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Home My WebLink About202-107 Image f',Jject Well History File C~.1r Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. .Q Q 2 - 1 0 7 Well History File Identifier RESCAN ~olor Items: 0 Greyscale Items: DIGITAL DATA ~escan Needed I OVERSIZED (Scannable) D Maps: Organizing (done) ~WO-Sided 1111111111111111111 D Diskettes, No. D Other, NolType: D Other Items Scannable by a Large Scanner D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: BY: Helen ~ D Other:~ . I Dateà ~ 0 S- 151 t^1P Project Proofing 1- Scanning Preparation BY: He'en8 J x 30 = 30 + Is/ rnP :3 = TOTAL PAGES. :J,3 (Count do~s not include cover sheet) iMP Date: ~ a-. ÐS:- /51 f , It . I - I . , BY: Helen QV1ariy Date:~ t"+ o-s- BY: Production Scanning Stage 1 Page Count from Scanned File: l3 4- (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES NO Helen ~ Date: ~ J. Ô s- /5/ )1111 P , YES NO Stage 1 If NO in stage 1, page(s) discrepancies were found: BY: Helen Maria Date: /5/ I I II Date: /s/ Quality Checked 1111111111111111111 Scanning is complete at this point unless rescanning is required. ReScanned BY: Helen Maria Comments about this file: 't ) lID~ TONY KNOWLES, GOVERNOR AI1A.SIiA OIL AND GAS CONSERVATION COMMISSION J. Edward Jones V ice President Aurora Gas LLC 10333 Richmond Avenue Ste 710 Houston TX 77042 333 w. -¡rH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Nicolai Creek Unit 5 Aurora Gas LLC Permit No: 202-107 Surface Location: 2183' SNL, 1622' WEL, Sec. 19, T11N, R12W, SM Bottomhole Location: 2183' SNL, 1622' WEL, Sec. 19, TllN, R12W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the. above referenced service well. The permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. ' The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035; and the mechanical integrity (M!) of the injection wells must be demonstrated under 20 AAC 25.412 and 20 AAC 25.030(g)(3). Sufficient notice (approximately 24 hours) of the MI test before operation, and of the BOPE test performed before drilling below the surface casing shoe, must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, (iJ/hn~.o/~' ~ C~~1\echs¡¡ Taÿíof' . Chair BY ORDER OF THE COMMISSION DATED this~ day of July, 2002 cc: Department ofFish & Game, Habitat Section wlo encl. Department of Environmental Conservation wlo encl. ) ) ~Od- t07 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Aurora Gas, LLC for disposal of Class II oil field wastes by underground injection in the Tyonek Formation, Nicolai Creek Unit No.5, Section 19, TIIN, RI2W, S. M. Disposal Injection Order No. 24 ) ) ) ) ) ) ) Nicolai Creek Field Nicolai Creek Unit No.5 Well June 26, 2002 IT APPEARING THAT: 1. By correspondence dated February 22, 2002, and received by the Alaska Oil and Gas Conservation Commission (HAOGCC") on February 26, 2002, Aurora Gas, LLC (HAurora") requested authorization for a disposal order to allow the underground injection of non-hazardous Class II oil field waste fluids into the Tyonek Formation within the NicolaiCreek Unit No.5 (HNCU #5") well bore. The NCU #5 well is located in the Nicolai Creek Field, Kenai Peninsula Borough, Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on March 22, 2002 in accordance with 20 AAC 25.540. 3. The Commission did not receive any protest or a request for a public hearing. FINDINGS: 1. Aurora is the operator of the Nicolai Creek Unit. There are no other operators within a one-quarter mile radius of the proposed disposal injection well. 2. The NCU #5 well is a vertical well within Federal lease AA-8426, which is administered by the Bureau of Land Management. Cook Inlet Region Inc. is the surface owner. 3. Aurora proposes to conduct disposal operations in the NCU #5 well between 2000' and 2550' measured depth ("MD"). Disposal Injeciion ûrder 24 Nicolai Creek Unit No.5 June 26, 2002 ß- -- " -i:' C. íC1l:;C ¿, VI V 4. There are no wells within a one-half mile radius of the NCD #5 well. 5. There are no recorded domestic water supply wells within 5 miles of the proposed injection site. The nearest drinking water supply source is Markley's Spring, an artesian spring located in the NW ~ of Section 27, TIIN, RI2W, S.M., which is over 2 ~ miles southeast of NCD #5. The closest known water well is a 120-foot deep utility water well located at the Nicolai Creek Dnit No.3 ("NCD #3") well site, about 3,230 feet to the east of the NCD #5 well. 6. The proposed disposal interval in the NCD #5 extends from 2000' to 2550' MD and true vertical depth ("TVD"), and is composed of Tyonek Fonnation sediments. The name Tyonek Fonnation is used to identify the disposal zone described in this order. 7. The lithologies in the proposed disposal zone consist of penneable very fine to coarse-grained sandstones and conglomerates interbedded with clays and siltstones. 8. Wire line log analytical techniques, which comply with EP A recommended methods as described in "Survey of Methods to Detennine Total Dissolved Solids Concentrations," (KEDA Project No. 30-956), were used to characterize fonnation water salinity in the NCD #5 well. Well log analysis indicates fonnation salinities within the proposed disposal interval are 10,000 ppm or greater. 9. Laboratory analysis of a produced water sample from equivalent or shallower sands in offset well NCD #3 yielded a value of 10,500 ppm, which confinns the well log analytical results. 10. Approximately 140 net vertical feet of sandstone are present in the proposed disposal interval. 11. The main confining zone is 80' of siltstone and mudstone located between the depths of 1840' and 1925' MD and TVD, which will prevent upward migration of injected fluids into overlying non-exempt aquifers. 12. The proposed disposal zone is confined below by over 50 net vertical feet of siltstone and approximately 90 net vertical feet of clay that lie between the depths of 2780' and 3120' MD and TVD. 13. The NCD #5 well was drilled to a depth of 8578' MD and TVD. The well was completed with 30" structural conductor from surface to a depth of 34' MD, 16" surface casing from surface to a depth of 308' MD, 10-%" casing from surface to 2628' MD, and 9 7/8" open hole from 2628' to 8578' MD. The original well bore was abandoned on March 7, 1972 with cement plugs in the 9 7/8" hole from 7215' to 7000' MD, 6718' to 6500' MD, 4151' to 3950' MD, 3314' to 3050' MD, 2756' to 2500'MD (into 10-%" casing), and at surface with a 25 sack cement plug. ) ) Disposal Injection Order 24 Nicolai Creek Unit No.5 June 26, 2002 Page 3 of6 14. Aurora proposes to re-enter NCU #5, drill out the surface plug and clean out the 10-%" casing to a depth of2500' MD. The well will be completed with 2 7/8" tubing and a packer at approximately 2250' MD. Perforations will be added between 2325' and 2345' MD. 15. The 10-3/4", 40.5 pound per foot ("ppf'), casing meets the requirements of AAC 252.412. 16. Aurora will test the mechanical integrity of theNCU #5 well in accordance with the requirements of 20 AAC 25.412 The surface plug will be drilled out, the casing will be cleaned, flushed, and pressure tested to 1500 psi for 30 minutes. A USIT logging tool or equivalent will be utilized to evaluate the integrity of the cement within the well bore. After running the completion packer and tubing, the casing/tubing annulus will be pressure tested to 1500. psi for 30 minutes. Pressure on the tubing/casing annulus will be monitored each day during injection operations to ensure continued mechanical integrity of the completion. 17. The disposal waste stream will consist of produced. water, drilling, completion and workover fluids, drill cuttings, rig wash, mud slun-ies, and" other Class II fluids and solids. The composition of the waste stream and constituent volumes will vary depending on drilling, workover, stimulation and maintenance activity. 18. Aurora proposes that the average daily injection volume will range from 350 to about 1,000 barrels per day (BPD") at rates ranging up to a maximum of. 5 barrels per minute ("BPM").The daily volume would depend on the number of producing wells, drilling activity and well work conducted annually. 19. At the proposed injection rates, Aurora estimates maximum surface injection pressure of 1500 pounds per square inch ("psi") under normal operating conditions. 20. A step rate test will be done after perforating the disposal interval to establish injection rate and pressure characteristics of the formation. 21. The workover, drilling and production programs are estimated to generate a maximum of 372,500 barrels of oilfield waste per year. Up to 3,725,000 barrels of waste may be disposed over the anticipated 10-year life of the project. 22. Aurora expects fractures will be created as the disposal zone begins to plug with injected solids and waste. Fractures (or disaggregation of the clogged pores and rock matrix) provide pathways to transport waste fluids to undamaged storage volume within the disposal zone. 23. Aurora submitted fracture-model analysis results of four different fracture scenarios. The results showed that during expected operations, injected wastes would not breach the confining layers between 1840' and 1985' MD and TVD. Disposal Injection Order 24 Nicolai Creek Unit No.5 June 26, 2002 Page 4 oÍó 24. The injection pump will be continuously manned during injection operations at the NCD #5 well. The annulus pressure of the NCD #3 well will be checked and recorded prior to and after each injection cycle. CONCLUSIONS: 1. The application requirements of20 AAC 25.252(c) have been met. 2. There are no wells within a one-half mile radius of the NCD #5 well. There are no recorded domestic water supply wells within 5 miles of the NCU #5. The nearest domestic water supply, Markley's Spring, is a surface water source that is located over 2 ~ miles southeast of the NCD #5. 3. Waste fluids will be contained within appropriate receiving intervals by the confining lithology in the Tyonek Formation, cement isolation of the well bore and operating conditions. 4. Disposal injection operations in the NCD #5 well will be conducted at rates and pressures below those estimated to fracture the confining zone. 5. Evaluation of operational performance data and surveillance data will reasonably assure there is no fracturing of the confining zone. 6. Surveillance of disposal material, daily monitoring of operational parameters, and demonstration of mechanical integrity will reasonably ensure continued mechanical integrity of the well and that waste fluids are contained within the disposal interval. 7. Disposal injection of Class II wastes into well NCU #5 will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: RULE 1: Authorized Iniection Strata for Disposal Injection of authorized fluids for purposes of underground disposal of oil field wastes is permitted into the Tyonek Formation between 2000' and 2550' MD in the NCU #5 well, in the Nicolai Creek Unit. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. RULE 2: Authorized Fluids Fluids authorized for injection in the NCD #5 well are: 1. produced water 2. drilling, completion and workover fluids ) ) Page 5 of6 Disposal Injection Order 24 Nicolai Creek Unit No.5 June 26, 2002 3. drilling mud 4. Norm scale 5. tank bottoms 6. rig wash 7. precipitation accumulating within containment areas 8. other fluids suitable for disposal in a Class II well and approved by the commission on a case-by-case basis. RULE 3: Demonstration of Tubine/Casine Annulus Mechanicallnteeritv In addition to the requirements of 20 AAC 25 .252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years. RULE 4: Maximum In.iection Pressure Disposal injection operations must be conducted at rates and pressures below those estimated to fracture the confining zone between 1840' and 1925' MD. The Commission may implement specific maximum injection rates and pressures by administrative action following a review of injection test data and evaluation of surveillance reports. RULE 5: Surveillance Operating parameters including disposal rate, disposal pressure, annulus pressures, step rate test results and volume of fluids and solids pumped must be monitored and reported according to requirements of 20 AAC 25.432(1). Operator will obtain a baseline temperature log and a baseline step rate test prior to initial injection. An initial report of operations must be provided after one month of injection. An annual report for the calendar year evaluating the performance of the disposal operation, including an annual MIT and step rate test, must be submitted by July 1 of each year. RULE 6: Notification of Improper Class II Iniection The operator must immediately notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. RULE 7: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Disposal Injection Oròer 24 Nicolai Creek Unit No.5 June 26, 2002 Page 6 of6 RULE 8: Other Conditions Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless specifically superseded by Commission order. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order may result in the revocation or suspension of this authorization. DONE at Anchorage, Alaska and dated June 26,2002. .~.. . '..,.: ..... ~, "''11: "It.:" '~'4 ... ~~â(J1/\{~ Cammy Oe~hsli Taylor, Chag ø;?7COrCOmmiSSion Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the lO-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). Ms. Cammy Oechsli Taylor, Chairman Alaska Oil and Gas Conservation Commission 333 West ih Ave., Suite 100 Anchorage, Alaska 99501 ~o,:)~~ ~\~t'? -\c ~ c¿n~,- ~~ o..~~~~1 ~("¿ \ \. "\\--.~~ ~~« <:,,J'o~\~~ C>-. \.\C) \ C\\\ \J\J ~ ":C" '\ "-:. G..\ \ ~\- '\<;. \I',~ ~ \\ ~C( '-lDs ~~.j~\p~~~ G\. ~ ~-\- Nt<è.<8<td ~..~Aurora Gas, LLC April 12, 2002 RE: Application for Sundry Approval; Re-Entry of Nicolai Creek Unit No.5, Granite Point Alaska Dear Ms. Taylor, Aurora Gas LLC, hereby applies for Sundry Approval of its plan to re-enter and re- complete Nicolai Creek Unit No.5, as a non-hazardous Class II Oilfield Waste injection well to support ongoing and future development plans on the Northwest side of the Cook Inlet. The required Application for Permit to Drill, is submitted under separate cover. Aurora plans to begin well reentry and work-over operations on June 1 S\ 2002. Upon receipt of all necessary permits and approvals, contractors will clear and repair the original NCD #5 access road and drillsite so that the rig, Aurora Well Service No.1, and support equipment can be mobilized to the site to begin well work operations. The well is currently permanently abandoned as depicted in Attachment 1. As the casing head was removed when the well was abandoned, it will be necessary to install a new cellar and casing head prior to moving the rig over the wellhead. When the rig is in place and inspected, a BOP stack will be installed and tested, and re-entry procedures will be initiated. During the original abandonment procedure, a series of cement plugs were placed along the course of the wellbore. Aurora intends to drill out the surface cement plug only, to gain access to the proposed injection zone. The deepest point in the wellbore after access is gained will be the top of the next cement plug in the sequence, which is at 2500 feet MD and placed across the shoe of the 10 %" casing. At this time we request that the BOPE test pressure to be used during this re-entry and completion procedure be limited to 3,000 psi. Calculations show that at 2500 feet MD & TVD, assuming the wellbore has been unloaded of all fluid and only gas remains, a 3000 psi surface pressure equates to an equivalent mud kill weight of over 23 ppg. There is no procedure Aurora plans to undertake on the NCU #5 well, which would require a pressure in excess of 3000 psi. Pertinent information attached to this application includes the following: 1) Form 10-403 Application for Sundry Approval - 3 copies RECEIVED , ! 0..- A\ PD ')., 2UIìO? ¡ ¡ \ L":" 'I... Alaska Oil & Gas Gons. CmmrHssiOn Anchoraoe ) ) Ms. Taylor Page 2 A copy of the proposed re-entry and re-completion procedure 2) 3) Schematics showing the current and planned wellbore configuration If you have any questions or require additional information, please contact me at (713)977-5799, or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC /7 ÇJ- ç ./h~. - /(-/t . // / ¿~ ~ef' /'j/:?-;tL_-;;;> /,/ I ./ CEd. Jones !// Executive Vice President / Production Manager Enclosures cc: Duane Vaagen Andy Clifford STATE OF ALASKA AND GAS CONSERVATION COl\r",\,'"SSION PERMIT TO DRILL l 20 AAC 25.005 [X ] Service [ ] Development Gas [ ] Single Zone [ ] Exploratory [ ] Stratigraphic Test [ ] Development Oil 5. Datum Elevation (OF or KB) 10. Field and Pool 89' RKB Wildcat 6. Property Designation A-/t ß</ "2.(, Á Lease A-034J.ê+" /..¡¿J 7. Unit or Property Name 11. Type Bond Nicolai Creek Unit 8. Well Number 5 9. Approximate spud date Re-Entry - Jan 15, 02 14. Number of acres in property 15. Proposed depth (MD and TVD) ...2.æo- /7::5 ~ /Šl') 2550' MD (2550' TVD) 17. Anticipated pressure {see 20 MC 25.035 (e) (2)} Maximum surface ~ psig, At total depth (TVD) t\"tbA.~~ . Quantity of Cement (include stage data) 10333 Richmond Ave. Ste 710 Houston, TX 77042 4. Location of well at surface ASP Z4 Y = 2,571,656 X = 239,830 2183' SNL, 1622' WEL Sec. 19, T11N, R12W S.M. At top of productive interval Upper Injection Interval 2290' MD (2290' TVD) At total depth 2500' MD (2500' TVDr 12: Distance to nearest property line 13. Distance to nearest well 2100' (1594' to Drill Unit) 3266' 16. To be completed for deviated wells Kick Off Depth N/A 18. Casing Program Size Casing 30" 16" 10 3/4" [ X] Filing Fee [ X] Property Plat [X] BOP Sketch [ ] Diverter Sketch [X ] Drilling Program [ ] Drilling Fluid Program [] Time vs Depth Plot [] Refraction Analysis [ ] Seabed Report [ ] 20AAC25.050 Req. . Contact Engineer Name/Number: Mr. Ed Jones 1 (713) 977-5799 Prepared By Name/Number: Duane Vaagen 1 (907) 258-3446 21. I hereby c~fy th~e foregoing is tr~,e""d correct to the best of my knowledge I Signed ~ ~4~.? Title ¡/í~(" /fe.r/(I~/}/ ':/ / / Commission Use Only Permit NUr1:lØer IAPI kúmber 50-283-20036 - C¡D AP,PfOVaIIDa~ I See cover letter ~ 2/)2 - ì D 1 I ~ () i~ for other requirements Conditions of Approval: Samples Required: [ ] Yes [K] No Mud Log Required [ ] Yes [x.] No Hydrogen Sulfide Measures: [ ] Yes [,Xl No Directional Survey Req'd [] Yes Þ<1 No Required Working Pressure for BOPE: [] 2M, [] 3M, [] 5M, [] 10M, [] 15M Other:~C)()O~~\ ~()'Ç> tQ:~~4~~ <..sz.~~~~\J4\ '\"-\''1 \~ ~ 't; \-\. \\ , Onglnal Slgnoo O} by order of 11' Qmlmy Oechsli T avlol Commissioner the commission Date C? t.8 Submit n Triplicate Un. () ¡ \ ~,.J,à.'. i~ L i'\; ~1'Jr\. ALASKA 1 a. Type of work [ ] Drill [] Redrill 11 b. Type of well [X J Re-Entry [] Deepen 2. Name of Operator Aurora Gas LLC 3. Address Maximum Hole Angle Hole Specifications Weight Grade Coupling Length .5" Wall 75# 40.5# 20" 15" J-55 J-55 STC Butt 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured 8578 feet true verticé 8578 feet Effective depth: measured 0 feet true verticé 0 feet Casing Length Size Structural 34' 30" Conductor 304.44' 20" Surface 2630' 10 3/4" Intermediate N/A Production N/A liner N/A Perforation depth: measured true vertical None 20. Attachments Approved By Form 10-401 Rev. 12-01-85 ~~ [ ] Multiple Zone (See 20 MC 25,025) Number NZS429815 Amount $200,000.00 1200 pslg 304.44 2630 Setting Depth Top Bottom MD TVD MD TVD 34' 34' 308' 308' 2628' 2628' Driven 600 Sacks Class "G" 1440 Sacks Class "G" (Cemented to Surface) 95 Sack 7215' - 7000' Plugs (measured) 115 Sack 6718' - 6500' 105 Sack 4151' - 3950' 145 Sack 3314' - 3050' 130 Sack 2756' - 2500' 25 Sack at Surface Junk (measured) Cemented Driven 600 Sacks Class G 1440 Sacks Class G MD TVD 34' 308' 2628' 34' 308' 2628' R E r "'.. k ",/. r-: " ~... ~ '!. r ". \""L~ \' ''- .(1) Alaska Oil & Anchora00 Date 4/11/02 ) ) AURORA GAS Proposed Well Re-Entry and Workover Program Nicolai Creek No.5 PTD 71-03 API No. 283-20036 1.0 Background Information & Present Condition The Nicolai Creek No.5 well was spudded by Texaco Inc., on February 2, 1972. The well was drilled vertically and achieved a total depth of 8,578' MD (8,578' TVD) on March 5, 1972. During the course of drilling, an intennediate casing string was run and cemented, and the well was drilled to TD, with no production string set. After reaching TD, sidewall cores were obtained and analyzed, wireline logs were run and the well was declared a dry hole. The decision was made to plug and abandon the well. On March 7, 1972, \following AOGCC guidelines, a series of 6 cement plugs were placed at various intervals in the wellbore to isolate different geologic zones, seal the casing shoe interval, and plug the top of the casing prior to removing the wellhead and installing a pennanent "dry hole" marker. On July 15, 1988 Unocal and Marathon Oil Company acquired the NicQlai Creek Unit from Texaco Inc. and Mobil Oil Company. Due to poor operating , economics at the time, the decision was made to plug and suspend all remaining wells in tlie~ìcölãiCÌ'èèk Unit until such time that the economics of producing them improved. Aurora Gas, LLC became operator of the Unit in the year 2000, and has since re-entered, worked over and brought NCU #3 on line as a commercial gas producer. Before other wells in the unit can be developed commercially, it has become evident that an injection well will be required to dispose of Class II non-hazardous oilfield waste, namely produced water, well workover fluids and drilling wastes. NCU #5 has been selected to be re-entered and developed as a Class II disposal well because of its strategic location, vertical well design, favorable cementing records, underlying geology and the economically viable solution it provides. All depths referenced in this application are original RKB, which was approximately 89' AMSL. Surface Grade level is 75' AMSL. A 30" diameter structural conductor pipe was driven to a depth of34'. A 20" hole was then drilled to 308' and a 16" conductor was set and cemented into place with 600 sacks of Class "G" cement. A 9 7/8" bit was then used to drill out to 2691', a 15" hole opener was run and 10 %", 40.5# J-55 casing was run, set and cemented in place at 2628' with 1440 sacks of Class "G" cement. Reports indicate good cement returns were observed at surface during the cementing procedure. A 9 7/8" bit was run and the well was drilled to TD at 8578'. Wire line logs were run and 32 sidewall cores samples were obtained from 3068 - 8150'. Lack of any commercial oil or gas indicators caused Texaco to make the decision to plug and abandon NCU #5. Class "G" cement plugs were then placed over the following intervals: 7215' -7000' MD 95 Sacks Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 1 of8 4/19/2002 ) 6718' - 6500' MD 4151' - 3950' MD 3314' - 3050' MD 2756' - 2500' MD Surface Plug 115 Sacks 105 Sacks 145 Sacks 130 Sacks 25 Sacks Attachment I depicts the current configuration of the pennanently abandoned Nicolai Creek Unit No.5 wellbore. 2,,0 Summary of Proposed Well Work In order to effectively re-enter and re-complete Nicolai Creek No.5 as a Class II non- hazardous oilfield waste disposal well in accordance with AOGCC regulations, the following tasks must be completed: ~l. Clear road and wellsite of trees and overgrowth. Initiate repairs to NCD #5 well site as necessary to mobilize in and spot equipment needed for well re-entry and work-over. 2. Remove abandonment marker, inspect wellhead base flange if in place. If it has been removed, dress surface casing stub and install a new wellhead. 3. Mobilize rig, RU, install and test BOP stack, drill out the cement plug at surface. 4. Verify the integrity of the 10 %" inch casing through pressure testing and squeezing as necessary. Run cement evaluation log(s). 5. Perforate the 10 %" inch casing at desired intervals for waste disposal, perfonn injection testing as required. 6. Re-complete the well as a Class II Non-hazardous Oil-field waste injection well. 7. Remove rig and well work-over equipment, clean well site, install surface injection support equipment and prep for injection. The above work will be performed in compliance with the regulations contained in Alaska Oil and Gas Conservation Commission Alaska Administrative Code: Title 20 Chapter 25. 