0) or Gas 11. AOGCC
(G) Pool Code
12. Final Test 13. Shut -In Time, 14. Press. 15. B.H. Temp. 16. Depth Tool 17. Final 18. LHtum NDss
Cate Hours Surv. Type T/Dss Observed (input)
(see Pressure at
instructions Tool Depth
for codes)
19. 20. Pressure at
Pressure Datum (caQ
Gradient,
psi/ft.
Comments Zone Code
MPC -23
50-500-29226-43-00
PROD 525150
6/14/2015 52 PP 202 8,580 1,764 8,750
0.210 1,839
Grad = 0.44 psi/ft SAG
MPF -73
50-029-22744-01-00
INJ 525150
12/24/2015 26,352 SBHP 177 7,321 3,819 8,750
0.505 4,419
Grad = 0.42 psi/ft SAG
MPK33
50-029-22729-00-00
PROD 1 525150
1/5/2016 2472 SBHP 220 8,750 2,654 8,750
0.303 2,654
Grad = 0.42 psi/ft SAG
Average 2,971
21. All esls reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation
Commission.
I hereby certify that the foregoing is true and correct to the best of ny know ledge.
Sign ature
Title
Reservoir Engineer
Printed Name
Anthony McConkey
Date
3/30/2016
FL
Fluid Leel
PBU
Pressure Build Up
PFO
Pressure Fall Off
PP
Pump Pressure
SBHP
Shut -In Bottom Hole Pressure
Section 4
Production/Injection Well Surveillance
List of Exhibits
Milne Point Kuparuk Surveillance
1/1/2015 — 12/31/2015
4-A
Milne Point Schrader Surveillance 1/1/2015 — 12/31/2015 4-B
Production/Injection Well Surveillance
As per Conservation Order 205 (Kuparuk River Oil Pool) and Order 477 (Schrader Bluff Oil
Pool), the Milne Point Operator runs injection surveys on at least one third of the existing online
multiple zone injectors annually and on new multiple zone injectors. In 2012 AOGCC verified
that for Milne Schrader these surveys would only apply to online unregulated injectors. There
were 27 existing Kuparuk multi -zone injectors in 2015. Nine injection surveys were obtained in
2015. All of these injection surveys were performed in multi -zone injectors. There were 18
existing unregulated Schrader Bluff multi -zone injectors in 2015, seven of which were shut in all
year. Injection surveys were run in 4 of the 11 online unregulated Schrader Bluff multi -zone
injectors. Three of those surveys were run on newly converted producer -to -injector conversions
(H-04, G-11, & J-12).
Since the majority of producers at Milne Point are completed with ESPs or jet pumps which
preclude logging below the pump while on production, few production logs are run. No
production logs were run in Kuparuk or Schrader wells in 2015.
Exhibits 5-A & 5-13 are a summary of the Milne Point field well surveillance performed in 2015 on
both Schrader and Kuparuk Pools.
Exhibit 4-A Prod uction/In iection 2015 Loeeine & Surveillance
Kuparuk River Pool
Sw Name
Reservoir
Well Type
Rec Date
Log Type
Field Analysis
Final Determination
15% C/B
85%A sands
Results derived from
combination of up
pass spinner data and
MPL-10
KUP
WINJ
4/24/2015
STP/IPROF
Notevaluatedbyfield
temperature log.
11%C
14% B
21%A3
54% A2
(Used 40 fpm Up pass
MPC-28AKUP
WINJ
5/3/2015
STP/IPROF
Notevaluatedbyfield
&templogforsplits)
23% C/B
52%A3/A2
25% Al
(Determined by stop
MPF -89
KUP
WINJ
6/27/2015
STP/IPROF
Notevaluatedbyfield
counts
PROFdid notindicate
leaking B/C Sand WRV's.
Appears that 100% of the
100%A2
injection is going intothe
MPC -06
IKUP
WIND
1 8/31/2015
STP/IPROF
A2 Sand.
100% A -sand (toe
injection)
IPROF was run to verify
dummy W FRV's were
holding at the heel of
MPL-33
KUP
WINJ
9/14/2015
STP/IPROF
Notevaluatedbyfield
well.
18% C/B
82% A3/A2
(C/B injection is
through two holes
discovered below the
bottom WFRV mandrel
at 8080' MD &
MPC -10
KUP
WINJ
9/16/2015
STP/IPROF
Notevaluated byfield
8105'MD
13% C/B
87% A3/A2
(Agree w/field
13% in C/B sand
interpretation)
(regulated completion),
MPJ -11 IKUP
WINJ 1
10/15/2015
STP/IPROF
87% in A3/A2.
Inconclusive -Inline
Inconclusive
spinner failed due
jamming from
debris/schmoo in
MPC -19
KUP
WINJ
10/16/2015
STP/IPROF
wellbore.
o cross upper
valve(11,626'MD),10%
95%C
Across lower RK valve
5% B
(11,686' MD).
Temperature logsuggests
Analysis based on
no injection below
temperature log
MPK-18Ai
KUP I
WIND I
12/29/2015
STP/I PROF
11740' MD.
