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Home My WebLink About2025-12-16_325-7611. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Well Clean Up 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD:Junk (MD): 21,148'N/A Casing Collapse Conductor Surface 2,260 Intermediate 4,750 Tieback 4,750 Production 9,210 Liner 9,210 Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 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 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:scott.leahy@santos.com Contact Phone: 907-330-4595 Authorized Title: Completions Specialist Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 2,313' 4-1/2" 21,148'9,496' 4-1/2" 12.6ppf 20"x34" 13-3/8" 128' 9-5/8"9,106' 2,883' 6,870 5,020 128' 2,384' 128' 2,883' 11,824' 4,044' Size Proposed Pools: P110S TVD Burst 11,690 Pikka Nanushuk Oil Pool N/A MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 393016, 393015, 391455, 393011, 391454 225-101 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20926-00-00 Oil Search Alaska, LLC Pikka NDBi-006 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): See attached packer report Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Leahy 11,690' 4-1/2" 11,690' 4,014' 11,590 1/7/2026 4,093' See attached packer report Perforation Depth MD (ft): 2,718' Tieback 2,718' 6,870 4,093 21,132 4,093 Length m n P s 2 6 5 6 t t p N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov e foregoing is true and th 12/16/2025 325-761 Page 1 of 1 Packer Set Depths - NDBi-006 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole ZXtreme Liner Top Packer W/HRD-E Profile 11,677.3 4,011.5 Original Hole HES Zoneguard OH Packer #25 11,945.6 4,064.0 Original Hole HES Zoneguard OH Packer #24 12,013.0 4,073.0 Original Hole HES Zoneguard OH Packer #23 12,556.1 4,084.3 Original Hole HES Zoneguard OH Packer #22 13,016.5 4,084.9 Original Hole HES Zoneguard OH Packer #21 13,125.1 4,085.2 Original Hole HES Zoneguard OH Packer #20 13,682.3 4,086.7 Original Hole HES Zoneguard OH Packer #19 13,832.5 4,087.2 Original Hole HES Zoneguard OH Packer #18 14,415.8 4,088.6 Original Hole HES Zoneguard OH Packer #17 14,524.1 4,088.8 Original Hole HES Zoneguard OH Packer #16 14,940.3 4,089.9 Original Hole HES Zoneguard OH Packer #15 15,131.3 4,089.9 Original Hole HES Zoneguard OH Packer #14 15,634.6 4,092.1 Original Hole HES Zoneguard OH Packer #13 16,094.4 4,094.5 Original Hole HES Zoneguard OH Packer #12 16,633.4 4,096.8 Original Hole HES Zoneguard OH Packer #11 17,133.0 4,098.8 Original Hole HES Zoneguard OH Packer #10 17,634.3 4,100.1 Original Hole HES Zoneguard OH Packer #9 18,131.8 4,100.3 Original Hole HES Zoneguard OH Packer #8 18,632.1 4,101.3 Original Hole HES Zoneguard OH Packer #7 19,176.1 4,102.6 Original Hole HES Zoneguard OH Packer #6 19,636.9 4,103.7 Original Hole HES Zoneguard OH Packer #5 20,136.6 4,100.8 Original Hole HES Zoneguard OH Packer #4 20,245.9 4,097.2 Original Hole HES Zoneguard OH Packer #3 20,682.6 4,094.2 Original Hole HES Zoneguard OH Packer #2 20,789.6 4,093.2 Original Hole HES Zoneguard OH Packer #1 21,045.1 4,092.7 Page 1 of 21 NDBi-006 Sundry Application Requirements 1. Affidavit of Notice – Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius – Attachment B 3. Identification of freshwater aquifers within ½ mile radius – There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBDi-006. At the NDBi-006 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifers are located at the NDBi-006 location. Wells within the Pikka unit (see table below) have measured water salinity values >10,000 ppm and are not considered freshwater. 4. Plan for freshwater sampling – There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information – Attachment C 6. Assessment of casing and cementing operations – Attachment C 7. Casing and tubing pressure test information – Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head – Attachments D and I 9. Lithological and geological descriptions of each zone – Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 977 feet (ft) total vertical depth subsea (TVDSS)/ 977 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 977 to 2,376 ft TVDSS/1,399 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelf setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,376 to 3,193 ft TVDSS/ 817 ft thick Hydrocarbon Zone: 2,754 to 3,193 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,193 to 3,669 ft TVDSS/ 476 ft thick Lithological Description: The Seabee Fm in the Pikka Unit area consists predominantly of claystone, shale, and volcanic tuff deposited in a deep marine setting. The base of the Seabee Fm grades into a condensed organic shale and provides an excellent seal and confining interval above the Nanushuk Fm reservoirs and also acts as a thick second overlying confining unit. Nanushuk Formation Depth/Thickness: 3,669 to 4,623 ft TVDSS/ 954 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Lower Confining Zone Name: Torok Formation Depth/Thickness: 4,623 to 5,522 ft TVDSS/899 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is composed primarily of shale (Hue Shale) with some thin interbedded siltstones. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. 10.Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) MAWP (psi) Stages 1-15 3,800 4,100 7,000 6,600 9,200 8,800 Note: x GORV and Pump trips to be set to 8,700 psi to open Toe Sleeve. x GORV may be increased to 8,000 psi and pump trips to 7,600 psi should treating pressures be higher than expected. Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 21,014 4,093 192 368 30 4,372 8 2 19,862 4,104 221 259 25 3,458 8 3 19,360 4,103 221 260 25 3,376 8 4 18,857 4,102 225 286 30 3,966 8 5 18,358 4,101 233 318 40 5,498 8 6 17,858 4,100 234 325 40 5,385 8 7 17,358 4,100 260 283 40 5,262 8 8 16,858 4,098 233 338 40 5,545 10 9 16,360 4,096 224 271 40 5,469 10 10 15,859 4,093 233 329 40 5,256 10 11 15,357 4,091 267 307 40 5,105 10 12 14,749 4,089 236 368 40 4,461 8 13 14,098 4,088 244 334 40 4,637 10 14 12,782 4,085 242 342 40 3,903 8 15 12,238 4,084 244 356 40 4,087 10 11.Mechanical condition of wells transecting the confining zones –NDB-010 is within 1/2-mile radius of NDBi-006. Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones: There are 5 known faults within the ½ mile radius of NDBi-006. Fault locations along the lateral are noted in Attachment J. Please See Attachment B. Note: Fractures are estimated to propagate along wellbore longitudinally at ~330o. 13.Detailed proposed fracturing program – Attachments F & K 14.Well Clean Up procedure – Attachment G Section (b) Casing Pressure Test – We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test – Attachment H Section (d) Pressure Relieve Valve – Attachment I Proposed Wellbore Schematic – Attachment J Attachment A Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Avenue Anchorage, Alaska 99501 (T) +1 907 375 4642 —santos.com 1/2 'HFHPEHU UG, 2025 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLC’s Sundry Application for a Fracture Stimulation for the Proposed NDBL-0Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDBL-0 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC 601 W 5th Ave Anchorage, AK 99501 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDBL-0well trajectory and fracture stimulation. Please contact Tim Jones should you require additional information. Sincerely, Jacob Owens Commercial Analyst Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC Sincerely, Jacob Owens 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL 601 W 5th Ave Anchorage, AK 99501 Repsol E&P USA LLC CERTIFIED MAIL 2455 Technology Forest Blvd. The Woodlands, TX 77381 81( 81(81( 81(81( 81( 81( 81( 81( 81( 81( 81(81(81( 81( 81( 81( 81( 81( 81( ADL 392963 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392984 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393021 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 19.22% DNR - 80.78% ADL 393019 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393018 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 29.67% DNR - 70.33% ADL 393020 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393015 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 31.69% DNR - 68.31% ADL 393017 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393016 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 393006 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 28.11% DNR - 71.89% ADL 393007 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 34.35% DNR - 65.65% ADL 393008 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 28.29% DNR - 71.7 ADL 391322 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 28.25% DNR - 71.7 ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391453 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 22.43% DNR - 77.5 ADL 391454 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 36.61% DNR - 63.39% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% ADL 393009 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.59% DNR - 59.41% ADL 393011 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 25.71% DNR - 74.29% ADL 393010 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 38.54% DNR - 61.46% OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD 0.5-MILE BUFFER NDBI-006 BOTTOM HOLE NDBI-006 SURFACE LOCATION PRODUCTION INTERVAL SANTOS LEASES NDBI-006 SECTIONS DATE: 12/3/2025. By: JB 0 1,000 2,000 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDBi006_well_ownership Map Frame: AP-DRL-PE-M_NDBi-006_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 200 400 Meters PIKKA DEVELOPMENT NDBi-006 WELL AREA Attachment B Fa u l t N a m e MD Es t . T h r o w i n NT 3 R e s e r v o i r Co n f i d e n c e Vi s i b l e o n se i s m i c Di p Di r e c t i o n Co m m e n t s SM _ N D B _ 0 1 8 11 6 0 2 99 f t Hi g h Ye s 1 1 0 Fa u l t l o c a t i o n p i c k e d b a s e d o n m i s s i n g se c t i o n o n L W D l o g s b u t n o o b v i o u s dr i l l i n g p a r a m e t e r i m p a c t . F a u l t t i p te r m i n a t e s w i t h i n u p p e r S e a b e e . F a u l t in t e r s e c t s t h e w e l l b o r e i n t h e in t e r m e d i a t e h o l e s e c t i o n a b o v e t h e re s e r v o i r i n t h e N T 4 o r u p p e r N T 3 . F a u l t is a d e q u a t e l y i s o l a t e d i n i n t e r m e d i a t e ho l e s e c t i o n a n d i s n o t c o n s i d e r e d a ri s k f o r f r a c . o r c o n t a i n m e n t . F a u l t i s 58 0 ’ a w a y f r o m S t a g e 1 5 Me r g e d _ S M _ N D B _0 1 3 _ 0 1 9 _ 0 2 5 1 4 7 9 0 0- 3 0 ’ f t Lo w Ye s 26 5 Lo w c o n f i d e n c e f a u l t . I m a g e l o g de t e c t e d d i p c h a n g e b u t n o c l e a r f a u l t pl a n e . S o m e d i s p l a c e m e n t i s v i s i b l e i n se i s m i c a r o u n d N T 3 ; n o d i s p l a c e m e n t in u p p e r N a n u s h u k . D i s p l a c e m e n t be l o w N T 3 u n c e r t a i n d u e t o l o w re f l e c t i v i t y . SM _ N D B _ 0 2 1 20 5 4 7 50 - 8 0 f t Hi g h Ye s 9 5 Se i s m i c i n t e r p r e t a t i o n i n d i c a t e s te r m i n a t i o n w i t h i n M i d d l e S c h r a d e r Bl u f f F m . SM _ N D B _ 0 2 5 Do e s n o t in t e r s e c t we l l b o r e < 3 0 f t Hi g h Ye s 2 5 0 Te r m i n a t e s w i t h i n N a n u s h u k a n d i s co n t a i n e d w i t h i n p o o l . N o t c o n s i d e r e d a r i s k f o r c o n t a i n m e n t . SM _ N D B _ 0 0 5 Do e s n o t in t e r s e c t we l l b o r e 70 f t Hi g h Ye s 1 1 5 Te r m i n a t e s i n N a n u s h u k a n d i s w i t h i n po o l . N o t c o n s i d e r e d a r i s k f o r co n t a i n m e n t . ND B i - 0 0 6 F a u l t S u m m a r y SM _ N D B _ 0 1 8 SM _ N D B _ 9 9 9 SM _ N D B _ 0 2 3 SM _ N D B _ 0 2 5 SM _ N D B _ 0 2 1 NT 3 T o p Re s e r v o i r ND B P a d Ma p s h o w i n g t h e l o c a t i o n a n d o r i e n t a t i o n o f g e o l o g i c d a t a f o r e a ch p r o g n o s e d f a u l t w i t h i n o n e q u ar t e r a n d o n e - h a l f m i l e r a d i u s of w e l l b o r e t r a j e c t o r y . Fa u l t s h a v e b e e n n a m e d a n d m a p p e d f r o m s e i s m i c . SM _ N D B _ 0 0 5 Me r g e d _ S M _ N D B _ 0 1 3 _ 0 1 9 _ 0 2 5 WE L L N A M E S T A T U S C a s i n g S i z e To p o f O i l P o o l C o n f i n i n g La y e r ( M D ) To p o f O i l P o o l C o n f i n i n g La y e r ( T V D S S ) To p o f Ce m e n t (M D ) To p o f C e m e n t (T V D S S ) To p o f C e m e n t De t e r m i n e d By Re s e r v o i r S t a t u s Z o n a l I s o l a t i o n Ce m e n t O p e r a t i o n s S u m m a r y Me c h a n i c a l I n t e g r i t y ND B - 0 1 0 A C T I V E 9 - 5 / 8 " 4 7 p p f 8 , 1 8 8 ' ( N a n u s h u k ) 3 , 7 1 7 ' ( N a n u s h u k ) 7 , 1 7 0 ' ' 3 , 4 6 2 . 4 ' l o g o p e n h o l e l i n e r f o r p r o d u c t i o n TO C 8 , 1 8 8 ' M D ' & p a c k e r @ 9 , 4 6 0 ' 9- 5 / 8 ” 1 s t S t a g e : -T h e B a k e r T O C l o g i n d i c a t e s t h e r e i s g o o d c e m e n t c o v e r a g e a c r o s s a n d a b o v e t h e U p p e r N a n u s h u k f o r m a t i o n s . S u m m a r y a s f o l l o w s : oT o p o f C e m e n t i s 7 , 1 7 0 ’ M D / 3 , 5 3 2 ’ T V D . 1 , 0 1 8 ’ M D / 2 5 5 ’ T V D a b o v e t h e T o p N a n u s h u k oT o p o f N a n u s h u k i s 8 , 1 8 8 ’ M D / 3 , 7 8 7 ’ T V D 9- 5 / 8 ” 2 n d S t a g e : -F o r t h e 2 n d s t a g e o f t h e c e m e n t j o b , b a s e d o n j o b e x e c u t i o n r e s u l t s , c e m e n t i s o l a t i o n w a s a c h i e v e d a c r o s s t h e h y d r o c a r b o n z o n e w i t h i n t h e u p p e r T u l u v a k fo r m a t i o n . 8/ 1 6 / 2 0 2 5 , 9 - 5 / 8 " c a s i n g p r e s s u r e t e s t e d t o 4 , 3 0 0 ps i f o r 3 0 m i n . Attachment C 9-5/8” 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensil e (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design 9-5/8” Intermediate 1 Liner x 9-5/8” Liner Top at 2,720” MD x 13-3/8” shoe at 2,883’ MD x 9-5/8” Archer 1st Cflex Mechanical Stage tool: 5,305’ MD x 9-5/8” Archer 2nd Cflex Mechanical Stage tool: 10,349’ MD (Note 2 nd CFLEX was run to give best possible chance for cement isolation given the losses associated with fault at 11,600’) x 9-5/8” Shoe at 11,828’ MD Geology x Top of Tuluvak TS 790 formation at 5,253 MD. x Top of the Nanushuk picked at 10,330’ MD. Top significant hydrocarbon in the Nanushuk was is in the NT8 based on relevant offsets Cement Job Planning/Execution Below and noted in attached cementing reports on subsequent pages for a summary of the work performed. 9-5/8” Intermediate Liner: 1st Stage x 1st stage of the cement job planned with 15.3 ppg tail slurry at 30% excess, targeting TOC 10,950’ MD (~26’ MD above NT6). Due to losses encountered with a fault crossing at ~11,600’ MD, the goal of this job was to attempt to cover the loss zone in preparation for the 2nd stage job. x During execution of the 1st stage cement, nearly full losses were encountered throughout the job. An estimated 70 bbls (of 70 bbls cement pumped) was lost after cement exited the shoe. However, some lift pressure was observed, indicating the cement did move up the annulus toward the loss zone. Good/hard cement was encountered in the shoe track and rathole. After drilling out the 9- 5/8” shoe a LOT was conducted to 13.63 ppg. 2nd Stage x 2nd Stage of cement job planned with CFLEX at 10,349’ MD at the Top Nanushuk formation (~19’ MD below Top Nan). Also planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 200’ TVD above the Top Nanushuk (~9335’ MD), for a job volume of ~74 bbls. x After opening the lower CFLEX, severe losses were still encountered, so the decision was made to pump all extra cement on location (total of 172 bbls 15.3ppg tail). x During execution of the 2nd stage cement, minimal returns were noted, but some lift pressure was observed. An estimated 162 bbls (of 172 bbls cement pumped) was lost after cement exited the lower CFLEX tool. 3rd Stage x 3rd Stage of cement job planned with CFLEX ~52’ below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeting TOC at the 9- 5/8” liner top. x During execution of the 3rd stage cement, no losses were encountered during mud conditioning or pumping cement (288 bbls 15.3ppg tail). While displacing cement with OBM, complete losses were encountered after pumping 39 bbls of the 111bbls displacement. Lift pressure was observed prior to losing full returns. After the CFLEX was closed and the LTP set, we circulated off the top of the liner and dumped ~160 bbls of spacer with trace cement and 452 bbls of contaminated interface. An estimated 72 bbls (of 288 bbls cement pumped) was lost after cement exited the upper CFLEX tool. Observations 9-5/8” Intermediate Liner: x For the 1st and 2nd stage of the cement job, Baker TOC log indicates no cement from top Nanushuk (10,330’ MD) to 11,225’ MD. 11,225’ – 11450’ MD contained intervals of partial bond, and Top of good cement was at 11,490’ MD. Cement isolation was achieved across the 9-5/8” shoe. The upper Nanushuk formations across the hydrocarbon-bearing formations (NT4 through NT8) have not been fully covered by cement based on the measured TOC at 11,490’ MD. x For the 3rd stage of the cement job, based on Baker TOC log, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation with many intervals of partial cement bond. Intervals of partial cement bond are above, across, and below the Tuluvak Hydrocarbon bearing formation. As there was insufficient cement coverage across the upper Nanushuk Oil Pool, a variance was submitted by Rob Williams to Bryan McLellan on 12/06/25. Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Surface Casing Cement Surface Casing Cement, Casing, 11/11/2025 00:00 Type Casing Cementing Start Date 11/11/2025 Cementing End Date 11/11/2025 Wellbore Original Hole String Surface Casing, 2,883.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Good lift pressure observed. 189 bbls of cement returns to surface. 108 bbls losses after cement exited the shoe. Comment Cement 13-3/8” surface casing as follows: Hold PJSM with rig & Halliburton crews. -Fill lines with 5 water and pressure test to 2500 psi for 5 minutes - Good test -Drop 1st bottom plug -Pump 80 bbls of 10.5 ppg Tuned Spacer at 3.0 bpm, 195psi. -Release 2nd bottom plug -Pump 440 bbls of 11.0 ppg ArcticCem lead cement at 5 bpm, excess volume 200% (975 sacks, yield 2.535 cu.ft/sk) - Pump 69 bbls of 15.3 ppg Type I/II tail at 5 bpm, excess volume 50% (312 sacks, yield 1.24 cu.ft/sk) -Drop top plug and followed by 20 bbls wash water. -Perform displacement with rig pumps and 9.4 ppg mud - At ~110 bbls into displacement, experienced full packoff at the hanger flutes. Decision to pull hanger up ~6-12". Regained circulation, but unable to land hanger back on the landing ring. - 424 bbls displaced at 1-6 bpm: ICP 475 psi 11% return flow, FCP 700 psi. Bump plug on calculated displacement and pressure up to 1,200 psi. Bleed off and check floats, floats held. - 189 bbls cement to surface. -Total losses from cement exit shoe to cement in place: 108 bbls - CIP at 06:18 hrs. 1, 0.0-2,900.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 2,900.0 Full Return? No Vol Cement Ret (bbl) 189.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 2 Final Pump Pressure (psi) 700.0 Plug Bump Pressure (psi) 1,200.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer (Add 8lb RED DYE to first 20 bbl) Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 2,900.0 Percent Excess Pumped (%) Yield (ft³/sack) 1.82 Mix H20 Ratio (gal/sack) 12.17 Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Lead Fluid Type Lead Fluid Description ArcticCem Lead Amount (sacks) 975 Class Volume Pumped (bbl) 440.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 2,900.0 Percent Excess Pumped (%) 200.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) Density (lb/gal) 11.00 Plastic Viscosity (cP) 15.8 Thickening Time (hr) 22.50 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Tail Fluid Type Tail Fluid Description 15.3ppg Tail Amount (sacks) 312 Class Volume Pumped (bbl) 69.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 2,900.0 Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.59 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 57.8 Thickening Time (hr) 10.80 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Intermediate Casing Cement Stage 1 Intermediate Casing Cement Stage 1, Casing, 11/18/2025 18:30 Type Casing Cementing Start Date 11/18/2025 Cementing End Date 11/19/2025 Wellbore Original Hole String Intermediate Liner, 11,824.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results Logged with Halliburton CAST-M. Logged 1st and 2nd stage cement jobs from 11,798' MD to 9,450' MD. Top of good cement at 11,458' MD with top of fair cement at 11,183' MD. Intermittent areas of poor cement and free pipe from 11.183' MD to 9,450' MD. See Halliburton report for more details. Comment Cement 1st stage 9-5/8" Intermediate liner. - Pump 5 bbls water & pressure test cement lines to 500 psi low 5,000 psi High 5 minutes - Pump 80 bbl 12.5 ppg Tuned Spacer with red dye, Surfactant B and Musol A - (65 gallons each) downhole at 3 bpm with 350 psi, - Release bottom pump down dart, chase with 70 bbls of 15.3 ppg Versacem tail cement type I/II at 3 bpm, 200 psi. - Open hole excess volume 30% - Release top pump down dart - Flush lines with 20 bbl. water to cuttings box - Perform displacement with rig pumps and 11.5 ppg MOBM as follows: - Begin pumping 708 bbls 11.5 ppg OBM at 3 bpm, ICP 316 psi, FCP 422 psi. No measurable returns. - 70 bbls lost after cement exited the shoe. (Bottom pump down dart latch up confirmed at 1,386 psi.) - Pressured up 500 psi over FCP (943 psi) and held 5 min, bled off, checked floats. Floats held. - Total displacement volume 708 bbls (measured by strokes at 96% pump efficiency). CIP @ 00:10hrs. - MOBM losses during cement job –864 bbls 1, 11,183.0-11,824.0ftKB Top Depth (ftKB) 11,183.0 Bottom Depth (ftKB) 11,824.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 400.0 Plug Bump Pressure (psi) 510.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Versacem Tail Fluid Type Versacem Tail Fluid Description Versacem Tail Type I/II Amount (sacks) 317 Class I/II Volume Pumped (bbl) 70.0 Estimated Top (ftKB) 11,183.0 Estimated Bottom Depth (ftKB) 11,824.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 93.0 Thickening Time (hr) 8.50 1st Compressive Strength (psi) 1,000.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Intermediate Casing Cement Stage 2 Intermediate Casing Cement Stage 2, Casing, 11/19/2025 18:00 Type Casing Cementing Start Date 11/19/2025 Cementing End Date 11/19/2025 Wellbore Original Hole String Intermediate Liner, 11,824.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results Logged with Halliburton CAST-M. Logged 1st and 2nd stage cement jobs from 11,798' MD to 9,450' MD. Top of good cement at 11,458' MD with top of fair cement at 11,183' MD. Intermittent areas of poor cement and free pipe from 11.183' MD to 9,450' MD. See Halliburton report for more details. Comment Conduct 2nd stage cementing of 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool as follows: -Fill lines with water and test 1,000 psi low, 4,500 psi high. - Mix and pump 80 bbls of 12.5 ppg Mud Flush at 4 bpm, ICP 550 psi, FCP 425 psi, 55 bbls loss. - Mix and pump 172 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm, ICP 767 psi, Final pump rate 4 bpm, FCP 485 psi. 94 bbls loss. - Total volume pumped 172 bbls cement - Excess Volume 30% - Displace with calculated volume of 233 bbls of 11.5 ppg OBM using rig pumps to Archer stage collar, 203 bbl loss. - Displace cement at 4 bpm, 109 psi ICP, 369 psi FCP with 70 bbls pumped and partial returns, slowed pump to 3 bpm, 369 psi ICP and 447 psi FCP. Maintained 3 bpm to calculated 2,527 calculated strokes, with minimal returns, 233 bbls total displacement to Archer tool. - 162 bbls lost after cement passed through C-Flex tool. - CIP @ 20:52 hrs. 2, 10,349.0-10,349.5ftKB Top Depth (ftKB) 10,349.0 Bottom Depth (ftKB) 10,349.5 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 700.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Tuned Spacer Fluid Type Tuned Spacer Fluid Description Mud Flush Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Versacem Tail Fluid Type Versacem Tail Fluid Description Versacem Tail Type I/II Amount (sacks) 780 Class Type I/II Volume Pumped (bbl) 172.0 Estimated Top (ftKB) 11,183.0 Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 93.0 Thickening Time (hr) 8.50 1st Compressive Strength (psi) 1,000.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Intermediate Casing Cement Stage 3 Intermediate Casing Cement Stage 3, Casing, 11/20/2025 12:30 Type Casing Cementing Start Date 11/20/2025 Cementing End Date 11/20/2025 Wellbore Original Hole String Intermediate Liner, 11,824.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results Logged with Halliburton CAST-M. Logged 3rd stage cement jobs from 6,350' MD to 2,646' MD. Several areas of good cement noted from 2,916'-3,285' MD, 4,125-4,154' MD, and 5,548'-5,603' MD, indicated good isolation above and below the Tuluvak hydrocarbon bearing sands. The remaining interval indicates all fair to poor cement bond classification. See Halliburton report for more details. Comment Conduct 3nd stage cementing of 9-5/8” 47# Intermediate casing by open hole annulus through Archer cementing tool as follows: -Fill lines with Water and test 1,000 psi low, 4,500 psi high. -Mix and pump 80 bbls of 12.5 ppg Mud Flush w/ Red Die at 4 bpm, ICP 340 psi, FCP 308 psi, No Losses. -Mix and pump 80 bbls 13.5 ppg Tuned spacer at 4.2 bpm ICP 328 psi, FCP 248 psi. No losses. -Mix and pump 288 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm, ICP 484 psi, Final pump rate 4 bpm, FCP 610 psi. No Losses. -Displace with calculated volume of 111 bbls of 11.5 ppg OBM thru Archer Stage Collar set at 5,305’. Initial pump rate 4 bpm ICP 336 psi slowed rate to 3 bpm 40 bbls into displacement after losing full returns. 72 bbl lost during displacement. -CIP @ 16:00 hrs. - Close C-flex and Set LTP. Circulate off liner top and dump 160 bbls of spacer + trace cement, and 452 bbls of contiminated interface to cuttings box. 3, 2,718.0-5,656.0ftKB Top Depth (ftKB) 2,718.0 Bottom Depth (ftKB) 5,656.0 Full Return? No Vol Cement Ret (bbl) Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 600.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Mud Flush Spacer Fluid Type Mud Flush Spacer Fluid Description Mud Flush Spacer 8# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Versacem Tail Fluid Type Versacem Tail Fluid Description Versacem Type I/II Amount (sacks) 1,295 Class I/II Volume Pumped (bbl) 285.0 Estimated Top (ftKB) 2,739.0 Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 122.3 Thickening Time (hr) 8.50 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Attachment D Attachment E Attachment F We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) (B B L ) a WF b WF 2 6 1. 0 0 0 0 0 0 c P u m p C h e c k WF 26 4 0 32 0 32 0 13 4 4 0 13 4 4 0 32 0 32 0 d Dr o p S t a g e 1 B a l l / C o l l e t F P 0 4 0 3 32 3 1 2 6 1 3 5 6 6 3 3 2 3 eD F I T XL 26 4 0 28 0 60 3 1 1 7 6 0 2 5 3 2 6 2 8 0 6 0 3 f Sl o w f o r S e a t XL 26 1 8 50 65 3 2 1 0 0 2 7 4 2 6 5 0 6 5 3 g D F I T D i s p l a c m e n t t h e n H S D WF 26 4 0 33 0 98 3 1 3 8 6 0 4 1 2 8 6 3 3 0 9 8 3 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T CL E A N V O L U M S T A G E A V E R A G E F L U I D R A T E S T A G E C U M T O T J O B ST A G E C U M ST A G E C U M S i z e o r S t a g e C u m # P P A T Y P E ( B P M ) ( B B L ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) T y p e ( B B L ) ( B B L ) 1 0 Li n e o u t X L X L 2 6 18 40 40 1 0 2 3 16 8 0 4 2 9 6 6 0 0 4 0 1 0 2 3 2 0 St a g e 1 P A D XL 2 6 18 3 2 5 36 5 1 3 4 8 13 6 5 0 5 6 6 1 6 00 CS G - I V 32 5 1 3 4 8 3 1 Fl a t ; A d d P a t i n a T r a c e r t o P O D XL 2 6 30 1 2 0 48 5 1 4 6 8 50 4 0 6 1 6 5 6 48 2 6 4 8 2 6 CS G - I V 11 5 1 4 6 3 4 2 Fl a t XL 2 6 30 1 3 5 62 0 1 6 0 3 56 7 0 6 7 3 2 6 10 4 1 5 1 5 2 4 1 CS G - I V 12 4 1 5 8 7 5 3 Fl a t XL 2 6 30 1 4 5 76 5 1 7 4 8 60 9 0 7 3 4 1 6 16 1 2 2 3 1 3 6 3 CS G - I V 12 8 1 7 1 5 6 4 Fl a t XL 2 6 30 1 4 5 91 0 1 8 9 3 60 9 0 7 9 5 0 6 20 6 8 6 5 2 0 4 9 CS G - I V 12 3 1 8 3 8 7 5 Fl a t XL 2 6 30 1 4 5 10 5 5 2 0 3 8 60 9 0 8 5 5 9 6 24 9 1 8 7 6 9 6 6 CS G - I V 11 9 1 9 5 7 8 6 Fl a t XL 2 6 30 1 4 5 12 0 0 2 1 8 3 60 9 0 9 1 6 8 6 28 8 5 3 1 0 5 8 1 9 CS G - I V 11 4 2 0 7 1 9 7 Fl a t XL 2 6 30 1 3 5 13 3 5 2 3 1 8 56 7 0 9 7 3 5 6 30 2 7 8 1 3 6 0 9 8 CS G - I V 10 3 2 1 7 4 10 8 Fl a t XL 2 6 30 1 1 5 14 5 0 2 4 3 3 48 3 0 1 0 2 1 8 6 28 5 1 2 1 6 4 6 0 9 CS G - I V 85 2 2 5 9 11 0 Cl e a r S u r f a c e L i n e s XL 2 6 30 2 5 14 7 5 2 4 5 8 10 5 0 1 0 3 2 3 6 0 1 6 4 6 0 9 2 5 2 2 8 4 12 0 Sp a c e r X L 2 6 30 15 14 9 0 2 4 7 3 63 0 1 0 3 8 6 6 0 1 6 4 6 0 9 1 5 2 2 9 9 13 0 Dr o p S t a g e 2 B a l l / C o l l e t F P 0 30 3 14 9 3 2 4 7 6 12 6 1 0 3 9 9 2 0 1 6 4 6 0 9 3 2 3 0 2 14 0 St a g e 2 P A D XL 2 6 30 2 7 1 17 6 4 2 7 4 7 11 3 8 2 1 1 5 3 7 4 0 1 6 4 6 0 9 2 7 1 2 5 7 3 15 0 Sl o w f o r S e a t X L 2 6 18 50 18 1 4 2 7 9 7 21 0 0 1 1 7 4 7 4 0 1 6 4 6 0 9 5 0 2 6 2 3 16 0 Re s u m e P a d XL 2 6 25 1 18 1 5 2 7 9 8 42 1 1 7 5 1 6 0 1 6 4 6 0 9 1 2 6 2 4 17 1 Fl a t XL 2 6 25 1 0 0 19 1 5 2 8 9 8 42 0 0 1 2 1 7 1 6 40 2 1 1 6 8 6 3 1 CS G - I V 96 2 7 2 0 18 2 Fl a t XL 2 6 25 1 2 0 20 3 5 3 0 1 8 50 4 0 1 2 6 7 5 6 92 5 8 1 7 7 8 8 8 CS G - I V 11 0 2 8 3 0 19 3 Fl a t XL 2 6 25 1 3 5 21 7 0 3 1 5 3 56 7 0 1 3 2 4 2 6 15 0 1 0 1 9 2 8 9 9 CS G - I V 11 9 2 9 4 9 20 4 Fl a t XL 2 6 25 1 3 5 23 0 5 3 2 8 8 56 7 0 1 3 8 0 9 6 19 2 5 9 2 1 2 1 5 8 CS G - I V 11 5 3 0 6 4 21 5 Fl a t XL 2 6 25 1 3 5 24 4 0 3 4 2 3 56 7 0 1 4 3 7 6 6 23 1 9 9 2 3 5 3 5 7 CS G - I V 11 0 3 1 7 4 22 6 Fl a t XL 2 6 25 1 3 5 25 7 5 3 5 5 8 56 7 0 1 4 9 4 3 6 26 8 6 3 2 6 2 2 2 0 CS G - I V 10 7 3 2 8 1 23 7 Fl a t XL 2 6 25 1 2 5 27 0 0 3 6 8 3 52 5 0 1 5 4 6 8 6 28 0 3 6 2 9 0 2 5 6 CS G - I V 95 3 3 7 6 24 8 Fl a t XL 2 6 25 1 1 0 28 1 0 3 7 9 3 46 2 0 1 5 9 3 0 6 27 2 7 2 3 1 7 5 2 8 CS G - I V 81 3 4 5 7 25 0 Cl e a r S u r f a c e L i n e s XL 2 6 25 2 5 28 3 5 3 8 1 8 10 5 0 1 6 0 3 5 6 0 3 1 7 5 2 8 2 5 3 4 8 2 26 0 Sp a c e r X L 2 6 25 15 28 5 0 3 8 3 3 63 0 1 6 0 9 8 6 0 3 1 7 5 2 8 1 5 3 4 9 7 27 0 Dr o p S t a g e 3 B a l l / C o l l e t F P 0 25 3 28 5 3 3 8 3 6 12 6 1 6 1 1 1 2 0 3 1 7 5 2 8 3 3 5 0 0 28 0 St a g e 3 P A D XL 2 6 25 2 6 4 31 1 7 4 1 0 0 11 0 8 8 1 7 2 2 0 0 0 3 1 7 5 2 8 2 6 4 3 7 6 4 29 0 Sl o w f o r S e a t X L 2 6 18 50 31 6 7 4 1 5 0 21 0 0 1 7 4 3 0 0 0 3 1 7 5 2 8 5 0 3 8 1 4 30 0 Re s u m e P a d XL 2 6 25 1 31 6 8 4 1 5 1 42 1 7 4 3 4 2 0 3 1 7 5 2 8 1 3 8 1 5 31 1 Fl a t XL 2 6 25 1 0 0 32 6 8 4 2 5 1 42 0 0 1 7 8 5 4 2 40 2 1 3 2 1 5 4 9 CS G - I V 96 3 9 1 1 FL U I D Ne a t W a t e r CO M M E N T S En s u r e S t a g e 2 b a l l / c o l l e t i s l o a d e d Pr i m e a n d P r e s s u r e T e s t Op e n w e l l We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 32 2 Fl a t XL 2 6 25 1 2 0 33 8 8 4 3 7 1 50 4 0 1 8 3 5 8 2 92 5 8 3 3 0 8 0 7 CS G - I V 11 0 4 0 2 1 33 3 Fl a t XL 2 6 25 1 3 5 35 2 3 4 5 0 6 56 7 0 1 8 9 2 5 2 15 0 1 0 3 4 5 8 1 7 CS G - I V 11 9 4 1 4 0 34 4 Fl a t XL 2 6 25 1 3 5 36 5 8 4 6 4 1 56 7 0 1 9 4 9 2 2 19 2 5 9 3 6 5 0 7 6 CS G - I V 11 5 4 2 5 5 35 5 Fl a t XL 2 6 25 1 3 5 37 9 3 4 7 7 6 56 7 0 2 0 0 5 9 2 23 1 9 9 3 8 8 2 7 6 CS G - I V 11 0 4 3 6 5 36 6 Fl a t XL 2 6 25 1 3 5 39 2 8 4 9 1 1 56 7 0 2 0 6 2 6 2 26 8 6 3 4 1 5 1 3 9 CS G - I V 10 7 4 4 7 2 37 7 Fl a t XL 2 6 25 1 2 5 40 5 3 5 0 3 6 52 5 0 2 1 1 5 1 2 28 0 3 6 4 4 3 1 7 4 CS G - I V 95 4 5 6 7 38 8 Fl a t XL 2 6 25 1 1 0 41 6 3 5 1 4 6 46 2 0 2 1 6 1 3 2 27 2 7 2 4 7 0 4 4 6 CS G - I V 81 4 6 4 9 39 0 Cl e a r S u r f a c e L i n e s XL 2 6 25 2 5 41 8 8 5 1 7 1 10 5 0 2 1 7 1 8 2 0 4 7 0 4 4 6 2 5 4 6 7 4 40 0 Sp a c e r X L 2 6 25 15 42 0 3 5 1 8 6 63 0 2 1 7 8 1 2 0 4 7 0 4 4 6 1 5 4 6 8 9 41 0 Dr o p S t a g e 4 B a l l / C o l l e t F P 0 25 3 42 0 6 5 1 8 9 12 6 2 1 7 9 3 8 0 4 7 0 4 4 6 3 4 6 9 2 42 0 St a g e 4 P A D XL 2 6 25 2 5 6 44 6 2 5 4 4 5 10 7 5 2 2 2 8 6 9 0 0 4 7 0 4 4 6 2 5 6 4 9 4 8 43 0 Sl o w f o r S e a t X L 2 6 18 50 45 1 2 5 4 9 5 21 0 0 2 3 0 7 9 0 0 4 7 0 4 4 6 5 0 4 9 9 8 44 0 Re s u m e P a d XL 2 6 30 4 4 45 5 6 5 5 3 9 18 4 8 2 3 2 6 3 8 0 4 7 0 4 4 6 4 4 5 0 4 2 45 1 Fl a t XL 2 6 30 1 2 0 46 7 6 5 6 5 9 50 4 0 2 3 7 6 7 8 48 2 6 4 7 5 2 7 2 CS G - I V 11 5 5 1 5 7 46 2 Fl a t XL 2 6 30 1 3 5 48 1 1 5 7 9 4 56 7 0 2 4 3 3 4 8 10 4 1 5 4 8 5 6 8 7 CS G - I V 12 4 5 2 8 1 47 3 Fl a t XL 2 6 30 1 5 0 49 6 1 5 9 4 4 63 0 0 2 4 9 6 4 8 16 6 7 8 5 0 2 3 6 5 CS G - I V 13 2 5 4 1 3 48 4 Fl a t XL 2 6 30 1 5 0 51 1 1 6 0 9 4 63 0 0 2 5 5 9 4 8 21 3 9 9 5 2 3 7 6 4 CS G - I V 12 7 5 5 4 0 49 5 Fl a t XL 2 6 30 1 5 0 52 6 1 6 2 4 4 63 0 0 2 6 2 2 4 8 25 7 7 7 5 4 9 5 4 1 CS G - I V 12 3 5 6 6 3 50 6 Fl a t XL 2 6 30 1 5 0 54 1 1 6 3 9 4 63 0 0 2 6 8 5 4 8 29 8 4 8 5 7 9 3 8 9 CS G - I V 11 8 5 7 8 1 51 7 Fl a t XL 2 6 30 1 4 0 55 5 1 6 5 3 4 58 8 0 2 7 4 4 2 8 31 4 0 0 6 1 0 7 8 9 CS G - I V 10 7 5 8 8 8 52 8 Fl a t XL 2 6 30 1 2 5 56 7 6 6 6 5 9 52 5 0 2 7 9 6 7 8 30 9 9 1 6 4 1 7 7 9 CS G - I V 92 5 9 8 0 53 0 Cl e a r S u r f a c e L i n e s XL 2 6 30 2 5 57 0 1 6 6 8 4 10 5 0 2 8 0 7 2 8 0 6 4 1 7 7 9 2 5 6 0 0 5 54 0 Sp a c e r X L 2 6 30 15 57 1 6 6 6 9 9 63 0 2 8 1 3 5 8 0 6 4 1 7 7 9 1 5 6 0 2 0 55 0 Dr o p S t a g e 5 B a l l / C o l l e t F P 0 30 3 57 1 9 6 7 0 2 12 6 2 8 1 4 8 4 0 6 4 1 7 7 9 3 6 0 2 3 56 0 St a g e 5 P A D XL 2 6 30 2 4 9 59 6 8 6 9 5 1 10 4 5 8 2 9 1 9 4 2 0 6 4 1 7 7 9 2 4 9 6 2 7 2 57 0 Sl o w f o r S e a t X L 2 6 18 50 60 1 8 7 0 0 1 21 0 0 2 9 4 0 4 2 0 6 4 1 7 7 9 5 0 6 3 2 2 58 0 Re s u m e P a d XL 2 6 40 7 6 60 9 4 7 0 7 7 31 9 2 2 9 7 2 3 4 0 6 4 1 7 7 9 7 6 6 3 9 8 59 1 Fl a t XL 2 6 40 1 2 5 62 1 9 7 2 0 2 52 5 0 3 0 2 4 8 4 50 2 7 6 4 6 8 0 6 CS G - I V 12 0 6 5 1 8 60 2 Fl a t XL 2 6 40 1 4 0 63 5 9 7 3 4 2 58 8 0 3 0 8 3 6 4 10 8 0 1 6 5 7 6 0 7 CS G - I V 12 9 6 6 4 7 61 3 Fl a t XL 2 6 40 1 7 0 65 2 9 7 5 1 2 71 4 0 3 1 5 5 0 4 18 9 0 2 6 7 6 5 0 9 CS G - I V 15 0 6 7 9 7 62 4 Fl a t XL 2 6 40 1 7 0 66 9 9 7 6 8 2 71 4 0 3 2 2 6 4 4 24 2 5 2 7 0 0 7 6 1 CS G - I V 14 4 6 9 4 1 63 5 Fl a t XL 2 6 40 1 7 0 68 6 9 7 8 5 2 71 4 0 3 2 9 7 8 4 29 2 1 4 7 2 9 9 7 5 CS G - I V 13 9 7 0 8 0 64 6 Fl a t XL 2 6 40 1 7 0 70 3 9 8 0 2 2 71 4 0 3 3 6 9 2 4 33 8 2 7 7 6 3 8 0 2 CS G - I V 13 4 7 2 1 4 65 7 Fl a t XL 2 6 40 1 4 0 71 7 9 8 1 6 2 58 8 0 3 4 2 8 0 4 31 4 0 0 7 9 5 2 0 2 CS G - I V 10 7 7 3 2 1 66 8 Fl a t XL 2 6 40 1 2 5 73 0 4 8 2 8 7 52 5 0 3 4 8 0 5 4 30 9 9 1 8 2 6 1 9 3 CS G - I V 92 7 4 1 3 67 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 73 2 9 8 3 1 2 10 5 0 3 4 9 1 0 4 0 8 2 6 1 9 3 2 5 7 4 3 8 68 0 Sp a c e r X L 2 6 40 15 73 4 4 8 3 2 7 63 0 3 4 9 7 3 4 0 8 2 6 1 9 3 1 5 7 4 5 3 69 0 Dr o p S t a g e 6 B a l l / C o l l e t F P 0 40 3 73 4 7 8 3 3 0 12 6 3 4 9 8 6 0 0 8 2 6 1 9 3 3 7 4 5 6 70 0 St a g e 6 P A D XL 2 6 40 2 4 1 75 8 8 8 5 7 1 10 1 2 2 3 5 9 9 8 2 0 8 2 6 1 9 3 2 4 1 7 6 9 7 71 0 Sl o w f o r S e a t X L 2 6 18 50 76 3 8 8 6 2 1 21 0 0 3 6 2 0 8 2 0 8 2 6 1 9 3 5 0 7 7 4 7 72 0 Re s u m e P a d XL 2 6 40 1 0 9 77 4 7 8 7 3 0 45 7 8 3 6 6 6 6 0 0 8 2 6 1 9 3 1 0 9 7 8 5 6 73 1 Fl a t XL 2 6 40 1 5 0 78 9 7 8 8 8 0 63 0 0 3 7 2 9 6 0 60 3 2 8 3 2 2 2 5 CS G - I V 14 4 8 0 0 0 74 2 Fl a t XL 2 6 40 1 7 5 80 7 2 9 0 5 5 73 5 0 3 8 0 3 1 0 13 5 0 1 8 4 5 7 2 6 CS G - I V 16 1 8 1 6 1 We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 75 3 Fl a t XL 2 6 40 2 0 0 82 7 2 9 2 5 5 84 0 0 3 8 8 7 1 0 22 2 3 8 8 6 7 9 6 4 CS G - I V 17 6 8 3 3 7 76 4 Fl a t XL 2 6 40 2 0 0 84 7 2 9 4 5 5 84 0 0 3 9 7 1 1 0 28 5 3 2 8 9 6 4 9 6 CS G - I V 17 0 85 0 7 77 5 Fl a t XL 2 6 40 2 0 0 86 7 2 9 6 5 5 84 0 0 4 0 5 5 1 0 34 3 6 9 9 3 0 8 6 5 CS G - I V 16 4 86 7 1 78 6 Fl a t XL 2 6 40 2 0 0 88 7 2 9 8 5 5 84 0 0 4 1 3 9 1 0 39 7 9 7 9 7 0 6 6 2 CS G - I V 15 8 88 2 9 79 7 Fl a t XL 2 6 40 1 7 0 90 4 2 1 0 0 2 5 71 4 0 4 2 1 0 5 0 38 1 2 8 1 0 0 8 7 9 0 CS G - I V 13 0 89 5 8 80 8 Fl a t XL 2 6 40 1 3 5 91 7 7 1 0 1 6 0 56 7 0 4 2 6 7 2 0 33 4 7 0 1 0 4 2 2 6 1 CS G - I V 10 0 90 5 8 81 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 92 0 2 1 0 1 8 5 10 5 0 4 2 7 7 7 0 0 1 0 4 2 2 6 1 2 5 90 8 3 82 0 Sp a c e r X L 2 6 40 15 92 1 7 1 0 2 0 0 63 0 4 2 8 4 0 0 0 1 0 4 2 2 6 1 1 5 90 9 8 83 0 Dr o p S t a g e 7 B a l l / C o l l e t F P 0 40 3 92 2 0 1 0 2 0 3 12 6 4 2 8 5 2 6 0 1 0 4 2 2 6 1 3 91 0 1 84 0 XL F l u s h ( D F I T ) XL 2 6 40 2 3 3 94 5 3 1 0 4 3 6 97 8 6 4 3 8 3 1 2 0 1 0 4 2 2 6 1 2 3 3 93 3 4 85 0 Sl o w f o r s e a t ( D F I T ) X L 2 6 18 50 95 0 3 1 0 4 8 6 21 0 0 4 4 0 4 1 2 0 1 0 4 2 2 6 1 5 0 9 3 8 4 86 DF I T F l u s h WF 2 6 40 20 5 9 7 0 8 1 0 6 9 1 86 1 0 4 4 9 0 2 2 20 5 9 5 8 9 87 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 7 0 97 7 8 1 0 7 6 1 29 4 9 4 5 1 9 7 1 TO T A L S 10 7 6 1 45 1 9 7 1 10 4 2 2 6 1 We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) (B B L ) a FP b WF 2 6 3. 