Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2019-04-30_319-221STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
A 00 '1 ril nn,n
1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate M Repair Well ❑ Operations shutdown 13
Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Chang eq
Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other
2. Operator Name: BP Exploration (Alaska), Inc
4. Current Well Class:
Exploratory ❑ Development
5. Permit to Drill Number. 188-100
3. Address: P.O. Box 196612 Anchorage, AK
6 API Number. 50-029-21859-00-00
99619-6612
Stratigraphic ❑ Service ❑
7. If perforating:
8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception? Yes ❑ No El
PBU Z 20
9. Property Designation (Lease Number):
1
10. FieldlPools:
ADL 028262
PRUDHOE BAY, BOREALIS OIL
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft):
Total Depth TVD(ft):
Effective Depth MD:
Effective Depth TVD:
MPSP (psl):
Plugs (MD):
Junk (MD):
11586
9216
11543
9181
2745
None
None
Casing
Length
size
MD
TVD
Burst
Collapse
Structural
Conductor
80
20"
39 -119
39 - 119
Surface
2625
13-318"
38 - 2663
38 - 2883
4930
2270
Intermediate
10674
9-518"
37 - 10711
37 - 8509
6870
4760
Production
Liner
1 1128
7"
10458 - 11586
8309 - 921 B
1 8150
1 7020
Perforation Depth MD (ft):
Perforation Depth TVD (ft):
Tubing Size:
Tubing Grade:
Tubing MD (ft):
11158 - 11358
8871 - 9033
4-112" 12.8#
13CrB51 L-80
-35 --�8000' 1-�8300' - 11318
Packers and SSSV Type: 4.112" HES TNT Packer
Packers and SSSV MD (ft) and TVD (ft): -78551 -8566
4-11E" Baker HS Packer
10386 18253
4-112" TIW HBBP Packer
1130418989
12. Attachments: Proposal Summary ® Wellbore Schematic
13. Well Class after proposed work:
Detailed Operations Program ❑ BOP Sketch ❑
Exploratory ❑ Stratigraphic ❑ Development ® Service ❑
14. Estimated Date for Commencing Operations: June 15, 2019
15. Well Status after proposed work:
Oil 1Z WINJ ❑ WDSPL ❑ Suspended ❑
16. Verbal Approval: Date:
GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑
Commission Representative:
GINJ ❑ Op Shutdown ❑ Abandoned ❑
17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: Wages, David
be deviated from without prior written approval.
Contact Email: David.Wages@bp.com
Authorized Name: Wages, David Contact Phone: +1 907 564 5559
Authorized Title: Well Interventigns Engineer
Authorized Signature: Date: /2' l
k COMMISSION USE ONLY
Conditions of approval: Notify Co ission so that a representative may witness Sundry Number. `
1
Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑
Other:
Past Initial Injection MIT Roq'd? Yes ❑ No ❑
Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required:
APPROVED BYTHE
Approved by: COMMISSIONER COMMISSION Date:
ORIGINAL
Submit Form and
Attachments in Duplicate
Form 10-403 Revised 0412017 Approved application is valid for 12 months from the date of approval.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
AFFIDAVIT OF NOTICE OF OPERATIONS
Before me, the undersigned authority, on this day personally appeared Vo q el who
being duly sworn states:
1. My name is David Wages. I am 18 years of age or older and I have personal knowledge of the
facts stated in this affidavit.
2. I am employed as an Engineer by BP Exploration (Alaska) Inc. ("BPXA") and I am familiar with
the Application for Sundry Approvals to stimulate the Z-20 Well (the "Well") by hydraulic
fracturing as defined in 20 AAC 25.283(m).
3. Pursuant to 20 AAC 25.283(1), BPXA prepared a Notice of Operations regarding the Well, a true
copy of which is attached to this Affidavit as Attachment 1 ("Notice of Operations").
On March 14, 20199 the Notice of Operations was sent to all owners, landowners, surface owners
and operators within a one-half mile radius of the current or proposed wellbore trajectory of the
Well. The Notice of Operations included:
a. A statement that upon request a complete copy of the Application for Sundry Approvals
is available from BPXA;
b. BPXA's contact information.