Exhibit 4-B Production/Injection 2015 Logging & Surveillance Schrader Bluff Pool
Sw Name
Reservoir
Well Type
Rec Date
Log Type
Field Analysis
Final Determination
95% N
5% OB
Results are not
representative of
actual performanceas
the well was only
injecting 142 bwpd
during logging versus a
target of 700 bwpd
when norma Ily on
MPJ -19A
SBL
WINJ
8/31/2015
STP/IPROF
Not evaluated by field
injection.
Inconclusive -Tagged fi I I.
Temperature anomaly at
4,152' MD suggests no
Inconclusive
injectivity pastthat
MPH -04
SBL
WI NJ
9/22/2015
STP/I PROF
poi nt.
70% OA
30%OB
OA (upper sand) does
a ppea r to be to ki ng
more, however, unsure
Using stop counts, 85% in
about stop counts due
WFRV at 4452'MD, 15%
to low injection rate...
down tubing into lower
Used up passes for
MPJ -12
SBL
WI NJ
10/15/2015
STP/IPROF
perforations.
evaI
Inconclusive,spinners
Inconclusive, temp Iog
continuously clogged
suggests majority of
with fill/schmoo during
injection down OB
MPG -11
SBL
WINj
12/20/2015
STP/IPROF
passes.
sands.
Section 5
Shut in Well Status
List of Exhibits
Milne Point Shut in Well Status 1/1/2015 —12/31/2015 5-A
Exhibit 5-A 2015 Shut -In Wells Milne Point Unit
Sw Name
Reservoir
Reason for Well
Current Mechanical Condition of Well, including integrity
Future Utility Plans &
Comments
Shut -Ing
issues'
Possibilities'
MPB-01
Ugnu
E
No flowline or surface kit. Well has failed ESP downhole.
1
Considering using well as backup disposal well for the field.
A
3
Although well has TxIA communication, WELLS has suggested that it could still be
MPB-03
Kuparuk
Currently has TxIA communication through broken GLV in
produced (leak is essentially no different than having a S/O in that mandrel). It is SI
GLM#1.
due to the high GOR and its proximity to gas injector MPE-02.
MPB-04A
Kuparuk
A
Operable well, SI due to high gas rates - Facility unable to
6
Currently evaluating options to get well back online. Has a stuck tubing tail plug.
handle extra gas.
Attempts have been made to pull plug, but may need RWO to fix.
MPB-06
Kuparuk
D
Surface casing leak.
3
Cost is approximately. $4MM for a SC repair. Not economic on a -100 bopd well.
D
5
High GOR well. Needs permanent flowlines installed and gas lift line is blinded.
MPB-07
Kuparuk
Tubing leak; IBP set in well Feb 2006 to secure.
Diagnostics determined potential source of pressure from packer leak. Well has
been secured. Well will have reservoir P&A.
MPB-08i
Kuparuk
E
4
Well does not support any producers. No flowlines or wellhouse.
MPB-11i
Kuparuk
D
Tubing leak; well secured with sand plug.
1
Need to fix leaking permanent patch and perform FCO.
MPB-12i
Kuparuk
E
No known problems.
6
Well supports MPB-03. If MPB-03 ever comes back online, then B-1 2i will be brought
BO1 to support it.
MPB-14i
Kuparuk
E
No known problems.
3
MPB-20's conversion to an injector has replaced the need for this well to be on
n'ection. No current Qlans to bring the well SOL
MPB-17i
Kuparuk
E
No mechanical problems.
3
Wellhouse and flowlines removed. Quick communication with producer. Evaluate
Potential sidetrack.
MPB-19
Kuparuk
B
No known problems.
3
Wellhouse and flowlines removed. GL well. High water cut producer. Possible frac
into water zone. Evaluate ootential sidetrack.
A
Cement Packer Squeeze repaired the TxIA communcation in
6
Producer is in the same HU as gas injector E-03. Well comes online with very high
MPB-23
Kuparuk
May 2012.
GOR. Will likely be used for gas flowbacks if Milne encounters a gas shortage for
fuel gas.
MPB-27LSi
Schrader
E
No known problems.
3
MPB-27LSi was shut in in April 2012 after offset producer MPE-30A was shut in and
P&A'd due to subsurface subsidence damage.
MPC -11 i
Kuparuk
E
No wellhouse, no flowlines
3
Further use as an injector not required while no offset producers on line.
MPC-12Ai
Kuparuk
D
Well suspended 7/13/03. Secured with CIBP and FP with
4
Wellbore lost during coiled tubing sidetrack.
diesel.
MPC -16
Kuparuk
A
Well suspended 10/27/93. Pulled completions and set 2
4
High GOR from E-03 gas breakthrough.
cement plugs with EZSV retainers over perfs.
MPC -17i
Kuparuk
D
Leak in 9 5/8" casing to surface
6
scoping out non -rig remedial actions
MPC -20
Kuparuk
B
No wellhouse, no flow lines
3
High water cut. Perfd without good logs. Wellhouse and flowlines removed. Would
need WSO.