5 40 40 16 8 0 16 8 0 40 40 c WF 2 6 3. 5 26 5 26 5 94 5 0 11 1 3 0 26 5 30 5 d P u m p C h e c k WF 26 4 10 0 36 5 42 0 0 15 3 3 0 10 0 40 5 0 4 0 5 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T CL E A N V O L U M S T A G E A V E R A G E F L U I D R A T E S T A G E C U M T O T J O B ST A G E C U M ST A G E C U M S i z e o r S t a g e C u m # P P A T Y P E ( B P M ) ( B B L ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) T y p e ( B B L ) ( B B L ) 1 0 Li n e o u t X L X L 2 6 18 40 40 4 0 5 16 8 0 1 7 0 1 0 0 0 4 0 4 4 5 2 0 St a g e 7 P A D XL 2 6 40 3 7 5 41 5 7 8 0 15 7 5 0 3 2 7 6 0 00 16 / 2 0 - C L 37 5 8 2 0 3 1 Fl a t XL 2 6 40 1 2 5 54 0 9 0 5 52 5 0 3 8 0 1 0 50 2 8 5 0 2 8 16 / 2 0 - C L 12 0 9 4 0 4 2 Fl a t XL 2 6 40 1 4 0 68 0 1 0 4 5 58 8 0 4 3 8 9 0 10 8 0 4 1 5 8 3 1 16 / 2 0 - C L 12 9 1 0 6 8 5 3 Fl a t XL 2 6 40 1 7 0 85 0 1 2 1 5 71 4 0 5 1 0 3 0 18 9 1 0 3 4 7 4 1 16 / 2 0 - C L 15 0 1 2 1 8 6 4 Fl a t XL 2 6 40 1 7 0 10 2 0 1 3 8 5 71 4 0 5 8 1 7 0 24 2 6 5 5 9 0 0 7 16 / 2 0 - C L 14 4 1 3 6 3 7 5 Fl a t XL 2 6 40 1 7 0 11 9 0 1 5 5 5 71 4 0 6 5 3 1 0 29 2 3 3 8 8 2 3 9 16 / 2 0 - C L 13 9 1 5 0 2 8 6 Fl a t XL 2 6 40 1 7 0 13 6 0 1 7 2 5 71 4 0 7 2 4 5 0 33 8 5 3 1 2 2 0 9 2 16 / 2 0 - C L 13 4 1 6 3 6 9 7 Fl a t XL 2 6 40 1 4 0 15 0 0 1 8 6 5 58 8 0 7 8 3 3 0 31 4 2 6 1 5 3 5 1 8 16 / 2 0 - C L 10 7 1 7 4 3 10 8 Fl a t XL 2 6 40 1 2 5 16 2 5 1 9 9 0 52 5 0 8 3 5 8 0 31 0 2 0 1 8 4 5 3 8 16 / 2 0 - C L 92 1 8 3 6 11 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 16 5 0 2 0 1 5 10 5 0 8 4 6 3 0 0 1 8 4 5 3 8 2 5 1 8 6 1 12 0 Sp a c e r X L 2 6 40 15 16 6 5 2 0 3 0 63 0 8 5 2 6 0 0 1 8 4 5 3 8 1 5 1 8 7 6 13 0 Dr o p S t a g e 8 B a l l / C o l l e t F P 0 40 3 16 6 8 2 0 3 3 12 6 8 5 3 8 6 0 1 8 4 5 3 8 3 1 8 7 9 14 0 St a g e 8 P A D XL 2 6 40 2 2 6 18 9 4 2 2 5 9 94 9 2 9 4 8 7 8 0 1 8 4 5 3 8 2 2 6 2 1 0 5 15 0 Sl o w f o r S e a t X L 2 6 18 50 19 4 4 2 3 0 9 21 0 0 9 6 9 7 8 0 1 8 4 5 3 8 5 0 2 1 5 5 16 0 Re s u m e P a d XL 2 6 40 1 2 4 20 6 8 2 4 3 3 52 0 8 1 0 2 1 8 6 0 1 8 4 5 3 8 1 2 4 2 2 7 9 17 1 Fl a t XL 2 6 40 2 0 0 22 6 8 2 6 3 3 84 0 0 1 1 0 5 8 6 80 4 4 1 9 2 5 8 2 16 / 2 0 - C L 19 2 2 4 7 0 18 2 Fl a t XL 2 6 40 2 2 5 24 9 3 2 8 5 8 94 5 0 1 2 0 0 3 6 17 3 6 3 2 0 9 9 4 5 16 / 2 0 - C L 20 7 2 6 7 7 19 4 Fl a t XL 2 6 40 2 7 5 27 6 8 3 1 3 3 11 5 5 0 1 3 1 5 8 6 39 2 5 3 2 4 9 1 9 8 16 / 2 0 - C L 23 4 2 9 1 0 20 6 Fl a t XL 2 6 40 2 6 0 30 2 8 3 3 9 3 10 9 2 0 1 4 2 5 0 6 51 7 7 5 3 0 0 9 7 2 16 / 2 0 - C L 20 5 3 1 1 6 21 8 Fl a t XL 2 6 40 2 4 0 32 6 8 3 6 3 3 10 0 8 0 1 5 2 5 8 6 59 5 5 8 3 6 0 5 3 0 16 / 2 0 - C L 17 7 3 2 9 3 22 10 Fl a t XL 2 6 40 2 0 0 34 6 8 3 8 3 3 84 0 0 1 6 0 9 8 6 58 2 3 3 4 1 8 7 6 3 16 / 2 0 - C L 13 9 3 4 3 2 23 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 34 9 3 3 8 5 8 10 5 0 1 6 2 0 3 6 0 4 1 8 7 6 3 2 5 3 4 5 7 24 0 Sp a c e r X L 2 6 40 15 35 0 8 3 8 7 3 63 0 1 6 2 6 6 6 0 4 1 8 7 6 3 1 5 3 4 7 2 25 0 Dr o p S t a g e 9 B a l l / C o l l e t F P 0 40 3 35 1 1 3 8 7 6 12 6 1 6 2 7 9 2 0 4 1 8 7 6 3 3 3 4 7 5 26 0 St a g e 9 P A D XL 2 6 40 2 1 8 37 2 9 4 0 9 4 91 5 6 1 7 1 9 4 8 0 4 1 8 7 6 3 2 1 8 3 6 9 3 27 0 Sl o w f o r S e a t X L 2 6 18 50 37 7 9 4 1 4 4 21 0 0 1 7 4 0 4 8 0 4 1 8 7 6 3 5 0 3 7 4 3 28 0 Re s u m e P a d XL 2 6 40 1 37 8 0 4 1 4 5 42 1 7 4 0 9 0 0 4 1 8 7 6 3 1 3 7 4 4 29 1 Sc o u r XL 2 6 40 6 0 38 4 0 4 2 0 5 25 2 0 1 7 6 6 1 0 24 1 3 4 2 1 1 7 6 40 / 7 0 - C L 57 3 8 0 1 30 3 Sc o u r XL 2 6 40 1 2 0 39 6 0 4 3 2 5 50 4 0 1 8 1 6 5 0 13 3 4 8 4 3 4 5 2 4 40 / 7 0 - C L 10 6 3 9 0 7 31 0 Re s u m e P a d XL 2 6 40 5 0 40 1 0 4 3 7 5 21 0 0 1 8 3 7 5 0 0 4 3 4 5 2 4 5 0 3 9 5 7 32 1 Fl a t XL 2 6 40 2 0 0 42 1 0 4 5 7 5 84 0 0 1 9 2 1 5 0 80 4 4 4 4 2 5 6 8 16 / 2 0 - C L 19 2 4 1 4 9 33 2 Fl a t XL 2 6 40 2 2 5 44 3 5 4 8 0 0 94 5 0 2 0 1 6 0 0 17 3 6 3 4 5 9 9 3 2 16 / 2 0 - C L 20 7 4 3 5 5 34 4 Fl a t XL 2 6 40 2 7 5 47 1 0 5 0 7 5 11 5 5 0 2 1 3 1 5 0 39 2 5 3 4 9 9 1 8 4 16 / 2 0 - C L 23 4 4 5 8 9 St a g e t o " L i n e o u t X L " FL U I D Ne a t W a t e r CO M M E N T S En s u r e S t a g e 8 b a l l / c o l l e t i s l o a d e d Pr i m e a n d P r e s s u r e T e s t Op e n w e l l Pu m p B a l l t o S e a t We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 35 6 Fl a t XL 2 6 40 2 6 0 49 7 0 5 3 3 5 10 9 2 0 2 2 4 0 7 0 51 7 7 5 5 5 0 9 5 9 16 / 2 0 - C L 20 5 4 7 9 5 36 8 Fl a t XL 2 6 40 2 4 0 52 1 0 5 5 7 5 10 0 8 0 2 3 4 1 5 0 59 5 5 8 6 1 0 5 1 7 16 / 2 0 - C L 17 7 49 7 2 37 10 Fl a t XL 2 6 40 2 0 0 54 1 0 5 7 7 5 84 0 0 2 4 2 5 5 0 58 2 3 3 6 6 8 7 5 0 16 / 2 0 - C L 13 9 51 1 0 38 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 54 3 5 5 8 0 0 10 5 0 2 4 3 6 0 0 0 6 6 8 7 5 0 2 5 51 3 5 39 0 Sp a c e r X L 2 6 40 15 54 5 0 5 8 1 5 63 0 2 4 4 2 3 0 0 6 6 8 7 5 0 1 5 51 5 0 40 0 Dr o p S t a g e 1 0 B a l l / C o l l e t F P 0 40 3 54 5 3 5 8 1 8 12 6 2 4 4 3 5 6 0 6 6 8 7 5 0 3 51 5 3 41 0 St a g e 1 0 P A D XL 2 6 40 2 1 1 56 6 4 6 0 2 9 88 6 2 2 5 3 2 1 8 0 6 6 8 7 5 0 2 1 1 53 6 4 42 0 Sl o w f o r S e a t X L 2 6 18 50 57 1 4 6 0 7 9 21 0 0 2 5 5 3 1 8 0 6 6 8 7 5 0 5 0 54 1 4 43 0 Re s u m e P a d XL 2 6 40 1 3 9 58 5 3 6 2 1 8 58 3 8 2 6 1 1 5 6 0 6 6 8 7 5 0 1 3 9 55 5 3 44 1 Fl a t XL 2 6 40 1 9 0 60 4 3 6 4 0 8 79 8 0 2 6 9 1 3 6 76 4 2 6 7 6 3 9 2 16 / 2 0 - C L 18 2 57 3 5 45 3 Fl a t XL 2 6 40 2 1 5 62 5 8 6 6 2 3 90 3 0 2 7 8 1 6 6 23 9 1 5 7 0 0 3 0 7 16 / 2 0 - C L 19 0 59 2 5 46 5 Fl a t XL 2 6 40 2 4 0 64 9 8 6 8 6 3 10 0 8 0 2 8 8 2 4 6 41 2 7 0 7 4 1 5 7 7 16 / 2 0 - C L 19 7 61 2 2 47 7 Fl a t XL 2 6 40 2 4 0 67 3 8 7 1 0 3 10 0 8 0 2 9 8 3 2 6 53 8 7 4 7 9 5 4 5 0 16 / 2 0 - C L 18 3 63 0 5 48 9 Fl a t XL 2 6 40 2 2 0 69 5 8 7 3 2 3 92 4 0 3 0 7 5 6 6 59 4 7 5 8 5 4 9 2 5 16 / 2 0 - C L 15 7 64 6 2 49 10 Fl a t XL 2 6 40 1 8 0 71 3 8 7 5 0 3 75 6 0 3 1 5 1 2 6 52 4 1 0 9 0 7 3 3 5 16 / 2 0 - C L 12 5 65 8 7 50 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 71 6 3 7 5 2 8 10 5 0 3 1 6 1 7 6 0 9 0 7 3 3 5 2 5 66 1 2 51 0 Sp a c e r X L 2 6 40 15 71 7 8 7 5 4 3 63 0 3 1 6 8 0 6 0 9 0 7 3 3 5 1 5 66 2 7 52 0 Dr o p S t a g e 1 1 B a l l / C o l l e t F P 0 40 3 71 8 1 7 5 4 6 12 6 3 1 6 9 3 2 0 9 0 7 3 3 5 3 66 3 0 53 0 St a g e 1 1 P A D XL 2 6 40 2 0 3 73 8 4 7 7 4 9 85 2 6 3 2 5 4 5 8 0 9 0 7 3 3 5 2 0 3 68 3 3 54 0 Sl o w f o r S e a t X L 2 6 18 50 74 3 4 7 7 9 9 21 0 0 3 2 7 5 5 8 0 9 0 7 3 3 5 5 0 68 8 3 55 0 Re s u m e P a d XL 2 6 40 1 74 3 5 7 8 0 0 42 3 2 7 6 0 0 0 9 0 7 3 3 5 1 68 8 4 56 1 Sc o u r XL 2 6 40 6 0 74 9 5 7 8 6 0 25 2 0 3 3 0 1 2 0 24 1 3 9 0 9 7 4 8 40 / 7 0 - C L 57 69 4 2 57 3 Sc o u r XL 2 6 40 1 2 0 76 1 5 7 9 8 0 50 4 0 3 3 5 1 6 0 13 3 4 8 9 2 3 0 9 6 40 / 7 0 - C L 10 6 70 4 8 58 0 Fl a t XL 2 6 40 5 0 76 6 5 8 0 3 0 21 0 0 3 3 7 2 6 0 0 9 2 3 0 9 6 5 0 70 9 8 59 1 Fl a t XL 2 6 40 2 0 0 78 6 5 8 2 3 0 84 0 0 3 4 5 6 6 0 80 4 4 9 3 1 1 4 1 16 / 2 0 - C L 19 2 72 8 9 60 2 Fl a t XL 2 6 40 2 2 5 80 9 0 8 4 5 5 94 5 0 3 5 5 1 1 0 17 3 6 3 9 4 8 5 0 4 16 / 2 0 - C L 20 7 74 9 6 61 4 Fl a t XL 2 6 40 2 7 5 83 6 5 8 7 3 0 11 5 5 0 3 6 6 6 6 0 39 2 5 3 9 8 7 7 5 7 16 / 2 0 - C L 23 4 77 2 9 62 6 Fl a t XL 2 6 40 2 6 0 86 2 5 8 9 9 0 10 9 2 0 3 7 7 5 8 0 51 7 7 5 1 0 3 9 5 3 1 16 / 2 0 - C L 20 5 79 3 5 63 8 Fl a t XL 2 6 40 2 4 0 88 6 5 9 2 3 0 10 0 8 0 3 8 7 6 6 0 59 5 5 8 1 0 9 9 0 8 9 16 / 2 0 - C L 17 7 81 1 2 64 10 Fl a t XL 2 6 40 2 0 0 90 6 5 9 4 3 0 84 0 0 3 9 6 0 6 0 58 2 3 3 1 1 5 7 3 2 2 16 / 2 0 - C L 13 9 82 5 1 65 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 90 9 0 9 4 5 5 10 5 0 3 9 7 1 1 0 0 1 1 5 7 3 2 2 2 5 82 7 6 66 0 Sp a c e r X L 2 6 40 15 91 0 5 9 4 7 0 63 0 3 9 7 7 4 0 0 1 1 5 7 3 2 2 1 5 82 9 1 67 0 Dr o p S t a g e 1 2 B a l l / C o l l e t F P 0 40 3 91 0 8 9 4 7 3 12 6 3 9 7 8 6 6 0 1 1 5 7 3 2 2 3 82 9 4 68 0 XL F l u s h ( D F I T ) XL 2 6 40 1 9 4 93 0 2 9 6 6 7 81 4 8 4 0 6 0 1 4 0 1 1 5 7 3 2 2 1 9 4 84 8 8 69 0 Sl o w f o r s e a t ( D F I T ) X L 2 6 18 50 93 5 2 9 7 1 7 21 0 0 4 0 8 1 1 4 0 1 1 5 7 3 2 2 5 0 85 3 8 70 0 Re s u m e D F I T XL 2 6 40 2 0 6 95 5 8 9 9 2 3 86 5 2 4 1 6 7 6 6 0 1 1 5 7 3 2 2 2 0 6 8 7 4 4 71 DF I T F l u s h WF 2 6 40 17 0 9 7 2 8 1 0 0 9 3 71 4 0 4 2 2 2 2 6 17 0 8 9 1 4 72 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 7 0 97 9 8 1 0 1 6 3 29 4 9 4 2 5 1 7 5 TO T A L S 10 1 6 3 42 5 1 7 5 11 5 7 3 2 2 We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) (B B L ) a FP b WF 2 6 4 40 40 16 8 0 16 8 0 40 40 c WF 2 6 3. 5 22 5 26 5 94 5 0 11 1 3 0 22 5 26 5 d P u m p C h e c k WF 26 4 10 0 36 5 42 0 0 15 3 3 0 10 0 36 5 0 3 6 5 PU M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T CL E A N V O L U M S T A G E A V E R A G E F L U I D R A T E S T A G E C U M T O T J O B ST A G E C U M ST A G E C U M S i z e o r S t a g e C u m # P P A T Y P E ( B P M ) ( B B L ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) T y p e ( B B L ) ( B B L ) 1 0 Li n e o u t X L X L 2 6 18 40 40 4 0 5 16 8 0 1 7 0 1 0 0 0 4 0 4 0 5 2 0 St a g e 1 2 P A D XL 2 6 40 4 5 0 49 0 8 5 5 18 9 0 0 3 5 9 1 0 00 16 / 2 0 - C L 45 0 8 5 5 3 1 Fl a t XL 2 6 40 1 7 5 66 5 1 0 3 0 73 5 0 4 3 2 6 0 70 3 9 7 0 3 9 16 / 2 0 - C L 16 8 1 0 2 3 4 2 Fl a t XL 2 6 40 1 9 0 85 5 1 2 2 0 79 8 0 5 1 2 4 0 14 6 6 2 2 1 7 0 1 16 / 2 0 - C L 17 5 1 1 9 7 5 3 Fl a t XL 2 6 40 2 1 0 10 6 5 1 4 3 0 88 2 0 6 0 0 6 0 23 3 5 9 4 5 0 6 0 16 / 2 0 - C L 18 5 1 3 8 3 6 4 Fl a t XL 2 6 40 2 1 0 12 7 5 1 6 4 0 88 2 0 6 8 8 8 0 29 9 7 5 7 5 0 3 5 16 / 2 0 - C L 17 8 1 5 6 1 7 5 Fl a t XL 2 6 40 2 1 0 14 8 5 1 8 5 0 88 2 0 7 7 7 0 0 36 1 1 1 1 1 1 1 4 6 16 / 2 0 - C L 17 2 1 7 3 3 8 6 Fl a t XL 2 6 40 2 1 0 16 9 5 2 0 6 0 88 2 0 8 6 5 2 0 41 8 1 8 1 5 2 9 6 4 16 / 2 0 - C L 16 6 1 8 9 9 9 7 Fl a t XL 2 6 40 1 7 0 18 6 5 2 2 3 0 71 4 0 9 3 6 6 0 38 1 6 0 1 9 1 1 2 4 16 / 2 0 - C L 13 0 2 0 2 9 10 8 Fl a t XL 2 6 40 1 5 5 20 2 0 2 3 8 5 65 1 0 1 0 0 1 7 0 38 4 6 4 2 2 9 5 8 8 16 / 2 0 - C L 11 4 2 1 4 3 11 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 20 4 5 2 4 1 0 10 5 0 1 0 1 2 2 0 0 2 2 9 5 8 8 2 5 2 1 6 8 12 0 Sp a c e r X L 2 6 40 15 20 6 0 2 4 2 5 63 0 1 0 1 8 5 0 0 2 2 9 5 8 8 1 5 2 1 8 3 13 0 Dr o p S t a g e 1 3 B a l l / C o l l e t F P 0 40 3 20 6 3 2 4 2 8 12 6 1 0 1 9 7 6 0 2 2 9 5 8 8 3 2 1 8 6 14 0 St a g e 1 3 P A D XL 2 6 40 1 8 4 22 4 7 2 6 1 2 77 2 8 1 0 9 7 0 4 0 2 2 9 5 8 8 1 8 4 2 3 7 0 15 0 Sl o w f o r S e a t X L 2 6 18 50 22 9 7 2 6 6 2 21 0 0 1 1 1 8 0 4 0 2 2 9 5 8 8 5 0 2 4 2 0 16 0 Re s u m e P a d XL 2 6 40 1 4 1 24 3 8 2 8 0 3 59 2 2 1 1 7 7 2 6 0 2 2 9 5 8 8 1 4 1 2 5 6 1 17 1 Fl a t XL 2 6 40 1 9 0 26 2 8 2 9 9 3 79 8 0 1 2 5 7 0 6 76 4 2 2 3 7 2 3 0 16 / 2 0 - C L 18 2 2 7 4 3 18 3 Fl a t XL 2 6 40 2 1 5 28 4 3 3 2 0 8 90 3 0 1 3 4 7 3 6 23 9 1 5 2 6 1 1 4 6 16 / 2 0 - C L 19 0 2 9 3 3 19 5 Fl a t XL 2 6 40 2 4 0 30 8 3 3 4 4 8 10 0 8 0 1 4 4 8 1 6 41 2 7 0 3 0 2 4 1 5 16 / 2 0 - C L 19 7 3 1 2 9 20 7 Fl a t XL 2 6 40 2 4 0 33 2 3 3 6 8 8 10 0 8 0 1 5 4 8 9 6 53 8 7 4 3 5 6 2 8 9 16 / 2 0 - C L 18 3 3 3 1 3 21 9 Fl a t XL 2 6 40 2 2 0 35 4 3 3 9 0 8 92 4 0 1 6 4 1 3 6 59 4 7 5 4 1 5 7 6 4 16 / 2 0 - C L 15 7 3 4 7 0 22 10 Fl a t XL 2 6 40 1 8 0 37 2 3 4 0 8 8 75 6 0 1 7 1 6 9 6 52 4 1 0 4 6 8 1 7 4 16 / 2 0 - C L 12 5 3 5 9 5 23 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 37 4 8 4 1 1 3 10 5 0 1 7 2 7 4 6 0 4 6 8 1 7 4 2 5 3 6 2 0 24 0 Sp a c e r X L 2 6 40 15 37 6 3 4 1 2 8 63 0 1 7 3 3 7 6 0 4 6 8 1 7 4 1 5 3 6 3 5 25 0 Dr o p S t a g e 1 4 B a l l / C o l l e t F P 0 40 3 37 6 6 4 1 3 1 12 6 1 7 3 5 0 2 0 4 6 8 1 7 4 3 3 6 3 8 26 0 St a g e 1 4 P A D XL 2 6 40 1 6 4 39 3 0 4 2 9 5 68 8 8 1 8 0 3 9 0 0 4 6 8 1 7 4 1 6 4 3 8 0 2 27 0 Sl o w f o r S e a t X L 2 6 18 50 39 8 0 4 3 4 5 21 0 0 1 8 2 4 9 0 0 4 6 8 1 7 4 5 0 3 8 5 2 28 0 Re s u m e P a d XL 2 6 40 1 8 6 41 6 6 4 5 3 1 78 1 2 1 9 0 3 0 2 0 4 6 8 1 7 4 1 8 6 4 0 3 8 29 1 Fl a t XL 2 6 40 1 5 0 43 1 6 4 6 8 1 63 0 0 1 9 6 6 0 2 60 3 3 4 7 4 2 0 7 16 / 2 0 - C L 14 4 4 1 8 1 30 2 Fl a t XL 2 6 40 1 7 5 44 9 1 4 8 5 6 73 5 0 2 0 3 9 5 2 13 5 0 5 4 8 7 7 1 2 16 / 2 0 - C L 16 1 4 3 4 2 31 3 Fl a t XL 2 6 40 2 0 0 46 9 1 5 0 5 6 84 0 0 2 1 2 3 5 2 22 2 4 7 5 0 9 9 5 9 16 / 2 0 - C L 17 7 4 5 1 9 32 4 Fl a t XL 2 6 40 2 0 0 48 9 1 5 2 5 6 84 0 0 2 2 0 7 5 2 28 5 4 7 5 3 8 5 0 6 16 / 2 0 - C L 17 0 4 6 8 9 33 5 Fl a t XL 2 6 40 2 0 0 50 9 1 5 4 5 6 84 0 0 2 2 9 1 5 2 34 3 9 1 5 7 2 8 9 7 16 / 2 0 - C L 16 4 4 8 5 2 34 6 Fl a t XL 2 6 40 2 0 0 52 9 1 5 6 5 6 84 0 0 2 3 7 5 5 2 39 8 2 7 6 1 2 7 2 4 16 / 2 0 - C L 15 8 5 0 1 0 FL U I D Ne a t W a t e r CO M M E N T S En s u r e S t a g e 1 3 b a l l / c o l l e t i s l o a d e d Pr i m e a n d P r e s s u r e T e s t Di s p l a c e P T - S D 5 M i n Pu m p B a l l t o S e a t St a g e t o " L i n e o u t X L " We l l N a m e ND B i - 0 0 6 12 / 1 1 / 2 5 D e s i g n ST A G E C O M M E N T S P U M P D I R T Y V O L U M E D I R T Y V O L U M E PR O P P A N T # T Y P E P P T R A T E S T A G E C U M ST A G E C U M ST A G E C U M S I Z E S t a g e C u m Pr e F r a c - N o n P r o p p a n t s t a g e s (B P M ) ( B B L ) ( B B L ) (G A L ) ( G A L ) (L B S ) ( L B S ) ( B B L ) ( B B L ) FL U I D Ne a t W a t e r 35 7 Fl a t XL 2 6 40 1 7 5 54 6 6 5 8 3 1 73 5 0 2 4 4 9 0 2 39 2 8 3 6 5 2 0 0 7 16 / 2 0 - C L 13 4 5 1 4 4 36 8 Fl a t XL 2 6 40 1 3 5 56 0 1 5 9 6 6 56 7 0 2 5 0 5 7 2 33 5 0 1 6 8 5 5 0 8 16 / 2 0 - C L 10 0 52 4 4 37 0 Cl e a r S u r f a c e L i n e s XL 2 6 40 2 5 56 2 6 5 9 9 1 10 5 0 2 5 1 6 2 2 0 6 8 5 5 0 8 2 5 52 6 9 38 0 Sp a c e r X L 2 6 40 15 56 4 1 6 0 0 6 63 0 2 5 2 2 5 2 0 6 8 5 5 0 8 1 5 52 8 4 39 0 Dr o p S t a g e 1 5 B a l l / C o l l e t F P 0 40 3 56 4 4 6 0 0 9 12 6 2 5 2 3 7 8 0 6 8 5 5 0 8 3 52 8 7 40 0 St a g e 1 5 P A D XL 2 6 40 1 5 6 58 0 0 6 1 6 5 65 5 2 2 5 8 9 3 0 0 6 8 5 5 0 8 1 5 6 54 4 3 41 0 Sl o w f o r S e a t X L 2 6 18 50 58 5 0 6 2 1 5 21 0 0 2 6 1 0 3 0 0 6 8 5 5 0 8 5 0 54 9 3 42 0 Re s u m e P a d XL 2 6 40 1 58 5 1 6 2 1 6 42 2 6 1 0 7 2 0 6 8 5 5 0 8 1 54 9 4 43 1 Sc o u r XL 2 6 40 6 0 59 1 1 6 2 7 6 25 2 0 2 6 3 5 9 2 24 1 3 6 8 7 9 2 1 40 / 7 0 - C L 57 55 5 1 44 3 Sc o u r XL 2 6 40 1 2 0 60 3 1 6 3 9 6 50 4 0 2 6 8 6 3 2 13 3 4 8 7 0 1 2 6 9 40 / 7 0 - C L 10 6 56 5 7 45 0 Re s u m e P A D XL 2 6 40 5 0 60 8 1 6 4 4 6 21 0 0 2 7 0 7 3 2 0 7 0 1 2 6 9 5 0 57 0 7 46 1 Fl a t XL 2 6 40 2 0 0 62 8 1 6 6 4 6 84 0 0 2 7 9 1 3 2 80 4 4 7 0 9 3 1 3 16 / 2 0 - C L 19 2 58 9 9 47 2 Fl a t XL 2 6 40 2 2 5 65 0 6 6 8 7 1 94 5 0 2 8 8 5 8 2 17 3 6 3 7 2 6 6 7 7 16 / 2 0 - C L 20 7 61 0 5 48 4 Fl a t XL 2 6 40 2 7 5 67 8 1 7 1 4 6 11 5 5 0 3 0 0 1 3 2 39 2 5 3 7 6 5 9 2 9 16 / 2 0 - C L 23 4 63 3 9 49 6 Fl a t XL 2 6 40 2 6 0 70 4 1 7 4 0 6 10 9 2 0 3 1 1 0 5 2 51 7 7 5 8 1 7 7 0 4 16 / 2 0 - C L 20 5 65 4 5 50 8 Fl a t XL 2 6 40 2 4 0 72 8 1 7 6 4 6 10 0 8 0 3 2 1 1 3 2 59 5 5 8 8 7 7 2 6 1 16 / 2 0 - C L 17 7 67 2 2 51 10 Fl a t XL 2 6 40 2 0 0 74 8 1 7 8 4 6 84 0 0 3 2 9 5 3 2 58 2 3 3 9 3 5 4 9 5 16 / 2 0 - C L 13 9 6 8 6 0 52 0 XL F l u s h XL 26 40 10 7 4 9 1 7 8 5 6 42 0 3 2 8 2 7 2 10 6 8 7 0 53 0 LG F l u s h WF 26 40 10 5 7 5 9 6 7 9 6 1 44 1 0 3 3 2 6 8 2 10 5 6 9 7 5 54 30 0 0 f e e t M D + S u r f a c e E q m t FP 20 7 0 76 6 6 8 0 3 1 29 4 9 3 3 5 6 3 1 TO T A L S 79 9 1 33 5 6 3 1 93 5 4 9 5 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 10 gal F103 Surfactant 1.0 Gal/mGal 913.