Signed this 22th day of April, 2019.
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
Subscribed and sworn to or affirmed before me at aui '& 2 e ; •� �L on the
day of r i , 20_
`S- 4nature of Officer
E
Alaska
Public
. Jordheim Imission Expkaa: 3.2Q-24
Af
Title of Officer
Date: April 25, 2019
Subject: Z-20 Fracture Stimulation
From: David Wages Engineer, BP Alaska o: 907.564.5669 c: 713.380.9836
To: AOGC Commission
Attached is BP's proposal and supporting documents to fracture stimulate the Kuparuk interval of
well Z-20.
The Ivishak interval has no remaining value and has been shut in since January 2017 due to
uncompetitive rates (single -digit IOR when it's online). The Kuparuk penetration of Z-20 is in an ideal
location for offtake, so this is an attractive recomplete candidate. This is already a gas -lifted producer,
so no surface piping work is required. All Kuparuk vertical wells are frac'ed, so this well will need a
post -rig frac to increase productivity and ensure competitive rates.
We are requesting a variance to sections 20 AAC 25.283, a, 3-4 which requires identification of fresh
water aquifers and a plan for basewater sampling.
Please direct questions or comments to David Wages
Summary of Work
This will be a conventional fullbore frac after a recomplete to the Kuparuk interval
Affidavit of Notification (20 AAC 25.283, a, i)
Partners notified 3/14/2019:
ConocoPhillips
ExxonMobil
Chevron
Department of Natural Resources
Plat Identifying Wells (20 AAC 25.283, a, 2, A-B)
& t #
Per the plat above, there are no water wells within 1h mile of the subject well.
Producers within'h mile of well trajectory (20 AAC 2-5.283, a, 2, Cj
Wen Name Well clorAflcatlot
Well Stat,.-s
Z-103PB2
Service
PI-,:gged Back Tor Bedrill
Z-22A
OeveloPr"e?t
Abandoned
W-25A
Dere,comerd
oil Producer shut-in
Z-108
Development
Oil Producer Shut -In
Z-223
oevelopmem
Oil Prod, a ShL;Mn
W-Z7
Deve:apme-t
Abandoned
Z-10A
Development
Oil Producer Gas::rt
Z-7
Developmet
Abandoned
V.1Z7A
Deve:Domert
Oil producer Shut -In
241
Development
Adardoned
Z-Z1A
Development
Abandoned
W-11
,7eve:npvie^t
Abandoned
2-112
Development
Oil Producer Gas l,tt
2-235
Development
Abandoned
W-31A
Deve:onrient
Oil Producer Gas _Ift
Z-112PS1
Development
Plugged Back Foriteddil
2-13C
Devel:Tunent
Oil Producer Shut-in
W-34
Deve'9pnert
Abandoned
Z-112PB2
Develolnrert
Plugged Back For ReMill
2-23P81
Development
Plugged Badr ForRedoll
W-34A
.".eve.anmea'.
Oil ➢roducer Gas Lift
Z-113
Development
Oil Pradlter Gas Litt
2-24
Developrfert
Oil Producer Hoeing
W-34AP81
Dere'c;.mer.:
Plugged Beck For Redrtl
Z-113PB1
Development
Plugged Back Tar Ra.'.rlh
2-25
Serru
Miscible lnjectaroperatIrg
W44
Serr.ee
Mier!.%''ec:or ia;ecti-g
Z-;1a
service
Water
Z-26
Development
Abandoned
Z-01
Development
Acarconed
Z__=
0-10O:'nelt
oil ➢rDC Lcer Gas:Sft
Z-25A
DevelopmaN
Cr. Producer Go LIft
Z-01A
Deve'apmert
Aaar.d-ned
Z---lE
SeMce
Water Injector Shut -In
Z-27
Oerelopmerit
Oil Producer Gas Lift
Z_MP81
D'ere:or>.ent
Pugged Bea',Fpr aesn!)