3~O Proposed Operations Program The following Operations Program addresses the work scope to be performed in the course of reentry and re-completing Nicolai Creek No.5 only. The construction of Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 2 of8 4/19/2002 'I ) surface injection facilities and eventual connection of Nicolai Creek No 5 to field gathering lines will be carried out at a later date. 1. Obtain all required permits and regulatory approvals before starting job. Anticipated permits and forms for the well work include the following: . Permit to Drill, Form 10-401(AOGCC) "'" . Application for Sundry Approval, Form 10-403(AOGCC) -~~~~ "'G~ ~cJ . Sundry Notice, Form 3160-5 (BLM) I-.\C)\ ~"'f'<-~~~ . Disposal Injection Order v-.J<e t I.. ~'> ~ ~ Clear access road and wellsite of trees and overgrowth. Rebuild and repair both as needed to permit access to and provide enough space for spotting well work- over equipment for Nicolai Creek No.5. 2. Mobilize all required personnel and equipment to the Nicolai Creek No.5 location on an as needed basis via barge and aircraft. The proposed personnel and 'equipment spread is as follows: 3. .~ Personnel: Equipment: Drilling Supervisor Toolpusher Drillers RoughneckslRoustabouts Vac Truck Operators Equipment/F orklift Operators Cementers Wireline Crew Medic Welder (I) (1) (2) (8) (2) (1) (3) (3) (1) (1) Wellhead Tubing Spool, valves and surface completion equipment Welding equipment 1 Drilling/W orkover rig BOP equipment and accumulator Choke manifold 966 loader Wireline unit wi perforating guns Fuel Truck Cement pump unit Bulk cement silo W ICement Cell Phone communications Drilling Fluid Additives Drilling Fluid mix water 1 Lot: Oil Spill Contingency Equipment Tools, sufficient for any contingency Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 3 of8 4/19/2002 ) 3 ~" drillpipe 2 7/8" production tubing (for completion) 1 Office bunk shack Gas detection system Pit volume/flow monitoring system W ell testing equipment Cement Retainer Retrievable packer Permanent packer Casing scraper 4. Hold safety meeting before starting work on the well. Notify AOGCC of intent to begin operations. 5. Excavate to install new well cellar as needed and gain access to top of 10 %" \ casing stub. Remove well abandonment marker. If base flange is present, inspect, clean up as necessary. If base flange in no longer present, trim up casing stub and install new casing head flange. 6., Move in rig and rig up. Hook up tanks, pumps, BOP stack, flòw lines and gas ~ detection and pit monitoring systems as per 20 AAC 25.033 and 20 AAC 25.066. 7. Give AOGCC 24 hour notice of pending BOP test so that they may witness same. r ~<L~ t.~" ~~..~rq <1. t) "\4.S; I Mix 100 bbl, 9 - 9.5 ppg mud to be used for drilling out the surface cement plug in Nicolai Creek No. 5:~ " ~\ ~Q: ~ Co \ \>C;\ c~t.~'oa.\().~ <t ';) 1\($ , Pressure test BOP stack, choke manifold and all surface equipment per AOGCC requirements. 8. 9. 10. Pick up 9 7/8" bit and drill out surface cement plug in 1 0 %" casing while maintaining constant watch on fluid volumes. When cement has been drilled out, shut down pumps and monitor well for flow. The well should be dead, but should still be treated as if potential pressures could exist in well-bore below cement plug. Be prepared to shut well in immediately should any flow be noticed. When satisfied well is dead, RIH with bit to PBTD while circulating to top of cement plug at 2500' MD (While tripping in hole, be cognizant of the possibility that junk could have been thrown down wellbore when the well was abandoned in 1972). Tag TOC plug but do not attempt to drill. ,~ <:..:;),c:...f:(.~f::.trù \ \<"(.~,,\~ C)\,)~ 11. Notify AOGCC 24 hours in advance of pending casing pressure integrity ~ ,~ ~ test so that they may witness same. Close pipe rams at surface and pressure test ,~,~~~~t" \,,~t<h 10 %" casing to 1500 psi. Record results. If test is satisfactory, proceed to step '0 ~<ë. -\- ~ ~~~<f 13. Ifunsatisfactory, proceed to step 12. ~\e,:)~ ()..~ ~\\ot4'\ ~Q ~\...)«. (.). " .ç. \~\ ""\:) Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 4 of8 4/19/2002 12. ) ) POOH with bit, PU and RIH with casing scraper to PBTD at 2500' MD. POOH, LD casing scraper and PU retrievable packer, TIH, stopping at 500 ft intervals to pressure test, isolate and repair leak using cement squeeze method as necessary (cementing procedure to be provided). If squeeze job is performed, drill out and retest casing to 1500 psi. Repeat as necessary to produce satisfactory pressure test. If during the course of this and subsequent testing, the casing in NCU #5 is deemed to be mechanically unsound and unsalvageable for use as an injector, the well will be shut in until such time that a new plan can be formulated. When casing has been pressure tested satisfactorily, POOH and PU casing scraper, RIH to PBTD and circulate out mud with 3% KCI or inhibited lease produced water solution and high-vis sweeps as necessary. POOH, RU wireline with lubricator and RIH with USIT cement evaluation logging tool on wireline. Prior to beginning logging operations, close wireline pack -off on wireline and pressure up wellbore to 1000 psi. Log entire 10 %" casing string, POOH and RD. :t ~~ \ ~~ \\. Ifresults of USIT are satisfactory, proceed to step 17. If USIT indicates poor pcl<>~ ~\ \ \ ~ ~ cement quality in annulus behind 10 %" casing, proceed to step 14. ÒO"«" ~\~"\)û-\ \>~S~'-o)~" 14. IfUSIT indicates poor cement quality behind 10 %" casing within 500 feet of '~ injection zone, RU wire line with 4" perforating gun, RIH to questionable area, perforate with 4 shots at 4 spf (90 deg. phasing). POOH with wireline. 'PU retrievable packer with bypass valve or cement retainer and TIH to just above perforated interval, set packer and initiate squeeze by establishing an injection rate with water. When circulation rate has been established, pump cement volume (to be calculated when decision to squeeze is made) to fill void plus 250/0 excess into perforations, use hesitation squeeze method. Release packer, reverse circulate out excess cement until tubing is clean, POOH and WOC. 13. 15. RU and TIH with bit and casing scraper, drill up excess cement in wellbore and pressure test. If test holds, re-run USIT to investigate success of squeeze job. If test fails, PU and RIH with retrievable packer, set above perforations, and repeat squeeze procedure in step 14. Repeat steps 14 - 15 as necessary to insure good cement seal exists in annulus behind the 10 3Ä" casing. 16. When casing has been successfully pressure tested and all testing is completed, PU bit and casing scraper. TIH, drilling out residual cement as necessary to 2500'. Do not drill out cement plug across the shoe. Circulate until returns are clean and insure final fluid in wellbore is clean inhibited water. 17. TOOH with work string, rig up wireline truck and perforate the interval from 2325'-2345' at 6 SPF (max expected BH pressure at this point is less than 1100 --., <;~ ~~~ psi, at +/- 2345' TVD). 18. Notify AOGCC of intent to perform injection test. Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 50f8 4/19/2002 ) '} 19. TIH with work string and retrievable packer, setting at 2200'. Begin injection test by injecting water to establish rate. Do not exceed 1500 psi at surface to initiate injection (actual pressures should be substantially less than 1000 psi). Perform step rate injection test and record pressures and rates. While injecting, monitor the drill pipe X 10 %" annulus for transient pressures and flows. If satisfactory, POOH with drill pipe and packer and proceed to step 21, if not proceed to step 20. 20. Kill well and pull work string and packer, RIH with wireline and perforate interval from 2315' - 2325', POOH. Repeat injection test and perforations as necessary to achieve acceptable injection rates and pressures. 21. Make up retrievable packer and WEG on tubing end and TIH to 2250', set packer, space out, land tubing hanger, set backpressure valve in tubing hanger, nipple down BOP and nipplç up tree. Dress packer shear out sub for 3500:1: psi and pressure test tubing while running packer. Check for pressure at surface in both ~ annulus and tubing prior to rigging down BOP stack and nipple up of tree. 22. RD rig and remove all equipment not pertinent to injection function of well and clean up site. 23. " File new Form 10-407 with AOGCC describing final status of well. Faìrweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 6 of8 4/19/2002 D Proposed I X I Present Condition ) ) Nicolai Creek No.5 Nicolai Creek Field Size WI. Grde Thrd CONDUCTOR 30" SURFACE 16" 75# J-55 INTERMEDIATE 103/4" 40.5# J-55 B~;SS LINER PRODUCTION TUBING Depth 34' 308' 2628' 25 Sack Cement plug at Surface Sks/Cmt 30" (.5" Wall Structural Conductor) Drive n to 34' 16", 75#J-55 30S' M D Drilling Mud 10 3/4", 40.5# J-55 262S'MD(262S' TVD) Cemented wI 1440 sks Class G to surface Drilling Mud Drilling Mud Drilling Mud Drilling Mud Drilling Mud 600 Sks 1440 Sks PTD: 71-03 API: 283-20036 Spud Date: Feb. 2, 1972 Date Abandoned: March 7, 1972 Elev. (RKB) 89.00' (Ground Elevation 75' AMSL) All depths are RKB measured depths. 130 Sack Class G Plug 2756' . 2500' M D 145 Sack Class G Plug 3314' - 3050' MD 105 Sack Class G Plug 4151' - 3950' MD Attachment I 115 Sack Class G Plug 671S' - 6500' MD 95 Sack Class G Plug 7215' - 7000' M D 97/S" Hole toTD @ S57S' MD(S57S' TVD) DRAWING NOT TO SCALE FAIRWEATHER E&P SERVICES ¡NO. Nicolai Creek No. 5 Rev. 01 Pcond I DHV 05-Nov-01 Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 70f8 4/19/2002 .) ) 0 Proposed D Present Condition Nicolai Creek No.5 Nicolai Creek Field 2 7/S" Tubing For Injection Size Wt. Grde Thrd Depth Sks/Cmt CONDUCTOR 30" 34' SURFACE 16" 75# J-55 308' 600 Sks INTERMEDIATE 10 3/4" 40.5 # J-55 STC 2628' 1440 Sks Buttress UNER PRODUCTION TUBING 27/8" 6.5# L-80 8 Rd 2250' ";11 ~':-.I ::;,~;¡:' TubIng _k., >""~",:i. @2250'MD ~\~!,-~~;;§~r!~;.~~ Class II Disposal s;;~D::f:i:}:.:?~~ Perforations Fluids .:~.i~:'~~"~'~ 2325' - 2345' MD . 10~'".40~J-55 T~~~; ~'ð <! - ~ 2628'MD(262S' TVD) '.",I\~::~..\i?fr~ ,',I';' ~'o"",,\ - ~-~ Cemented w/1440 ~.:::;, <}:.\;..... 130 Sack Class G Plug sks Class G ~:'''~:''..~;;.¡¿..:. 2756' - 2500' MD to surface .,.,,'. PTD: 71-03 API: 283-20036 Spud Date: Feb. 2,1972 Date Abandoned: March 7, 1972 Elev. (RKB) 89.00' (Ground Elevation 75' AMSL) All depths are RKB measured depths. 30" (.5" Wall Structural Conductor) Driven to 34' 16", 75#J-55 30S' M D Cemented W/600 Sks Class G to Surface Drilling Mud -' - .., "'~' - \:- ~~ .- '". ...~.. ".., ::;;:..;~ i..':'i.-~~~: ~ ".."; ~ 145 Sack Class G Plug 3314' - 3050' MD Drilling Mud ,... i. ""''','... , .. .~., ". ,;: -_~r~'. - ~':'".=- /~¿;.,'r..?i.,~ : 105 Sack Class G Plug 4151' - 3950' MD Attachment II Drilling Mud ~~~:~'.:';:..~~;:~l 115 Sack Class G Plug 671S' - 6500' MD Drilling Mud ~':: ~:-:;~.~.::. f ~~-:. 95 Sack Class G Plug 7215' - 7000' MD Drilling Mud 97/S" Hole toTD @ S57S' M D (S57S' TVD) DRAWING NOT TO SCALE FAIRWEATHER E& P SERVICES INe. Nicolai Creek No. 5 Rev. 01 Proposed I DHV 05-Nov-01 Fairweather E & P Services, Inc. Nicolai Creek Unit No.5 Rev. 2 Page 8 of8 4/19/2002 . ~ ) ) Surface Location Information Nicolai Creek Unit No.5 (NCU #5) is an abandoned well located on Federal lease number ///1 ;:~ tlZ? FFDA ?34161, which is owned 1~0% by Aurora Ga~ LLC. ~his lease, located onshore, a?jacent //~fD to TradIng Bay on the northwest sIde of Cook Inlet, IS compnsed of 2260 acres. Surface nghts ' are owned by Cook Inlet Region Incorporated (CIRI). NCU #5 was drilled as a vertical hole, tested, plugged and abandoned in 1972. There are no other lease holders within one-half mile of NCU #5. Figure 1-1 is a copy of the original surveyors report. Figure 1-2, is a Sundry notice filed with the AOGCC depicting the actual "as-built" coordinates and finished pad elevation. Location information for the NCU #5 well is as follows. Nicolai Creek No.1 Lease Number: Surface Location: FEDA 034161 2183' SNL, 1622' WEL, Sec. 19, TI1N, R12W S.M ASPX = 239,830 ASPY = 2,571,656 SM Same 8578' Same Bottom Hole Location: Measured Depth: True Vertical Depth: Aurora Gas LLC. Nicolai Creek Unit No.5 Page 1 of5 4/22/2002 , ) ') I . ¡- - - - - -- _':'_\!I~'!?