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 456.0 gal J475 Breaker J475 6.0 lb/mGal 5,477.0 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,826.0 lbm J532 Crosslinker 2.5 Gal/mGal 2,282.0 gal J580 Gel J580 26.0 lb/mGal 23,736.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 68.0 gal M002 Additive 0.0 lb/mGal 2 lbm M117 Clay Control Agent 333.3 lb/mGal 304,304.0 lbm M275 Bactericide 0.3 lb/mGal 264.0 lbm S522-1620 Propping Agent varied concentrations 3,085,516.0 lbm S522-4070 Propping Agent varied concentrations 47,362.0 lbm ~ 70 % ~ 27 % ~ 3 % < 1 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % 100 % State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDBi-006 Basin/Field: Pikka Fluid Name & Volume Concentration Volume Disclosure Type: Pre-Job Well Completed: Date Prepared: 12/15/2025 CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF126ST:WF126 912,910 gal † Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate 7647-14-5 Sodium chloride 7727-54-0 Diammonium peroxodisulphate 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum 9003-35-4 Phenolic resin 50-70-4 Sorbitol 67-63-0 Propan-2-ol 56-81-5 1, 2, 3 - Propanetriol 102-71-6 2,2`,2"-nitrilotriethanol 1303-96-4 Sodium tetraborate decahydrate 68131-39-5 Ethoxylated Alcohol 37288-54-3 Beta-Mannanase 91053-39-3 Diatomaceous earth, calcined 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 14807-96-6 Magnesium silicate hydrate (talc) 9002-84-0 poly(tetrafluoroethylene) 111-42-2 2,2'-Iminodiethanol 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 127-08-2 Acetic acid, potassium salt (impurity) 14808-60-7 Quartz, Crystalline silica 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 63148-62-9 Dimethyl siloxanes and silicones 64-19-7 Acetic acid (impurity) 1310-73-2 Sodium hydroxide 68308-89-4 Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 14464-46-1 Cristobalite 532-32-1 Sodium benzoate 1338-41-6 Sorbitan stearate 9005-65-6 Sorbitan monooleate, ethoxylated 11138-66-2 Xanthan Gum 9004-32-4 Sodium carboxymethylcellulose 36089-45-9 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-propenoate 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9000-90-2 Amylase, alpha Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 7632-00-0 Sodium nitrite 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 2634-33-5 1,2-benzisothiazolin-3-one # SLB-Private Page: 1 / 1 Up d a t e d 1 2 / 1 6 / 2 0 2 5 12 / 1 6 / 2 0 2 5 TB D AK T S C A S t a t u s No r t h S l o p e TB D Pr e TB D TB D TB D Tr a d e N a m e S u p p l i e r P u r p o s e I n g r e d i e n t s N a m e C A S # Pe r c e n t a g e b y Ma s s o f In g r e d i e n t Pe r c e n t o f I n g r e d i e n t in T o t a l M a s s Pu m p e d Ma s s o f I n g r e d i e n t (l b s ) SM E T r a c e r c o C a r r i e r F l u i d S o y M e t h y l Es t e r 6 7 7 8 4 - 8 0 - 9 1 0 0 # V A LU E ! 1 1 2 . 6 5 6 0 8 2 0 0 0 0 T- 1 6 0 D T r a c e r c o C h e m i c a l T r a c e r 2 , 4 , 5 - T r i b r om o t o l u e n e 3 2 7 8 - 8 8 - 4 1 0 0 #V A L U E ! 0 . 6 6 1 3 8 6 0 0 0 0 T- 1 6 3 B T r a c e r c o C h e m i c a l T r a c e r 1 , 2 - D i i o d ob e n z e n e 6 1 5 - 4 2 - 9 10 0 # V A L U E ! 0 . 4 4 0 9 2 4 0 0 0 0 T- 1 6 4 C T r a c e r c o C h e m i c a l T r a c e r 1 - Io d o n a p h t h a l e n e 9 0 - 14 - 2 1 0 0 # V A L U E! 0 . 4 4 0 9 2 4 0 0 0 0 T- 1 6 5 C T r a c e r c o C h e m i c a l T r a c e r 9- B r o m o p h e n a n t h r e n e 57 3 - 1 7 - 1 1 0 0 #V A L U E ! 0. 6 6 1 3 8 6 0 0 0 0 T- 1 6 8 A T r a c e r c o C h e m i c a l T r a c e r 1 - C h l o r o - 4- i o d o b e n z e n e 6 3 7 - 87 - 6 1 0 0 # V A L U E! 0 . 4 4 0 9 2 4 0 0 0 0 T- 1 6 8 B T r a c e r c o C h e m i c a l T r a c e r 1 , 2 - D i c h l o r o - 4- i o d o b e n z e n e 2 0 5 5 5 - 9 1 - 3 1 0 0 # V A L U E ! 0 . 4 4 0 9 2 4 0 0 0 0 T- 1 6 8 C T r a c e r c o C h e m i c a l T r a c e r 1 - B r o m o - 4 - i o do b e n z e n e 5 8 9 - 8 7 - 7 1 0 0 # V A L U E ! 0 . 4 4 0 9 2 4 0 0 0 0 T- 7 1 6 T r a c e r c o C h e m i c a l T r a c e r 1 , 3 , 5 - T r ib r o m o b e n z e n e 6 2 6 - 39 - 1 1 0 0 # V A L U E! 0 . 4 4 0 9 2 4 0 0 0 0 T- 7 1 8 T r a c e r c o C h e m i c a l T r a c e r 4 - C h l o r o b e n z o p h e n o n e 1 3 4 - 8 5 - 0 1 0 0 # V A L U E ! 0 . 6 6 1 3 8 6 0 0 0 0 T- 7 2 9 T r a c e r c o C h e m i c a l T r a c e r 1 , 4- D i b r o m o - 2 , 5 - d i m e t h y l b e nz e n e 1 0 7 4 - 2 4 - 4 10 0 # V A L U E ! 2. 2 0 4 6 2 0 0 0 0 0 T- 7 3 1 T r a c e r c o C h e m i c a l T r a c e r 1 - Br o m o - 3 , 5 - d i c h l o r o b e n z e n e 1 9 7 5 2 - 5 5 - 7 1 0 0 # V A L U E ! 0 . 4 4 0 9 2 4 0 0 0 0 T- 7 4 8 T r a c e r c o C h e m i c a l T r a c e r 1 - B r o m o - 2 - ch l o r o b e n z e n e 6 9 4 - 8 0 - 4 1 0 0 # V A L U E ! 2 . 2 0 4 6 2 0 0 0 0 0 T- 7 5 0 T r a c e r c o C h e m i c a l T r a c e r 1 , 4 - D i b r o m o - 2 - f lu o r o b e n z e n e 1 4 3 5 - 5 2 - 5 1 0 0 # V A L U E ! 0 . 4 4 0 9 2 4 0 0 0 0 T- 7 5 8 T r a c e r c o C h e m i c a l T r a c e r 3 , 4 - D i f l u o r o be n z o p h e n on e 8 5 1 1 8 - 0 7 - 6 1 0 0 # V A L U E ! 0 . 4 4 0 9 2 4 0 0 0 0 T- 7 8 4 T r a c e r c o C h e m i c a l T r a c e r 2 , 4 , 6 - T r i b ro m o a n i s o l e 6 0 7 - 9 9 - 8 10 0 # V A L U E ! 0 . 44 0 9 2 4 0 0 0 0 Wa t e r T r a c e r c o C a r r i e r F l u i d W a t e r 7 7 3 2 - 1 8 - 5 1 0 0 # V A L U E ! 1 3 1 . 7 4 2 5 5 0 0 0 0 0 T- 1 4 0 a T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 2 - f lu o r o b e n z o a t e 4 9 0 - 9 7 - 1 1 0 0 # V A L U E ! 0. 7 7 1 6 1 7 0 0 0 0 T- 1 5 8 b T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 2 , 5 - D i f lu o r o b e n z o a t e 5 2 2 6 5 1 - 4 2 - 9 1 0 0 #V A L U E ! 0. 7 7 1 6 1 7 0 0 0 0 T- 1 5 8 d T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 3 , 4 - D i f lu o r o b e n z o a t e 5 2 2 6 5 1 - 4 4 - 1 1 0 0 #V A L U E ! 0. 7 7 1 6 1 7 0 0 0 0 T- 1 5 8 e T r a c e r c o C h e m i c a l T r a c e r S o di u m - 3 , 5 - D i f l u o r o b e n z o a t e 5 3 0 1 4 1 - 3 9 - 0 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 1 9 0 a T r a c e r c o C h e m i c a l T r a c e r S o d iu m - 2 - ( T r i f l u o r o m e t h y l ) b e n z oa t e 2 9 6 6 - 4 4 - 1 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 8 0 4 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 2 , 3 - d ic h l o r o b e n z o a t e 1 1 8 5 3 7 - 8 4 - 1 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 8 0 8 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 3 , 4 - d ic h l o r o b e n z o a t e 1 7 2 7 4 - 1 0 - 1 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 8 0 9 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 3 , 5 - d ic h l o r o b e n z o a t e 1 5 4 8 6 2 - 4 0 - 5 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 9 1 0 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 2 - c h l o r o- 3 - f l u o r o b e n z oa t e 1 3 8 2 1 0 6 - 8 3 - 3 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 9 1 1 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 2 - c h l o r o- 4 - f l u o r o b e n z oa t e 8 8 5 4 7 1 - 4 3 - 1 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 9 1 7 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 4 - c h l o r o - 2 , 5- d i f l u o r o b e n z o a t e 14 2 1 0 2 9 - 9 1 - 5 10 0 # V A L U E ! 0. 7 7 1 6 1 7 0 0 0 0 T- 9 2 1 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 3 - c h l o r o- 2 - f l u o r o b e n z oa t e 1 4 2 1 0 2 9 - 8 9 - 1 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 9 2 8 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 2 - f l u o r o -4 - m e t h y l b e n z o a te 1 7 0 8 9 4 2 - 1 9 - 1 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 9 3 1 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 4 - f l u o r o -2 - m e t h y l b e n z o a te 1 7 0 8 9 4 2 - 2 3 - 7 1 0 0 # V A L U E ! 0 . 7 7 1 6 1 7 0 0 0 0 T- 9 4 3 T r a c e r c o C h e m i c a l T r a c e r S o d i u m - 3 - c h l o ro - 2 - m e t h y l b e n z oa t e 1 7 0 8 9 4 2 - 1 7 - 9 10 0 # V A L U E ! 0. 7 7 1 6 1 7 0 0 0 0 Re p o r t T y p e ( P r e o r P o s t J o b ) To t a l W a t e r V o l u m e ( g a l ) : Wa t e r M a s s F r a c t i o n To t a l M a s s P u m p e d ( l b s ) Co u n t y : AP I N u m b e r : Op e r a t o r N a m e : O i l S e a r c h A l a s k a , L L C We l l N a m e a n d N u m b e r : N D B i - 0 6 / 0 1 2 Hy d r a u l i c F r a c t u r i n g F l u i d P r o d u c t C o m p o n e n t I n f o r m a t i o n D i s c l o s u r e Ma n u f a c t u r e r C o n t a c t T r a c e r c o 4 1 0 6 N e w W e s t D r . P a s a d e n a T e x a s 7 7 5 0 7 T e l : 2 8 1 - 2 9 1 - 7 7 6 9 Fr a c t u r e D a t e St a t e : Ap p r o v e d F o r T r a c e r c o Hydraulic Fracturing Chemical Information Disclosure Supplier: Patina Energy 20 Kg Patina Brass Flow Insurance Proprietary chemical information on ﬁle supplied by Patina Energy to the AOGCC. Attachment G NDBi-006 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: x Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. x Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. x Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. x Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. x Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. x Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 g Attachment H NDBi-006 4-1/2” Production Liner Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P-110S TSH563 lower completions per tally. 2. Drop 1.125” phenolic ball during circulation to close WIV collar. 3. Pressure up to close the WIV at 1,485 psi. 4. Continue increasing pressure to start setting the liner hanger/packer at 2,500 psi. 5. Set the openhole packers and neutralize pusher tool to 4,100 psi. 6. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi. 7. Release running tool from liner hanger. 8. Flow check for 10 minutes. 9. POOH with liner hanger running tool. 10.Prepare to run upper completion. NDBi-006 4-1/2” Upper Completion Section Summary Procedure: 11.Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 12.Circulate 9.2 ppg NaCl Corrosion Inhibited Brine. 13.Land tubing hanger. 14.MIT-T to 3,500 psi. (Post drilling rig move, MIT-T to be tested to 5,500 psi) a. (8,800 psi MAWP – 3,800 psi IA hold) * 1.1 = 5,500 psi 15.MIT-IA to 4,000 psi. (Post drilling rig move, MIT-IA to be tested to 4,300 psi) 16.Shear circulation valve. 17.Reverse circulate freeze protect and U-Tube. 18.Install TWCV into the tubing hanger and pressure test from direction of flow. 19.Nipple down BOP stack and install 10k frac tree. 20.RDMO NDBi-006 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 – 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment I Attachment J Tuluvak Sand @ 3256' MD Top Nan 3.2 @11,785' MD NDBi-006 Well Schematic As-Built 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2718' MD 13-3/8" 68 ppf L-80 Surface Casing2883' MD 9-5/8", 47ppf L-80 Production Liner 11,824' MD 4-½”, 12.6ppf P-110S Production Liner21,132' MD 4-½” Liner Hanger/ Top Packer11,652' MD GL 70.1' RKB – Bottom Flange 12/15/2025 9-5/8" Tieback2718' MD 9-5/8" Cflex Stage Tool (50' MD below TS790) 5305' MD 8-½” Openhole TD21,148' MD Fault 20,532'/20612' MD Fault ~11,600' MD 9-5/8" Cflex Stage Tool (Placed @ Top Nan FM.)10349' MD 9-5/8" Primary TOC~11,183' MD Fault 14,790' MD Top of Nan 10,334' MD 1 2 3 4 5 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 6 #CompletionItem TopDepth(MD') Depth(TVD') Inc ID" OD" 1XLandingNipple 1601 1463 27 3.813 4.784 2GasliftMandrel1.5" 2198 1978 46 3.865 7.630 3XLandingNipple 2268 2027 48 3.813 4.784 4D/HPsiͲTempGauge 11490 3978 78 3.905 5.040 5EGLValve 11554 3991 78 3.909 6.118 6TiebackSealAssy 11690 4014 78 3.860 5.230 7 9.625"x4.5"LH/Packer 11652 4006 78 6.030 8.480 8#25OHpacker 11939 4063 81 3.918 8.000 9#24OHpacker 12006 4072 83 3.918 8.000 10 Stage15 12238 4084 90 3.735 5.630 11 #23OHpacker 12550 4084 90 3.918 8.000 12 Stage14 12782 4085 90 3.735 5.630 13 #22OHpacker 13010 4085 90 3.918 8.000 14 #21OHpacker 13118 4085 90 3.918 8.000 15 #20OHpacker 13676 4087 90 3.918 8.000 16 #19OHpacker 13826 4087 90 3.918 8.000 17 Stage13 14098 4088 90 3.735 5.630 18 #18OHpacker 14409 4089 90 3.918 8.000 19 #17OHpacker 14517 4089 90 3.918 8.000 20 Stage12 14749 4089 90 3.735 5.630 Fault 14790 4089 90 21 #16OHpacker 14934 4090 90 3.918 8.000 22 #15OHpacker 15125 4090 90 3.918 8.000 23 Stage11 15357 4091 90 3.735 5.630 24 #14OHpacker 15628 4092 90 3.918 8.000 25 Stage10 15859 4093 90 3.735 5.630 26 #13OHpacker 16088 4095 90 3.918 8.000 27 Stage9 16360 4096 90 3.735 5.630 28 #12OHpacker 16627 4097 90 3.918 8.000 29 Stage8 16858 4098 90 3.735 5.630 30 #11OHpacker 17126 4099 90 3.918 8.000 31 Stage 7 17358 4100 90 3.735 5.630 32 #10OHpacker 17628 4100 90 3.918 8.000 33 Stage 6 17858 4100 90 3.735 5.630 34 #9OHpacker 18125 4100 90 3.918 8.000 35 Stage 5 18358 4101 90 3.735 5.630 36 #8OHpacker 18626 4101 90 3.918 8.000 37 Stage 4 18857 4102 90 3.735 5.630 38 #7OHpacker 19169 4103 90 3.918 8.000 39 Stage 3 19360 4103 90 3.735 5.630 40 #6OHpacker 19630 4104 90 3.918 8.000 41 Stage 2 19862 4104 90 3.735 5.630 42 #5OHpacker 20130 4101 92 3.918 8.000 43 #4OHpacker 20239 4097 92 3.918 8.000 Fault 20532Ͳ20612 4092 89 44 #3OHpacker 20676 4094 90 3.918 8.000 45 #2OHpacker 20783 4093 91 3.918 8.000 46 Stage1 21014 4093 90 3.735 5.630 47 #1OHpacker 21038 4093 90 3.918 8.000 48 Toe Sleeve 21104 4093 90 3.040 5.610 49 WIV Collar 21118 4093 90 0.880 5.610 50 Eccentricshoe 21130 4093 90 3.930 5.200 LinerToe 21132 4093 90 Attachment K Kinetix-Frac Completion Report Santos Country:United States Well Name:NDBi-006 Operator:Santos Field:Pikka Formation:Nanushuk Prepared By: Javier M. Del Real Report Date:December 11, 2025 Table of Contents Well Description ......................................................................................................................................................................................... 4 Stage 1 ....................................................................................................................................................................................................... 5 Zoneset Simulated: ................................................................................................................................................................................ 5 Pumping Schedule Simulated: ............................................................................................................................................................... 9 Simulation Summary: ........................................................................................................................................................................... 10 Stage 2 ..................................................................................................................................................................................................... 11 Zoneset Simulated: .............................................................................................................................................................................. 11 Pumping Schedule Simulated: ............................................................................................................................................................. 15 Simulation Summary: ........................................................................................................................................................................... 16 Stage 3 ..................................................................................................................................................................................................... 17 Zoneset Simulated: .............................................................................................................................................................................. 17 Pumping Schedule Simulated: ............................................................................................................................................................. 21 Simulation Summary: ........................................................................................................................................................................... 22 Stage 4 ..................................................................................................................................................................................................... 23 Zoneset Simulated: .............................................................................................................................................................................. 23 Pumping Schedule Simulated: ............................................................................................................................................................. 27 Simulation Summary: ........................................................................................................................................................................... 28 Stage 5 ..................................................................................................................................................................................................... 