2-216PB3
Semice
Plugged Back Far Red1li
Z-29
5ervke
Water Injector Injecting
Z-U MB2
Development
P'aglled neck F=, ke,2111
Z-116PB2
Service
Plugged Back For Aedrlll
Z-29
Development
V. Pmdacer Flowing
Z-018
Development
Ot! Prnt.rav S::ut-:-.
Z-11A
De Iopnrent
Ol! Producer S4ut-i-i
Z-30
Deve!cnrr.eit
Abandoned
Z-02
:eve apmer=t
A_andcred
Z-12
service
Wsdblei;jetty C-erat:rg
Z-30A
Deveicpnert
C;i Pr^r.:i:ersrA r
Z-01A
se-:'.x
watef:,.feCMri.'1;'e:`-'r<s
Z=_'a
Development
Abandoned
241
U7,a
V:a:e, rje^or Si:ut-in
Z-03
Aoardcned
Z-13A
Development
Oil Producer Gas lift
2-32
5e-MrP,-S,t
AVndPrea
Z-03A
:efe.:Pre:--t
0.1
Z-13APB3
Development
?rigged Balk Tt, aeLri;
Z-32A
Dave'aPmen:
Abandc•,ed
Z-04
:.a *Mane.^
Abatdcnez
2-14
Development
Abasderec
2-32B
De-:e!:pms!:t
Aear.:oned
Z_W
:;-Eit}meat
C!Prcdu:e^Gasiift
Z-14A
5er:ce
Abe^doa:
Z-32BLi
3e;relap-.art
Azar, p07e_,
2-05
Dere,opmert
A:arc.r '_
Z-143
Development
Gil Pmd_cer Gasr't
Z-320PBL
se-'.
F•:s3e1 Bars FPr Re+ :I
YEA
Dere:ap:neri
-_IPr.d wS. 'n
Z-25
Development
Abandoned
Z-328PBZ
Dere:oprre^:
F::gged sack For Kelm:
2-05APB1
^eve:epma:t
':_nei Sa:k F,r Re:r,.
Z-15A
Devdopmerd
Oil Producer Gas Lltt
Z-32C
2ere:»men..t
C', :juoer SF�t-'r
Z-06
:e. elsp:Fert
A_aruted
:-150,9111
Development
P;-._ega? Ee:e For Reir'i
Z-33
r-weica,e",
Aharlcne'_'
Z-}�',
`e:eorrer•
Oil Producer Gas Lift
2-15APB1
Development
P': Uec Bask FCC TV_ i-.
i-33A
Srrrx
water injedor ln'.ecting
Z-^
:cve,2r . t
Aba•,c:red
2-16
Development
Abandoned
Z-34
Derei:p,•'e-t
071 Prad�ce Co Lit
Z__
:e r i,^en:
Abandored
2-16A
Development
O+I Prd,cerGas-M
Z-35
X e:car-:ert
CNI Pm'Sax: SY,:rt-:r
Z-078
Oil Producer Stag -In
Z-17
De!el.p:ner:
Abandoned
Z-35M
Dzpv..eot
pugged Eack For 4edrlii
Z-0B
:e: e..pTe;:
L'car.Cered
2-17A
Demcomert
D?