MPC -25i
Kuparuk
B
S/I for pressure management
6
Pressures up when on injection. Not sure if it's supporting any offset producers.
Under Eval for other opportunities.
MPCFP-02i
Kuparuk
E
No known mechanical problems
3
Thief zone directly to offset producers. Evaluate Sag/Schrader potential.
MPD -01
Kuparuk
C
Dead ESP completion downhole, no support to block
5
No support to block. No flowlines from D pad. Plan to P&A in the future.
MPD -02A
Kuparuk
B
Well has TxIA communication. Well resecured post SBHP April
5
High water cut well. No flowlines from D pad. Plan to P&A in the future.
- 2008 with downhole plug.
MPE-08
Kuparuk
D
Failed ESP
1
Possible donor well bore.
MPE-16i
Kuparuk
E
Long term shut in
1
MPE-16 supports MPB-06 which is shut-in for surface casing leak. MPE-16 will
remain shut-in until B-06 comes back on line.
MPE-21
Schrader
E
ESP failed
5
Wellhouse and flowlines removed. Planned P&A in 2016.
MPE-25A
Schrader
E
Injector in a highly compartmentalized area
3
MPE-28
Schrader
D
ESP failed, leak in surface casing
3
MPE-30A
Schrader
C
Suspended well 7/28/2012
4
Severe casing buckling
MPE-33
Schrader
C
ESP failed; no surface casing and liner has no cement
3
Wellhouse and flowlines removed. Possible conversion to injection.
MPF -17i
Kuparuk
D
Tubing integrity ri
g ty problem
1
RWO needed to replace tubing. Requires new seismic to understand HU
connective
MPF -33A
Sag River
D
Stuck jet pump
2
Attempted RWO in 2014, failed to pull tubing. Looking at sidetrack opportunities.
MPF -41 i
Kuparuk
E
S/I for pressure management
6
Drilled as a producer. High water saturation so converted to injection. No response
seen in offset producer. Evaluate potential sidetrack.
MPF-73Ai
Sag River
E
S/I for pressure management
6
Only plan to bring on if F -33A comes online, or a Sag re -drill in same area.
Exhibit 5-A 2015 Shut -In Wells Milne Point Unit
Sw Name
Reservoir
Reason for Well
Shut -In'
Current Mechanical Condition of Well, including integrity
issues'
Future Utility Plans &
Possibilities'
Comments
MPF -80
Kuparuk
E
Suspended well June 2011. Well plugged
4
Suspended well June 2011
MPF -90
Kuparuk
C
No producer connections
1
S/I for lack of producer connections
MPG -03
Schrader
E
Suspected MBE to G-16
1
SI until MBE treatment is carried out between G-03 & G-16.
MPG -04
Schrader
C
ESP failed
3
Marginal economics for repair- may re-evaluate in 2016.
MPG -12
Schrader
C
ESP failed
3
Bottom Hole location replaced. No surface casing.
MPG -13
Schrader
E
Offset producer SI
1
Offset well is producer G-15, SI until offset production is back online.
MPG -15
Schrader
B
Produces 100% Watercut
1
Well likely has a matrix bypass event (MBE) to the aquifer.
MPH -01
Schrader
C
ESP failed
1
Well house has been removed.
MPH -02
Ugnu
A
No known problems. Has a temp drive for ESP
3
Oil sample retrieved during 2006 but no production to plant
MPH -03
Schrader
C
No known problems. ESP still functional.
1
MPH -07A
Schrader
C
Failed ESP
1
Low rate producer due to compartmentalization - unable to provide injection support.
MPH -09
Schrader
D
Suspended, Hole in casing at 311'
5
P&A in progress.
MPH -10
Schrader
D
ESP failed, Hole in casing
3
MPH -11
Schrader
E
No known problems
6
Injector will be put back online with offset producers
MPH -12
Schrader
E
Unintentional ST into N -sand
6
Abnormally pressured. Historically used for pigging returns.
MPH -15
Schrader
E
SI due to potential MBE with producer H-16
1
Will attempt to bring BO1 following MBE treatment with H-16.
MPH -18
Schrader
C
Produces solids which upsets the facility
1
Determining strategies to get well back online with minimal solids production. May be
a result of MBE in which the path forward will be an MBE treatment.
MPH -19
Schrader
B
Produces high watercut
1
Considering plugging off toe section of well which might be bringing in water.
MPI -01
Schrader
C
ESP failed
3
Flowline removed in'98. Solids producer. Bottom hole location replaced by 1-15.
MPI -02
Schrader
E
SI due to MBE with producer H-18
1
Working to fix MBE in H-18 prior to bringing back on injection.
MPI -05
Schrader
E
No offset production
6
N -sand only injector. No offset producers completed in the N -sand.
MPI -06
Schrader
C
ESP failed
3
Failed ESP and MBE to injector, high WC if POP'd
MPI -11
Schrader
D
Surface Casing Leak
2
Repair requires excavation or RWO.