29 Zoneset Simulated: .............................................................................................................................................................................. 29 Pumping Schedule Simulated: ............................................................................................................................................................. 33 Simulation Summary: ........................................................................................................................................................................... 34 Stage 6 ..................................................................................................................................................................................................... 35 Zoneset Simulated: .............................................................................................................................................................................. 35 Pumping Schedule Simulated: ............................................................................................................................................................. 39 Simulation Summary: ........................................................................................................................................................................... 40 Stage 7 ..................................................................................................................................................................................................... 41 Zoneset Simulated: .............................................................................................................................................................................. 41 Pumping Schedule Simulated: ............................................................................................................................................................. 45 Simulation Summary: ........................................................................................................................................................................... 46 Stage 8 ..................................................................................................................................................................................................... 47 Zoneset Simulated: .............................................................................................................................................................................. 47 Pumping Schedule Simulated: ............................................................................................................................................................. 51 Simulation Summary: ........................................................................................................................................................................... 52 Attachment K: NDBI-006 Page 3 of 101 Stage 9 ..................................................................................................................................................................................................... 53 Zoneset Simulated: .............................................................................................................................................................................. 53 Pumping Schedule Simulated: ............................................................................................................................................................. 57 Simulation Summary: ........................................................................................................................................................................... 59 Stage 10 ................................................................................................................................................................................................... 60 Zoneset Simulated: .............................................................................................................................................................................. 60 Pumping Schedule Simulated: ............................................................................................................................................................. 64 Simulation Summary: ........................................................................................................................................................................... 65 Stage 11 ................................................................................................................................................................................................... 66 Zoneset Simulated: .............................................................................................................................................................................. 66 Pumping Schedule Simulated: ............................................................................................................................................................. 70 Simulation Summary: ........................................................................................................................................................................... 72 Stage 12 ................................................................................................................................................................................................... 73 Zoneset Simulated: .............................................................................................................................................................................. 73 Pumping Schedule Simulated: ............................................................................................................................................................. 80 Simulation Summary: ........................................................................................................................................................................... 81 Stage 13 ................................................................................................................................................................................................... 82 Zoneset Simulated: .............................................................................................................................................................................. 82 Pumping Schedule Simulated: ............................................................................................................................................................. 86 Simulation Summary: ........................................................................................................................................................................... 87 Stage 14 ................................................................................................................................................................................................... 88 Zoneset Simulated: .............................................................................................................................................................................. 88 Pumping Schedule Simulated: ............................................................................................................................................................. 92 Simulation Summary: ........................................................................................................................................................................... 93 Stage 15 ................................................................................................................................................................................................... 94 Zoneset Simulated: .............................................................................................................................................................................. 94 Pumping Schedule Simulated: ............................................................................................................................................................. 98 Simulation Summary: ......................................................................................................................................................................... 100 Attachment K: NDBI-006 Page 4 of 101 Well Description Completion Stages and Perforations Stage Perforation Top MD (ft) Perforation Bottom MD (ft) Spacing (ft) Perforation Top TVD (ft) Perforation Bottom TVD (ft) 15 12239 12245 538 4084.12 4084.15 14 12783 12789 1309 4084.45 4084.46 13 14098 14104 646 4087.84 4087.86 12 14750 14756 602 4089.21 4089.24 11 15358 15364 495 4090.65 4090.68 10 15859 15865 495 4093.29 4093.32 9 16360 16366 493 4095.66 4095.68 8 16859 16865 493 4097.9 4097.94 7 17358 17364 494 4099.49 4099.51 6 17858 17864 494 4100.14 4100.15 5 18358 18364 494 4100.73 4100.74 4 18858 18864 496 4101.93 4101.95 3 19360 19366 496 4103.12 4103.13 2 19862 19868 1170 4103.81 4103.82 1 21014 21020 0 4092.73 4092.72 Attachment K: NDBI-006 Page 5 of 101 Stage 1 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 1 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4371.8 psi ǣ Zoneset name: ZS-1 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4002.69 10 0.74 2953.69 1461000.3 0.22 2500 Shale 4012.7 15 0.7 2794.01 1762000.5 0.22 2500 Nanushuk 3 SS 4027.69 15.3 0.68 2735.99 1898000.5 0.22 2000 Top Nan 4043.01 6 0.66 2650.13 838900.2 0.27 1000 SHALE 4049.02 2 0.71 2879.58 2665000.7 0.23 2500 DIRTY-SANDSTONE 4050.98 1.5 0.64 2601.25 819400.2 0.27 1500 DIRTY-SANDSTONE 4052.49 2 0.65 2634.76 1222000.3 0.26 1500 CLEAN-SANDSTONE 4054.49 13 0.64 2578.77 869100.2 0.27 1000 CLEAN-SANDSTONE 4067.49 1.5 0.62 2542.66 1002000.3 0.27 1000 Attachment K: NDBI-006 Page 6 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) CLEAN-SANDSTONE 4069 4 0.65 2646.21 706600.2 0.28 1000 CLEAN-SANDSTONE 4073 9 0.61 2475.07 1166000.3 0.27 1000 CLEAN-SANDSTONE 4081.99 7 0.66 2675.95 769000.2 0.27 1000 CLEAN-SANDSTONE 4089.01 5.5 0.61 2483.63 1278000.4 0.26 1000 CLEAN-SANDSTONE 4094.49 13 0.65 2682.04 691700.2 0.28 1000 DIRTY-SANDSTONE 4107.51 2.5 0.69 2835.05 1748000.4 0.26 1500 DIRTY-SANDSTONE 4110.01 12.5 0.65 2667.39 1111000.3 0.27 1500 DIRTY-SANDSTONE 4122.51 4 0.7 2907.72 1692000.4 0.26 1500 DIRTY-SANDSTONE 4126.51 2.5 0.65 2691.32 822100.2 0.27 1500 SHALE 4129 2 0.71 2932.37 2665000.7 0.23 2500 DIRTY-SANDSTONE 4131 4 0.66 2727.72 1159000.3 0.27 1500 DIRTY-SANDSTONE 4135.01 4 0.64 2643.6 838300.2 0.27 1000 SHALE 4139.01 4 0.69 2853.18 2665000.7 0.23 2500 DIRTY-SANDSTONE 4143.01 6 0.65 2699.01 1133000.3 0.27 1500 SHALE 4149.02 2 0.71 2946.44 2665000.7 0.23 2500 DIRTY-SANDSTONE 4150.98 2 0.62 2553.53 1078000.3 0.27 1500 Attachment K: NDBI-006 Page 7 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) DIRTY-SANDSTONE 4152.99 6.5 0.67 2797.2 1694000.4 0.26 1500 DIRTY-SANDSTONE 4159.51 4 0.62 2592.55 898500.2 0.27 1500 DIRTY-SANDSTONE 4163.48 3.5 0.66 2728.16 929100.3 0.27 1500 SHALE 4166.99 2 0.71 2959.2 2665000.7 0.23 2500 DIRTY-SANDSTONE 4169 12.5 0.65 2718.15 1562000.4 0.26 1500 DIRTY-SANDSTONE 4181.5 2 0.66 2764.56 1397000.4 0.26 1500 SHALE 4183.5 2 0.69 2883.06 2665000.7 0.23 2500 DIRTY-SANDSTONE 4185.5 2 0.65 2725.4 1242000.3 0.26 1500 SHALE 4187.5 8 0.71 2976.03 2665000.7 0.23 2500 DIRTY-SANDSTONE 4195.51 2 0.63 2627.07 932500.2 0.27 1500 SHALE 4197.51 4 0.71 2981.69 2665000.7 0.23 2500 DIRTY-SANDSTONE 4201.51 6 0.66 2796.04 1427000.4 0.26 1500 SHALE 4207.51 8 0.71 2990.1 2665000.7 0.23 2500 DIRTY-SANDSTONE 4215.49 6.5 0.66 2784.43 1469000.4 0.26 1500 SHALE 4222.01 6 0.71 2995.46 2665000.7 0.23 2500 DIRTY-SANDSTONE 4227.99 2 0.65 2744.55 838400.2 0.27 1000 Attachment K: NDBI-006 Page 8 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) SHALE 4229.99 2 0.69 2915.11 2665000.7 0.23 2500 DIRTY-SANDSTONE 4231.99 4 0.67 2836.79 1469000.4 0.26 1500 SHALE 4235.99 2 0.71 3008.23 2665000.7 0.23 2500 DIRTY-SANDSTONE 4237.99 6 0.68 2866.96 1545000.4 0.26 1500 SHALE 4244 12 0.69 2928.31 2665000.7 0.23 2500 DIRTY-SANDSTONE 4256 2.5 0.63 2690.6 1214000.3 0.27 1500 SHALE 4258.5 20 0.71 3026.36 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 9 of 101 ǣ Name: Stage 1 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 1 PAD 30 YF126ST 13650 325 10.83 2 1 PPA 30 YF126ST 4826.4 120 CarboLite 16/20 1 4826.4 4 3 2 PPA 30 YF126ST 5207.9 135 CarboLite 16/20 2 10415.8 4.5 4 3 PPA 30 YF126ST 5374.4 145 CarboLite 16/20 3 16123.2 4.83 5 4 PPA 30 YF126ST 5171.8 145 CarboLite 16/20 4 20687.2 4.83 6 5 PPA 30 YF126ST 4983.9 145 CarboLite 16/20 5 24919.5 4.83 7 6 PPA 30 YF126ST 4809.2 145 CarboLite 16/20 6 28855.2 4.83 8 7 PPA 30 YF126ST 4326.2 135 CarboLite 16/20 7 30283.4 4.5 9 8 PPA 30 YF126ST 3564.5 115 CarboLite 16/20 8 28516 3.83 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.29 23.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 51914.3 164626.7 1409.99 47 Attachment K: NDBI-006 Page 10 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 1 MD: [21014, 21020] 4371.8 191.51 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4010.4 4201.91 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 1 MD: [21014, 21020] 735.7 151.84 0.38 Attachment K: NDBI-006 Page 11 of 101 Stage 2 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 2 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3457.7 psi ǣ Zoneset name: ZS-2 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4056.5 10 0.73 2981.11 1461000.3 0.22 1000 Shale 4066.5 15 0.7 2831.43 1762000.5 0.22 1000 Nanushuk 3 SS 4081.5 15.3 0.68 2772.4 1898000.5 0.22 1000 Top Nan CS 4096.78 19.5 0.64 2636.35 900400.2 0.27 1000 Nan SS 4116.31 2 0.69 2845.06 2665000.7 0.23 2500 Nan CS 4118.31 1.5 0.65 2693.79 1292000.4 0.26 1000 Nan CS 4119.78 4.5 0.62 2539.18 643500.2 0.28 1000 Nan DS 4124.28 3.5 0.69 2851.15 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 12 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4127.79 14.5 0.66 2733.24 1388000.3 0.26 1500 Nan CS 4142.29 1.5 0.66 2713.66 1145000.3 0.27 1000 Nan CS 4143.8 12.5 0.65 2680.88 882100.2 0.27 1000 Nan DS 4156.3 2 0.65 2698.14 1402000.4 0.26 1500 Nan CS 4158.3 9 0.61 2526.85 853600.2 0.27 1000 Nan DS 4167.29 7 0.67 2794.44 1397000.4 0.26 1500 Nan DS 4174.28 9 0.66 2745.42 1132000.3 0.27 1500 Nan DS 4183.3 3.5 0.66 2762.1 1688000.4 0.26 1500 Nan DS 4186.78 5 0.64 2672.76 757000.2 0.27 1000 Nan DS 4191.8 2 0.71 2968.49 1795000.5 0.25 1500 Nan CS 4193.8 10.5 0.63 2645.34 735600.2 0.27 1000 Nan CS 4204.3 3.5 0.64 2712.93 1098000.3 0.27 1000 Nan CS 4207.81 2 0.63 2651.58 670200.2 0.28 1000 Nan CS 4209.78 5.5 0.66 2776.02 1300000.3 0.26 1000 Nan DS 4215.29 3.5 0.71 2981.4 1531000.4 0.26 1500 Nan DS 4218.8 3.5 0.65 2739.18 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 13 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4222.28 5.5 0.7 2936.43 1416000.4 0.26 1500 Nan CS 4227.79 10.5 0.64 2700.75 1171000.3 0.27 1000 Nan DS 4238.29 1.5 0.66 2818.95 1376000.4 0.26 1500 Nan DS 4239.8 5 0.64 2710.76 1139000.3 0.27 1500 Nan DS 4244.78 2 0.67 2848.98 1560000.5 0.26 1500 Nan DS 4246.78 4 0.64 2727.72 896400.2 0.27 1500 Nan DS 4250.79 2 0.69 2916.71 1656000.4 0.26 1500 Nan DS 4252.79 10 0.63 2669.56 981000.2 0.27 1500 Nan DS 4262.8 4 0.65 2789.22 1633000.4 0.26 1500 Nan DS 4266.8 4 0.71 3018.09 1749000.4 0.26 1500 Nan DS 4270.8 9.5 0.65 2791.98 1327000.4 0.26 1500 Nan DS 4280.28 2 0.63 2688.71 781500.2 0.27 1000 Nan DS 4282.28 9.5 0.7 3018.09 1692000.4 0.26 1500 Nan DS 4291.8 2 0.66 2854.78 1365000.4 0.26 1500 Shale 4293.8 2 0.7 3010.69 2665000.7 0.23 2500 Nan DS 4295.8 2 0.64 2732.8 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 14 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4297.8 2 0.7 3013.45 2665000.7 0.23 2500 Nan DS 4299.8 4 0.66 2852.17 1287000.3 0.26 1500 Shale 4303.81 19.5 0.71 3058.27 2665000.7 0.23 2500 Nan DS 4323.29 2 0.65 2828.09 1356000.3 0.26 1500 Shale 4325.3 2 0.71 3067.4 2665000.7 0.23 2500 Nan DS 4327.3 8 0.66 2863.04 1373000.4 0.26 1500 Nan DS 4335.3 8 0.66 2881.32 1558000.4 0.26 1500 Shale 4343.31 20 0.71 3086.55 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 15 of 101 ǣ Name: Stage 2 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 2 PAD 25 YF126ST 13230 315 12.6 2 1 PPA 25 YF126ST 4022.1 100 CarboLite 16/20 1 4022.1 4 3 2 PPA 25 YF126ST 4629.2 120 CarboLite 16/20 2 9258.4 4.8 4 3 PPA 25 YF126ST 5003.7 135 CarboLite 16/20 3 15011.1 5.4 5 4 PPA 25 YF126ST 4815.1 135 CarboLite 16/20 4 19260.4 5.4 6 5 PPA 25 YF126ST 4640.3 135 CarboLite 16/20 5 23201.5 5.4 7 6 PPA 25 YF126ST 4477.8 135 CarboLite 16/20 6 26866.8 5.4 8 7 PPA 25 YF126ST 4005.5 125 CarboLite 16/20 7 28038.5 5 9 8 PPA 25 YF126ST 3409.5 110 CarboLite 16/20 8 27276 4.4 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.43 24.