Z-38
De. e:Pn er.1.-
Ill Produzeruas Lilt
ZA3A
:e-ee.2emert
swTeude'd
7-17APB3
`e:re.c7'pen:
P!.ise_Be:k F:r Fec:::i
:-5pFs1
Dere__pr.:e+:
n.fasged Back For Redrill
Z-09
:=_vebr^art
Abandoned
2-28
Ser.!ce
rrate:!-je=- je:.7g
Z-39
De�_e.cr:vert
Abandoned
Z-09A
:ere.cL'^e-'
Z-19
=eve;r:-ant
4:erv-es'
Z-39A
Sever:,^^^ct
pi; Prcdu:er 5i+it-Ir
Z-20
:.e, a:nF.-e-:
r.he':era_
Z19A
Se,1011
240
Z,9. e`.p--eirt
rill ➢rcdu,ce• u35«ift
Z-1W
--.e.:F e:-t
Oil Prod Ken Gas lift
Z-211
:e+e:c cre,t
Cr!7.rd.::e-5- •:'
:-45
.are':,re--
Abandoned
Z-Silt
Z.21
Development
Aas:d:-ed
Z-454
Oere:p-'^ert
C117rcdDce:Sn;,K-.ir
r-M
Se-.':e
Water Injector injecting
Z-210
Service
ACM. A^.7 Scs-je=
_5
:e:e:p�e:t
vd P:DI'im 3nst-In
Z-}D2n51
Service
Plugged Back For Redriil
2-210PB1
Service
:`_aseb Sa:k Ta, ve:'.+:
Zfrl
'fie.:fv-ert
,«•cdwcer S>::at-!r
Z103
5e�r:e
Water Injector injecting
Z-21A
neve]oanenf
O:'PMb,,:a 3^ 'r
Z-61➢B3
:e,•e::p-e::
Plugged 3au Fcr3ed-:tl
5e�',:e
Mailed Back For Rednil
Z-22
Development
,^-.^a^. a:e:
Z-5
2s'e.=a-:
-.I F.'Cdvicer Gss Lift
Z-65
:2.2oyrcnc
Oil Producer Gestift
-_-c_
:a:e.:.,-e^:
Plugged Back Tor Redrlll
Z-66
Oil Predu,;u5hut-in
Z-6RE1
_nr:_T:e-:
Plugged Back For Rednll
2-67
Se-a::e
Water]njectorl jering
Z-69
:e•.a2pTe+:
suspended
Z-GMI
:e: elP,^.-e':
Plugged Back For ReeAll
Z459
:e�ercre::
of Producer Shut-in
Z-70
:e:e-cc^ex
sjsce,:e:
Z-71
De;e.or-'-per'
2:1P:_d_:e:5-L'-:r.
Exemption for Freshwater Aquifers (20 AAC 25.283, a, 3-4)
Well Z-20 is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated
July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas
Conservation Commission to issue an order exempting those portions of all aquifers lying directly
below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection
activities. Findings 1-4 state:
1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad
areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water.
2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad
areas of the Prudhoe Bay Unit are situated at a depth and location the makes recovery of
water for drinking water purposes economically impracticable.
3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad
areas of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000
mg/1 or more.
4- By letter of July 1, 19B6, EPA -Region 10 advises that the aquifers occurring beneath the
Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is
considered to be a minor exemption and a non -substantial program revision not requiring
notice in the Federal Registrar.
Per the above findings, "Those portions of freshwater aquifers lying directly below the Western
Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under
20 AC 25.440." thus allowing BP exemption from 20 AAC 25.283, a, 3-4 which requires
identification of freshwater aquifers and establishing a plan for basewater sampling.
Detailed Casing and Cement Information (20 AAC 25.283, a, 5-6)
Drill 17-1/2" hole to 2672' and cement 13-3/8" L-80 Buttress casing to surface with 3580 cu ft
Permafrost.
Directionaily drill 12-1/4 r hole to the 9-5/8" casing point above the Ivishak SS. Run 9-5/8" 474 L-80
buttress/NSCC casing to within 5' of 12-1/4" TD and cement in two stages with 2243 cu ft of class G.
Directionally drill 8-1/2" hole to TF. Run 7" liner from TD to —250' within the 9-5/8" casing shoe and
cement with 354 cu ft class G.
Clean out to 7" float equipment. Change over to 9.4 ppg filtered NaCl brine completion fluid and test
casing and lap to 3000 psi.
Perforate then run upper completion.
Please see completion schematic
Pressure Test Information (20 AAC 25.283, a, 7)
Prior to fracing operations, as part of the prep work, the tubing will be pressure tested to 4000 psi
and IA will be pressure tested to 3500 psi per the pre/post frac procedure included.
Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 81
NIA 1J4•A11= M:Xvor
;ACRIAIM=
_ BAKM
BF. 6-EV =
55.9T
�[Md■mlfU"
f110
DutunTYb-
_...NW55
1G`CDNGUi:TOR 11CP
! 3.716• C9G.6d{. L-60 917rf, o * i2,4t5•
[M1nMnarn 1D � 3.726" � '173Et7'
44-1/2" OTIS XN NIPPLE )
17 = 3A59'
70POp 7` LNR
F97E 0R0t7 NSL%fAkRY
RE F LCG: BHCS CN 1010W81 CET ON 10/2M
ANGLEAT TOP R3IF: 37" Q 11170
Naga: Rafer 10Pmdn8on DE for Wmt16aE parf data _
S� SkF P11H1VAL0. � SE#Or 94Z
2.7W
S
11156.11100
0
08117169
2-70
6
11165 - 11170
O
0611 T,1i19
2-7W
6
11170-11faO
O
010"
2-70
6
11190 112M
O
0(1113/01
2-7M•
0
11224 - 11239
(]
02*&&W
2.fir
4
11250,11200
S
Obx) 190
10131R0
5'
6
11277 - 11297
O
11118W
2-7fir
4
11300- 11310
S
05M&W
10131191E
2-7AS'
A
11310 -11320
5
111Oe168
101131180
27Ar
6
1I=-1ISM
S
i?jMA8
IQGI 90
3-30
4
11328 - I I=
Q
031.10191
5'
8
11338-11358
0
11116W
v
6 1
11335 - 11358
0
1 the 0
2 I
Un1r N016C
PRO PO SRID, RN Q
NFOPLE
GAS LFT Mi4 NDRELS
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i1fiO4` 5-ir.� wvs�waw+•acr�s.naai,�a¢3,8T5'�
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51502' 4-1/C D7[f )1N � D s 7:775•--
y „�11Z07' A-t1iYYlE�+_oT 5455'
118013• Li Ml) TI LOKI(2:11071�7l�
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F€N BY
CC&V0E F 5
641E i fCV EFY
flJhGran
10M46t
A1aD12
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A1IDP9i1 {Oef17![1B}
119f1F4O
me
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11 IARIPJC
GLY CJO 05wM1)
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Me
F11M0
13 Ol1P3C
TR79ECO(4VIN13)
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PE3+lrri' Ne: ' 4 e81000
AR No: W4Q9-21659-W
SEC 19. 71 iK Fi X 9e4' F W 8 ZOE16' FW
EFPE1rplwedw (A 41)
Name/Size
Weight
Grade
ID
Burst, psi
Collapse, psi
9-5/8" Prodiction Casing
47#
L-80
80681
6871
4760
7" Production Liner
26#
L-80
6.267"
7240
5410
4-1/2" Production tbg
12.6#
L-80
3.958"
8430
7500
Wellhead:
McEvoy manufactured wellhead, rated to 5000 psi.
Tree: 4-1/16" 5,000psi
Tubing head adaptor: 11 " 5,000psi x 4-1/16" 6,500psi
Tubing Spool: 11 " 5,000psi w/ 2-1116" side outlets
Casing Spool: 11 " 5,000psi w12-1116" side outlets
Geological Frac Information 120 AAC 25.283, a, 9)
L}tl,,Qlogic Desc.
Sur#a.a
TVDSS, top
TVDSS, 6t3n
ND Thickness
MD, lmp
MD, btnn
MDThickness
=st. =.ac Pressure
Shale
8016
W30
0.72
Shale
T +-3
-.tea=,
-561
16
9030
8053
v,
39
8053
3109
56
E"
C �g;e
YLEI
N/A
N/A
$1D4
I N/A
N/A
7
Location, Orientation and a Report on Mechanical Condition of Each Well that may Transect
Confining Zone (20 AAC 25.283, a, 10)
TPA 9-t0 fte iJig35: wsx�.c .sPL''2:' lA�I '=V
1-eet 1 + Y-
i Z-20 Free Location
Fautt Throw (ft)
X TKUP
0-10
— Z-20 Frac Half Lengths
11 - 20
Z 20 - OeYiatcn SurYey
• 21 - 30
— Weis within 112 mile of Z-20 Production Interval
• 31 - 50
Z-20 1a2 Mile Buffer
•
=_-20 Production Interval V2 Mile 5utfer
• 101 -323
TKUP fautt Polygons with fault number
LLLBP teases
ENV
N
N
N
w
„
N
N
N
N
N
N
N
r N+
N
1�i
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w
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M
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7
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Location of, Orientation of, and Geological data for each known or suspected fault. (20 AAC
25.283, a,11)
nLaa�asa
J�J
BP's technical analysis based on seismic, well, and other subsurface information available indicates
that there are five mapped faults that transect the Kuparuk interval and enter the confining zone
within the 'h mile radius of the production and confining zone trajectory for Z-20. Fracture gradients
within the confining zone (Kalubik and HRZ) and will not be exceeded during fracture stimulation and
would therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are
predominantly shale, with some silts with an estimated fracture pressure of —13.5 ppg. No faults
were crossed while drilling Z-20.
