Facility Detail

COGIS - WELL SCOUT CARD

Related Insp MIT GIS Doc COA Wellbore Orders Bradenhead
Surface Location API# 05-073-06610		Well Classification: ERIW	Status: SI - 3/1/2022
Well Name/No:	BLACKCOMB #12-14 (Click Well Name for Production Data)	Click Here for Transporter Gatherer Info
Operator:	POLARIS PRODUCTION OPCO LLC - 10793 (Click Operator Name for Company Detail Report)	Federal Or State Lease #:
Facility Status:	SI	Status Date	3/1/2022
FacilityID:	437313	LocationID:	437317
County:	LINCOLN #073	Location:	NWSW 14 6S54W 6
Field:	ARIKAREE CREEK - #2914	Elevation:	5195 ft.
Basin:	DENVER (DJ) BASIN
Planned Location:	2245FSL 640 FWL	Lat/Long: 39.527400 / -103.414280	Lat/Long Source: Field Measured
As Drilled Location:	Footages Not Available	Lat/Long: 39.527400 / -103.414280	Lat/Long Source: Field Measured


Wellbore And Formation Details -- select either a wellbore Or formation to expand.

Wellbore #00 Wellbore Classification: OW Status: SI - 3/1/2022 Measured TD: 8445 ft.

Wellbore Data for Original Wellbore		Wellbore Classification: OW SI - 3/1/2022
Wellbore Permit
Permit #:		Expiration Date:	11/26/2018
Proposed Depth/Form:	8445 ft.
Surface Mineral Owner Same:	No
Mineral Owner:	FEE	Surface Owner:	FEE
Unit:		Unit Number:
Formation And Spacing:	Code: ATOK , Formation: ATOKA , Order: , Unit Acreage: , Drill Unit:
Formation And Spacing:	Code: CHRK , Formation: CHEROKEE , Order: , Unit Acreage: , Drill Unit:
Formation And Spacing:	Code: LGKC , Formation: LANSING-KANSAS CITY , Order: , Unit Acreage: , Drill Unit:
Formation And Spacing:	Code: MRTN , Formation: MARMATON , Order: , Unit Acreage: , Drill Unit:
Formation And Spacing:	Code: MS-SP , Formation: MISSISSIPPIAN-SPERGEN , Order: , Unit Acreage: , Drill Unit:
Formation And Spacing:	Code: SPGN , Formation: SPERGEN , Order: 556-2 , Unit Acreage: 600, Drill Unit:
Formation And Spacing:	Code: WFCMP , Formation: WOLFCAMP , Order: , Unit Acreage: , Drill Unit:
Casing:	String Type: SURF, Hole Size: 12.25 in., Size: 8.625 in., Top: 0 ft., Depth: 351 ft., Weight: 24 , Citings Type: PLANNED
Cement:	Sacks: 175, Top: 0 ft., Bottom: 351 ft.
Casing:	String Type: 1ST, Hole Size: 7.875 in., Size: 5.5 in., Top: 0 ft., Depth: 8443 ft., Weight: 17 , Citings Type: PLANNED
Cement:	Sacks: 1218, Top: 940 ft., Bottom: 8443 ft.

Wellbore Completed
Completion Date:	8/14/2014
Spud Date:	6/13/2014	Spud Date Is:	ACTUAL
Measured TD:	8445 ft.	Measured PB depth:	8351 ft.
True Vertical TD:		True Vertical PB depth:
Log Types:	Ind/Dens/Neut.
Casing:	String Type: SURF, Hole Size: 12.25 in., Size: 8.625 in., Top: 0 ft., Depth: 351 ft., Weight: 24 , Citings Type: ACTUAL
Cement:	Sacks: 175, Top: 0 ft., Bottom: 351 ft., Determination Method: VISU
Casing:	String Type: 1ST, Hole Size: 7.875 in., Size: 5.5 in., Top: 0 ft., Depth: 8443 ft., Weight: 17 , Citings Type: ACTUAL
Cement:	Sacks: 1218, Top: 940 ft., Bottom: 8443 ft., Determination Method: CBL
Formation	Interval Top	Log Bottom	Cored	DSTs
NIOBRARA	3745 ft.
WOLFCAMP	6128 ft.
LANSING-KANSAS CITY	6858 ft.
MARMATON	7201 ft.
CHEROKEE	7403 ft.
ATOKA	7559 ft.
MORROW	7817 ft.
SPERGEN	8045 ft.