~'---T -- - --- ¡-- - - --,--- ---I I. I I I ! \ I ¡ II Ii 12 I 7 I 8 ..1 9 10 ¡ I i I ¡ I I I ~______L______~------~-______L______-------~ , I I 1 : : : 14 : 13 I 18 17 ¡ 16 I 15 I II t ¡ 1 I I ¡ 1 ¡ I I I I ~-----r------II----lî---20---r-~~-- : ---: !. 23.1. 24 19 ~~¡594' NIKOlA I C R~EK. ~NIT NO.5 22 I ¡ f I LAT. : 61og151.7S" j I I I LONG:: 151 28.~.31! f \ X:: 239.859 ¡ !- - - ---- ~ ---- - --~ - - ---- ~-- -_Y"':~~~.' 7!Q--ì--_~ --- - --~ ! t. I I APPROX. GROU~ ELEV. 125 FT. ¡ I I I ' ¡ i 26 1¡ 25 I 30 ~ 29 " 26 ! 27 I. I! I ! 1 I I ¡ I t 1 I I I I t ~------1------1-------r------l------r------1 ; I I I. ! I' ¡ ¡ I I ì ! 35 I 36 1 31 I 32 I 33 I 34 ¡ I I I I I ! I I I I I, ~--~--~---~--~--~--_U~- I SCALE: ¡":: I MILE TION. CERTIFICATE OF SURVEYOR I ~ ~ 1 ¡ I hereby certify thot ! om properly registered and I icensed to practice londsurveying in the Stote of Alaska and thot this plot represents 0 location survey mode by me or under my supervision) ond thot 011 dimensions and other deta í Is are correct. """""" '\... _....~ OF ~( ~, ,,:r~ ..........,.4.n It ,Ä,.'r..' ji'eev+ I "" '? .' ... e. "9 , :"l49!~ .":L .... *' I (.~...... '.~""t~"¡''''''..~.'.1 ..../ ~~ I' /"; -~ ...~. 'Ld: ":J...~ê: a ('., ~~.. ;41r.:.. ...-............~ " .. l \ .//7.Y8-$i-,.;.-v, ~# ....~~~~'" J f~< "'eGIS,.~~...'~.., ., "".IiD"''''.'''ê,-\O_- ',,,, SUR"~...." ,~",,,....,.... ... ,. .... /..~::.;7"' ;¿"7,/:::.L Date ,¿ .-;;7' /. -Þ- /" / Þ.?0.-~../;::'.~..,:.-,;~s../, .:Ø ,/ SURVEYOR/:--:// N I KG LAI CREEK UNIT NO.5 ~~, L (' \/ r Located in NE 1/4 SEC. 19 T.IIN..R 12W. SEWARD MERIOIAN.ALASK'I Surveyed for TEXACO INC. ".;..:;--, GAS i~H\/ ¡;;, ('~'rJ~ ~CÜ~:,Gr . Surveye db)' F M. LINDSEY 8 ASSOC. LAND 8 HYDROGRAPHIC SURVEYORS! 2502 West Northern Lights Boulevord 80), 4-081. Anchoroge AIOska I Figure 1-1 Aurora Gas LLC. Nicolai Creek Unit No.5 Page 2 of5 4/22/2002 . . ) ) Form P-3 REV. 9-30-67 e. Submit "Intentions" In Triplicate & "Subsequent Reports" in Duplicate . STATE OF AlASKA OIL AND GAS CONSERVATION COMMITTEE S. API NtTM.ERJCAL CODE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form lor proposals to drIll or to decpon or plug back to a dilfierent reSCl'VOir Use "APPLICATION FOR PE:RMlT-" for such proposals,) 50-283-20036 6. LEASE DESIGNATION AND SERIAL NO. A - 034161 1. 7, IF INDIAN, ALLOTTEE OR TRIBE NAME ~;:Lt, ~ ;,A¡;I!LL 0 '2. NAME OF OPERATOR TEXACO Inc. OTHER 3. ADDRESS OF OPERATOR P. O. Box 4-1579, Anchorage, Alaska 99509 8, UNIT FARM OR LEASE NAME :- Nicolai Creek Uni t 9. WELL NO. 5 4. LOCATION OF WELL It), FŒ!..D AND POOL, OR WI!..DCAT At surface I Wildcat 1622 I W/E, 2128 I 'SIN line, Sec. 19, T11N, R12W, 15 S~~~itE~" (BOTTOMRÔi.E S.M. 19 12 Sec. ,T11N,R W,S.M. 13, ELEVATIONS (Show whether DF, RT, GR, etc: 12. PERMIT NO, 14, 88' Rotary Table (75' Grd. Level) 71-30 Check Appropriate Box To I'ndicate Nature of Notice, Report, or Other Data NOTICII or IN'rIlNTION TO: 8UR8:B:QUZNT RIlPOa'r OJ': ::::T:::::::VT-on :1~LL~I::I!A~::p!.m ::A:::~I:::::ln~'T :::;::~:G C::I~G I-I SHOOT OR ACIDIZI!I ARANDON. SHOOTING on ACItlIZING ABA:;DOS~'Z:!fT. I-I R'£PAIR \\'IIILL CHASOI! PLASIi (Otber) Fi n;=t 1 S'.1rV9Y Røport LxJ (Othf'r) ~~;'~;tro~P~~tR~~~~~le~1o~'ii~~~;t C::A1t~~ofo:~,)well I:;, pl:eCl\lRt PIIOI'O,!'!:D Oil COMPLETED OPERATIOSS (Cleol'ly stote tI!! 1"'rtlnellt detallN. lIod ;1\'(' pertlDE'nt dateB, Including I!IItlmated dat'! ot Btartlng liDJ' proposed WorK, The subject we11site location has been completed and a final lias built" survey was made on January 24 and 25, 1972. The survey indicates the following: Location: 1622' W/E, 2183' SIN, Sec. 19, T11N, R12W, Seward Meridian or Lat. = 61°01'51.21" and Long. = 151°28'01.92" or X = 239,830 and Y = 2,571,656 using Alaska State Plane Coordinate System, Zone 4. Elevation 88' Rotary Table or 89' Kelly Bushing or 751 Ground Level U«[¡;~~Ú~~lU; J A N ~ 1 1979 Oi\4ISIOt4 C~ é.ilt ANB Straight Line Dis tance to Nicolai Creek Unit # 3 ::: 3266/","''''''':'' ',:,= 16 1 hereby certUy.. ~t ./ :..,?IrOIDIrj: (trlJ<l and C.orrect SIGNED, ,- Ce. / ) ~2'ï\'t''"- TITLE T. () Mr. .;mn (Tbll Ipa~ for State office use) Field Foreman DATE 1/28/72 APPROVED BY CONDITIONS OF APPROVAL, IF ANY ; TITLE DATE See 1nstructions On Reverse Side ~;L f~';.' ~' " , ", r.-~ ,~~~" i ¡,¡ ~ ~! ¡,j \.: ~.;I L.; ~ ~t..l:' id ~ -- ~. ¡.;;.¡ Figure 1-2 Aurora Gas LLC. Nicolai Creek Unit No.5 Page 3 of5 4/22/2002 1.~ Surroundine Area ) ') The operator of Federal Lease number FEDA 034161, where NCU #5 is located, is: Aurora Gas LLC 10333 Richmond Ave. Ste 710 Houston, TX 77042 The surface owner for the lease is Cook Inlet Region Incorporated (CIRI). There are no other surface owners or operators within a one-half mile radius of the surface location of the NCU #5 disposal well. Figures 2-1 and 2-2 show proximity of nearby oil and gas properties and developments. Cook Inlet Activity Map Legend 0 Unit Bounda..,. , ~ 011 Field I Accumulation . Gas Fjeld I Accumulation 8 Selected Wells Proposed {Active Wells 1"\ PI"t:arm ::::: Pï:;¡'9rL.'1!!s . ?~~uct¡ÇÕl I:ar;¡¡Üy /--,~_.~- .;~ "'-;; --,---~;;~~:;:~ Aurora Gas LLC. Nicolai Creek Unit No.5 '" ~ ~ * c ÛC 1\ ~~f(~~ ,forth Fork ..-! ,,/7 Figure 2-1 Page 4 of5 4/22/2002 í", ) .) Units Oil Field I Accumulation Gas Field I Accumulation No State Minerals '" Platform Oil Pipeline - Tesoro Products Line - Gas Pipeline .-..--.. Military Products Line Production Facility 0 5 10 I I I COOK INLET OIL & GAS MAP D . . * ~\~ OJ "-.;: ~ ~ ÛO Gulf of Alaska ~ D08, G 6/95 ~:)=~~::=:~-::::r=~m4 §?§::::=::,Ë~~~:;æ;:;:\. Figure 2-2 Aurora Gas LLC. Nicolai Creek Unit No.5 Page 5 of5 4/22/2002 ,..t:::: f~IRWfm~fR E & P SERVICES. INC. Company: Rig Number: I. DRILL SITE - a AUTHORIZED PERSONNEL signs posted b. HARD HAT/SAFETY GLASSES - signs posted - c. NO SMOKING areas designated - d. H2S controls if applicable - e. Escape and guy lines flagged - f. Hard hats/Safety glasses available for visitors II. DOG HOUSE - a. Adequate exits, doors installed properly, operate freely - b. Approved heaters used - c. General housekeeping d. First aid kit and facilities - e. Crew trained in first aid = f. Emergency phone numbers posted - g. Two-way radio provided - h. Safety equipment available - i. Crew wearing hard hats and safety glasses - j. Crew wearing hard-toed shoes - k. Proper clothing worn by crew - I. No hazardous jewelry worn m. NO SMOKING rules observed = n. OSHA log posted - accidents - o. B.O.P. drills, test logged - p. S~fety meètings logged. - q. Driller at or near controls - r. TOOlpusher/Rig Manager at rig location -- s. Approved and adequate lighting - 1. Hazard communication/MSDS sheet on site III. DRILLING FLOOR AREA - a. Rotary table area - b. Kelly bushing guard used - c. Controls adequate if no guard used - d. Rotary chain drive guarded e. All unused floor holes covered = f. General housekeeping, lighting - g. Pipe slips, dies - h. Racking floor area - i. Vee door gate provided, in place - j. Makeup and breakout tongs - k. Tong snubbing lines, clamps -I. Tong counter weights - m. Tong body and jaws condition - n. Tong safety handle pin secured - 0 Tong dies sharp, keeper used - p. Air hoist line, guide guarded - q. Catheads r. Catlines = 1. Spinning chain, headache post - u. Crown-O-Matic device, operating - v. Drilling line - w. Drawworks and overrunning clutch x. Driller's controls = y. Hand toOI$, bench grinders - z. Gauges and meters functional - aa. Safety valve and wrench accessible - bb. Tong counter weight in guides, cable and sheave condition - cc. Subs properly stored - dd. Mud box used when required, in good condition and properly rigged - ee. Doghouse heater not an ignition source - ff. Geolograph, flow-show, PVT equipment properly working - gg. BOP procedures, maximum allöwable casing pressure, fill-up information posted - hh. Overall condition of all rope, cHains, slings and hooks used for lifting - ii. Choke panel operational, gauges and controls function properly IV. STAIRS, HANDRAILS, GUARDRAILS -- a. Adequate stairs provided off rig - b. Stairs level, secure, no obstructions - c. Adequate handrails provided (stairs) - d. Stair treads uniform, of non-skid type - e. Guardrails, midrails, toeboards V.DERRICK AND SUBSTRUCTURE - a. Derrick, A-frame assembly pins in place, secured with keepers b. Booms and boom lines = c. Manufacturer's specification plate on derrick ( ~ )If Okay ( -) If not applicable ( ,.) If correction is needed /~ RIG ACCEPTANCE FOR-Dlt. Inspection Date: Inspected By: - d. Flashing red light on crown - e. Bumper sills installed on crown - 1. Hinge points, structural cross members free of damage, cracks, and excessive corrosion - g. Derrick ladder in safe condition - h. Crown block in good condition; regularly maintained VI. BLOWOUT PREVENTERS - a. B.O.P. properly installed, tested - b. Wheels and stems in place - c. Stack properly stabilized - d. All hydraulic lines connected - e. All unused lines capped - f. Accumulator unit properly located - g. Gauges properly located - h. Housekeeping, drainage - i. Choke manifold and line, secured - j. Blooey line used, pilot light used - k. Approved and adequate lighting -I. Signage - j. BOPE rated working pressure adequate for planned work - k. Remote closing station properly located - J. No short bolts, loose or missing nuts _m. Adequate number of BOPE closing methods handrails or laid across walkways _no Accumulator controls labeled, handles in open or closed position with blind handle guarded _0. Accumulator relief line vented to hydraulic tank - p. Control line condition, steel or armored hose - q. Blast points on headers protected by targeted plugs - r. Personnel trained in operation of BOP's, crew assignments for shut-in procedures posted - s. BOPE securely braced to substructure -1. Mud gas separator secured VII. PIPE RACK AREA - a. Ends of pipe raCks chocked - b. Layers of pipe chocked, spacers used - C. Pipe racks level, stable - d. Stairs with handrails provided - e. Vee door slide, pipe stops used - f. Pipe tubs and bridles - g. Derrick stand and ladder - h. General housekeeping, lighting - i. Dead end of drilling line elevated - j. Employees not on top of pipe VIII. DERRICK BOARD AREA a. Derrick ladder - b. Derrick climber installed and used = C. Safety belt, safety catch - d. Safety lines or lanyards used - e. Derrick emergency escape line - f. Geronimo on line and ready for use - g. Pipe fingers and tools secured ....... h. Mud standpipe secured i. Mudhose snubbed on both ends IX. MUD PUMP AREA - a. Drive belts, pony rods guarded - b. Head and valve covers fully bolted - C. Shear pin pop-off valve covered/tested d. Ends of mud vibrator hose snubbed - e. Ends of relief lines secured = f. General housekeeping - g. Approved and adequate lighting X. MUD MIXING AREA - a. Bagged material properly stacked - b. Walkways and guardrails - C. Condition of walkways, free from obstruction - d. Guardrails provided on crossovers - e. Approved and adequate lighting - f. Eye protection required warning signs - g. Shale shaker guarded - h. General housekeeping - i. Explosive-proof equipment at shale shaker - j. Agitator shafts and couplings guarded - k. Mud guns and jetting hoses secured -I. Desander, desilter, degasser units XI. MUD TANKS AND PITS - a. Adequate stairs with handrails - b. Adequate personal protective equipment - C. Adequate eyewash available - d. General housekeeping - e. Adequate ventilation in area - 1. Elevated loading door opening protected - g. Approved and adequate lighting - h. Chemicals properly labeled, stored and handled - i. Adequate ventilation -- j. Bulk tanks in goOd conditioh - k. Pit level and flow show indicators Unsatisfactory remark requires clarifying comment: XII. GENERATOR AREA - a. Generators properly located - b. All generator moving parts secured - C. Generators properly grounded - d. Cover panels on electrical control boxes - e. Emergency lighting provided in SCR building - f. HIGH VOLTAGE warning signs used - g. SCR doors closed, A.G. unit properly working - h. All electrical tools grounded - i. Condition of electrical wiring - j. Electrical wires properly strung k. Unused electrical outlets covered = I. Air compressors properly guarded - m. Air storage tanks equipped with pop-off - n. General housekeeping, lighting - o. Hearing protection available - p. Wiring, motors, receptacles, switches, lighting, etc. meet