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 48233.2 152934.8 1310 52.4 Attachment K: NDBI-006 Page 16 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 2 MD: [19862, 19868] 3457.7 221.23 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4067.85 4289.08 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 2 MD: [19862, 19868] 517.57 181.33 0.3 Attachment K: NDBI-006 Page 17 of 101 Stage 3 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 3 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3375.8 psi ǣ Zoneset name: ZS-3 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4050.79 10 0.73 2976.9 1461000.3 0.22 1000 Shale 4060.79 15 0.7 2827.51 1762000.5 0.22 1000 Nanushuk 3 SS 4075.79 15.3 0.68 2768.63 1898000.5 0.22 1000 Top Nan CS 4091.11 19.5 0.64 2632.73 900400.2 0.27 1000 Nan SS 4110.6 2 0.69 2841.14 2665000.7 0.23 2500 Nan CS 4112.6 1.5 0.65 2690.16 1292000.4 0.26 1000 Nan CS 4114.11 4.5 0.62 2535.69 643500.2 0.28 1000 Nan DS 4118.6 3.5 0.69 2847.24 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 18 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4122.11 14.5 0.66 2729.47 1388000.3 0.26 1500 Nan CS 4136.61 1.5 0.66 2710.03 1145000.3 0.27 1000 Nan CS 4138.09 12.5 0.65 2677.25 882100.2 0.27 1000 Nan DS 4150.59 2 0.65 2694.37 1402000.4 0.26 1500 Nan CS 4152.59 9 0.61 2523.37 853600.2 0.27 1000 Nan DS 4161.61 7 0.67 2790.67 1397000.4 0.26 1500 Nan DS 4168.6 9 0.66 2741.79 1132000.3 0.27 1500 Nan DS 4177.59 3.5 0.66 2758.33 1688000.4 0.26 1500 Nan DS 4181.1 5 0.64 2669.13 757000.2 0.27 1000 Nan DS 4186.09 2 0.71 2964.43 1795000.5 0.25 1500 Nan CS 4188.09 10.5 0.63 2641.86 735600.2 0.27 1000 Nan CS 4198.59 3.5 0.64 2709.16 1098000.3 0.27 1000 Nan CS 4202.1 2 0.63 2647.95 670200.2 0.28 1000 Nan CS 4204.1 5.5 0.66 2772.25 1300000.3 0.26 1000 Nan DS 4209.61 3.5 0.71 2977.48 1531000.4 0.26 1500 Nan DS 4213.09 3.5 0.65 2735.41 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 19 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4216.6 5.5 0.7 2932.52 1416000.4 0.26 1500 Nan CS 4222.11 10.5 0.64 2697.12 1171000.3 0.27 1000 Nan DS 4232.61 1.5 0.66 2815.18 1376000.4 0.26 1500 Nan DS 4234.09 5 0.64 2707.13 1139000.3 0.27 1500 Nan DS 4239.11 2 0.67 2845.06 1560000.5 0.26 1500 Nan DS 4241.11 4 0.64 2724.1 896400.2 0.27 1500 Nan DS 4245.11 2 0.69 2912.79 1656000.4 0.26 1500 Nan DS 4247.11 10 0.63 2666.08 981000.2 0.27 1500 Nan DS 4257.09 4 0.65 2785.45 1633000.4 0.26 1500 Nan DS 4261.09 4 0.71 3014.03 1749000.4 0.26 1500 Nan DS 4265.09 9.5 0.65 2788.21 1327000.4 0.26 1500 Nan DS 4274.61 2 0.63 2685.08 781500.2 0.27 1000 Nan DS 4276.61 9.5 0.7 3014.03 1692000.4 0.26 1500 Nan DS 4286.09 2 0.66 2850.86 1365000.4 0.26 1500 Shale 4288.09 2 0.7 3006.63 2665000.7 0.23 2500 Nan DS 4290.09 2 0.64 2729.18 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 20 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4292.09 2 0.7 3009.39 2665000.7 0.23 2500 Nan DS 4294.09 4 0.66 2848.25 1287000.3 0.26 1500 Shale 4298.1 19.5 0.71 3054.2 2665000.7 0.23 2500 Nan DS 4317.59 2 0.65 2824.32 1356000.3 0.26 1500 Shale 4319.59 2 0.71 3063.34 2665000.7 0.23 2500 Nan DS 4321.59 8 0.66 2859.27 1373000.4 0.26 1500 Nan DS 4329.59 8 0.66 2877.55 1558000.4 0.26 1500 Shale 4337.6 20 0.71 3082.49 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 21 of 101 ǣ Name: Stage 3 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 3 PAD 25 YF126ST 13230 315 12.6 2 1 PPA 25 YF126ST 4022.2 100 CarboLite 16/20 1 4022.2 4 3 2 PPA 25 YF126ST 4629.2 120 CarboLite 16/20 2 9258.4 4.8 4 3 PPA 25 YF126ST 5003.7 135 CarboLite 16/20 3 15011.1 5.4 5 4 PPA 25 YF126ST 4815.1 135 CarboLite 16/20 4 19260.4 5.4 6 5 PPA 25 YF126ST 4640.3 135 CarboLite 16/20 5 23201.5 5.4 7 6 PPA 25 YF126ST 4477.8 135 CarboLite 16/20 6 26866.8 5.4 8 7 PPA 25 YF126ST 4005.5 125 CarboLite 16/20 7 28038.5 5 9 8 PPA 25 YF126ST 3409.5 110 CarboLite 16/20 8 27276 4.4 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.43 24.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 48233.3 152934.9 1310 52.4 Attachment K: NDBI-006 Page 22 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 3 MD: [19360, 19366] 3375.8 221.36 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4062.54 4283.9 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 3 MD: [19360, 19366] 520.51 179.53 0.27 Attachment K: NDBI-006 Page 23 of 101 Stage 4 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 4 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3965.5 psi ǣ Zoneset name: ZS-4 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4046.69 10 0.73 2974 1461000.3 0.22 1000 Shale 4056.69 15 0.7 2824.61 1762000.5 0.22 1000 Nanushuk 3 SS 4071.69 15.3 0.68 2765.87 1898000.5 0.22 1000 Top Nan CS 4087.01 19.5 0.64 2630.11 900400.2 0.27 1000 Nan SS 4106.5 2 0.69 2838.24 2665000.7 0.23 2500 Nan CS 4108.5 1.5 0.65 2687.4 1292000.4 0.26 1000 Nan CS 4110.01 4.5 0.62 2533.08 643500.2 0.28 1000 Nan DS 4114.5 3.5 0.69 2844.34 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 24 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4118.01 14.5 0.66 2726.85 1388000.3 0.26 1500 Nan CS 4132.51 1.5 0.66 2707.27 1145000.3 0.27 1000 Nan CS 4133.99 12.5 0.65 2674.64 882100.2 0.27 1000 Nan DS 4146.49 2 0.65 2691.76 1402000.4 0.26 1500 Nan CS 4148.49 9 0.61 2520.9 853600.2 0.27 1000 Nan DS 4157.51 7 0.67 2787.92 1397000.4 0.26 1500 Nan DS 4164.5 9 0.66 2739.04 1132000.3 0.27 1500 Nan DS 4173.49 3.5 0.66 2755.72 1688000.4 0.26 1500 Nan DS 4177 5 0.64 2666.52 757000.2 0.27 1000 Nan DS 4181.99 2 0.71 2961.53 1795000.5 0.25 1500 Nan CS 4183.99 10.5 0.63 2639.25 735600.2 0.27 1000 Nan CS 4194.49 3.5 0.64 2706.55 1098000.3 0.27 1000 Nan CS 4198 2 0.63 2645.34 670200.2 0.28 1000 Nan CS 4200 5.5 0.66 2769.64 1300000.3 0.26 1000 Nan DS 4205.51 3.5 0.71 2974.58 1531000.4 0.26 1500 Nan DS 4208.99 3.5 0.65 2732.8 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 25 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4212.5 5.5 0.7 2929.62 1416000.4 0.26 1500 Nan CS 4218.01 10.5 0.64 2694.51 1171000.3 0.27 1000 Nan DS 4228.51 1.5 0.66 2812.43 1376000.4 0.26 1500 Nan DS 4229.99 5 0.64 2704.52 1139000.3 0.27 1500 Nan DS 4235.01 2 0.67 2842.3 1560000.5 0.26 1500 Nan DS 4237.01 4 0.64 2721.49 896400.2 0.27 1500 Nan DS 4241.01 2 0.69 2910.04 1656000.4 0.26 1500 Nan DS 4243.01 10 0.63 2663.47 981000.2 0.27 1500 Nan DS 4252.99 4 0.65 2782.69 1633000.4 0.26 1500 Nan DS 4256.99 4 0.71 3011.13 1749000.4 0.26 1500 Nan DS 4260.99 9.5 0.65 2785.59 1327000.4 0.26 1500 Nan DS 4270.51 2 0.63 2682.47 781500.2 0.27 1000 Nan DS 4272.51 9.5 0.7 3011.13 1692000.4 0.26 1500 Nan DS 4281.99 2 0.66 2848.25 1365000.4 0.26 1500 Shale 4283.99 2 0.7 3003.73 2665000.7 0.23 2500 Nan DS 4285.99 2 0.64 2726.56 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 26 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4287.99 2 0.7 3006.63 2665000.7 0.23 2500 Nan DS 4289.99 4 0.66 2845.64 1287000.3 0.26 1500 Shale 4294 19.5 0.71 3051.3 2665000.7 0.23 2500 Nan DS 4313.48 2 0.65 2821.71 1356000.3 0.26 1500 Shale 4315.49 2 0.71 3060.44 2665000.7 0.23 2500 Nan DS 4317.49 8 0.66 2856.52 1373000.4 0.26 1500 Nan DS 4325.49 8 0.66 2874.79 1558000.4 0.26 1500 Shale 4333.5 20 0.71 3079.59 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 27 of 101 ǣ Name: Stage 4 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 STAGE 4 PAD 30 YF126ST 14700 350 11.67 2 1 PPA 30 YF126ST 4825.7 119.98 CarboLite 16/20 1 4825.7 4 3 2 PPA 30 YF126ST 5207.7 135 CarboLite 16/20 2 10415.4 4.5 4 3 PPA 30 YF126ST 5559.6 150 CarboLite 16/20 3 16678.8 5 5 4 PPA 30 YF126ST 5350.1 150 CarboLite 16/20 4 21400.4 5 6 5 PPA 30 YF126ST 5155.8 150 CarboLite 16/20 5 25779 5 7 6 PPA 30 YF126ST 4975.3 150 CarboLite 16/20 6 29851.8 5 8 7 PPA 30 YF126ST 4486.2 140 CarboLite 16/20 7 31403.4 4.67 9 8 PPA 30 YF126ST 3874.4 125 CarboLite 16/20 8 30995.2 4.17 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.15 23.81 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 54134.8 171349.7 1469.97 49 Attachment K: NDBI-006 Page 28 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 4 MD: [18858, 18864] 3965.5 225.39 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4056.56 4281.95 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 4 MD: [18858, 18864] 572.86 181.05 0.32 Attachment K: NDBI-006 Page 29 of 101 Stage 5 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 5 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5498.1 psi ǣ Zoneset name: ZS-5 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4042.81 10 0.73 2971.1 1461000.3 0.22 1000 Shale 4052.79 15 0.7 2821.85 1762000.5 0.22 1000 Nanushuk 3 SS 4067.81 15.3 0.68 2763.11 1898000.5 0.22 1000 Top Nan CS 4083.1 19.5 0.64 2627.65 900400.2 0.27 1000 Nan SS 4102.59 2 0.69 2835.63 2665000.7 0.23 2500 Nan CS 4104.59 1.5 0.65 2684.94 1292000.4 0.26 1000 Nan CS 4106.1 4.5 0.62 2530.76 643500.2 0.28 1000 Attachment K: NDBI-006 Page 30 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4110.6 3.5 0.69 2841.58 1774000.4 0.26 1500 Nan DS 4114.11 14.5 0.66 2724.24 1388000.3 0.26 1500 Nan CS 4128.61 1.5 0.66 2704.66 1145000.3 0.27 1000 Nan CS 4130.09 12.5 0.65 2672.03 882100.2 0.27 1000 Nan DS 4142.59 2 0.65 2689.14 1402000.4 0.26 1500 Nan CS 4144.59 9 0.61 2518.44 853600.2 0.27 1000 Nan DS 4153.61 7 0.67 2785.3 1397000.4 0.26 1500 Nan DS 4160.6 9 0.66 2736.43 1132000.3 0.27 1500 Nan DS 4169.59 3.5 0.66 2753.11 1688000.4 0.26 1500 Nan DS 4173.1 5 0.64 2664.05 757000.2 0.27 1000 Nan DS 4178.08 2 0.71 2958.77 1795000.5 0.25 1500 Nan CS 4180.09 10.5 0.63 2636.79 735600.2 0.27 1000 Nan CS 4190.58 3.5 0.64 2704.08 1098000.3 0.27 1000 Nan CS 4194.09 2 0.63 2642.88 670200.2 0.28 1000 Nan CS 4196.1 5.5 0.66 2767.03 1300000.3 0.26 1000 Nan DS 4201.61 3.5 0.71 2971.82 1531000.4 0.26 1500 Attachment K: NDBI-006 Page 31 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4205.09 3.5 0.65 2730.19 1193000.3 0.27 1500 Nan DS 4208.6 5.5 0.7 2926.86 1416000.4 0.26 1500 Nan CS 4214.11 10.5 0.64 2691.9 1171000.3 0.27 1000 Nan DS 4224.61 1.5 0.66 2809.82 1376000.4 0.26 1500 Nan DS 4226.12 5 0.64 2702.05 1139000.3 0.27 1500 Nan DS 4231.1 2 0.67 2839.69 1560000.5 0.26 1500 Nan DS 4233.1 4 0.64 2718.88 896400.2 0.27 1500 Nan DS 4237.11 2 0.69 2907.28 1656000.4 0.26 1500 Nan DS 4239.11 10 0.63 2661.01 981000.2 0.27 1500 Nan DS 4249.11 4 0.65 2780.23 1633000.4 0.26 1500 Nan DS 4253.08 4 0.71 3008.37 1749000.4 0.26 1500 Nan DS 4257.09 9.5 0.65 2782.98 1327000.4 0.26 1500 Nan DS 4266.6 2 0.63 2680.01 781500.2 0.27 1000 Nan DS 4268.6 9.5 0.7 3008.37 1692000.4 0.26 1500 Nan DS 4278.08 2 0.66 2845.64 1365000.4 0.26 1500 Shale 4280.09 2 0.7 3000.98 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 32 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4282.09 2 0.64 2724.1 1088000.3 0.27 1500 Shale 4284.09 2 0.7 3003.88 2665000.7 0.23 2500 Nan DS 4286.09 4 0.66 2843.03 1287000.3 0.26 1500 Shale 4290.09 19.5 0.71 3048.55 2665000.7 0.23 2500 Nan DS 4309.61 2 0.65 2819.1 1356000.3 0.26 1500 Shale 4311.61 2 0.71 3057.69 2665000.7 0.23 2500 Nan DS 4313.62 8 0.66 2853.91 1373000.4 0.26 1500 Nan DS 4321.59 8 0.66 2872.18 1558000.4 0.26 1500 Shale 4329.59 20 0.71 3076.83 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 33 of 101 ǣ Name: Stage 5 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 STAGE 5 PAD 40 YF126ST 15750 375 9.38 2 1 PPA 40 YF126ST 5027.5 125 CarboLite 16/20 1 5027.5 3.12 3 2 PPA 40 YF126ST 5400.5 140 CarboLite 16/20 2 10801 3.5 4 3 PPA 40 YF126ST 6300.9 170 CarboLite 16/20 3 18902.7 4.25 5 4 PPA 40 YF126ST 6063.6 170 CarboLite 16/20 4 24254.4 4.25 6 5 PPA 40 YF126ST 5843.3 170 CarboLite 16/20 5 29216.5 4.25 7 6 PPA 40 YF126ST 5638.5 170 CarboLite 16/20 6 33831 4.25 8 7 PPA 40 YF126ST 4486.2 140 CarboLite 16/20 7 31403.4 3.5 9 8 PPA 40 YF126ST 3874.5 125 CarboLite 16/20 8 30996 3.13 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.98 23.66 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 58385 184432.5 1584.98 39.62 Attachment K: NDBI-006 Page 34 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 5 MD: [18358, 18364] 5498.1 232.84 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4051.01 4283.85 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 5 MD: [18358, 18364] 635.29 196.11 0.34 Attachment K: NDBI-006 Page 35 of 101 Stage 6 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 6 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5385.1 psi ǣ Zoneset name: ZS-6 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4040.81 10 0.73 2969.65 1461000.3 0.22 1000 Shale 4050.79 15 0.7 2820.55 1762000.5 0.22 1000 Nanushuk 3 SS 4065.81 15.3 0.68 2761.81 1898000.5 0.22 1000 Top Nan CS 4081.1 19.5 0.64 2626.34 900400.2 0.27 1000 Nan SS 4100.59 2 0.69 2834.18 2665000.7 0.23 2500 Nan CS 4102.59 1.5 0.65 2683.63 1292000.4 0.26 1000 Nan CS 4104.1 4.5 0.62 2529.46 643500.2 0.28 1000 Nan DS 4108.6 3.5 0.69 2840.27 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 36 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4112.11 14.5 0.66 2722.94 1388000.3 0.26 1500 Nan CS 4126.61 1.5 0.66 2703.36 1145000.3 0.27 1000 Nan CS 4128.08 12.5 0.65 2670.72 882100.2 0.27 1000 Nan DS 4140.58 2 0.65 2687.84 1402000.4 0.26 1500 Nan CS 4142.59 9 0.61 2517.27 853600.2 0.27 1000 Nan DS 4151.61 7 0.67 2783.85 1397000.4 0.26 1500 Nan DS 4158.6 9 0.66 2735.12 1132000.3 0.27 1500 Nan DS 4167.59 3.5 0.66 2751.8 1688000.4 0.26 1500 Nan DS 4171.1 5 0.64 2662.75 757000.2 0.27 1000 Nan DS 4176.12 2 0.71 2957.32 1795000.5 0.25 1500 Nan CS 4178.08 10.5 0.63 2635.48 735600.2 0.27 1000 Nan CS 4188.62 3.5 0.64 2702.78 1098000.3 0.27 1000 Nan CS 4192.09 2 0.63 2641.72 670200.2 0.28 1000 Nan CS 4194.09 5.5 0.66 2765.72 1300000.3 0.26 1000 Nan DS 4199.61 3.5 0.71 2970.37 1531000.4 0.26 1500 Nan DS 4203.08 3.5 0.65 2728.89 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 37 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4206.59 5.5 0.7 2925.56 1416000.4 0.26 1500 Nan CS 4212.11 10.5 0.64 2690.74 1171000.3 0.27 1000 Nan DS 4222.6 1.5 0.66 2808.51 1376000.4 0.26 1500 Nan DS 4224.11 5 0.64 2700.75 1139000.3 0.27 1500 Nan DS 4229.1 2 0.67 2838.39 1560000.5 0.26 1500 Nan DS 4231.1 4 0.64 2717.72 896400.2 0.27 1500 Nan DS 4235.1 2 0.69 2905.98 1656000.4 0.26 1500 Nan DS 4237.11 10 0.63 2659.85 981000.2 0.27 1500 Nan DS 4247.11 4 0.65 2778.92 1633000.4 0.26 1500 Nan DS 4251.12 4 0.71 3006.92 1749000.4 0.26 1500 Nan DS 4255.09 9.5 0.65 2781.68 1327000.4 0.26 1500 Nan DS 4264.6 2 0.63 2678.85 781500.2 0.27 1000 Nan DS 4266.6 9.5 0.7 3007.07 1692000.4 0.26 1500 Nan DS 4276.12 2 0.66 2844.34 1365000.4 0.26 1500 Shale 4278.08 2 0.7 2999.67 2665000.7 0.23 2500 Nan DS 4280.09 2 0.64 2722.79 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 38 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4282.09 2 0.7 3002.43 2665000.7 0.23 2500 Nan DS 4284.09 4 0.66 2841.72 1287000.3 0.26 1500 Shale 4288.09 19.5 0.71 3047.24 2665000.7 0.23 2500 Nan DS 4307.61 2 0.65 2817.79 1356000.3 0.26 1500 Shale 4309.61 2 0.71 3056.24 2665000.7 0.23 2500 Nan DS 4311.61 8 0.66 2852.6 1373000.4 0.26 1500 Nan DS 4319.59 8 0.66 2870.88 1558000.4 0.26 1500 Shale 4327.59 20 0.71 3075.38 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 39 of 101 ǣ Name: Stage 6 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 6 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 6033.2 150 CarboLite 16/20 1 6033.2 3.75 3 2 PPA 40 YF126ST 6750.8 175 CarboLite 16/20 2 13501.6 4.38 4 3 PPA 40 YF126ST 7413 200 CarboLite 16/20 3 22239 5 5 4 PPA 40 YF126ST 7133.6 200 CarboLite 16/20 4 28534.4 5 6 5 PPA 40 YF126ST 6874.5 200 CarboLite 16/20 5 34372.5 5 7 6 PPA 40 YF126ST 6633.6 200 CarboLite 16/20 6 39801.6 5 8 7 PPA 40 YF126ST 5447.6 170 CarboLite 16/20 7 38133.2 4.25 9 8 PPA 40 YF126ST 4184.4 135 CarboLite 16/20 8 33475.2 3.38 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 24.97 21.86 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67270.7 216090.7 1830 45.75 Attachment K: NDBI-006 Page 40 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 6 MD: [17858, 17864] 5385.1 233.86 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4048.8 4282.66 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 6 MD: [17858, 17864] 649.58 198.24 0.34 Attachment K: NDBI-006 Page 41 of 101 Stage 7 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 7 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5261.7 psi ǣ Zoneset name: ZS-7 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4037.8 10 0.73 2967.47 1461000.3 0.22 1000 Shale 4047.8 15 0.7 2818.37 1762000.5 0.22 1000 Nanushuk 3 SS 4062.8 15.3 0.68 2759.78 1898000.5 0.22 1000 Top Nan CS 4078.08 19.5 0.64 2624.46 900400.2 0.27 1000 Nan SS 4097.6 2 0.69 2832.15 2665000.7 0.23 2500 Nan CS 4099.61 1.5 0.65 2681.6 1292000.4 0.26 1000 Nan CS 4101.12 4.5 0.62 2527.72 643500.2 0.28 1000 Nan DS 4105.61 3.5 0.69 2838.24 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 42 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4109.09 14.5 0.66 2720.91 1388000.3 0.26 1500 Nan CS 4123.59 1.5 0.66 2701.47 1145000.3 0.27 1000 Nan CS 4125.1 12.5 0.65 2668.84 882100.2 0.27 1000 Nan DS 4137.6 2 0.65 2685.95 1402000.4 0.26 1500 Nan CS 4139.6 9 0.61 2515.53 853600.2 0.27 1000 Nan DS 4148.59 7 0.67 2781.97 1397000.4 0.26 1500 Nan DS 4155.61 9 0.66 2733.24 1132000.3 0.27 1500 Nan DS 4164.6 3.5 0.66 2749.77 1688000.4 0.26 1500 Nan DS 4168.11 5 0.64 2660.86 757000.2 0.27 1000 Nan DS 4173.1 2 0.71 2955.29 1795000.5 0.25 1500 Nan CS 4175.1 10.5 0.63 2633.6 735600.2 0.27 1000 Nan CS 4185.6 3.5 0.64 2700.89 1098000.3 0.27 1000 Nan CS 4189.11 2 0.63 2639.83 670200.2 0.28 1000 Nan CS 4191.11 5.5 0.66 2763.69 1300000.3 0.26 1000 Nan DS 4196.59 3.5 0.71 2968.2 1531000.4 0.26 1500 Nan DS 4200.1 3.5 0.65 2727 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 43 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4203.61 5.5 0.7 2923.38 1416000.4 0.26 1500 Nan CS 