Formation SPGN Formation Classification: OW Status: SI - 3/1/2022 Interval Top: 8072 ft. Interval Bottom: 8090 ft.

Completed Information for Formation SPERGEN

1st Production Date:	N/A	Choke Size:
Formation Name:	SPERGEN	Commingled:	No
Production Method:
Open Hole Completion:	No

Formation Treatment
Treatment Type:
Treatment Date:	1/9/2017	Treatment End Date:	N/A
Treatment Summary:	1st injection - Changing status to injection well
Total fluid used in treatment (bbls):		Max pressure during treatment (psi):
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):		Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):
Fresh water used in treatment (bbls):		Disposition method For flowback:
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized:
Formation Treatment
Treatment Type:
Treatment Date:	12/30/2016	Treatment End Date:	N/A
Treatment Summary:	No treatment performed. Waiting on approval to commence injection.
Total fluid used in treatment (bbls):		Max pressure during treatment (psi):
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):		Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):
Fresh water used in treatment (bbls):		Disposition method For flowback:
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized:
Formation Treatment
Treatment Type:	ACID JOB
Treatment Date:	8/22/2016	Treatment End Date:	8/26/2016
Treatment Summary:	Perf'd 8,072'-8,090' w/ 6spf, 108 holes, 4" scallop gun, 26gm shot, .46" EHD 51.3" penetration (listed since different info that initial perf info reported) Pump premixed 1,000 gallons Acetone, 750 gallons acetone, 750 gallons ethanol, 6,000 gals 2% KCl w/ 6.5 gals RAS-92 (anti sludge) 12 gal IC-75 (iron control) 7 gal SI-4 (scale inhibitor), 18 gal B-172 (biocide) & 150 bio balls
Total fluid used in treatment (bbls):	212	Max pressure during treatment (psi):	1750
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):	61	Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):	372
Fresh water used in treatment (bbls):	151	Disposition method For flowback:	DISPOSAL
Total proppant used (lbs):		Green completions techniques utilized:	Yes
Reason green techniques Not utilized:
Formation Treatment
Treatment Type:	ACID JOB
Treatment Date:	8/24/2015	Treatment End Date:	8/27/2015
Treatment Summary:	Treated well with 12,000 gal 2% KCL mixed w/2,000 gal acetone and 1,000 gal ethanol and 100 bio balls. Displaced with 23 bbls of 2% KCl
Total fluid used in treatment (bbls):	385	Max pressure during treatment (psi):	2580
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):	76	Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):	0
Fresh water used in treatment (bbls):	309	Disposition method For flowback:	DISPOSAL
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized: PIPELINE
Formation Treatment
Treatment Type:	ACID JOB
Treatment Date:	4/17/2015	Treatment End Date:	4/24/2015
Treatment Summary:	Re-perforated original perfs Acidized with 4500 gallons of 2% KCL mixed with 1000 gallons of Acetone and 500 gallons of ethanol. Displaced with 46 bbls of 2% KCL. Dropped 80 bio balls throughout the job.
Total fluid used in treatment (bbls):	189	Max pressure during treatment (psi):	3450
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):	36	Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):	264
Fresh water used in treatment (bbls):	153	Disposition method For flowback:	DISPOSAL
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized: PIPELINE
Formation Treatment
Treatment Type:
Treatment Date:	8/20/2014	Treatment End Date:	8/20/2014
Treatment Summary:	Perforated only
Total fluid used in treatment (bbls):		Max pressure during treatment (psi):
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):		Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):
Fresh water used in treatment (bbls):		Disposition method For flowback:
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized:

Test Type	Measure
Tubing Size:		Tubing Setting Depth:
Tubing Packer Depth:		Tubing Multiple Packer:
Open Hole Top:		Open Hole Bottom:
Initial Test Data:
Test Date:	N/A	Test Method:
Hours Tested:		Gas Type:
Gas Disposal:
BBLS_H2O	262
BBLS_OIL	2
BTU_GAS	820
CALC_BBLS_H2O	262
CALC_BBLS_OIL	2
CALC_GOR	1000
CALC_MCF_GAS	2
CASING_PRESS	48
GRAVITY_OIL	36
MCF_GAS	2
TUBING_PRESS	65

Perforation Data:
Interval Top:	8072 ft.	# Of Holes:	208
Interval Bottom:	8090 ft.	Hole Size:	0.53 in.