code requirements - q. Use of household electric outlets on rig or associated equipment prohibited - r. Electrical control boxes marked "Danger High Voltage" and state voltage S. Dielectric mats in front of all electric control boxes =1. S. O. electric cords properly routed - not tied to XIII. FUEL STORAGE TANKS - a. Fuel storage tanks properly located - b. All storage valves marked as to connects - C. Discharge nozzles, hoses, valves - d. Piping and fuel lines - e. General housekeeping, lighting - f. Stationary ladders on storage tanks XIV. FIRE PROTECTION - a. Adequate fire extinguishers - b. Tanks properly vented - c. Flammables in U.L. safety cans d. NO SMOKING rules enforced - e. Flare area clear of combustibles = f. Boiler and Its safety controls - g. Welding performed safely - h. Spark and heat arrester on engines - i. Fire extinguishers inspected, charged, tagged and sealed - j. Personnel are trained in the use of portable fire extinguishers - k. Flammable/combustible liquids are properly labeled and stored - I. Oily rags/waste picked up and stored in closed metal containers -- m. Engines equipped with spark arresting mufflers and emergency shutdown device XV. HYDROGEN SULFIDE - a. Appropriate warning signs - b. H2S monitors, alarms - c. Briefing areas, breathing equipment - d. Site specific training - e. Contingency Plans available XVI. HOISTING EQUIPMENT - a. Number of wraps on hoisting drum - b. Drillline conditions, ton miles records available, slipped and cut as required - c. Condition of brake pads and flanges, brake linkage adjustment, retainer pins in place - d. Weight indicator installed, maintained and calibrated e. Condition of bails and elevators = f. Boom line and pole in good condition - g. Lifting chain/slings inspected and tagged - h. Traveling block and hook in good condition XVII. ENVIRONMENTAL - a. No fuel spills, trash in reserve pit, reserve pit leaks - b. Spill Contingency Plans (SPCC) - C. Trash container provided and used - d. Oil container (drip pans) under engines and pumps XVIII. TOOLS AND MACHINERY - a. Hand tools clean, inspected and properly stored - b. Broken or damaged tools remove from service - c. Moving parts properly guarded - d. Equipment repaired or adjusted by authorized personnel - e. Power source locked out and/or tagged - 1. Air tanks drained daily, relief valve installed XIX. RECORDS AND TRAINING - a. Inspection by contractors along with corrective action taken - b. Accident Prevention Program in effect - c. Minutes of safety meetings d. Pit/BOP drills = e. Accident, Injury/Illness Reports - f. Accident Investigation follow-ups - g. Drilling permit - h. Current well control training - i. Current well control training - j. Procedure for reporting accidents - k. Maintenance program and records for critical equipment -I. OSHA Form 200 available Aurora Well Service Rig No.1 Proposed Rig and Pit Layout (See additional attad 'tntsfor BOP, Choke Manifold and We//head""1,figuration. Also note that below diagram L Jbject to change as fabrication and design wo,;~ still being done) Rig (Franks 300) 215,000 lb capacity derrick 460 HP ( AWSRig 1 J II c::: .S - (,) Q) .!= 0 ~ 0 ~ 'If - -., BOP (See BOP Diagram) / "=~:=Ioo ]: : =-= f?"'" ')¡ ðõ . ~~ 0 ~ To Annulus "Kill" (See BOP Diagram) þ!t. Returns from Power Swivel / Choke Line (See BOP Diagram) -.::==... -'L Choke I Kill Manifold / (See Attached Manifold Diagram for valve layout) Choke Manifold, rigged for reverse circulating during workover operations(pump down annulus belowrotating head, with returns up workstring ID through power swivel to pit or choke and gas buster as needed). **See Attached BOP and Choke Manifold Drawings for Valve Details. Pump # 1 Pump #2 r ~ r ì '-- ~ ;= i y=- '-- n ~ Charge Pump ---1 - / Mix Hopper == c::::J - , , ,- S- Wiered Mud / Fluid Tank -200 Bbls Designed Dimensions 5' H X 8' W X 30 ' L Suction & Mix Section I 80 Bbl Capacity ---.J With Pit Level Monitor Settling Section -.-r- 80 Bbl Capacity With Pit level Monitor Shaker Pit Section 40 Bbl Capacity 400 Bbl Devided Steel Pit With Gas Detector 200 Bbl Section for Solids 200 Bbl Section for Flare ,.,.!'. ',"",. ;::: 1\ --_II. Shaker Solids Collection Flare Pit lllllllllllllllllllllllllllllllllll!lII~ ~ 0= - 11u' 'gh A h. G B- pn t tmosp enc as uster Drawing Not to Scale Aurora Well Service Rig No. 1 Fairweather E&P SeNices, Inc. Rev. 01.1 Plan Vafm / DHV 17-April-02 Aurora Well Service Rig No.1: Proposed 3M BOPÇonfiguration for well re-entry and worr')er procedures using reverse ch ')ation. I, I 2" 3M Manual Valve (Kill Line), 2" 3M Hydraulic Valve (Kill Line) ~ ~ I ~ Fluid flow direction while reverse circulating Returns taken up workstring and through power swivel to pits. ... Spool /1 ~(t)n 3M Washington Rotating Head 2" 3M Manual Valve on spool for either pumping into or taking returns above rams. Pipe Rams sized to work string. 11" 5M Double Gate Blind Rams 2" 3M Manual Valve (Choke Line) ./ ----- 2" 3M Hydraulic Valve / ......r--- (Choke Line) Drilling Spool I I 11"X3M ~fPr-, Well Head ~ 2" 3M Manual Valves On Wellhead , Fluid flow 9' Drawing Not to Scale Fairweather E&P Services, Inc. Nicolai Creek No.5 BOP System Rev. 01.1 / DHV 17 -April-02 Aurora Well Service R~ No.1 Proposed Choke I Kill Ma,t',.,. ifold Configuration All valves are 2" rate, lt 3000 psi. ) Inlet from Power Swivel (Reverse Circulation Mode) Output to Pits ê ~ Ii L ¡ i Manual Choke c - , f. , .. ,.(] -,....~.~"., ,..:::'J~" ,.'., ..........,.....~:,"'m ' '~ '.. , .: '~-"""'''''.'-,,,..,,...,~,.m___....,.,~,,",,.'_.'',,^~,," "."~.y.. ¡"""^"."",,,~,,,,,;,,,.y;c"",~r"..'.ø-,,.,, '. - "" " ~ n \ r . Inlet from BOP Choke Line § ¡ ¡ ¡ ".,'. H r I ;" i; . ~ ~ : ,~~:~.,;:..;i.~;=:c;:.:c:::=.:;;.::::,..~þ:;:;:;,.,.._..."...~.:;; --:;0:; ;,.;~:;;::CJ":".'-""'::':;;:'''~':.J.:: - ::Of ",;.;; :Of I ~, -, " \ - - Bleed Flare Line to ~ All Valves: 203M Rated ' I Open Flare Pit n 6 ' ~ ~ ~' [þ.;.;.;;:;-_J:~..;~;:,::;:;,;:::..: ~ ':0( ':::,:';'; ::",<\ ;;,::..tD I'i \ ¡ < ~ L t L Hydraulic Remote Activated choke . ,,,'.' ._"",~;::_'.:,.~:}J To Gas Buster "Atmospheric Degasser" Drawing Not to Scale Fairweather E&P Services, Inc. Nicolai Creek No. 5 Choke/Kill Manifold Rev. 01.1 I DHV 17 -April-02 ) ) AURORA GAS LLC. NICOLAI CREEK # 5 2-9/16" 5,000 Tree Run l,¡~cP) C.'- ¡ml ~ cii[UJj UJj1 (0' @L@ 0 0 ::@ 0 ~"l . . 2-9/16" 5,000 Wing 11" 3,000 Fig 2-1/16" 5,000 10-3/4 CSG -----. 2-7/8 TBG .L::d fØ CAMERON David Shaw Anchorage Ak 04/04/02 ) ~Aurora Gas, I.I.C April 12, 2002 Ms. Cammy Oechsli Taylor, Chainnan Alaska Oil and Gas Conservation Commission 333 West ih Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Pennit to Drill: Nicolai Creek Unit No.5 4c~,S~\?\\) \'\\-CJ~D Dear Ms. Taylor, Aurora Gas LLC, hereby applies for a Pennit to Drill, as a prerequisite for re-entering an abandoned well. At this time, Aurora Gas LLC would like to re-enter the NCU #5 well and re-complete it as a non-hazardous Class II Oilfield Waste injection well. The well will be used to support both ongoing production and future development plans on the northwest side of the Cook Inlet. The Application for Disposal of Oilfield Waste is being submitted under separate cover. The Nicolai Creek Unit No.5 well, is located onshore Granite Point, in the Nicolai Creek operating unit, and is approximately 11 miles Southwest of the village of Tyonek. Aurora plans to begin well reentry and work-over operations on June 1 st, 2002. Upon receipt of all necessary pennits and approvals, contractors will clear and repair the original NCU #5 access road and drillsite so that the rig, Aurora Well Service No.1, and support equipment can be mobilized to the site to begin well work operations. Pertinent information attached to this application includes the following: 1) 2) 3) 4) 5) 6) 7) 8) Form 10-401 Application for Permit to Drill- 3 copies Fee of$100.00 payable to the State of Alaska Well Prognosis and discussion of Operational Considerations Location Plat and surrounding area map Re-entry, wellbore integrity testing and completion procedure Rig Acceptance Checklist W ellbore, Wellhead and BOP schematics The following are Aurora Gas LLC' s designated contacts for reporting responsibilities to the Commission. 1) Completion Report (20 AAC 25.070) Duane Vaagen, Proj ect Engineer (907)258-3446 2) Geologic Data and Infonnation Andy Clifford, President (20 AAC 25.071) (713)977-5791( E C E !. \1 E D j\ DP ? r) 2¡QO? t"\. ., ..... ..... I.., Alaska Oil & Gas Cons. Commission Anchorage ) Ms. Taylor Page 2 3) Injection Reporting (20 AAC 25.432) Ed Jones, Excecutive Vice President (713)977-5799 If you have any questions or require additional information, please contact the undersigned at (713)977-5799, or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC Q;- (/'7 , 1 l J-... . . \ /; ~/~ / /f 1./ L/" v,.. Ed. Jones Executive Vice President / Production Manager Enclosures cc: Duane Vaagen Andy Clifford RECEIVED ? 'Î ?tll'12 L~ '-. ,-v ' Alaska & ,,-,¡¡;,~.. :>:..;¡¡ìf Anchoraoe -'. ') FAIRWEA THER EXPLORATION & PRODUCTION SERVICES INC. GENERAL ACCOUNf P.O. BOX 103296 ANCHORAGE,AK 99510-3296 PH. (907) 258-3446 1e Hundred Dollars And 00 Cents rATE OF ALASKA ,""t.".;,~...:.,,"~~~...,-~~<:,.';'r.o;:""~~":'~b.~.''t.~. -~ ---~'A......~~~,,,,,,~,,,,,,,,~,,',,~,,,'~~"-,..~""';"'---,,"'_.""~~~";"'",".'Efh'-ò<:>O:'.',.'.,~.....,.:,r.,.."...~..:..:~"""~t.~'I~'¿"~,",,<!\,~~OQ"..,:'l>_I.:"-~"~_.'t<''',p.-",~c:--.~:"..,,,,, ¡ FIRST NATIONAL BANK OF ANCHORAGE ANCHORAGE, AK 99501 89-611252 - 1 DATE 4/22/2002 RECEIVED APP I) I) 2nn? I 1\ L. L \,1\1'- Alaska Oil & Gas Cons. Ccmt«ì1üíoìJ Anchorage 8403 AMOUNT $100.00 ..Ii () ('J tJ) c c .!!l. i¡¡ ê:: 0 6J "9 .g l' ìr G.' M' 3 ~, (J i.!J r t ) TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BEINCLUDEDIN~MITfAL~ETTER . . - . WELLNAMEA0eoJ<-¿ ~~(I #~ CHECK 1 ST ANDARD LEITER DEVELOPMENT CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If api number last two (2) digits are between 60-(9) DEVELOPMENT REDRlLL PILOT HOLE (PH) . EXPLORATION ANNULAR mL. DI OSAI:. / yÑo-' INJECTI07 ANNULAR DISPOSAL ¡?¿ - e Yr!r;j L.J YES INJECTION WELi ANNULAR DISPOSAL REDRlLL THIS WELL "CLUE" The permit is for a new wellbore segment of existing well ~ Permit No, API No. . . Production should continue to be reported as a function of the original API number stated above. . In accordance with 2.0 AAC 2S.005(f), all records, data and logs acquired for the pilot hole must be dearly . differentiated in both name (name on permit plus PH) and API number (50 -70/80) from . records, data and logs acquired for well (name on permit). Annular disposal has ~ot been requested.. . Annular Disposal of drilling wastes will not be approved. . . Annular Disposal of drilling wastes will not be approved. . . DISPOSAL INTO OTHER Please note that an disposal of fluids generated., . ANNULUS L-) YES + SP ACING EXCEPTION Enclosed is the approved application for permit to drill the above referenced well. The permit is approved .sùbject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuan.ce of a conservation order approving a spacing exception. {Company Name) will assume the liability of any protest to the spacing exception that may occur. t-:Jo~ q.;:\~\Cl\ \SO\>~S.\- ~0,?\ '0,,- ~~~<;.,>~:2\c..Q:)~~ ~\\ ì"-~<:;~~c<è -\?o, ~ \3ò\? ~S-\- ~~\,\"',. \\-")", Templates are located m drive\jody\templates ~ ~ WELL PERMIT CHECKLIST COMPANY ,Auns-r........ WELL NÞ,.ME/V'::(4.i Cre.d d,/~ROGRAM: Exp - Dev - R~ -~7 Wellbore seg - Ann. disposal para req- FIELD & POOL Sl;'()O.3,"-,~ INIT CLASS.~ i/'~ (i.-.j D5'P'-') GEOL AREA 6C¡D UNIT#"vA ~ . ON/OFF SHORE ()'1 ADMINISTRATION 1. Permit fee attached. . . . .;. . . . . .~ L' . . . . ~ . (j) N . L?;?e. ,- ,¿h ,t-v V ,0/' /1'-:)'9 ..J ", l4ha--r, L~ . ~¡ I 2. Le~senumberappropriate',~, '~.':C-;~;jJPf;¡/../.O:-.q;OIS(Ñ)...." rl'-~ ~, .~¿>,:if.. I~ j;:¿v}M-~ z.<, A.4-Ú68~~, ~ -P.(¿y- 6SLÞ( 3. Unlquewellnameandnumber.~.ð.è'.;-c;. ~i.ç/J.< f7.¿''"1,l-,;./t;>-:yc.1 L~ ,(J ~i'(' ..prl.i AAr:x-5~L/~. ;£D, ~-/~-P2- /. . 4. Well located in a defined pool.. . . . . . . . . . . ... . " . . y @ I>~Srú~~ ~ I( ~!::-.. ¿\Ji M..