4209.09 10.5 0.64 2688.71 1171000.3 0.27 1000 Nan DS 4219.59 1.5 0.66 2806.48 1376000.4 0.26 1500 Nan DS 4221.1 5 0.64 2698.86 1139000.3 0.27 1500 Nan DS 4226.12 2 0.67 2836.36 1560000.5 0.26 1500 Nan DS 4228.08 4 0.64 2715.69 896400.2 0.27 1500 Nan DS 4232.09 2 0.69 2903.95 1656000.4 0.26 1500 Nan DS 4234.09 10 0.63 2657.96 981000.2 0.27 1500 Nan DS 4244.09 4 0.65 2776.89 1633000.4 0.26 1500 Nan DS 4248.1 4 0.71 3004.89 1749000.4 0.26 1500 Nan DS 4252.1 9.5 0.65 2779.79 1327000.4 0.26 1500 Nan DS 4261.61 2 0.63 2676.96 781500.2 0.27 1000 Nan DS 4263.62 9.5 0.7 3004.89 1692000.4 0.26 1500 Nan DS 4273.1 2 0.66 2842.3 1365000.4 0.26 1500 Shale 4275.1 2 0.7 2997.49 2665000.7 0.23 2500 Nan DS 4277.1 2 0.64 2720.91 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 44 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4279.1 2 0.7 3000.4 2665000.7 0.23 2500 Nan DS 4281.1 4 0.66 2839.69 1287000.3 0.26 1500 Shale 4285.1 19.5 0.71 3045.07 2665000.7 0.23 2500 Nan DS 4304.59 2 0.65 2815.91 1356000.3 0.26 1500 Shale 4306.59 2 0.71 3054.06 2665000.7 0.23 2500 Nan DS 4308.6 8 0.66 2850.57 1373000.4 0.26 1500 Nan DS 4316.6 8 0.66 2868.85 1558000.4 0.26 1500 Shale 4324.61 20 0.71 3073.2 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 45 of 101 ǣ Name: Stage 7 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 7 PAD 40 YF126ST 15750 375 9.38 2 1 PPA 40 YF126ST 5027.5 125 CarboLite 16/20 1 5027.5 3.12 3 2 PPA 40 YF126ST 5400.5 140 CarboLite 16/20 2 10801 3.5 4 3 PPA 40 YF126ST 6300.9 170 CarboLite 16/20 3 18902.7 4.25 5 4 PPA 40 YF126ST 6063.6 170 CarboLite 16/20 4 24254.4 4.25 6 5 PPA 40 YF126ST 5843.3 170 CarboLite 16/20 5 29216.5 4.25 7 6 PPA 40 YF126ST 5638.5 170 CarboLite 16/20 6 33831 4.25 8 7 PPA 40 YF126ST 4486.2 140 CarboLite 16/20 7 31403.4 3.5 9 8 PPA 40 YF126ST 3874.5 125 CarboLite 16/20 8 30996 3.13 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.98 23.66 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 58385 184432.5 1584.98 39.62 Attachment K: NDBI-006 Page 46 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 7 MD: [17358, 17364] 5261.7 260.29 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4037.25 4297.54 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 7 MD: [17358, 17364] 566.89 226.9 0.31 Attachment K: NDBI-006 Page 47 of 101 Stage 8 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 8 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5544.8 psi ǣ Zoneset name: ZS-8 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4032.81 10 0.73 2963.7 1461000.3 0.22 1000 Shale 4042.81 15 0.7 2815.04 1762000.5 0.22 1000 Nanushuk 3 SS 4057.81 15.3 0.68 2756.44 1898000.5 0.22 1000 Top Nan CS 4073.1 19.5 0.64 2621.12 900400.2 0.27 1000 Nan SS 4092.59 2 0.69 2828.67 2665000.7 0.23 2500 Nan CS 4094.59 1.5 0.65 2678.41 1292000.4 0.26 1000 Nan CS 4096.1 4.5 0.62 2524.53 643500.2 0.28 1000 Nan DS 4100.59 3.5 0.69 2834.76 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 48 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4104.1 14.5 0.66 2717.57 1388000.3 0.26 1500 Nan CS 4118.6 1.5 0.66 2698.14 1145000.3 0.27 1000 Nan CS 4120.11 12.5 0.65 2665.65 882100.2 0.27 1000 Nan DS 4132.61 2 0.65 2682.76 1402000.4 0.26 1500 Nan CS 4134.61 9 0.61 2512.49 853600.2 0.27 1000 Nan DS 4143.6 7 0.67 2778.49 1397000.4 0.26 1500 Nan DS 4150.59 9 0.66 2729.9 1132000.3 0.27 1500 Nan DS 4159.61 3.5 0.66 2746.43 1688000.4 0.26 1500 Nan DS 4163.09 5 0.64 2657.67 757000.2 0.27 1000 Nan DS 4168.11 2 0.71 2951.66 1795000.5 0.25 1500 Nan CS 4170.11 10.5 0.63 2630.55 735600.2 0.27 1000 Nan CS 4180.61 3.5 0.64 2697.56 1098000.3 0.27 1000 Nan CS 4184.09 2 0.63 2636.64 670200.2 0.28 1000 Nan CS 4186.09 5.5 0.66 2760.5 1300000.3 0.26 1000 Nan DS 4191.6 3.5 0.71 2964.72 1531000.4 0.26 1500 Nan DS 4195.11 3.5 0.65 2723.81 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 49 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4198.59 5.5 0.7 2919.9 1416000.4 0.26 1500 Nan CS 4204.1 10.5 0.64 2685.52 1171000.3 0.27 1000 Nan DS 4214.6 1.5 0.66 2803.14 1376000.4 0.26 1500 Nan DS 4216.11 5 0.64 2695.67 1139000.3 0.27 1500 Nan DS 4221.1 2 0.67 2833.02 1560000.5 0.26 1500 Nan DS 4223.1 4 0.64 2712.5 896400.2 0.27 1500 Nan DS 4227.1 2 0.69 2900.46 1656000.4 0.26 1500 Nan DS 4229.1 10 0.63 2654.77 981000.2 0.27 1500 Nan DS 4239.11 4 0.65 2773.7 1633000.4 0.26 1500 Nan DS 4243.11 4 0.71 3001.27 1749000.4 0.26 1500 Nan DS 4247.11 9.5 0.65 2776.46 1327000.4 0.26 1500 Nan DS 4256.59 2 0.63 2673.77 781500.2 0.27 1000 Nan DS 4258.6 9.5 0.7 3001.41 1692000.4 0.26 1500 Nan DS 4268.11 2 0.66 2838.97 1365000.4 0.26 1500 Shale 4270.11 2 0.7 2994.01 2665000.7 0.23 2500 Nan DS 4272.11 2 0.64 2717.72 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 50 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4274.11 2 0.7 2996.91 2665000.7 0.23 2500 Nan DS 4276.12 4 0.66 2836.36 1287000.3 0.26 1500 Shale 4280.09 19.5 0.71 3041.44 2665000.7 0.23 2500 Nan DS 4299.61 2 0.65 2812.57 1356000.3 0.26 1500 Shale 4301.61 2 0.71 3050.58 2665000.7 0.23 2500 Nan DS 4303.61 8 0.66 2847.38 1373000.4 0.26 1500 Nan DS 4311.61 8 0.66 2865.51 1558000.4 0.26 1500 Shale 4319.59 20 0.71 3069.72 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 51 of 101 ǣ Name: Stage 8 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 8 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 8044.5 200 CarboLite 16/20 1 8044.5 5 3 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 4 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 5 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 6 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 7 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.76 22.22 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 65213.3 234071.1 1800 45 Attachment K: NDBI-006 Page 52 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 8 MD: [16859, 16865] 5544.8 232.52 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4040.79 4273.31 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 8 MD: [16859, 16865] 675.58 194.61 0.38 Attachment K: NDBI-006 Page 53 of 101 Stage 9 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 9 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5468.8 psi ǣ Zoneset name: ZS-9 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4029.79 10 0.73 2961.53 1461000.3 0.22 1000 Shale 4039.8 15 0.7 2812.86 1762000.5 0.22 1000 Nanushuk 3 SS 4054.79 15.3 0.68 2754.41 1898000.5 0.22 1000 Top Nan CS 4070.11 19.5 0.64 2619.24 900400.2 0.27 1000 Nan SS 4089.6 2 0.69 2826.64 2665000.7 0.23 2500 Nan CS 4091.6 1.5 0.65 2676.38 1292000.4 0.26 1000 Nan CS 4093.11 4.5 0.62 2522.79 643500.2 0.28 1000 Nan DS 4097.6 3.5 0.69 2832.59 1774000.4 0.26 1500 Nan DS 4101.12 14.5 0.66 2715.69 1388000.3 0.26 1500 Attachment K: NDBI-006 Page 54 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan CS 4115.58 1.5 0.66 2696.25 1145000.3 0.27 1000 Nan CS 4117.09 12.5 0.65 2663.62 882100.2 0.27 1000 Nan DS 4129.59 2 0.65 2680.73 1402000.4 0.26 1500 Nan CS 4131.59 9 0.61 2510.6 853600.2 0.27 1000 Nan DS 4140.58 7 0.67 2776.6 1397000.4 0.26 1500 Nan DS 4147.6 9 0.66 2727.87 1132000.3 0.27 1500 Nan DS 4156.59 3.5 0.66 2744.55 1688000.4 0.26 1500 Nan DS 4160.1 5 0.64 2655.79 757000.2 0.27 1000 Nan DS 4165.09 2 0.71 2949.63 1795000.5 0.25 1500 Nan CS 4167.09 10.5 0.63 2628.52 735600.2 0.27 1000 Nan CS 4177.59 3.5 0.64 2695.67 1098000.3 0.27 1000 Nan CS 4181.1 2 0.63 2634.76 670200.2 0.28 1000 Nan CS 4183.1 5.5 0.66 2758.47 1300000.3 0.26 1000 Nan DS 4188.62 3.5 0.71 2962.54 1531000.4 0.26 1500 Nan DS 4192.09 3.5 0.65 2721.78 1193000.3 0.27 1500 Nan DS 4195.6 5.5 0.7 2917.87 1416000.4 0.26 1500 Attachment K: NDBI-006 Page 55 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan CS 4201.12 10.5 0.64 2683.63 1171000.3 0.27 1000 Nan DS 4211.61 1.5 0.66 2801.26 1376000.4 0.26 1500 Nan DS 4213.09 5 0.64 2693.79 1139000.3 0.27 1500 Nan DS 4218.11 2 0.67 2830.99 1560000.5 0.26 1500 Nan DS 4220.11 4 0.64 2710.61 896400.2 0.27 1500 Nan DS 4224.11 2 0.69 2898.43 1656000.4 0.26 1500 Nan DS 4226.12 10 0.63 2652.89 981000.2 0.27 1500 Nan DS 4236.09 4 0.65 2771.67 1633000.4 0.26 1500 Nan DS 4240.09 4 0.71 2999.09 1749000.4 0.26 1500 Nan DS 4244.09 9.5 0.65 2774.57 1327000.4 0.26 1500 Nan DS 4253.61 2 0.63 2671.89 781500.2 0.27 1000 Nan DS 4255.61 9.5 0.7 2999.24 1692000.4 0.26 1500 Nan DS 4265.09 2 0.66 2836.94 1365000.4 0.26 1500 Shale 4267.09 2 0.7 2991.98 2665000.7 0.23 2500 Nan DS 4269.09 2 0.64 2715.83 1088000.3 0.27 1500 Shale 4271.1 2 0.7 2994.74 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 56 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4273.1 4 0.66 2834.33 1287000.3 0.26 1500 Shale 4277.1 19.5 0.71 3039.41 2665000.7 0.23 2500 Nan DS 4296.59 2 0.65 2810.69 1356000.3 0.26 1500 Shale 4298.59 2 0.71 3048.4 2665000.7 0.23 2500 Nan DS 4300.59 8 0.66 2845.35 1373000.4 0.26 1500 Nan DS 4308.6 8 0.66 2863.63 1558000.4 0.26 1500 Shale 4316.6 20 0.71 3067.55 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 57 of 101 ǣ Name: Stage 9 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 9 PAD 40 YF126ST 10500 250 6.25 2 1 PPA Scour 40 YF126ST 2414.8 60 CarboLite 40/70 1 2414.8 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8044.5 200 CarboLite 16/20 1 8044.5 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 28.68 24.66 Attachment K: NDBI-006 Page 58 of 101 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67885.6 249858.4 1880.01 47 Attachment K: NDBI-006 Page 59 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 9 MD: [16360, 16366] 5468.8 223.76 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4040.61 4264.37 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 9 MD: [16360, 16366] 542.3 180.33 0.59 Attachment K: NDBI-006 Page 60 of 101 Stage 10 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 10 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5256.3 psi ǣ Zoneset name: ZS-10 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4025.79 10 0.73 2958.62 1461000.3 0.22 1000 Shale 4035.79 15 0.7 2810.11 1762000.5 0.22 1000 Nanushuk 3 SS 4050.79 15.3 0.68 2751.66 1898000.5 0.22 1000 Top Nan CS 4066.11 19.5 0.64 2616.63 900400.2 0.27 1000 Nan SS 4085.6 2 0.69 2823.88 2665000.7 0.23 2500 Nan CS 4087.6 1.5 0.65 2673.77 1292000.4 0.26 1000 Nan CS 4089.11 4.5 0.62 2520.32 643500.2 0.28 1000 Nan DS 4093.6 3.5 0.69 2829.83 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 61 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4097.11 14.5 0.66 2712.93 1388000.3 0.26 1500 Nan CS 4111.61 1.5 0.66 2693.64 1145000.3 0.27 1000 Nan CS 4113.09 12.5 0.65 2661.15 882100.2 0.27 1000 Nan DS 4125.59 2 0.65 2678.12 1402000.4 0.26 1500 Nan CS 4127.59 9 0.61 2508.14 853600.2 0.27 1000 Nan DS 4136.61 7 0.67 2773.85 1397000.4 0.26 1500 Nan DS 4143.6 9 0.66 2725.26 1132000.3 0.27 1500 Nan DS 4152.59 3.5 0.66 2741.94 1688000.4 0.26 1500 Nan DS 4156.1 5 0.64 2653.18 757000.2 0.27 1000 Nan DS 4161.09 2 0.71 2946.73 1795000.5 0.25 1500 Nan CS 4163.09 10.5 0.63 2626.05 735600.2 0.27 1000 Nan CS 4173.59 3.5 0.64 2693.06 1098000.3 0.27 1000 Nan CS 4177.1 2 0.63 2632.14 670200.2 0.28 1000 Nan CS 4179.1 5.5 0.66 2755.86 1300000.3 0.26 1000 Nan DS 4184.61 3.5 0.71 2959.79 1531000.4 0.26 1500 Nan DS 4188.09 3.5 0.65 2719.17 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 62 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4191.6 5.5 0.7 2915.11 1416000.4 0.26 1500 Nan CS 4197.11 10.5 0.64 2681.17 1171000.3 0.27 1000 Nan DS 4207.61 1.5 0.66 2798.5 1376000.4 0.26 1500 Nan DS 4209.09 5 0.64 2691.18 1139000.3 0.27 1500 Nan DS 4214.11 2 0.67 2828.38 1560000.5 0.26 1500 Nan DS 4216.11 4 0.64 2708 896400.2 0.27 1500 Nan DS 4220.11 2 0.69 2895.68 1656000.4 0.26 1500 Nan DS 4222.11 10 0.63 2650.42 981000.2 0.27 1500 Nan DS 4232.09 4 0.65 2769.06 1633000.4 0.26 1500 Nan DS 4236.09 4 0.71 2996.33 1749000.4 0.26 1500 Nan DS 4240.09 9.5 0.65 2771.82 1327000.4 0.26 1500 Nan DS 4249.61 2 0.63 2669.42 781500.2 0.27 1000 Nan DS 4251.61 9.5 0.7 2996.48 1692000.4 0.26 1500 Nan DS 4261.09 2 0.66 2834.33 1365000.4 0.26 1500 Shale 4263.09 2 0.7 2989.08 2665000.7 0.23 2500 Nan DS 4265.09 2 0.64 2713.22 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 63 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4267.09 2 0.7 2991.98 2665000.7 0.23 2500 Nan DS 4269.09 4 0.66 2831.72 1287000.3 0.26 1500 Shale 4273.1 19.5 0.71 3036.51 2665000.7 0.23 2500 Nan DS 4292.59 2 0.65 2808.08 1356000.3 0.26 1500 Shale 4294.59 2 0.71 3045.5 2665000.7 0.23 2500 Nan DS 4296.59 8 0.66 2842.74 1373000.4 0.26 1500 Nan DS 4304.59 8 0.66 2860.87 1558000.4 0.26 1500 Shale 4312.6 20 0.71 3064.79 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 64 of 101 ǣ Name: Stage 10 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 7642.2 190 CarboLite 16/20 1 7642.2 4.75 3 3 PPA 40 YF126ST 7969 215 CarboLite 16/20 3 23907 5.37 4 5 PPA 40 YF126ST 8249.6 240 CarboLite 16/20 5 41248 6 5 7 PPA 40 YF126ST 7690.8 240 CarboLite 16/20 7 53835.6 6 6 9 PPA 40 YF126ST 6602.8 220 CarboLite 16/20 9 59425.2 5.5 7 10 PPA 40 YF126ST 5236.2 180 CarboLite 16/20 10 52362 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.91 23.74 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 60190.6 238420 1685.01 42.13 Attachment K: NDBI-006 Page 65 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 10 MD: [15859, 15865] 5256.3 232.87 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4033.78 4266.65 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 10 MD: [15859, 15865] 657.57 196.82 0.36 Attachment K: NDBI-006 Page 66 of 101 Stage 11 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 11 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5105.3 psi ǣ Zoneset name: ZS-11 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4020.8 10 0.73 2955 1461000.3 0.22 1000 Shale 4030.81 15 0.7 2806.63 1762000.5 0.22 1000 Nanushuk 3 SS 4045.8 15.3 0.68 2748.18 1898000.5 0.22 1000 Top Nan CS 4061.09 19.5 0.64 2613.43 900400.2 0.27 1000 Nan SS 4080.61 2 0.69 2820.4 2665000.7 0.23 2500 Nan CS 4082.61 1.5 0.65 2670.58 1292000.4 0.26 1000 Nan CS 4084.09 4.5 0.62 2517.13 643500.2 0.28 1000 Nan DS 4088.62 3.5 0.69 2826.5 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 67 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4092.09 14.5 0.66 2709.6 1388000.3 0.26 1500 Nan CS 4106.59 1.5 0.66 2690.3 1145000.3 0.27 1000 Nan CS 4108.1 12.5 0.65 2657.82 882100.2 0.27 1000 Nan DS 4120.6 2 0.65 2674.93 1402000.4 0.26 1500 Nan CS 4122.6 9 0.61 2505.09 853600.2 0.27 1000 Nan DS 4131.59 7 0.67 2770.51 1397000.4 0.26 1500 Nan DS 4138.62 9 0.66 2722.07 1132000.3 0.27 1500 Nan DS 4147.6 3.5 0.66 2738.6 1688000.4 0.26 1500 Nan DS 4151.12 5 0.64 2649.98 757000.2 0.27 1000 Nan DS 4156.1 2 0.71 2943.25 1795000.5 0.25 1500 Nan CS 4158.1 10.5 0.63 2622.86 735600.2 0.27 1000 Nan CS 4168.6 3.5 0.64 2689.87 1098000.3 0.27 1000 Nan CS 4172.11 2 0.63 2629.1 670200.2 0.28 1000 Nan CS 4174.11 5.5 0.66 2752.53 1300000.3 0.26 1000 Nan DS 4179.59 3.5 0.71 2956.16 1531000.4 0.26 1500 Nan DS 4183.1 3.5 0.65 2715.98 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 68 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4186.61 5.5 0.7 2911.63 1416000.4 0.26 1500 Nan CS 4192.09 10.5 0.64 2677.98 1171000.3 0.27 1000 Nan DS 4202.59 1.5 0.66 2795.17 1376000.4 0.26 1500 Nan DS 4204.1 5 0.64 2687.98 1139000.3 0.27 1500 Nan DS 4209.09 2 0.67 2824.9 1560000.5 0.26 1500 Nan DS 4211.09 4 0.64 2704.81 896400.2 0.27 1500 Nan DS 4215.09 2 0.69 2892.2 1656000.4 0.26 1500 Nan DS 4217.09 10 0.63 2647.23 981000.2 0.27 1500 Nan DS 4227.1 4 0.65 2765.87 1633000.4 0.26 1500 Nan DS 4231.1 4 0.71 2992.85 1749000.4 0.26 1500 Nan DS 4235.1 9.5 0.65 2768.63 1327000.4 0.26 1500 Nan DS 4244.59 2 0.63 2666.23 781500.2 0.27 1000 Nan DS 4246.59 9.5 0.7 2993 1692000.4 0.26 1500 Nan DS 4256.1 2 0.66 2830.99 1365000.4 0.26 1500 Shale 4258.1 2 0.7 2985.6 2665000.7 0.23 2500 Nan DS 4260.1 2 0.64 2710.03 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 69 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 4262.11 2 0.7 2988.5 2665000.7 0.23 2500 Nan DS 4264.11 4 0.66 2828.38 1287000.3 0.26 1500 Shale 4268.11 19.5 0.71 3033.03 2665000.7 0.23 2500 Nan DS 4287.6 2 0.65 2804.74 1356000.3 0.26 1500 Shale 4289.6 2 0.71 3042.02 2665000.7 0.23 2500 Nan DS 4291.6 8 0.66 2839.4 1373000.4 0.26 1500 Nan DS 4299.61 8 0.66 2857.53 1558000.4 0.26 1500 Shale 4307.61 20 0.71 3061.17 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 70 of 101 ǣ Name: Stage 11 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 11 PAD 40 YF126ST 10500 250 6.25 2 1 PPA Scour 40 YF126ST 2414.8 60 CarboLite 40/70 1 2414.8 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8044.5 200 CarboLite 16/20 1 8044.5 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 28.68 24.66 Attachment K: NDBI-006 Page 71 of 101 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67885.6 249858.4 1880.01 47 Attachment K: NDBI-006 Page 72 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 11 MD: [15358, 15364] 5105.3 267.02 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4016.73 4283.75 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 11 MD: [15358, 15364] 614.67 242.22 0.35 Attachment K: NDBI-006 Page 73 of 101 Stage 12 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 12 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4461.1 psi ǣ Zoneset name: ZS-12 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 3998.2 10 0.71 2854.34 1461000.3 0.22 1000 Shale 4008.2 15 0.7 2790.96 