Fault #1-6 intersect the production interval and confining zone within the 'h mile radius. Their
displacements, sense of throw and zone in which they terminate upwards in are given below.
Faults
Throw
Upward Fault Termination Zone
Fault #1
60' DTW
Colville
Fault #2
30'DTE
HRZ
Fault #3
110' DTS
Colville
Fault #4
75' DTN
Colville
Fault #5
15' DTE
HRZ
The drilling inclination through the Kuparuk is —46 degrees from vertical, at an azimuth of —83
degrees. The closest point of entry for the frac is 580 feet away from the nearest fault (fault 1) in the
Kuparuk. The primary horizontal stress direction in this area is 30 degrees W of N, and the fault is due
east of the well (see plat 2 for fault, frac orientation, and frac half length). The frac will propagate
approximately perpendicular to the wellbore and nearly parallel to nearby faults.
Summary Hydraulic Fracture Program (20 AAC 25.283, a,12)
(Detailed Program and Pump Schedule included)
Maximum Anticipated Treating Pressure: 3500 psi
Maximum Allowable Treating Pressure: 4500 psi
Anticipated half length: 250'
Anticipated height growth: 90'
Each frac will initiate at their corresponding perforations. The perforations are located at:
Frac Stage MD, feet TVD, feet
1 8055'-8105' 6612'-6646'
Estimated TVD Top and Bottom of Frac: 6608'-6670'
Estimated MD Top and Bottom of Frac: 8050'-8140'
The above frac dimensions were calculated using modeling software.
Surface pressure is calculated based on a closure pressure of -0.62 psi/ft or -2700 psi, this
combined with the anticipated net pressure to be built, hydrostatics and the friction gives a surface
pressure of 2500 psi at the time of flush.
The frac height is primarily based on closure pressure differences between the confining shale layers
and the unconfined sandstone reservoir. Average confining layer stress is anticipated to be -0.7
psi/ft.
Half length is based on confining layer stress as well as leak -off and formation modulus. Given the
values, the above half lengths are calculated.
Pressure Test Information (20 AAC 25.283, a, 7)
Per the frac program, the both the tubing and the IA will be pressure tested. The IA will be tested to
3500 psi and the tubing will be tested to 4000 psi.
PRV setting procedures and annulus monitoring:
Maximum Allowable Treating Pressure: 4500 psi
Stagger Pump Kickouts between: 4050 psi and 4250 psi (90% to 95% of MATP)
Global Kickout:
4250 psi (95% of MATP)
IA pop -off set pressure: 2600 psi (75% of MIT -IA)
Treating line test pressure:
Sand Reouirement
6000
90,000# 16-20 CarboLite, 50,000# 16-20
CarboBOND
Minimum Water Requirement 1500 bbls (pump schedule: 1063 bbls)
IA Hold Pressure
OA
2400 psi (IA pop -off @ 2600 psi)
Monitor and maintain open to atmosphere
There are three overpressure devices that protect the surface equipment and the wellbore from
overpressure. Each individual frac pump has an electronic kickout that will kick the pumps into neutral
as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are set
between 90% and 95% of the maximum allowable treating pressure. There is the primary pressure
transducer in the treating line that will trigger a global kickout which will kick all the pumps into
neutral. Finally, there is a manual kickout that is controlled from the frac van. All three of these
shutdown systems will be individually tested prior to high pressure pumping operations.
Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van.
Irrg�x
r Z-20 Rig Up
_� _I
J
Chemical Disclosure (20 AAC 25.283, a, 12)
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Wellwork Procedure Request
To:
Date:
4/25/2019
VER1
AFE:
From:
David Wages
[OR:
565
Est. Cost:
sow
Subject:
Z-20 - Pre/Post Frac Procedure
Please perform the following steps
1.
W
Drop B&R, Set Packer, Circ Packer Fluid and freeze protect
2
S
Drift, Install pluglcatcher in XN, Pull LGLVs, Install Dummy valves 2-5, load IA,
dummy station 1, MIT-T, MIT -IA, pull plug/catcher
2.
F
Assist SL MITs
3.
F
Hydraulic Fracture Treatment
3.
CP
Contingent FCO
4.
S
D&T, Install GI -Vs
5.
C
Post frac FCO
6.
T
Post frac flowback
Current Status:
Minimum ID:
Max Deviation:
Tbg Tail Deviation:
Last TD Tag:
Last Downhole Op:
SBHP/SBHT:
Latest H2S:
Program Contacts
Operable
3.725" at @ -8, 000 MD
-50 deg at 5300'MD
-46 deg at 6800' MD
Rig workover
Rig Workover
NIA
32 ppm, 112017
4-112" XN-Nipple
Contact
Phone - Work
Phone - Mobile
Interventions Engineer
David Wages
907-564-5669
713-380-9836
Pad Engineer
Cale Peru
907-564-4522
832-316-5774
Page 1 1 of 9
Well Summary:
The lvishak interval has no remaining value and has been shut to since ,January 2017 due to
uncompetitive rates (single -digit IOR when it's online). The Kuparuk penetration of Z-20 is in an ideal
location for offtake, so this is an attractive recomplete candidate. This is already a gas -lifted producer, so
no surface piping work is required. All Kuparuk vertical wells are fraded, so this well will need a post -rig
frac to increase productivity and ensure competitive rates.
History:
11/2018: Set MCX
11/2018: Schmoo-B-Gone
1/2017: Change MCX
812016: Change MCX
Objectives:
* Frac and pop Z-20
1.1 Critical Issues:
Latest MIT-T: 5/22/2011: to 2500 psi
Latest MIT -IA: 511212015to 3750 psi
Latest Caliper: NIA, tubing swap during workover
1.2 Pressure Prediction:
Reservoir Pressure
Kuparuk Offset pressures: 2699 psi and 2486 psi
Page 12 of 9
Procedure
1. Wellhead- Pull TWC, Circ Annulus fluid, Set packer and MIT-T, MIT -IA
a. Have Wellhead crew service the wellhead and tree.
b. Pressure test tree to 5000 psi high
c. Pull TWC
d. Rig up to reverse circulate down the IA valve
e. Pump heated (100-120 deg F) seawater wl MI KI-3869 corrosion inhibitor down the IA
taking returns up the tubing.
i. Total round trip volume: 550 bbls
ii. Water vol req: -600 bbls
f. Drop B&R
i. Ensure B&R lands at XN profile, 4500 psi is over the pressure rating of the
standard X-lock
g. Pressure up on the tubing to set the packer.
h. Test the tubing to 4,000 psi for 30 charted minutes. Bleed tubing pressure off to 2,000-psi
and shut in. Test the IA to 3,500-psi for 30 charted minutes.
i. Max Applied on tubing: 4500 psi
ii. Max applied to IA: 3750
iii. AOGCC witnessed MITs, ensure 24 notice is given, Form 10-426 required
i. Bleed off tubing pressure to shear DCK valve. Pump both ways through valve to confirm
shear.
L Freeze Protect wl Dead Crude vol req: 175 bbls (Assumes GLM @ 2500)
Fullbore-Assist WH with circ and MITs
2. Slickline- Drift, Pull B&R, Dummy GLMs, Pull RHC
a. If necessary, have siickline set lock in XN for MITs and have fullbore assist with MITs after
lock changed out.