MPJ -02
Schrader
E
No offset production
6
N -sand only injection w/ no offset N -sand production. May place on injection if G -08A
is repaired.
MPJ -07
Schrader
D
ESP failed; Tx1AxOA
3
Bottom hole location replaced by H-18
MPJ -15
Schrader
E
SI due to MBE with producer J-15
1
Planning on MBE treatment in 2016 between J-01 and J-15.
MPJ -16
Kuparuk
E
No known problems
1
No surface facilities. Evaluate potential sidetrack targets.
MPJ -20A
Schrader
E
Injector with MBE and offset producers SI
6
Injector will be put back online with offset producers
MPJ -21
Schrader
C
ESP failed
3
RDS well no surface csg. Bottom Hole location replaced by J-26
MPJ -23
Schrader
C
MBE with supporting injector
3
MPJ -24
Schrader
E
Fill in casing, unsuccessful FCO
1
MPK-02
Kuparuk
B
Failed ESP
1
Produced 99.8% watercut at time of ESP failure. Uneconomic to fix. Looking at
potential for Kuparuk or Sag sidetack.
MPK-09
Kuparuk
C
ESP failed
1
Needs RWO to replace failed ESP
MPK-13
Kuparuk
C
ESP failed
1
Needs RWO to replace failed ESP
MPL-06
Kuparuk
D
Reservoir section abandoned
4
Well suspended during 5/2012 RWO. Reservoir section abandoned.
MPL-10
Kuparuk
E
No known mechanical problems
1
Intervention under evaluation
MPL-17
Kuparuk
D
ESP failed. Low remaining reserves
1
Low remaining reserves. Evaluate potential gas storage well or Kuparuk sidetrack.
MPL-21
Kuparuk
E
High pressure block.
1
Intervention under evaluation
MPL-34
Kuparuk
E
Suspended 12/1/2008. High pressure block.
4
No indication of communicating with surrounding producers.
MPL-35A
Schrader
C
Attempt to produce from NW Schrader 0 -sands. Low rate, ESP
failed.
1
No plans fixing well. Planning on drilling grass roots wells to target NW Schrader
area. May be opportunity for ST/Infill drilling in future.
MPL-37A
Schrader
C
Dead ESP, no other mechanical issues
1
Planned sidetrack for NW Schrader development
MPL-39
Kuparuk
E
No known mechanical problems
2
Plan to convert to producer. Brought online very briefly in November 2014 (<1 day
POP time) using 'poor boy'jet pump lift. Considering replacing JP system with an
ESP.
MPL-42
Kuparuk
D
Slow TAA communication on gas injection
1
Intervention under evaluation
Exhibit 5-A 2015 Shut -In Wells Milne Point Unit
Sw Name
Reservoir
Reason for Well
Shut -In'
Current Mechanical Condition of Well, including integrity
issues'
Future Utility Plans &
Possibilities'
Comments
MPL-45
Schrader
C
ESP failed.
1
Low productivity. Evaluate conversion to jet pump or potential Schrader sidetrack.
MPS -01 BLS
Schrader
D
No integrity issues
3
Injector has MBE
MPS -03
Schrader
A
No integrity issues
2
SI due to high GOR; may have injection support now to bring well online
MPS -06
Schrader
E
No integrity issues
6
No offtake in 2012, plan to return to injection when offset producers are online
MPS-07LS
Schrader
D
Suspended 11/17/2011. Surface casing leak
4
Suspended Nov. 2011
MPS-07SS
Schrader
D
Suspended 11/17/2011. Surface casing leak
4
Suspended Nov. 2011
MPS -08
Schrader
D
Well produces large volume of solids which upsets the plant.
2
Ran IPROF/WFL and caliper to locate potential screen breach. Planning on setting
patch over screen breach.
MPS-09LS
Schrader
D
Surface casing Issue
3
MPS-09SS
Schrader
D
Surface casing Issue
3
MPS-10ALS
Schrader
D
Operable with String communication
3
Intervention under evaluation
MPS-10ASS
Schrader
D
Operable with String communication
3
Intervention under evaluation
MPS -14
Schrader
C
MBE to offset producer S-24.
6
Will not bring back on injection until S-24 is back online, in which the MBE between
the two wells needs to be fixed.
MPS-13LS
Schrader
D
Matrix Bypass Event (MBE) present in well
2
Intervention planned - will likely pump MBE treatment in future.
MPS -21
Schrader
E
No known problems, Cement over perforations
1
Lost CT under -reamer in hole
MPS -22
Ugnu
C
No known problems
1
Low PI.
MPS -24
Schrader
C
Produces a lot of solids, part of a failed sand consolidation
treatment with BP. Has an MBE with offset producer 5-14.
3
No plans on fixing well, may consider if fixing sanding problem in S-08 and/or S-03 is
successful.
MPS -32
Schrader
D
Casing leak
1
Intervention under evaluation
MPS-33ASS
Schrader
E
No integrity issues
1
MBE to producer, potential MBE treatment candidate
MPS -34
Schrader
C
Needs Coiled Tubing Fill -Cleanout
6
Fill above jet pump that needs to be cleaned out prior to production. May need a
RWO due to sliding sleeve potentially washed out, but that cannot be confirmed until
back on oroduction.