~- 4- ~ VI? d.L.J-L~d r~1 ~lk~ 5. Well located proper d~stance from drilling unit, t??undary:~~. . . ~. N +tlR- (''1U7U.../- l-ðÞ-rYV\.c;'fr~, 6. . Well located proper distance from other wells~ . . . . . . .. . ' (1) N Jk 'ff..' , ",' (),.f' , ,( 7. Suffic~ent a~reage availabl~ in drilling unit~. . . . . . . . . . Cfj N .,/~ -:' e'¡.. (~ ~. () ..L'<... .' 8. If deviated, IS wellbore plat Included.. . . . . . . . . . . . . . Nrt8?.' N ti ,,,-,..../7.¿~',< "\.i-.Il, 9. Operator only affected party.. . . . . . . . . . . . . . . . . . Y N .ð ..,.. . I. / . I '. J' / .~ 10. Operator has appropriate bond in force. . . . . . .. . . . . . Y 1M.. 7ft. ré>/'~Æ~ . c~ I ~~w~k l.¿+, ó~ <3Á.~ j'¡" ~/"ZS '''¡Z~'3'15/ 11. Permit can be issued without conservation order.-*~.. . . . . y.fi) ~ ~ 'I..t-. t.u'7'./Á-...fI\.J2- C) e~Þ\-t.l:> ~I ~ , U AP~F, ,",R ,~J1T~ 12. Permit ca~ be issued without admi~istrativ~ approval.. . . . . ß)-Þk~* ~?~'kf~~h~.ð-Y~ I-i"-'}¡ v;¡..u}. A~Vi.:fZ.r E~~ì-IA..?~~\.. ßD .~ ,t:>o~>". 13. Can permit be approved before 15 day walt.. . . . . . . . . . y @ 0rYck-v no.f- ¡....¡¿s;; u, 'resd .. () l/ I ENGINEERING 14. Conductor s~ring provided. . . .. . . . . . . . . . . . . . . .. ~ N ~ ~~~k P~.L..S..'. 1?"eR'M~.. -r{, «'6S~f'.~. ~ ~ >'. ~ ~~. ;U'..t(.) ,/I UW.. l. k.. ".'...r-' .-1-. . e~".u" 15. Surface casing protects all known USDWs. . . . . . . . . . . Y N perry¡t!f -~ drJ/1 e:;;;~'.p/¡ t!¿.}1-r6'?1' ..€!:Q5/JJ-5 r't2..~V.il'e...š (::¿~{...jL .p~-"'>n~ll-/- 16. CMT vol adequate to circulate on conductor & surf csg. . . . . N /Ju/J?be..:r be-- ¡::¿.ss.'oc.¡~:.J*-d i.07-/-i, p- un/c.' iAß ,tM~ //u);'I'¡:5¿r¿," 17. CM. Tvoladequatetotie-inlongstringtosurfcsg.. . .,.. ~þ-. "¥--W ¡Cõ/../Þ~¡"ì5~ '~~.'.' /~...&r..?Y4.e/>~ b1-:::;¡~G...?7;fq dt/é.,fi. è"';'K.."./ý!i.;f., 18. CMT will cover all known productive horizons. . . . . . . . . . C:ô N MÍI/fric 1'k#/ ¡ .¡..h- ¡/ r~ ~ e~~;~7 ;,.V)jl k &:l.S</;¡-U/(/)u¿dlJ t:<.. /u.:04.J ..., 19. Casing designs adequate for C! T, B & permafrost. . . . . . ~ 0 N (/~) /?/l.:..f.- I'll..) . 'l'j:-r )_.~. ~:~,rff>7 fb¡ ..VrJl.6..L. ' r¡¿ tV,/J he c/..a-¡~¡ 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . Y N -/--v 5 u 2- 83 2. c....;(_.,!3f:.~ 0 ( (;> . $' - 21. If a re-drill, has a 10-403 for abandonment been approved. . .~" Y N ~/...).. 22. Adequate wellbore separation proposed.. . . . . . . . . . . . \Y) N 23. If diverter required, does it meet regulations. . . . . . . . . . ~ "'. Y N 24. Drilling fluid program schematic & equip list adequate. . . . . Y N 25. BOPEs, do they meet regulation. . . .. . . .~. . . -:--:... . . . . ~ N ~ ~ \ \ C:\. (' 26. BOPE press rating appropr.iate; test to a<::>Cv psig. ' ø N \>\~"N,4~ ') Qo~{)~C'-'T \ ~ \~OO '+..)~ \5.t)(:) ~\ ~~"" c.t\. \ \c.!r} ~r- 27. Choke manifold complies w/API RP-53 (May 84). . . . . . . . Y N À..:1t:c~ ~~(t:~'ð '!>~Ò ~? ~ <;~C b~; 28. Work will occur without operation shutdown. . . . . . . . . . . ø N ~ , .. ' 29. Is presence ofH2S gas probable.. . . . . . . . . . . . . . . . Y N ~~t-""'--..)Cù ~().':"\ ~<:).~(t <i..()W\.q. ~').~~~~ $1-"~)' t ~~'-~'" 30. Permit can be issued wlo hydrogen sulfide measures. . . . . 0' ~~~~\~ ~~~ ~«. \~ 31. Data presented on potential overpressure zones. . . . . .. \~ Y N 32. Seismic analysis of shallow gas zones. . . . . . . . . . . .. ~ Y N APPR DATE 33. Seabed condition survey (if off-shore). . . . . . . . . . . . . Y N ,.)J() b-:-Z. DO¿ 34. Contact name/phone for weekly progress reports [eXPlora7"êmIY] Y N ANNULAR DISPOSAL 35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; . . . . . . . Y N (B) will not contaminate freshwater; or cause drilling waste. .. Y N to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N GEOLOGY: ENGINEERING: UIC/Annular: COMMISSION: RP~--;;;r- - TE~!~~:> COT SF~~-"WGA DTS()1/(*J'j la? JMH ~II DATE I<tÞ'IVt 'J(~') GEOLOGY APPR DATE I ) h. "> ....<>~~ \ \' \0-..... '\ ~ \6 ~,,$! -- ~"o.~~~ ~ \ \. \"' "'....;, \M. u.~ <:,. r\~ ~ ~..::>q; ~D ~~~~ t--1\.~c:). X~ ~~,,~(~O~~ 1r-""'~F~\ \c:;, ~«..C)-\ \ bù~ '~"''''-<è ~£.\\ ~~\~'\o~ ~C'~~("~~l~~~,~\k.. \\ ~ \.~ -\."'-.«. O~~ ~ ~~ ~ ~ ('.,.. Þ'\s.c.~ ~C!"..,) 'ß~~<t.~ wI $ ""'~"-(f '-J ~"-c:§r ". Comments/Instructions: * 1'4..€.:K..d ,l¿&.~ LDd.(;..,.. '~1--CY- /'V'<:...r:.:./~(.' C t-~c-L w.\.Á.(.~;~ ~* tlë.5 óu h;,¡,.J..,...., Cu r'H-J'\'.( /\¡~~ /e.. L C¡- I.:. . ..( ..bó o. 1 t:::<::. U "( , vV\<.::-o41~j . ) Well History File APPENDIX Infornlation of detailed nature that is not particulariy gernìane to the Well Pennitting Process but is part of the history file. . To improve the readability of the Well History fìle and to sinlplify finding infornìation, information of this nature is accunlulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of infonnation. ) ) Schlumberger q7TJ:) I)JXk~ { ð 7 Formation Water Salinity Determination RECEIVED Nicolai Creek Unit 5 S\GI\NNElv DE f~ 2 1 20D5 " Company Field Well Date Logged Date Processed Reference Number API Number Log Ana Iyst DEG 1 9 Z001 Alaska Oil & Gas Cons. Commissior~ Anchorage Fairweather E&P Services Nicolai Creek Nicolai Creek Unit 5 10-FEB-1972 23-NOV-2001 21487 50-283-20036-00 Douglas Hupp, PE Alaska Data and Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, Alaska 99503 (907)273-1700 All interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and we shall not. except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cost, damages or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current price schedule. ) ') Fairweather Field: Nicolai Creek Log Date: 10-FEB-1972 Well: Nicolai Creek Unit 5 Introduction Fairweather E&P Services, Inc. (Fairweather) has asked Schlumberger to evaluate the salinity of the formation water on well Nicolai Creek Unit 5, which was drilled by Texaco in 1972. The intervals of interest are from 2300 ft to 2350 ft and 2500 ft to 2550 ft. The data available for this evaluation included Dual Induction - Laterolog, Gamma Ray, and Sonic well logging tools. In addition, Fairweather asked Schlumberger to discuss possible formation correlations between the Nicolai Creek Unit 3 and Nicolai Creek Unit 5 wells. Salinity Determination The salinity of the formation water (Rw) was determined by two techniques, SP interpretation and Rwa interpretation. Both techniques assume the fluid in the formation is water with no hydrocarbon. The charts used in this work are included in this report. SP Interpretation SP interpretation consisted of the following steps. 1. Determine temperature at the zone of interest (T zone = 40 + 0.013 X Depth) 2. Determine Rmf at temperature of zone (Chart Gen-9) 3. Determine Rmfeq (Chart SP-2) 4. Determine SP deflection from shale baseline 5. Determine constant K (K = 61 + (0.133 x Temperature)) 6. Determine Rweq from formula SPdeflection = -k x log (RmfeqlRweq) 7. Determine Rw (Chart SP-2) 8. Determine salinity (Chart Gen-9) Zone 2300 ft to 2350 ft. 1. Temperature at zone = 70.2 of 2. Rmf at temperature = 2.56 ohm-m 3. Rmfeq = 1.2 ohm-m 4. SP deflection = -30 mv 5. K = 70.3 6. Rweq = 0.45 7. Rw = 0.46 ohm-m 8. Salinity = 13,500 ppm Zone 2500 ft to 2550 ft. 1. Temperature at zone = 72.8 of 2. Rmf at temperature = 2.56 ohm-m 3. Rmfeq = 1.2 ohm-m 4. SP deflection = -25 mv 5. K = 70.3 6. Rweq = 0.53 7. Rw = 0.58 ohm-m 8. Salinity = 11,000 ppm ) ) Fairweather Field: Nicolai Creek Log Date: 10-FEB-1972 Well: Nicolai Creek Unit 5 Rwa Interpretation Rwa interpretation consists of the following steps. 1. Determine Rt from the DIL log 2. Determine ~tlog from sonic log 3. Calculate porosity (<Þ) from the sonic log (<Þ = 0.67 x (~tlog - ~tmatrix) / ~tlog) 4. Calculate Rwa (Rwa = <þ2 x Rt / 0.81) 5. Determine salinity (Chart Gen-9) The sonic measurement in this well is the largest source of uncertainty in the Rwa interpretation technique. Sonic measurements at shallow depths can be affected by poor compaction of the rock. If this is the case, the sonic porosity calculated from the equation in step 3 (above) may result in an optimistic (high) interpreted porosity. A description of the Nicolai Creek Gas Field in the Oil and Gas Fields in the Cook Inlet Basin, Alaska, published by the Alaska Geological Society, 1975 indicated the porosity of the pay ranged from 25% to 35%. Salinity results are presented in this report are based on porosity from the Hunt-Raymer equation and assuming porosity = 25%. Porosity from Hunt-Raymer Equation Porosity Assumed to be 25% Zone 2300 ft to 2350 ft. 1. Rt = 7.7 ohm-m 2. ~tlog = 120 µsec/ft 3. <Þ = 35.9% 4. Rwa = 1.23 ohm-m 5. Salinity = 4900 ppm Zone 2300 ft to 2350 ft. 1. Rt = 7.7 ohm-m 2. ~tlog = 120 µsec/ft 3. <Þ = Assume 25% 4. Rwa = 0.59 ohm-m 5. Salinity = 10,500 ppm Zone 2500 ft to 2550 ft. 1. Rt = 5.7 ohm-m 2. ~tlog = 125 µsec/ft 3. <Þ= 37.2% 4. Rwa = 1.22 ohm-m 5. Salinity = 4900 ppm Zone 2500 ft to 2550 ft. 1. Rt = 5.7 ohm-m 2.~tlog = 125 µsec/ft 3. <Þ= Assume 25% 4. Rwa = 0.44 ohm-m 5. Salinity = 14,000 ppm Correlation Comparison Fairweather asked Schlumberger to discuss the correlation between Nicolai Creek Unit 3 and Nicolai Creek Unit 5 wells. Zones of interest for correlation ranged from 1900 ft to 2330 ft in the Nicolai Creek Unit 3 well and 1985 ft to 2410 ft in the Nicolai Creek Unit 5 well. Cross well correlations are subjective, being based on logging curve similarities. Several factors, beyond the control of this analyst, affect the accuracy of this work including lithological changes, formation fluid differences, borehole mud salinity differences, and other geological variations. Similar log responses were noted as described in Table 1. Fairweather Field: Nicolai Creek Nicolai Creek Unit 5 2550 ft 2375 ft to 2410 ft 2350 ft 2190 ft ,) ) Log Date: 10-FEB-1972 Well: Nicolai Creek Unit 5 Table 1 Nicolai Creek Unit 3 Discussion Very sharp increase SP at the base of apparent sand. This suggests a possible errosional unconformity. Apparent fining upward sequence noted on SP. Increase resistivity spike noted on both logs. Increase resistivity spike noted on both logs. 2500 ft 2300 ft to 2330 ft 2265 ft 2100 ft Summary Interpreted salinities based on SP and Rwa techniques range from 4900 ppm to 13,500 ppm for the upper zone and between 4900 ppm and 14,000 ppm for the lower zone. The SP and Rwa techniques show close agreement in salinity when the formation porosity is assumed to be 25%, ranging from 10,500 ppm to 14,000 ppm. If you have any questions regarding the formation water salinity calculations, please feel free to contact Douglas Hupp at (907)273-1700. Conversion ::: + + + or ::: 10 8 c: e ~ 15 fJj Õ 6 5 4 3 1 0.8 0.6 0.5 OA 0.3 0.2 0.1 0.08 0.06 0.05 0.04 0.03 0.02 0.01 "F 50 "C 10 I I 100 40 ! I 125 50 I I 200 80 90 100 I ¡ I I 300 350 400 120 140 160 180200 I I ! I' ! I 20 I 30 I 150 60 70 ! ¡ or © Schlumberger ~'!õIIII"""!""I". !.I.. Q to I'-- (i.1 10 20 25 30 ..... e 200 250 300 400 500 5 ro Z 10,000 1·5 ~-mI'!I""'I!"..J 0.001 1.0 - 1 I I t \ ' , ! , ~ ~ I , I , , I I 1 I 1 ! 0.1 0.2 0.3 0.5 1.0 or , l ' \ , 2 3 4 5 0.002 _ 0.005 _ 0.Q1 - 0.02 0.05 I- o 0.1 :: 0.2 0.5 _ 2.0 I I I I I"., ,,\\,1 I 1 . , ,I 1 0.005 0.Q1 0.02 0.03 0.05 © Schlumberger These charts convert equivalent water Rweq, from Chart SP-1 to actual water Rw. They may also be used to convert Rmf to Rmfeq in saline muds. Use the solid lines for NaC1 waters. The dashed lines are approximate for fresh formation waters (where effects of salts other than NaCI become cant). The dashed portions may also be used for mud filtrates. Rweq = 0.025 ohm-m at 120°C From chart, Rw = 0.031 ohm-m at 120°C for muds Ca or Mg in solution are discussed in Reference 3. Lime-base muds have a amount of Ca in may be treated as mud types. 2·6 'r ) } Analytica Alaska Southeast 5438 Shaune Drive Juneau, AK 99801 (907) 780-6668 Fax (907) 780-6670 ANALYTICA Environmental Laboratories 11/26/01 Fairweather E & P P.O. Box 103296 Anchorage, Ak 99510-3296 Attn: Jeff Osborne Work Order#: JOII0064 Date: 11/26/0 I Work ID: Nicolai Creek Unit #3 Date Received: 10/23/01 Sample Identification Lab Sample Number JO 11 0064-0 1 Client Description Produced Water Lab Sample Number Client Description Enclosed are the analytical results for the submitted sample{s). Please review the CASE NARRATIVE for a discussion of any data and/or quality control issues. Listings of data qualifiers, analytical codes, key dates, and QC relationships are provided at the end of the report. Sincerely, David Wetzel Project Manager "The Science of Analysis, The Art of Service" RECEIVED DEC 1. 