1762000.5 0.22 1000 Siltstone 4023.2 15.3 0.68 2732.95 1898000.5 0.22 1000 Top Nan CS 4038.48 17.5 0.62 2525.54 818100.2 0.27 1000 Nan DS 4056 2 0.6 2434.17 784600.2 0.27 1000 Nan DS 4058.01 5.5 0.63 2554.26 1248000.4 0.26 1500 SHALE 4063.48 3.5 0.69 2813.15 2665000.7 0.23 2500 Nan DS 4066.99 1.5 0.64 2587.04 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 74 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4068.5 2 0.64 2584.14 913900.3 0.27 1500 Nan CS 4070.51 1.5 0.61 2487.54 669900.2 0.28 1000 Nan CS 4072.01 2 0.64 2610.82 1249000.4 0.26 1000 Nan CS 4074.02 1.5 0.6 2444.9 771600.2 0.27 1000 SHALE 4075.49 2 0.69 2820.98 2665000.7 0.23 2500 Nan CS 4077.49 4.5 0.61 2484.5 873800.2 0.27 1000 Nan DS 4081.99 7 0.66 2675.95 1417000.3 0.26 1500 Nan DS 4089.01 2.5 0.61 2495.08 757700.2 0.27 1000 Nan DS 4091.5 2 0.68 2787.05 1692000.4 0.26 1500 Nan DS 4093.5 5 0.61 2506.69 997700.3 0.27 1500 Nan CS 4098.49 4.5 0.64 2640.85 1120000.3 0.27 1000 Nan CS 4102.99 9.5 0.61 2505.67 778000.2 0.27 1000 Nan DS 4112.5 2.5 0.64 2640.99 1685000.4 0.26 1500 Nan DS 4114.99 12 0.62 2563.25 964800.3 0.27 1500 Nan DS 4127 2.5 0.66 2708.14 1469000.4 0.26 1500 Nan DS 4129.49 9.5 0.63 2621.12 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 75 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4139.01 2 0.65 2674.5 1444000.4 0.26 1500 Nan DS 4141.01 41 0.63 2609.23 1021000.3 0.27 1500 Nan DS 4181.99 1.5 0.62 2610.1 862400.2 0.27 1000 Nan CS 4183.5 6 0.62 2608.21 764700.2 0.28 1000 Nan DS 4189.5 6 0.67 2804.74 1242000.3 0.26 1500 Nan DS 4195.51 4 0.69 2896.26 1692000.4 0.26 1500 Nan DS 4199.51 2 0.64 2700.89 1009000.2 0.27 1500 Nan DS 4201.51 2 0.69 2887.12 1692000.4 0.26 1500 Nan DS 4203.51 2 0.63 2661.44 1134000.3 0.27 1500 Nan DS 4205.51 5.5 0.69 2899.45 1692000.4 0.26 1500 Nan DS 4210.99 4 0.62 2633.16 949900.2 0.27 1000 Nan DS 4214.99 2 0.68 2866.82 1692000.4 0.26 1500 Nan DS 4216.99 12 0.63 2656.22 919900.3 0.27 1000 Nan DS 4229 4 0.68 2898.29 1428000.4 0.26 1500 Nan DS 4233.01 4 0.64 2689.29 1474000.5 0.26 1500 SHALE 4237.01 2 0.68 2894.52 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 76 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4239.01 1.5 0.64 2721.92 1373000.4 0.26 1500 SHALE 4240.49 8 0.69 2924.4 2665000.7 0.23 2500 Nan DS 4248.49 8 0.62 2649.26 1127000.3 0.27 1500 Nan DS 4256.5 1.5 0.64 2703.36 1424000.3 0.26 1500 SHALE 4258.01 2 0.69 2934.4 2665000.7 0.23 2500 Nan DS 4260.01 4 0.64 2714.96 1282000.3 0.26 1500 SHALE 4264.01 2 0.68 2912.94 2665000.7 0.23 2500 Nan DS 4266.01 6 0.63 2680.88 1072000.3 0.27 1500 SHALE 4272.01 20 0.68 2924.54 2665000.7 0.23 2500 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Shale 3998.2 10 0 1 1913 Shale 4008.2 15 0 1 1918 Siltstone 4023.2 15.3 0 10 1925 Top Nan CS 4038.48 17.5 39.47 24.9 1932 Nan DS 4056 2 113.24 25.3 1940 Attachment K: NDBI-006 Page 77 of 101 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Nan DS 4058.01 5.5 22.02 19.7 1941 SHALE 4063.48 3.5 0 1 1944 Nan DS 4066.99 1.5 21.67 21.3 1945 Nan DS 4068.5 2 159.89 23.6 1946 Nan CS 4070.51 1.5 110.14 27 1947 Nan CS 4072.01 2 2.87 19.7 1948 Nan CS 4074.02 1.5 94.75 25.5 1949 SHALE 4075.49 2 0 1 1949 Nan CS 4077.49 4.5 44.13 24.1 1950 Nan DS 4081.99 7 4.28 17.9 1952 Nan DS 4089.01 2.5 91.63 25.7 1956 Nan DS 4091.5 2 0.02 15 1957 Nan DS 4093.5 5 31.6 22.6 1958 Nan CS 4098.49 4.5 3.11 21.1 1960 Nan CS 4102.99 9.5 131.71 25.4 1962 Nan DS 4112.5 2.5 1 15.1 1967 Attachment K: NDBI-006 Page 78 of 101 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Nan DS 4114.99 12 104.14 23 1968 Nan DS 4127 2.5 2.35 17.3 1974 Nan DS 4129.49 9.5 31.76 19.2 1975 Nan DS 4139.01 2 3.79 17.6 1979 Nan DS 4141.01 41 72.28 22.4 1980 Nan DS 4181.99 1.5 68.11 24.3 1999 Nan CS 4183.5 6 156.15 26.2 2000 Nan DS 4189.5 6 40.96 19.9 2003 Nan DS 4195.51 4 0.02 15 2006 Nan DS 4199.51 2 17.85 22.4 2008 Nan DS 4201.51 2 0.01 15 2009 Nan DS 4203.51 2 22.09 21 2010 Nan DS 4205.51 5.5 0.02 15 2011 Nan DS 4210.99 4 63.42 23.1 2013 Nan DS 4214.99 2 0.02 15 2015 Nan DS 4216.99 12 74.62 23.5 2016 Attachment K: NDBI-006 Page 79 of 101 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Nan DS 4229 4 11.77 17.8 2022 Nan DS 4233.01 4 2.49 17.3 2023 SHALE 4237.01 2 0 1 2025 Nan DS 4239.01 1.5 3.22 18.4 2026 SHALE 4240.49 8 0 1 2027 Nan DS 4248.49 8 65.69 21.2 2031 Nan DS 4256.5 1.5 4.8 17.8 2035 SHALE 4258.01 2 0 1 2035 Nan DS 4260.01 4 11.98 19.3 2036 SHALE 4264.01 2 0 1 2038 Nan DS 4266.01 6 60.61 22.1 2039 SHALE 4272.01 20 0 1 2042 Attachment K: NDBI-006 Page 80 of 101 ǣ Name: Stage 12 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 12 PAD 40 YF126ST 18900 450 11.25 2 1 PPA 40 YF126ST 7038.8 175 CarboLite 16/20 1 7038.8 4.38 3 2 PPA 40 YF126ST 7329.4 190 CarboLite 16/20 2 14658.8 4.75 4 3 PPA 40 YF126ST 7783.7 210 CarboLite 16/20 3 23351.1 5.25 5 4 PPA 40 YF126ST 7490.3 210 CarboLite 16/20 4 29961.2 5.25 6 5 PPA 40 YF126ST 7218.3 210 CarboLite 16/20 5 36091.5 5.25 7 6 PPA 40 YF126ST 6965.3 210 CarboLite 16/20 6 41791.8 5.25 8 7 PPA 40 YF126ST 5447.6 170 CarboLite 16/20 7 38133.2 4.25 9 8 PPA 40 YF126ST 4809 155 CarboLite 16/20 8 38472 3.88 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.9 22.73 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 72982.4 229498.4 1980 49.5 Attachment K: NDBI-006 Page 81 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 12 MD: [14750, 14756] 4461.1 235.91 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4010.79 4246.7 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 12 MD: [14750, 14756] 735.05 192.25 0.36 Attachment K: NDBI-006 Page 82 of 101 Stage 13 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 13 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4637 psi ǣ Zoneset name: ZS-13 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 3997.21 10 0.71 2853.62 1461000.3 0.22 1000 Shale 4007.19 15 0.7 2790.24 1762000.5 0.22 1000 Siltstone 4022.21 15.3 0.68 2732.22 1898000.5 0.22 1000 Top Nan CS 4037.5 17.5 0.62 2524.82 818100.2 0.27 1000 Nan DS 4054.99 2 0.6 2433.59 784600.2 0.27 1000 Nan DS 4056.99 5.5 0.63 2553.53 1248000.4 0.26 1500 SHALE 4062.5 3.5 0.69 2812.43 2665000.7 0.23 2500 Nan DS 4066.01 1.5 0.64 2586.46 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 83 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4067.49 2 0.64 2583.56 913900.3 0.27 1500 Nan CS 4069.49 1.5 0.61 2486.96 669900.2 0.28 1000 Nan CS 4071 2 0.64 2610.1 1249000.4 0.26 1000 Nan CS 4073 1.5 0.6 2444.32 771600.2 0.27 1000 SHALE 4074.51 2 0.69 2820.26 2665000.7 0.23 2500 Nan CS 4076.51 4.5 0.61 2483.92 873800.2 0.27 1000 Nan DS 4081 7 0.66 2675.37 1417000.3 0.26 1500 Nan DS 4087.99 2.5 0.61 2494.5 757700.2 0.27 1000 Nan DS 4090.49 2 0.68 2786.32 1692000.4 0.26 1500 Nan DS 4092.49 5 0.61 2506.11 997700.3 0.27 1500 Nan CS 4097.51 4.5 0.64 2640.27 1120000.3 0.27 1000 Nan CS 4102 9.5 0.61 2505.09 778000.2 0.27 1000 Nan DS 4111.52 2.5 0.64 2640.41 1685000.4 0.26 1500 Nan DS 4114.01 12 0.62 2562.67 964800.3 0.27 1500 Nan DS 4125.98 2.5 0.66 2707.42 1469000.4 0.26 1500 Nan DS 4128.51 9.5 0.63 2620.54 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 84 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4137.99 2 0.65 2673.77 1444000.4 0.26 1500 Nan DS 4139.99 41 0.63 2608.65 1021000.3 0.27 1500 Nan DS 4181 1.5 0.62 2609.37 862400.2 0.27 1000 Nan CS 4182.51 6 0.62 2607.63 764700.2 0.28 1000 Nan DS 4188.48 6 0.67 2804.16 1242000.3 0.26 1500 Nan DS 4194.49 4 0.69 2895.53 1692000.4 0.26 1500 Nan DS 4198.49 2 0.64 2700.31 1009000.2 0.27 1500 Nan DS 4200.49 2 0.69 2886.4 1692000.4 0.26 1500 Nan DS 4202.49 2 0.63 2660.86 1134000.3 0.27 1500 Nan DS 4204.49 5.5 0.69 2898.72 1692000.4 0.26 1500 Nan DS 4210.01 4 0.62 2632.43 949900.2 0.27 1000 Nan DS 4214.01 2 0.68 2866.24 1692000.4 0.26 1500 Nan DS 4216.01 12 0.63 2655.64 919900.3 0.27 1000 Nan DS 4227.99 4 0.68 2897.56 1428000.4 0.26 1500 Nan DS 4231.99 4 0.64 2688.56 1474000.5 0.26 1500 SHALE 4235.99 2 0.68 2893.79 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 85 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4237.99 1.5 0.64 2721.34 1373000.4 0.26 1500 SHALE 4239.5 8 0.69 2923.82 2665000.7 0.23 2500 Nan DS 4247.51 8 0.62 2648.68 1127000.3 0.27 1500 Nan DS 4255.51 1.5 0.64 2702.78 1424000.3 0.26 1500 SHALE 4256.99 2 0.69 2933.82 2665000.7 0.23 2500 Nan DS 4258.99 4 0.64 2714.24 1282000.3 0.26 1500 SHALE 4262.99 2 0.68 2912.36 2665000.7 0.23 2500 Nan DS 4264.99 6 0.63 2680.3 1072000.3 0.27 1500 SHALE 4271 20 0.68 2923.96 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 86 of 101 ǣ Name: Stage 13 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 13 PAD 40 YF126ST 15750 375 9.38 2 1 PPA 40 YF126ST 7642.1 190 CarboLite 16/20 1 7642.1 4.75 3 3 PPA 40 YF126ST 7969 215 CarboLite 16/20 3 23907 5.37 4 5 PPA 40 YF126ST 8249.6 240 CarboLite 16/20 5 41248 6 5 7 PPA 40 YF126ST 7690.8 240 CarboLite 16/20 7 53835.6 6 6 9 PPA 40 YF126ST 6602.8 220 CarboLite 16/20 9 59425.2 5.5 7 10 PPA 40 YF126ST 5236.2 180 CarboLite 16/20 10 52362 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.63 22.59 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59140.5 238419.9 1660.01 41.5 Attachment K: NDBI-006 Page 87 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Bottomhole Pressure (psi) Max Height (ft) Stage 13 MD: [14098, 14104] 4637 243.76 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4005 4248.76 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 13 MD: [14098, 14104] 668.58 218.41 0.31 Attachment K: NDBI-006 Page 88 of 101 Stage 14 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 14 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3903.3 psi ǣ Zoneset name: ZS-14 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 3994.19 10 0.71 2851.44 1461000.3 0.22 1000 Shale 4004.2 15 0.7 2788.06 1762000.5 0.22 1000 Siltstone 4019.19 15.3 0.68 2730.19 1898000.5 0.22 1000 Top Nan CS 4034.51 17.5 0.62 2522.93 818100.2 0.27 1000 Nan DS 4052 2 0.6 2431.85 784600.2 0.27 1000 Nan DS 4054 5.5 0.63 2551.65 1248000.4 0.26 1500 SHALE 4059.51 3.5 0.69 2810.4 2665000.7 0.23 2500 Nan DS 4062.99 1.5 0.64 2584.57 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 89 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4064.5 2 0.64 2581.53 913900.3 0.27 1500 Nan CS 4066.5 1.5 0.61 2485.08 669900.2 0.28 1000 Nan CS 4068.01 2 0.64 2608.21 1249000.4 0.26 1000 Nan CS 4070.01 1.5 0.6 2442.44 771600.2 0.27 1000 SHALE 4071.49 2 0.69 2818.23 2665000.7 0.23 2500 Nan CS 4073.49 4.5 0.61 2482.18 873800.2 0.27 1000 Nan DS 4077.99 7 0.66 2673.34 1417000.3 0.26 1500 Nan DS 4085.01 2.5 0.61 2492.62 757700.2 0.27 1000 Nan DS 4087.5 2 0.68 2784.29 1692000.4 0.26 1500 Nan DS 4089.5 5 0.61 2504.37 997700.3 0.27 1500 Nan CS 4094.49 4.5 0.64 2638.24 1120000.3 0.27 1000 Nan CS 4099.02 9.5 0.61 2503.35 778000.2 0.27 1000 Nan DS 4108.5 2.5 0.64 2638.53 1685000.4 0.26 1500 Nan DS 4110.99 12 0.62 2560.79 964800.3 0.27 1500 Nan DS 4123 2.5 0.66 2705.53 1469000.4 0.26 1500 Nan DS 4125.49 9.5 0.63 2618.51 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 90 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4135.01 2 0.65 2671.89 1444000.4 0.26 1500 Nan DS 4137.01 41 0.63 2606.76 1021000.3 0.27 1500 Nan DS 4177.99 1.5 0.62 2607.49 862400.2 0.27 1000 Nan CS 4179.49 6 0.62 2605.75 764700.2 0.28 1000 Nan DS 4185.5 6 0.67 2802.13 1242000.3 0.26 1500 Nan DS 4191.5 4 0.69 2893.5 1692000.4 0.26 1500 Nan DS 4195.51 2 0.64 2698.28 1009000.2 0.27 1500 Nan DS 4197.51 2 0.69 2884.37 1692000.4 0.26 1500 Nan DS 4199.51 2 0.63 2658.98 1134000.3 0.27 1500 Nan DS 4201.51 5.5 0.69 2896.69 1692000.4 0.26 1500 Nan DS 4206.99 4 0.62 2630.55 949900.2 0.27 1000 Nan DS 4210.99 2 0.68 2864.21 1692000.4 0.26 1500 Nan DS 4212.99 12 0.63 2653.76 919900.3 0.27 1000 Nan DS 4225 4 0.68 2895.53 1428000.4 0.26 1500 Nan DS 4229 4 0.64 2686.68 1474000.5 0.26 1500 SHALE 4233.01 2 0.68 2891.76 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 91 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4235.01 1.5 0.64 2719.31 1373000.4 0.26 1500 SHALE 4236.52 8 0.69 2921.64 2665000.7 0.23 2500 Nan DS 4244.49 8 0.62 2646.79 1127000.3 0.27 1500 Nan DS 4252.49 1.5 0.64 2700.75 1424000.3 0.26 1500 SHALE 4254 2 0.69 2931.65 2665000.7 0.23 2500 Nan DS 4256 4 0.64 2712.35 1282000.3 0.26 1500 SHALE 4260.01 2 0.68 2910.33 2665000.7 0.23 2500 Nan DS 4262.01 6 0.63 2678.41 1072000.3 0.27 1500 SHALE 4268.01 20 0.68 2921.93 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 92 of 101 ǣ Name: Stage 14 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 14 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 6033.2 150 CarboLite 16/20 1 6033.2 3.75 3 2 PPA 40 YF126ST 6750.8 175 CarboLite 16/20 2 13501.6 4.38 4 3 PPA 40 YF126ST 7413 200 CarboLite 16/20 3 22239 5 5 4 PPA 40 YF126ST 7133.6 200 CarboLite 16/20 4 28534.4 5 6 5 PPA 40 YF126ST 6874.5 200 CarboLite 16/20 5 34372.5 5 7 6 PPA 40 YF126ST 6633.6 200 CarboLite 16/20 6 39801.6 5 8 7 PPA 40 YF126ST 5447.6 170 CarboLite 16/20 7 38133.2 4.25 9 8 PPA 40 YF126ST 4184.4 135 CarboLite 16/20 8 33475.2 3.38 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 24.97 21.86 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67270.7 216090.7 1830 45.75 Attachment K: NDBI-006 Page 93 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 14 MD: [12783, 12789] 3903.3 242.39 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4003 4245.39 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 14 MD: [12783, 12789] 684.97 211.34 0.28 Attachment K: NDBI-006 Page 94 of 101 Stage 15 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 15 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4086.7 psi ǣ Zoneset name: ZS-15 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Shale 3993.7 10 0.71 2851.01 1461000.3 0.22 1000 Shale 4003.71 15 0.7 2787.77 1762000.5 0.22 1000 Siltstone 4018.7 15.3 0.68 2729.9 1898000.5 0.22 1000 Top Nan CS 4033.99 17.5 0.62 2522.64 818100.2 0.27 1000 Nan DS 4051.51 2 0.6 2431.56 784600.2 0.27 1000 Nan DS 4053.51 5.5 0.63 2551.36 1248000.4 0.26 1500 SHALE 4058.99 3.5 0.69 2810.11 2665000.7 0.23 2500 Nan DS 4062.5 1.5 0.64 2584.28 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 95 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4064.01 2 0.64 2581.24 913900.3 0.27 1500 Nan CS 4066.01 1.5 0.61 2484.79 669900.2 0.28 1000 Nan CS 4067.49 2 0.64 2607.92 1249000.4 0.26 1000 Nan CS 4069.49 1.5 0.6 2442.15 771600.2 0.27 1000 SHALE 4071 2 0.69 2817.79 2665000.7 0.23 2500 Nan CS 4073 4.5 0.61 2481.89 873800.2 0.27 1000 Nan DS 4077.49 7 0.66 2673.05 1417000.3 0.26 1500 Nan DS 4084.51 2.5 0.61 2492.33 757700.2 0.27 1000 Nan DS 4087.01 2 0.68 2784 1692000.4 0.26 1500 Nan DS 4089.01 5 0.61 2503.93 997700.3 0.27 1500 Nan CS 4094 4.5 0.64 2637.95 1120000.3 0.27 1000 Nan CS 4098.49 9.5 0.61 2502.92 778000.2 0.27 1000 Nan DS 4108.01 2.5 0.64 2638.09 1685000.4 0.26 1500 Nan DS 4110.5 12 0.62 2560.5 964800.3 0.27 1500 Nan DS 4122.51 2.5 0.66 2705.24 1469000.4 0.26 1500 Nan DS 4125 9.5 0.63 2618.22 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 96 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4134.51 2 0.65 2671.6 1444000.4 0.26 1500 Nan DS 4136.52 41 0.63 2606.47 1021000.3 0.27 1500 Nan DS 4177.49 1.5 0.62 2607.2 862400.2 0.27 1000 Nan CS 4179 6 0.62 2605.46 764700.2 0.28 1000 Nan DS 4185.01 6 0.67 2801.84 1242000.3 0.26 1500 Nan DS 4191.01 4 0.69 2893.21 1692000.4 0.26 1500 Nan DS 4195.01 2 0.64 2697.99 1009000.2 0.27 1500 Nan DS 4197.01 2 0.69 2884.08 1692000.4 0.26 1500 Nan DS 4199.02 2 0.63 2658.54 1134000.3 0.27 1500 Nan DS 4200.98 5.5 0.69 2896.4 1692000.4 0.26 1500 Nan DS 4206.5 4 0.62 2630.26 949900.2 0.27 1000 Nan DS 4210.5 2 0.68 2863.77 1692000.4 0.26 1500 Nan DS 4212.5 12 0.63 2653.47 919900.3 0.27 1000 Nan DS 4224.51 4 0.68 2895.1 1428000.4 0.26 1500 Nan DS 4228.51 4 0.64 2686.39 1474000.5 0.26 1500 SHALE 4232.51 2 0.68 2891.47 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 97 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Young’s Modulus (psi) Poisson’s Ratio Toughness (psi.in0.5) Nan DS 4234.51 1.5 0.64 2719.02 1373000.4 0.26 1500 SHALE 4235.99 8 0.69 2921.35 2665000.7 0.23 2500 Nan DS 4244 8 0.62 2646.5 1127000.3 0.27 1500 Nan DS 4252 1.5 0.64 2700.46 1424000.3 0.26 1500 SHALE 4253.51 2 0.69 2931.36 2665000.7 0.23 2500 Nan DS 4255.51 4 0.64 2712.06 1282000.3 0.26 1500 SHALE 4259.51 2 0.68 2909.89 2665000.7 0.23 2500 Nan DS 4261.52 6 0.63 2678.12 1072000.3 0.27 1500 SHALE 4267.49 20 0.68 2921.5 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 98 of 101 ǣ Name: Stage 15 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 15 PAD 40 YF126ST 8400 200 5 2 1 PPA Scour 40 YF126ST 2414.8 60 CarboLite 40/70 1 2414.8 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8044.2 200 CarboLite 16/20 1 8044.2 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.41 22.6 Attachment K: NDBI-006 Page 99 of 101 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 65785.3 249858.1 1830 45.75 Attachment K: NDBI-006 Page 100 of 101 ǣ Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 15 MD: [12239, 12245] 4086.7 243.52 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4003 4246.52 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 15 MD: [12239, 12245] 711.45 218.83 0.33 Attachment K: NDBI-006 Page 101 of 101 Material Totals Fluids Fluid Volume (BBL) Proppants Proppant Mass (lbm) YF126ST WF126 22510 1000 CarboLite 40/70 CarboLite 16/20 47370 3085506 Totals Total Fluid Volume (BBL) Total Proppant Mass (lbm) Total Pump Time (h) 23510 3132876 13.87