MPS -37
Ugnu
D
Pump problem.
3
Long term shut in well.
MPS -39
Ugnu
D
Pump Failed.
3
Will attempt to re -activate after GNI facility is finished in 2015.
MPS -41A
Ugnu
D
Suspended with cement.
4
Unable to fish tubing.
MPS -41A
Ugnu
D
Pump Failed.
3
No current plans to re -activate well, may do so after successful repair of S-39.
MPS -90
Ivishak
E
Currently has kill string and IBP.
1
Purposed for Ivishak source water for S -pad, however produced large amounts of
CO2. Looking to use for Sag producer.
Reasons for Well Shut -In
A. High GOR, currently uncompetitive to produce due to facility constraints, no known mechanical problems
B. High water, currently uneconomic to produce, no known mechanical problems
C. Low production rate, no known mechanical problems
D. Mechanical problems
E. Other (Specify under comments)
Current Mechanical Condition
Briefly describe the current mechanical condition including the condition of installed tubing and casing strings.
Future Utility
1. Evaluating remedial, sidetrack and/or redrill opportunities
2. Remedial well work planned
3. Long term Shut-in well/No immediate plans
4. Suspended well
5. P&A planned
6. Other (Specify under comments)
Exhibit 6-A Well Test Summary Milne Point Unit
Section 6
Milne Point Well Testing with ASRC Unit 5 and
Weatherford Gen 2 (VSRD) Summary
List of Exhibits
Summary of Milne Point Welltesting and Gen 2 (VSRD) Installations 6-A
Well Test Frequency
M:
Well Test Allocation Factors 6-C
Exhibit 6-A Well Test Summary Milne Point Unit
Milne Point Well Testing
Milne Point primarily utilizes on -pad separators for well testing. The pad separators at C, E, F, H,
K and L -Pads employ volumetric, vessel -based gas-liquid separation. Separators at I and J -Pads
employ centrifugal separation, while the separators at B, G, and S -Pads are multiphase meters,
aka Alpha "VSRD" (Venturi, Sonar, Red Eye, and Densitometer). Thus, a variety of metering
technologies are employed across Milne Point including:
- Turbine positive -displacement, Micro Motion coriolis meters or Venturi/Sonar meters for
liquid flow rate.
- Phase Dynamics or Red Eye watercut meters on the separator liquid legs.
- Turbine, Micro Motion coriolis meters or densitometers for gas flow rate.
Wells are automatically routed into test on a rolling schedule, such that a well is always being
tested on every pad with in-place testing facilities. Test duration is at least 6 hours, not including
the necessary purge time to flush the lines and vessel.
Exhibit 7-A provides information on the well tests conducted for consideration in production
allocation during 2014.
The services of portable test separators, provided by contractors ASRC and PTS, are utilized on
an ad-hoc basis whenever there are concerns about individual pad separators or to verify readings
from the fixed pad separators. As part of the continuing effort to improve performance in test
separation systems, Milne Point is also employing the use of new types of multi -phase meters, as
well as proper use of chemical additives such as emulsion breaker.
At Milne Point, Weatherford multiphase meters, aka Alpha VSRD (Venturi, Sonar, Red Eye,
Densitometer), were installed at G and S -Pads in 2009 and 2011 respectively. For the 2015 year,
all G -Pad and S -Pad wells were allocated from the VSRD well tests. The gross fluid and gas rates
shown in Figure 7-C were repeatable and reliable in 2015.
The VSRD meter at G -Pad has not been maintenance free. The MVT (Multi -Variable
Transmitter), i.e. primary bulk fluids meter, and Red Eye, i.e. water cut meter, both failed and
were replaced in February 2015. The sonar has been selected as the primary bulk fluids meter for
most of 2015.
Milne Point operators review well test quality on a daily basis and work with engineers and field
technicians to get meters fixed when needed.
During a scheduled 2011 inspection of B -Pad's test separator, internal corrosion was found. The
separator was taken online in June 2011 and the pad relied on ASRC portable tests for
production allocation. Following the success of the VSRD's at both G & S -pads, work began in
2013 to install a VSRD multiphase meter on B -Pad. While the meter has been successfully
installed at B -Pad, work has been on-going to calibrate the B -Pad VSRD meter to the three-phase
production rates at B -Pad. The main problems with the B -pad VSRD are related to the constant
`slugging' on the B -pad wells (B -pad is all gas lift and tends to produce the highest GOR out of
any other pad at MPU). The slugging caused vibrational damage to the systems, primarily the
RedEye watercut meter. Weatherford created new RedEye probes specially designed for Milne
Exhibit 6-A Well Test Summary Milne Point Unit
Point B -pad. The new probe was planned to be installed in the fall of 2014, however the
equipment was damaged during the shipping process. Another probe was specially developed and
installed in 2015. Weatherford tech representatives calibrated the VSRD meter following the
installation and deemed the system to be working correctly. Milne Point began using the B -pad
VSRD meter for welltest allocations in January 2015.