3. Valveshop- RU Treesaver
4. Special Projects- Hydraulic fracture treatment
a. Frac well per pump schedule
Pressure testing
Maximum Allowable Treating
Pressure:
Stagger Pump Kickouts between:
Global Kickout
IA pop -off set pressure
Treating Line Test Pressure
Page 13 of 9
4500 osi
4050 psi and 4250 psi (90% to 95% of MATP)
4260 psi (95% of MATP)
2600 psi (75% of MIT -[A)
5500 [)Si
Sand Requirement
Minimum Water Requirement
IA Hold Pressure
OA
90,000# 16-20 Carbolite, 50,000# 16-20
CarboBOND
1500 bbls (pump schedule: 1063 bbls) _
2400 psi IA pop -off @ 2600psi)
Monitor and maintain open to atmosphere
5. ValveShop-RD Treesaver
6. Pending Coil- Contingent FCO
a. See Appendix A - CT Screenout FCO Procedure
7. Slickline- D&T, Install Generic LGLVs (Deep design if possible)
a. D&T
b. Install Generic LGLVs (Deep design if possible)
i. This step can be moved to after the post frac FCOlmillout if sand top is expected
to be above the perforations or if a hard screenout occurred.
B. Flowback
a. See Appendix B - Test Separator Additional Flowback Procedure
9. Pending Coil- Contingent FCO
a. See Appendix A - CT Screenout FCO Procedure
Page 14of9
Appendix A - CT Screenout FCOIMillout Procedure
i. This is a generic FCOlmillout procedure for a post screenout FCO. Specific info
such as amount of proppant left in tubing and estimated sand top will not be known
until after the event.
ii. The objective of this procedure is to get the well cleaned to continue frac
operations or to prep the well for POP.
iii. Recommend reviewing PE Manual section for Coiled Tubing Fill Cleanouts for
specifics on reversing rates, speeds and CT loading.
Planned Procedure
b. MIRU CT
c. MU BHA.
d. RIH down to estimated sand top and begin cleaning out with slick 1% KCL.
e. Continue down to —8000' CTMD. At this point we are 100' above the uppermost
perforations. Ensure CT is clean as it is expected that returns will begin to fall off as the
nozzle nears the sleeve. If returns begin to fall off, reducing BHP by lowering rate may
keep returns at a manageable level.
f. Slowly continue to clean out until returns fall off to —80%. If returns are still good even
after the nozzle is past the sleeve (not likely but possible), continue to clean out to IBP
i. If returns are too low, it may be necessary to pull the IBP after LGLVs are installed.
g. Once IBP is clear of sand, RIH and pull IBP.
h. FP to 2500'.
i. Pump a gel pill at surface out to the tanks to ensure CT is clean if necessary.
i. RDMO.
Page 15of9
Appendix B - Test Separator Additional Flowback Procedure
9. MIRU ASRC. RU equipment to in a manner that allows CT to RU if an additional FCO is
necessary.
2. POP the well to ASRC at minimum choke. Flow the initial returns to the flowline as long as the
shake -outs meet the returned fluid/solids management guidelines.
3. Limit flow to 500 bpd
4. If solids are < 1 %, increase the production rate to 1000 BLPD.
5. Flow bottoms up and sample for solids production. If solids are still below 1 %, allow well to flow to
1500 BLPD. Flow bottoms up and sample for solids production. If solids are still below 1 %
continue to increase the flow rate in 500 BPD increments. The objective is to achieve maximum
drawdown. Watch returns and do not continue to open choke if solids > 1 %; allow well clean up
before choke is opened further.
6. Once at FOC, stabilize the well for 4 hrs. Obtain a 3 hr purge, 8 hr welltest.
Page 16 of 9
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PRLC HOE SAY LUT
FERmrr No: °1sel000
APIM' 5&W9-215590Q
T111'i R12- 984' RC & 2W PWVL
HP BgWwafto [Alaka}
TubeMove Analysis:
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MIT -IA: 3750 psi
Frac SO: 4500 psi on tubing, 2400 psi on IA, 12.7 ppg fluid
Page 19 of 9
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