9 2001 Alaska Oil & Gas Coos. CommisSion Anchorage ~ . J ) Case Narrative Analytica Alaska Southeast Work Order: JO 110064 Samples were prepared and analyzed according to methods outlined in the following references: o Methods for Chemical Analysis of Water and Wastes, USEPA 600/4-79-020, March 1983. o Test Methods for Evaluating Solid Waste, USEPA SW-846, Third Edition, Revision 4, December 1996. Problems encountered with the analyses are discussed in the following narrative. Cr, Cu, Pb, Mn, and Zn are present in a small amount in the laboratory method blank. This value is less than 1/10 of any detected values in the samples, so the effect on the data is insignificant. · . j ) Detailed Analytical Report Analytica Alaska Southeast Workorder (SDG): JOI10064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number! none Report Section: Client Sample Report Client Sample Name: Produced Water , Matrix: Aqueous Collection Date: 10/18/01 4:45:00PM Lab Sample Number: JOII0064-01B Analysis Date: 11/14/01 5:59:15PM Prep Date: 11/8/01 Instrument: Elan Analytical Method ID: SW6020 - ICPMS - ICPMS Total File Name: J011112009.cs Prep Method ID: 3010A Dilution Factor: 5 Prep Batch Number: J011112009 Report Basis: As Received Analyst Initials: SAW Analvte CASNo Result Ftaes Units ~ MOL Rerun #: Aluminum 7429-90-5 ND ugIL 25 3.4 I Antimony 7440-36-0 ND ugIL 2.5 0.43 Arsenic 7440-38-2 S.13 ugIL 5.0 0.43 Barium 7440-39-3 3,910 ug/L 1.3 0.32 Beryllium 7440-41-7 ND uglL 1.5 0.50 Cadmium 7440-43-9 ND ugIL 1.0 0.15 Chromium 7440-47-3 3.85 uglL 0.50 0.15 Cobalt 7440-48-4 4.41 uglL 0.50 0.15 Copper 7440-50-8 130 ugIL 2.5 0.85 Lead 7439-92-1 7.68 ug/L 0.75 0.19 Manganese 7439-96-5 2,130 ug/L 2.5 0.31 Molybdenum 7439-98-7 ND ug/L 5.0 0.75 Nickel 7440-02-0 37.9 ugIL 2.5 0.050 Selenium 7784-49-2 20.4 ugIL 5.0 1.5 Silver 7440-22-4 ND ugIL 1.8 0.55 Thallium 7440-28-0 ND ugIL 1.3 0.21 Vanadium 7440-62-2 66.5 uglL 5.0 0.75 Zinc 7440-66-6 47.8 uglL 5.0 0.80 Lab Sample Number: JOII0064-01B Analysis Date: 11/14/01 6:07:17PM Prep Date: 11/8/0 I Instrument: Elan Analytical Method ID: SW6020 - ICPMS - ICPMS Total File Name: JOIII12009.cs Prep Method ID: 3010A Dilution Factor: 100 Prep Batch Number: JOI1112009 Report Basis: As Received Analyst Initials: SA Analvte CASNo Result FtaRs Units mL MOL Rerun #: Calcium 7440-70-2 406,000 ugIL 5,000 890 3 Iron 7439-89-6 85,500 ugIL 5,000 490 Magnesium 7439-96-5 22S,OOO ugIL 5,000 170 Potassium 7440-09-7 375,000 ugIL 5,000 630 Sodium 7440-23-5 3,870,000 ugIL 5,000 740 Page 3 of9 ) , Detailed Analytical Report Workorder (SDG): JOII0064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Analytica Alaska Southeast Client Project Number: none Report Section: Client Sample Report Client Sample Name: Produced Water I Matrix: Aqueous Collection Date: Lab Sample Number: JOII0064-01C Analysis Date: Prep Date: 10/31/01 Instrument: Analytical Method ID: 200.8 - Metals by ICPIMS - ICPMS Dissolved File Name: Prep Method ID: 200.8-D Dilution Factor: Prep Batch Number: J011031001 Report Basis: As Received Analyst Initials: Analvte CASNo Result F1a2s Units fQb MOL Aluminum 7429-90-5 ND ug/L 1.0 0.33 Antimony 7440-36-0 1.01 uglL 0.10 0.027 Arsenic 7440-38-2 11.6 ug/L 0.15 0.044 Beryllium 7440-41-7 ND ug/L 0.15 0.045 Cadmium 7440-43-9 ND uglL 0.20 0.062 Chrom ium 7440-47-3 1.16 ug/L 0.15 0.049 Cobalt 7440-48-4 4.08 ug/L 0.50 0.14 Copper 7440-50-8 9.80 ugIL 0.10 0.034 Lead 7439-92-1 ND ug/L 0.10 0.030 Molybdenum 7439-98-7 3.68 ug/L 0.50 0.13 Nickel 7440-02-0 29.2 ugIL 0.15 0.050 Selenium 7784-49-2 44.4 ugIL 0.50 0.14 Silver 7440-22-4 0.154 ug/L 0.10 0.028 Thallium 7440-28-0 ND ugIL 0.050 0.017 Vanadium 7440-62-2 25.7 ugIL 5.0 1.4 Zinc 7440-66-6 30.0 uglL 0.25 0.084 Lab Sample Number: JOII0064-01C Analysis Date: Prep Date: 10/31/01 Instrument: Analytical Method ID: 200.8 - Metals by ICPIMS - ICPMS Dissolved File Name: Prep Method ID: 200.8-D Dilution Factor: Prep Batch Number: JOII031001 Report Basis: As Received Analyst Initials: Analvte CASNo Result F1a2s Units .mL MOL Barium 7440-39-3 3,000 ugIL 1.3 0.41 Iron 7439-89-6 31,200 uglL 250 75 Manganese 7439-96-5 1,890 ug/L 0.25 0.085 Lab Sample Number: JOII0064-01C Analysis Date: Prep Date: 10/31/01 Instrument: Analytical Method 10: 200.8 - Metals by ICPIMS - ICPMS Dissolved File Name: Prep Method 10: 200.8-D Dilution Factor: Prep Batch Number: J011031001 Report Basis: As Received Analyst Initials: Analvte CASNo &m!! Fla2S Units ~ MOL Page 4 of9 10/18/01 4:45:00PM 11/5/01 6:43:48PM Elan J011031001.cs 1 SAW Rerun #: I 11/5/01 1O:1O:57PM Elan JOII031001.cs 5 SA Rerun #: 2 11/5/01 1O:15:04PM Elan JOl1031001.cs 100 SA Rerun #: , .' ) Detailed Analytical Report Workorder (SOG): JO 11 0064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: Report Section: Client Sample Name: Matrix: Lab Sample Number: Prep Date: Analytical Method 10: Prep Method 10: Prep Batch Number: Report Basis: Analvte Calcium Magnesium Potassium Sodium Lab Sample Number: Prep Date: Analytical Method ID: Prep Method ID: Prep Batch Number: Report Basis: Analvte Total Dissolved Solids Page 5 of9 J0110064-01A 10/23/01 160.1 - Residue, Filterable, Gravimetric, Dried at 180C - 160.1 J011024010 As Received CASNo none Client Sample Report IProduced Water Aqueous J0110064-01C 10/31/01 200.8 - Metals by ICPIMS - ICPMS Dissolved 200.8-D J011031001 As Received CASNo Result Fla2S Units 7440-70-2 418,000 ug/L 7439-96-5 209,000 uglL 7440-09- 7 319,000 ug/L 7440-23-5 3,510,000 uglL Result Flaes Units 10,500 mglL ) Analytiea Alaska Southeast ~ Collection Date: Analysis Date: Instrument: File Name: Dilution Factor: Analyst Initials: l.Q1 MOL 25,000 5,800 50,000 12,000 50,000 20,000 50,000 13,000 Analysis Date: Instrument: File Name: Dilution Factor: l.Q1 20 Analyst Initials: MOL 5.0 10/18/01 4:45:00PM 11/5/01 1O:15:04PM Elan JO 1103100 1.es 100 SA Rerun #: 3 10/25/01 2:02:00PM SCALE CT Rerun #: 2 o '} Detailed Analytical Report W orkorder (SDG): JO 11 0064 Project: Nitolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none Analytica Alaska Southeast Page 6of9 . . . J ) Detailed Analytical Report Workorder (800): JOII0064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none Analytica Alaska Southeast QC BATCH ASSOCIATIONS - BY METHOD BLANK Lab Project 10: 6,351 Lab Project Number: JOII0064 Test: 160.1 - Residue, Filterable, Gravimetric, Dried at 180C - (TDS) Prep Date: 10/23/01 Lab Method Blank Id: JOl102401O-MB Prep Batch ID: J011024010 Method: 160.1 - Residue, Filterable, Gravimetric, Dried at 180C - (TDS) This Method blank and sample preparation batch are associated with the following samples, spikes, and duplicates: SampleNum ClientSampleName DataFile AnalysisDate JOl10050-01A Batch QC 10/23/01 3:28:01PM JOII0064-0IA Produced Water 10/25/01 2:02:00PM J01102401O-LCS LCS 10/23/01 3:28:0IPM JOll024010-LCSD LCSD 10/23/01 3:28:0IPM JOII0050-0IA-DUP DUP 10/23/01 3:28:0IPM Test: 200.8 - Metals by ICP/MS - ICPMS Dissolved Prep Date: 10/31/01 Lab Method Blank Id: JOll031001-MB Prep Batch ID: JOII031001 Method: 200.8 - Metals by ICP/MS - ICPMS Dissolved This Method blank and sample preparation batch are associated with the following samples, spikes, and duplicates: SamnleNum ClientSampleName DataFile AnalysisDate JOI10064-01C Produced Water JOII031001.csv 11/5/01 6:43:48PM JOll 0064-0 lC Produced Water JOll031001.csv 11/5/01 10:1O:57PM JOI10064-01C Produced Water JOI1031001.csv 11/5/01 10:15:04PM JOl10077-07B Batch QC JOl1031001.csv 11/5/01 6:10:49PM JOll031001-LCS LCS JOll031001.csv 11/5/01 5:29:56PM JOII031001-LCSD LCSD JOII031001.csv 11/5/01 5:34:04PM JOII0077-07B-MS MS JOII03100l.csv 11/5/01 6:14:56PM JOl10077-07B-MSD MSD JOl1031001.csv 11/5/01 6:19:03PM Page 7of9 J ) Detailed Analytical Report Workorder (SDG): 10110064 Project: Nicolai Creek Unit #3 Client: Fairweather E & P Client Project Number: none Analytica Alaska Southeast QC BATCH ASSOCIATIONS - BY METHOD BLANK Lab Project ID: 6,351 Lab Project Number: JOII0064 Test: SW6020 - ICPMS - ICPMS Total Prep Date: 1118/01 Lab Method Blank Id: JO 11112009-MB Prep Batch ID: 10 11112009 Method: SW6020 - ICPMS - ICPMS Total This Method blank and sample preparation batch are associated with the following samples, spikes, and duplicates: SampleNum ClientSampleName DataFile AnalysisDate JOI10064-01B Produced Water J011112009.csv 11114/01 5:59:15PM JO11 0064-01B Produced Water J011112009.csv 11/14/01 6:07:17PM J0110077-02B Batch QC JOI1112009.csv 11/14/01 1 :52:55PM JOI1112009-LCS LCS JOI1112009.csv 11/14/011:01:19PM JOll1l2009-LCSD LCSD JOl1112009.csv 11/14/01 1:05:21PM JO 11 0077 -02B-MS MS JO 11112009 .csv 11/14/01 1 :56:56PM JOII0077-02B-MSD MSD J011112009.csv 11/14/01 2:00:57PM DA T A FLAGS AND DEFINITIONS Reporting Limit: Limit below which results are shown as "NO". This may be the PQL, MOL, or a value between. See the report conventions below. Result Field: NO = Not Oetected at or above the Reporting Limit NA = Analyte not applicable (see Case Narrative for discussion) Qualifier Fields: LOW = Recovery is below Lower Control Limit HIGH = Recovery, RPO, or other parameter is above Upper Control Limit E = Reported concentration is above the instrument calibration upper range Organic Analysis Flags: B = Analyte was detected in the laboratory method blank J = Analyte was detected above MOL or Reporting Limit but below the Quant Limit (PQL) Inorganic Analysis Flags: J = Analyte was detected above the Reporting Limit but below the Quant Limit (PQL) W = Post digestion spike did not meet criteria S = Reported value determined by the Method of Standard Additions (MSA) Other Flags may be applied. See Case Narrative for Description Page 8 of9 .. . J #It Detailed Analytical Report Workorder (8DG): JOI10064 Project: Nicolai Creek Unit #3 Client: FairweatherE & P Client Project Number: none .) Analytica Alaska Southeast REPORTING CONVENTIONS FOR THIS REPORT TestPk~Name 160.1/160.1 (Aqueous) - (TDS) 200.8/200.8 (Aqueous) - ICPMS Dissolved 6020/3010A (Aqueous) - ICPMS Total Basis As Received As Received As Received Page 9 of9 # Si~ Fi~s 3 3 3 Reportinø Limit Report to PQL Report to PQL Report to PQL ) Nicolai )~ek No.5 Nicolai l;Î"eek Field Size Wt. Grde Thrd Depth Sks/Cmt 30" 34' 16" 75# J-55 3081 600 Sks 10 3/4" 40.5 # J-55 STC 2628' 1440 Sks Buttress I X I Proposed I I Present Condition 27/8" Tubing For Injection 30" (.5" Wall Structural Conductor) Driven to 34" NaCI21 KCI2 in Tbg I Csg annulus Class II Disposal Fluids 10 3/4". 40.5# J-55 2628'MD(2628' TVD) Cemented wI 1440 sks Class G to surface Drilling Mud Drilling Mud Drilling Mud CONDUCTOR SURFACE INTERNEDlATE LINER PRODUCTION TUBING 2 7/8" 6.5 # L-80 8 Rd 2250' f, I Tubing Packer . @ 2250' MD PTD: 171-03 API: 283-20036 Spud Date: Feb. 2, 1972 Date Abandoned: March 7. 1972 Elev. (RKB) 89.001 (Ground Elevation 75' AMSL) All depths are RKB measured depths. Perforations 2320' - 2340' MD 130 Sack Class G Plug 2756' - 2500' MD 145 Sack Class G Plug 3314' - 3050' MD ~I2CI2II1I2D ÐEC 1 AlaskaOi/& fJ 2001 ~~~ 105 Sack Class G Plug 4151' - 3950' MD Attachment II 115 Sack Class G Plug 6718' - 6500' MD 95 Sack Class G Plug 7215' - 7000' MD 9 7/8" Hole toTD @ 8578' MD (8578' TVD) DRAWING NOT TO SCALE FAIRWEATHER E&P SERVICES INC. Nicolai Creek No.5 Rev. 01 Proposed / DHV 05-Nov-0 1 I Proposed ) Nico~_)Creek No.3 Nicolai Creek Field X I Present Condition Size Wt. Grde Thrd Depth Sks/Cmt 3112" Production Tubing CONDUCTOR 20" 85# 282' 720 Sks SURFACE 13 54.5# J-55 2001' 1770 Sks 3/8" INTERMEDIATE 7" 29# N-80 25221 220 Sks LINER PRODUCTION TUBING 3 1/2" 9.2 # L-80 8-RD 23851 Drilling Mud Sliding Sleeve @ 1812' PTD: 167-007 API: 283-20003 Re-Entry Start Date: Dec 6, 2000 Date Re-Completed: Dec 25,2000 Elev. (RKB) 16' (Ground Elevation 246' AMSL) All depths are RKB measured depths. Perforations 1900' - 1930' MD 95/8"47# Bakerweld Screen @ 1900 -1931' Well has been Gravel Packed with 29,744 Ibs of gravel. TOL @ 1941' 13 3/8" 54.5# WI 1770 Sks Cmt @ 2001' Perforations 2005' - 2032' MD Perforations 2201' - 2238' MD 3 1/2" 9.2# Bakerweld Screen 1933' - 2346' Perforations 2302' - 2328' MD Perforations 2360' - 2380' MD Bullplug @ 2385' RIEC€/VIED DEC 1 Alaska . 