I and J pads currently use Kvaerner -Hydro cyclone separators. The separators have had issues
with accurate testing as a result of oversized gas and gross fluid Coriolis meters. The gas meters
were downsized and control valves rebuilt during 2015. This enabled many of the wells to be
allocated with the permanent separators. Portable Test Units (ASRC and PTS) were utilized to
assess permanent unit performance and for some well test allocations in 2015.
ASRC Unit #5 Operational and Performance Issues
ASRC Unit 5 is a portable well test unit that uses FMC Technologies Enhanced Multiphase
System (EMS) to measure well production. The EMS is comprised of a venturi meter and
capacitance and conductance electrodes coupled with a cyclonic pre -separator allowing partial
separation and metering in high gas volume fraction wells. The unit was used at the Milne Point
Field throughout 2008 under temporary AOGCC approval and approved for permanent use at
Milne Point on December 30, 2008.
ASRC Unit 5 underwent a trial period in early 2008 where piggy back testing was conducted with
an established gravity test separator, ASRC Unit 1. The resulting test data from Unit 5 was
compared to Unit 1 tests, manual fluid samples and historic field well tests. In this way, it was
determined that Unit 5 measures total liquid volume within ±10% and water cut with an
uncertainty band of±2.5 to 5%.
Following the trial period, Unit 5 was accepted as a full time portable test separator at Milne
Point, and it began autonomous testing across the field. Work is ongoing with ASRC to continue
to improve the accuracy of Unit 5 with a focus on metering gross fluid rates, water cuts and gas
volumes.
Exhibit 6-B Well Test Frequency— By Pad/Oil Pool Milne Point Unit
Welltest Frequency By Pad
Pool Name
Pad Name
Average Tests Per Month
MPU Pad B General
4.8
MPU Pad C General
6.9
MPU Pad E General
4.0
MPU Pad F General
4.4
MPU Pad G General
11.7
MPU Pad H General
6.0
MPU Pad I General
5.5
MPU Pad J General
MPU Pad K General
4.7
7.6
MPU Pad L General
5.3
MPU Pad S General
8.5
Welltest Frequency By Oil Pool
Pool Name
Average Tests Per Month
MPU Kuparuk PA (MLNE) 5.1
MPU Sag ADL 47434 (MP16) 7.1
MPU Sag/Und ADL 375132 (MP03) 3.1
MPU Schrader Bluff PA (SCHR) �5.6
Exhibit 6-B Well Test Frequency- By Well Kuparuk Oil Pool
Welltest Frequency By Well
Well Name
Pool Name
Days On
Production
Total Welltests
in 2015
Average
Welltests Per
Month
MPU KR B-003 Kuparuk PA
MPU Ku paruk PA (MLNE)
0
2.0
0
MPU KR B-009 Kuparuk PA
MPU Kuparuk PA (MLNE)
318
17.0
1.6
MPU KR B-010 Kuparuk PA
MPU Kuparuk PA (MLNE)
363
41.0
3.4
MPU KR B-015 Kuparuk PA
MPU KR B-016 Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
362
356
57.0
50.0
4.8
4.3
MPU KR B-021 Kuparuk PA
MPU Ku paruk PA (MLNE)
353
45
3.9
MPU KR B -022A Kuparuk PA
MPU KR C-001 Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
362
361
47
70
4.0
5.9
MPU KR C-003 Kuparuk PA
MPU Kuparuk PA (MLNE)
358
92
7.8
MPU KR C-004 Ku aruk PA
MPU KR C -005A Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
358
153
76
46
6.5
9.2
MPU KR C-007 Ku aruk PA
MPU Kuparuk PA (MLNE)
360
71
6.0
MPU KR C-009 Kuparuk PA
MPU Kuparuk PA (MLNE)
357
86
7.3
MPU KR C-013 Kuparuk PA
MPU Kuparuk PA (MLNE)
249
56
6.9
MPU KR C-014 Kuparuk PA
MPU Kuparuk PA (MLNE)
312
77
7.5
MPU KR C-021 Kuparuk PA
MPU Ku paruk PA (MLNE)
354
90
7.8
MPU KR C -022A Kuparuk PA
MPU Kuparuk PA (MLNE)
365
86
7.2
MPU KR C -024A Kuparuk PA
MPU Kuparuk PA (MLNE)
360
73
6.2
MPU KR C-026 Kuparuk PA