Formation MRTN Formation Classification: OW Status: AB - 12/22/2016 Interval Top: 7220 ft. Interval Bottom: 7326 ft.

Completed Information for Formation MARMATON

1st Production Date:	12/17/2014	Choke Size:
Formation Name:	MARMATON	Commingled:	No
Production Method:
Open Hole Completion:	No

Formation Treatment
Treatment Type:
Treatment Date:	11/1/2016	Treatment End Date:	12/13/2016
Treatment Summary:	Perf'd formation for cement squeeze prep 11-1-16 7,316' - 7,321' 20 holes 11-7-16 7,320' - 7,324' 4 holes 11-16-16 7,320' 2 holes
Total fluid used in treatment (bbls):		Max pressure during treatment (psi):
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):		Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):
Fresh water used in treatment (bbls):		Disposition method For flowback:
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized:
Formation Treatment
Treatment Type:
Treatment Date:	8/10/2016	Treatment End Date:	8/26/2016
Treatment Summary:	Mix and pump 30 sx 6.1 bbls Class G cement with 0.2% C-15 fluid loss, 1.15 cu ft/sk yield. 15.8 ppg (squeeze) Pressured tested squeeze and also previous perfs that were squeezed 7,313'-7,326' re-squeezing lower perfs Perf'd 7,319'-7,321' 8 holes Pump 30sx 6.1bbls Class G cement with 0.2% C-15 fluid loss, 1.15 cu ft/sk yield 15.8 ppg - pressure tested and held.
Total fluid used in treatment (bbls):		Max pressure during treatment (psi):
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):		Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):
Fresh water used in treatment (bbls):		Disposition method For flowback:
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized:
Formation Treatment
Treatment Type:	ACID JOB
Treatment Date:	10/28/2014	Treatment End Date:	12/16/2014
Treatment Summary:	Acidize with 2,000 gallons of 15% HCL and 44 bbls of 2% KCL water Squeezed initial perfs of 7,316' - 7,326' Re-perf'd 7,316'- 7,326' Acidized with 2,500 galons of 15% HCL and displaced with 50 bbls of 2% KCI-Squeezed again and closed perfs Perf'd 7220-7228 Acidized with 29 bbls of 15% HCL displaced with 51 bbls of 2@ KCI water
Total fluid used in treatment (bbls):	281	Max pressure during treatment (psi):	1800
Total gas used in treatment (mcf):		Fluid density (lbs/gal):
Type Of gas:		Number Of staged intervals:
Total acid used in treatment (bbls):	136	Min frac gradient (psi/ft):
Recycled water used in treatment (bbls):		Total flowback volume recovered (bbls):	243
Fresh water used in treatment (bbls):	145	Disposition method For flowback:	DISPOSAL
Total proppant used (lbs):		Green completions techniques utilized:	--
Reason green techniques Not utilized: PIPELINE

Test Type	Measure
Tubing Size:		Tubing Setting Depth:
Tubing Packer Depth:		Tubing Multiple Packer:
Open Hole Top:		Open Hole Bottom:
Initial Test Data:
Test Date:	N/A	Test Method:
Hours Tested:		Gas Type:
Gas Disposal:
BBLS_H2O	175
BBLS_OIL	28
CALC_BBLS_H2O	175
CALC_BBLS_OIL	28
CASING_PRESS	22
GRAVITY_OIL	38
TUBING_PRESS	45

Perforation Data:
Interval Top:	7220 ft.	# Of Holes:	202
Interval Bottom:	7326 ft.	Hole Size:	0.48 in.

All Designations		Date
Primary Well Designation: Noticed Inactive i
Reported Plugged	N
Out Of Service Repurposed	N
Out Of Service	N
Inactive Exception	N
Noticed Inactive	Y	Noticed Date 11/06/2024
Defined Inactive (UIC)	Y	Defined Inactive 08/31/2021
Low Producing	N

October 2024 - September 2025	i
BOE/MCFE/GOR Calculations Production for Previous 12 Months
Total Oil Produced (Barrels)	0
Total Gas Produced (MCF)	0
GOR
GOR Determination
Average BOE per Day	0.000
Average MCFE per Day	0.000

Federal Financial Assurance

Tribal Well