MPU Ku paruk PA (MLNE)
362
68
5.7
MPU KR C-040 Kuparuk PA
MPU KR C-043 Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
361
314
65
66
5.5
6.4
MPU KR E-004 Kuparuk PA
MPU Kuparuk PA (MLNE)
360
54
4.6
MPU KR E-006 Kuparuk PA
MPU Kuparuk PA (MLNE)
358
47
4.0
MPU KR E-009 Kuparuk PA
MPU Kuparuk PA (MLNE)
358
47
4.0
MPU KR E-010 Kuparuk PA
MPU Ku paruk PA (MLNE)
358
47
4.0
MPU KR E-011 Kuparuk PA
MPU Kuparuk PA (MLNE)
272
32
3.6
MPU KR E -014A Kuparuk PA
MPU Kuparuk PA (MLNE)
365
52
4.3
MPU KR E-018 Kuparuk PA
MPU Kuparuk PA (MLNE)
338
47
4.2
MPU KR E-019 Kuparuk PA
MPU Kuparuk PA (MLNE)
235
29
3.8
MPU KR E-022 Kuparuk PA
MPU KR F-001 Kuparuk PA
MPU Ku aruk PA (MLNE)
MPU Kuparuk PA (MLNE)
356
282
52
36
4.5
3.9
MPU KR F-005 Kuparuk PA
MPU Kuparuk PA (MLNE)
104
10
2.9
MPU KR F-006 Kuparuk PA
MPU Ku aruk PA (MLNE)
359
46
3.9
MPU KR F-009 Kuparuk PA
MPU Kuparuk PA (MLNE)
356
49
4.2
MPU KR F-014 Kuparuk PA
MPU Ku paruk PA (MLNE)
360
46
3.9
MPU KR F-018 Kuparuk PA
MPU Ku paruk PA (MLNE)
344
43
3.8
MPU KR F-022 Kuparuk PA
MPU Kuparuk PA (MLNE)
359
49
4.2
MPU KR F-025 Kuparuk PA
MPU Ku paruk PA (MLNE)
361
51
4.3
MPU KR F-029 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
53
4.4
MPU KR F-034 Ku aruk PA
MPU Ku earuk PA (MLNE)
365
52
4.3
MPU KR F-037 Kuparuk PA
MPU KR F-038 Kuparuk PA
MPU Ku paruk PA (MLNE)
MPU Ku paruk PA (MLNE)
359
357
47
47
4.0
4.0
MPU KR F-045 Kuparuk PA
MPU Ku paruk PA (MLNE)
350
44
3.8
Exhibit 6-13 Well Test Freauencv- By Well Kuparuk Oil Pool
Welltest Frequency By Well
Well Name
Pool Name
Days On
Production
Total Welltests
in 2015
Average
Welltests Per
Month
MPU KR F-050 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
46
3.8
MPU KR F -053A Kuparuk PA
MPU KR F-054 Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
365
365
47
44
3.9
3.7
MPU KR F -057A Kuparuk PA
MPU Kuparuk PA (MLNE)
359
46
3.9
MPU KR F-061 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
47
3.9
MPU KR F-065 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
44
3.7
MPU KR F -066A Kuparuk PA
MPU Kuparuk PA (MLNE)
365
44
3.7
MPU KR F-069 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
44
3.7
MPU KR F -078A Kuparuk PA
MPU Kuparuk PA (MLNE)
365
45
3.8
MPU KR F-079 Kuparuk PA
MPU Kuparuk PA (MLNE)
359
40
3.4
MPU KR F-081 Kuparuk PA
MPU Kuparuk PA (MLNE)
289
36
3.8
MPU KR F-086 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
46
3.8
MPU KR F -087A Kuparuk PA
MPU Kuparuk PA (MLNE)
359
38
3.2
MPU KR F-093 Kuparuk PA
MPU Kuparuk PA (MLNE)
357
42
3.6
MPU KR F-094 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
43
3.6
MPU KR F-096 Kuparuk PA
MPU KR H-005 Ku aruk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
160
319
20
72
3.8
6.9
MPU KRJ-006 Kuparuk PA
MPU Kuparuk PA (MLNE)
318
72
6.9
MPU KRJ-010 Kuparuk PA
MPU Kuparuk PA (MLNE)
325
53
5.0
MPU KR K-005 Kuparuk PA
MPU Kuparuk PA (MLNE)
363
107
9.0
MPU KR K-006 Kuparuk PA
MPU Kuparuk PA (MLNE)
56
12
6.5
MPU KR K-017 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
79
6.6
MPU KR K-030 Kuparuk PA
MPU Kuparuk PA (MLNE)
140
52
11.3
MPU KR K-033 Kuparuk PA
MPU Kuparuk PA (MLNE)
146
32
6.7
MPU KR K-037 Kuparuk PA
MPU Kuparuk PA (MLNE)
64
20
9.5
MPU KR K-038 Kuparuk PA
MPU Kuparuk PA (MLNE)
351
96
8.3
MPU KR L -001A Kuparuk PA
MPU Kuparuk PA (MLNE)
361
69
5.8
MPU KR L -002A Kuparuk PA
MPU Kuparuk PA (MLNE)
314
52
5.1
MPU KR L-003 Kuparuk PA
MPU Kuparuk PA (MLNE)
341
74
6.6
MPU KR L-004 Kuparuk PA
MPU Kuparuk PA (MLNE)
331
67
6.2
MPU KR L-005 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
74
6.2
MPU KR L-007 Kuparuk PA
MPU Kuparuk PA (MLNE)
358
65
5.5
MPU KR L-011 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
63
5.3
MPU KR L-012 Kuparuk PA
MPU Kuparuk PA (MLNE)
334
53
4.8
MPU KR L-013 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
55
4.6
MPU KR L-014 Kuparuk PA
MPU Kuparuk PA (MLNE)
358
55
4.7
MPU KR L-020 Kuparuk PA
MPU KR L-025 Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
341
358
76
57
6.8
4.9
MPU KR L -028A Kuparuk PA
MPU Kuparuk PA (MLNE)
316
57
5.5
MPU KR L-029 Kuparuk PA
MPU Kuparuk PA (MLNE)
338
67
6.0
MPU KR L-036 Kuparuk PA
MPU KR L-039 Kuparuk PA
MPU Kuparuk PA (MLNE)
MPU Kuparuk PA (MLNE)
365
14
69
2
5.8
4.4
MPU KR L-040 Kuparuk PA
MPU Kuparuk PA (MLNE)
365
74
6.2
MPU KR L-043 Kuparuk PA
MPU Kuparuk PA (MLNE)
348
62
5.4
bxnlnit b -b Well lest Frequency — By Well Schrader Blutt & Sag Oil Pools
Welltest Freauencv By Well
Well Name
MPU SR C-023 Tr 03 ADL 47434
MPU SR K-033 Tr 26 ADL 375132
MPU SB E-015 Schrader Bluff PA
MPU SB E -020A Schrader Bluff PA
MPU SB E -024A Schrader Bluff PA
MPU SB E-031 Schrader Bluff PA
MPU SB E-032 Schrader Bluff PA
MPU SB G-002 Schrader Bluff PA
MPU SB G -008A Schrader Bluff PA
MPU SB G-014 Schrader Bluff PA
MPU SB G-015 Schrader Bluff PA
MPU SB G-016 Schrader Bluff PA
MPU SB G-018 Schrader Bluff PA
MPU SB H-0086 Schrader Bluff PA
MPU SB H-016 Schrader Bluff PA
MPU SB H-018 Schrader Bluff PA
MPU SB 1-001 Schrader Bluff PA
MPU SB 1-003 Schrader Bluff PA
MPU SB 1-004A Schrader Bluff PA
MPU SB 1-007 Schrader Bluff PA
MPU SB 1-011 Schrader Bluff PA
MPU SB 1-012 Schrader Bluff PA
MPU SB 1-014 Schrader Bluff PA
MPU SB 1-015 Schrader Bluff PA
MPU SB 1-017 Schrader Bluff PA
MPU SB 1-019 Schrader Bluff PA
MPU SB J -001A Schrader Bluff PA
MPU SB J-003 Schrader Bluff PA
MPU SB J-004 Schrader Bluff PA
MPU SB J -008A Schrader Bluff PA
MPU SB J -009A Schrader Bluff PA
MPU SB J-025 Schrader Bluff PA
MPU SB J-026 Schrader Bluff PA
MPU SB L-046 Schrader Bluff PA
MPU SB S-005 Schrader Bluff PA
MPU SB 5-012 Schrader Bluff PA
MPU SB 5-017 Schrader Bluff PA
MPU SB S -019A Schrader Bluff PA
MPU SB 5-023 Schrader Bluff PA
MPU SB S-025 Schrader Bluff PA
MPU SB S-027 Schrader Bluff PA
MPU SB S-028 Schrader Bluff PA
MPU SB S-035 Schrader Bluff PA
Pool Name
MPU Sag ADL 47434 (MP16)
MPU Sag/Und ADL 375132 (MP03
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
MPU Schrader Bluff PA (SCHR)
Days On
Production
357
245
217
341
360
364
350
364
39
365
_. 34
365
355
354
354
48
0
299
359
364
357
22
364
332
364
364
285
365
222
289
181
356
356
365
311
351
363
284
361
362
158
363
339
Total Welltests
in 2015
83
25
26
49
46
45
45
126
15
128
12
117
110
78
46
10
1
38
53
44
47
4
53
54
66
63
36
64
38
55
17
45
39
21
45
70
83
66
53
73
44
84
79
Average
Welltests Per
Month
7.9
3.]
3.7
131
5.3
3.9
5.3
5.2
5.8
2.9
3.9
3.3
1.8
4.4
6.1
7.0
7.1
4.5
6.2
8.5
7.1
7.1
Exhibit 6-C Well Test Allocation Factors By Month Schrader Bluff& Sag Oil Pools
2015 Production Allocation Factors by Month
Month
Oil Production
Gas Production
Water Production
January
0.872
0.994
1.016
February
0.911
1.081
1.157
March
0.923
1.006
1.149
April
0.914
0.961
1.119
May
0.862
0.921
1.116
June
0.830
0.910
1.160
July
0.833
0.788
1.107
August
0.832
0.957
0.908
September
0.824
1.019
1.089
October
0.832
0.874
1.086
November
0.863
0.881
1.123
December
0.842
1.031
1.096
Section 7
Annual Review of Plan of Development
List of Exhibits
Presentation Documents for MPU Annual POD 7-A