9 ZOO J Oi/&Gasc A onsC #'1ßchorage DrnmiSSiofi PBTD @ 2478' 7" 29# N-80 Liner @ 2522' Cement W/220 Sks Cmt 50 Sk Cement Plug from 4915' to 5000' 50 Sk Cement Plug from -6890' to 7000' TD @ 8841' DRAWING NOT TO SCALE FAIRWEATHER E&P SERVICES INC. Nicolai Creek No. 3 Rev. 01Finall DHV 18-Dec-0 1 SENT BY: 12-19- 1 15:28 :# 1/10 ) ) "f'III"I'f..-...., - .....-. ! I ~~.>- iJ....~ ' ,~~..,j '. l~. ~ .... ~ E & P SElfVICE8, INC, Fax Transmittal Sheet To. ~~" Ak4("-.I~ð<'(Fromo ... Û¿fio....~., FaXl ~/~ - ?S~~ Pages, (Including Cover Sheet): Phon..: . 7 'J ;J'... / ~ i ý' Date; /}?.. ~¿- ~ è) / Re: Job #h tJ Urgent ~~view (J Ple..e Comment 0 Please Reply 0 Pie... Reeycl. . Comments: N-r:'()~,' " /~C(.fe tJú~~ ~ t/"" II 'I //J I! f.~ /' /7 ..../ /(-'51 Ib/~ ~ C't:. r r~' /.,J oJ r, V (../ ". c?5· 5 - J vý l.o RECE1VED nç(' ..\ 9 2001 ~,~'....I ,~ 1 Oil R Gas Cons. Commismo\; d\ ~"H'~ l{a al 01. '" j~~~ Anchora~e 715 L. Street, Anchorage, Alaska 99501 Voice: (907) 258-3446 Fax: (907) 258-5557 SENT BY: 12-19- 1 15:29 :# 2/10 ) ) duane vaagen From: Ed Jones Uejones@aurorapower.com] Sent: Wednesday, December 19, 2001 1 :02 PM To: duane vasgen Cc: Andy Clifford Subject: Re: NCU #5 Duane, Here is some info to respond to Steve Davies: 1) The well was worked over (cleaned out, reperforated, and gravel packed) in December 2000, and was 81 after pumping about 1100 bbllnto the well during the workover. The well was tested in Febraury 2001, during which time it flowed back about 220 bbl of water (see Monthly Production Report for Feb" a copy is being faxed). The well was then flowed some in September to condition it for start up of production (the comnpressor and production facility-unloading water)-it prodcued 406 bbl in Sept. (see Production Report for Sept.). The well actually went on line (first sales) on October 2001and produced 1427 bbl of water in that month. . 2) The water sampled were caught on October 18, 2001, after about 1402 bbl of water had been produced since the workover, exceeding the estimated load by a safe margin (i.e., our estimate may have been off 20-50 bbl, but no more)-a daily production report for October is attached with a cummulative water production shown each day. 3) I am also faxinQ you copies of water caught during the test (load water being recovered), which show much higherTDS (37,800 mgll [ppm) on the first day of the test and 31.400 mgll on the second). The samples from October 18th show 10,500 mgfl, 4) Regarding the water contact Issue, 1 don't think that we have enough information to address that well. We do see supposed water contacts in some of the 5 producing sands on the original logs of the No. 3, b~~t not knowing from which zone the water is being produced or how much gas has been produced from each ZQne, it is difficult to predict where the water contacts now are. We could estimate where they were originally-I believe that Andy has done some work on that. and I will get with him when he returns on Friday to take a look at that. Let me know if you need additional Information. Thanks, Ed J. -< ~ *- (]';I C\ LD ,.... ,.... I (]';I ,.... I "I ,.... -- .. f>- CO ¡.... - Z [¡J (/) > .. D ro r 0 I I ( -- IV " .- 0 , ~ ! .. 0 -J "'D ::: ... ; . I : 406 ~9156 -u Q) (£j ro .,.. e-___. ... n~... STÄTE OF A-Ì..ÁSKA ALASKA. Oil A1tD G.\s CONSERVA.TJOH COMMISSfOt{ MONTH LV PROD fJC110 N REPORT 20 4N:. &.231 { . -. --- ~~~Q.C '^~-~ u,ø - -Jilà~ ........r ¡"l , .... Dll"'þtl'rrf RItti ..s Poal .... ~,.. aI "a jb. :'IMi 1..-at. '1 !!.ÃA~ ~.;-c.-Aàti ~'-I' i..Þr5r.~~ ~ ' ~ -Õa1&.8,J~..œ " .,- - - ..........~ NO. 1 ~ ~ c~ ¡ POOl IÎM ~ IIØÐ fSIG If i.. OK.. ~ 1G.. _")45' 't..'Gi*t f2'~UIl - 11 __ ': 1C..GItS 4, ~ ¡ 5~ CODE ( ! OJIM ~ '; t:8ILa .-u! (1ICFt - eaJ 1881)' ~ . 1 .? .-- ~ ì1 -.- , i ~ 12· ~ w¡Â . ~ 2éó-'! ~o- :-.: 34 ~ 163 ' 0 ~406 ~ 91W- . . . ~ '(1~ f"r_ ' j : gcave1 r*1t) ~ ; ~ · '1_ ~or i' 'to"l of 73~,25 àoU'S oh:r " péciod af IJ þ~. .. ......,.... ::: < , .. f ;- ! ~ , ~ ; I. ~ ! ~ ~ - 2 ,f ~ I , < i < .; - -- )-,- J ... o ..¡II --"7_ 10/17/01 . .'-. 'c:.. _ _ _. _ JØnIIL --.... --Ir_ (.I> (t; .-t (¡) '< » ( ..,J .-.. (¡.) IV -..¡ -J w ". '" SHerYl.: ,., DI.-·t·,..~2 , ~ fNSTR'J~~'CINS ON ReVE.RSE ~fQr: FOIm ')()..1OS Rev 12·1·85 ~ CO f- Z ù.J {/} 15. ~::CM¡V~;~~ð;my._.~g. rl"\ Vjçe.Pre$Ìèem 11/16101 . _\ ,e -- .- . u .-.. .-- _.. .- -. -.. _ _ ___ _ __ _ . ._ _ ___ _ _ _. Oale . _ . _ _ _ TOTAL CD 0> ...... "'U Q) (D (\) 111,457 1427 o ~ , ú) -. ID --J ':::!. ú.) ~ -....I ) ~ 0 C') .. 1.O ~ ,. { 0 ~ t1> ~ -. 0 I CP .- ~ fO- rD I ; C'J '- 0 ~ .-- - +:-- . . 0 (p ""D 3:: /.-ï.o..; . . _ Octohe[" 2001 MOflttt anó Yea! ot Produc~jon TOTAL MONTHLY POODlICTIOtl U. OIL i' U WATER ' ,,,. GAS 4BBtJ ¡ fBBtl CMCF) o 1427 111,457 - -- NICOlai Cn=ck-tJDdefmcd Poo] - -"'\l _ 1_.. . ....", #. Field ...nd Pool 816- [)Þo'1S 17. ûAS--On.. T S. TUBING', _ _ .. DAILY AVG. PROO. ¡:. IN : RATiO PStG g. OIL -,1C. WATER· I~. GAS ~ ~ OPER : <BeW ; {seW , (MCFt 1· 31! NA 35Q -:~ - ' 46 3595 S60SOO 3gf <: ~ u 2 ; Am-on Gas. LtC l' ~4"~-" -- i Name or OÞer~u{)r - , ,. WELL - 2 APt NUMBER NO. 50- 283-20003 3 .t. F: E.LD .,5. t POOL CODE :Þ STATE OF ALASKA ALASKA OlL AND GAS CONSERVATION COMMISSION MONTHLY PRODUCTION REPORT 20 AAC 25.23C *- CD '< , ~ C/; cr, ::s ..-t =: SENT BY: 'Sent By: Aj 12-19- 1; 15:30; ) 7139771347; Dec-19-01 '. 4:07PM; ) ',,-,,' "--./ SUPPLEMENTAL REPORT -roRM 10421 FACILITY REPORT 0' PRODUCED GAS DISPOSITION AURORA GAS,ILC\ Opeøtor NICOLAt CRBBK UNIT NO, 3 SEPTEMBER 200 1 The Fonn 10-422~ Facility Report of Produced Gas Disposition. for the montb of Se~ 2001 indica1eS that a volume of au was vented during tímes exceeding an hour, The reason for this wDtiaø is to: 1) condition the w.e11 før start up of production. and 2) start-up. test, and lkijust the prodUQÛOn equipment, whicb incJudes: productjon unit. ¡lyoo) (mo) debyclnttØrþ compressor, ønd facility electrioity øeneratDr. The Mil required. cxmditiooing due to the introduçtÎon of 1100 (+1.) barre1s ofKCI water d\1l'mg the cleønout and \Wrko~ in ~ 2000. Some of this fluid was recovered when 1M well was flow 1eSIed in Pebrwuytñ2oo1, but 1\1~ of itrcmained 1n the weJJ and reeervoir. Tbis ftuid wu beÎDI ~ at. Júabet tate tbø the "ip rate oftbe pro4uction equiPßlll'l11t so it was vontod into a test tank to n:covcr the3c fluids. This venting COOk pbwe for a totaJ 0(73.25 houß over a period of daY1~ including 12 days between SepCen1b« 1 ~tb IUJd 3QIh, The volume of.. was not meaauRd dmina this time but is estimated to awrap about 125 mct1bour (3000 mofpd)-this I1d8 is &ub$taøtiated by die rate of initial øa1es metered in euJy October, During this SqJtember &im. period, 406 blttell of load water was recom-ed ('.5 bpi¡ or an estimated 44 bmels per miUion çubjc feet). Notifiœtion of Aurora'8 pJans to 'Vent the wen was given to the AOGCC via emlÙl and phone coovenatioas tiom loffOsbomo of Fairweather B &. P Services. engineering consultants to Aurora Gas. to TOlD Maundèr oftbe Commission on September 14tti. Although the pedod 0( days ext\mded beyond that origiÐal pbmned, the ac.Lua1 titne of venting the well (boun) and total volume expected to be vented did not exceed tile pllJJS conveyed in the DOtiration. (Tbewell was vuaœd for another S hours in early ~, mOltly for periods of Ie. 'Ihøt I hour, in tho s.-t·up process). The woll was put on stream with first sales on October 3m. 2001. ; # .f) / HI page 5;9 .,J 11"\ I c:. u r 1"\ LI'\~ l\ A ALASKA OiL AND GAS CONSERVATION COMMfSSION MONTHLY PRODUCTION REPORT 2() AAC 25.230 Aurora Gas., LLC Name of Opetator ,. WeLL 2. A.PI flJUlU8EA 3. ~! 4. FIELD 5. NO 50- 1:{ &. POOL d ; CODE 3 283..20003 2 2 S 6OS()o ., ';::Jißq ,s ".., a c '-eel 10 !he oes1 ot my ".o-..,edg. -p~/' ~- 7i(~e . - arfr. lO·"C~ Re" ¡2·1·9: Nicolai Creek Field Undefined Pool Field and Pool g 6. DAyS 7 GAS· OIL 8. TUBING ~ IN RATro. PSJG ' 'i OPER ..~ NJA ~ 256 J - - ----. -.. ..... -.. -- . _ Dale _ 4.l~Ü/O J ._ iNSTRUCT;"C'N$ ON qPiERSE. SIDE TOTAL DAILY A),IG.. PROD. 9 01 L 10. WATER 11. GAS ta5W (BBl) (MCF) o 73 1382 ..''10__. _ 15. 12. .oIL f88U o () en ro :::::I if) rt t'T1 OJ 2 ""< . -i .. i I;tj Fcbrval)' lOOt >- -< , ., J Month and Year Of Produc. Îon TOTAL MONTHlY PROOUGTIO!II 'CJ. WAtER t4. GAS (BBll (MCF) 220 414!) (load from Glavel Pack) ( - ..... ~ I ..... <D I "'-.J ..... ú) (!) --J ~ ..... ... 01 C6) .. .þ.. ~ -..¡ ..... 220 4146 SO!)I':"!11 In DI,..O'I':2.õt: / \ a (!) () I ..... CD ~ ~ '+:- .. o ...,¡ \j == -u !» (,Q (t) fù .. '* (: = SENT BY: Sent By: A; 12-19- 1: 15:32 ) 71 39771 347; Dec-19-01 ,4:08PM; , ;# 7/10 Page 7/9 ~..- ' ,. . I .. \,1. .- ~ h ¿: ''L . 3330 INOUST"I~l AVE.NUe 6"'" SILVERAQ() WAy; UNIT N ÞOVCH 340M3 FAIRBANKS. AlASKA 9iJ701 ANCHORAGE, AlASKA ~gS1B f'RU[)HOE BAY, ALASKA 911734 NORTHERN TESTING LABORATORIES, INC. ~90?) 1I!5.ß..3))6· FAX 4~·~125 (907134910¢O. FAX ~9· 1016 (I~O?) m!9·Z14t'. ' FAX 63O¡-~14.U Auror~ Gas, LLC 5718 Westheimer, Ste. 1850 HQuston, TX 17057 AttI1: Bd ]onc¥ Client ID: No. ~ Client Project #: St)uree: Nicolai Cwek. #3 Workover NTL 1.Ib##: A 17113 7 Samp1c Matr~: Liquid Co.ou11entll¡ I . ¡ Motbod PIU3Meter lJnit$ Result ...._, '...--....., SM 2540 C Total Dis$o1ved S.olids mgIL 37800 (.~d.--i~~. ..:*r..h. U Reported By: WeI1dy M. Ml~chell Anchcnae CbcmisU'y $up~visor ....-....""1.............. ··,·:·.~:'..~I; ',' ~'....~..;.....:,;,~..~_. Report Da.te; 3113/01 Dote Arrived: 31lJOl Sàmple DlI\te: 2124/01 Sample Time; 19:00 Collected By: FA ,J()nes ... Legend ... M RL - MIOtJmd R.~11: "~,,t1 MCI. '" MAx. COfl""TmUlt1.t ~.r:, a "" ~ll'¡ 'M(,Ir\1I;K1 91nn.k E "" Estlnwd V9.111'" M M.IItn.'Ko Inw~ Ii = Above Mcr . D ~ "l.06t To Dilurion M1tL ..,.""'.'---.,-. DBt~ ' Date Prepan-A Ana)Y.?tHJ 20.0 3/ SIO , ..'.......;~..'~...._..~.--.- .......:.~... SENT BY: ·Sent By: Aj ) 12-19- 1; 15:32; 7139771347 j Dee -19-("\1 ) 4: 09PM; ;# 8/10 rage 8/9 ~..._II'J\.."~;,.,""t'I,,· ....'''.....-. ~..,." i~ ¡. :' ....... _ _I;. ,J NORTHERN TESTING LABORATORIES, INC. 3330 INDV$íRIAL AVENUE !)71J' ~ VERADO WAY; UNIT N "OUCH 340Clo43 FAI~8ANKS, ALASKA a~m;n A~CHORAGE, AlASKA 991na PRUDHOE BAY, At.ASKA 99734 (gO"1f 456-3 t ¡ (J · fAX 41$6-3123> (907> -349.1090' fA)( 349·t016 (9C7) 66~-:1Ub· fAX 6r;S'lH!I Aurora O~ I~LC '718 Westbeimer1 St~. u~o Houston, TIC 77057 Attn~ Ed Jones Client W: No. 5 CUeAt Projoct II: Souxce: Nicolai Creek #3 Work-over NTL L~þN: A 171139 Samplê'Matrix; tfquid ComJUeDts; Report Date: 3/13/01 Døte An'ivcd: ~/l/O. Sl1DP1c Date: 2/25/01 Sample Time~ 18:00 ColleGted By: Ed]cme¡¡; .. Legend *'II MR.!. .. Method R~port f.<:vl-'! MCL a: Ma:t. Cont.amiMnt Level B '" 1"rcsmt IT1 MetlJOO :ERlank R ... B!tin]ll,v,ffi V"U~ M II: ~htri)( lr.ltt'feNnœ H '" Above MCL D w f..»$t To PRutlm'l' r'" Date TJat40 jM~~d, Paramotl:1 Uni&s R.~su It MPJ.. Pr~par~ An81)"l,~d ,.~-_.. 8M 2540 C Total Disso]ved Solid! m¡lL 31400 20,0 J/'j/O 1 '(-" ~-;~~ Reponed By: Wondy M. Mitchel] Ancborage Chetñistry Supervisor ..~_._--_._, . SENT BY: Sent By.: A; DetaIled Allalydeal Repott WOIkunkr (,100): ......... ~ a.t""'" N......r Report Secdo.: CInIt....... oN_ MMrix: " . :..·.:n,· UJI ~ NoIDba: ,... DMo: ~~ro: Pnp Mdbod 10: Pftp BùoIIi~; ~"t~ ....... ~ )·.n.. l\.: ,,__~ ... ~ If' _-",.,,~, -\..... LIb~~ ttr.:9 Dde~ ~ Mt;6dd Rk "'" ~ w; 1'np ....'N~ .... BfIIb: -- .....m.Md.... .tI( . ,,,._ PapS of9 12-19- 1: 15:33 7139771 347; ) - ........ -- ,.... 3.,11'" I:JM .\till IIfIL ..rL -'-' .. ..1..._&... ..-Lht.\Þ'I' ." .x..... ..... Dac-19-01 4:09PMj ) ; # ~)/ 1 0 pagE! gig A:øaly1jQa AJMta Sov1beIs't u,·,~~:~L·· ,. ' Daœ: . . '. ...... ." '" m', 'I: "..,.. Date: "'~l~ ..1. PUe NIII1* Dilvtti)R ,~~ AIIII1ytt ~; œL. .. 2$.00(1 ',100 ~t,œo 12.- sopoo ~ $O,O(IQ I),GOO .. ",... '" JO UOO64-01 A 14},1'131O 1 1"1.1.. ~~~..Dri4Id ..løGC - 160.1 .to I' 024f(U 0 ÂI.~ ga& tlr .. IlMI ..,. JOIlOO64 NiIoo&Il c..-. VmaN F-,",~". P ..... ClInt Sample Report ~òed~.r ~'..'\_'-- ~ ....."'.. - , ...L~,,":· . ~:.t tf '\ .J0110064..o1C lOOJI01 1fXU - Meœb by ICPfMS -lCPMS ~wd 2OO.8-D J011031oo1 AI h:åwd ÇAIIÞ 1... ?(J..% 7~N6.-S 744C).ð9.J 14MNJ.., .A.at1JtIs ~ ~"'''MtUI1: PIt: N,..,. Dø.ion PMmr: ~ 1nIJtMI: !Ilk .. 30 ',0 Þ'I. \:~ M....,a"~ ........ 10118101 4:4S;QOPM ~ il!' . ".' ...,.)"..."I!!;,!~"![",~).:tlln 111'10' IC}:I':~PM R.... J() 11 0';11 00 tce 100 SA .1\tIU,I¡ 3 ,., ~ "".' JI-;;·'''._'''~I.,_.~,..""...,~,".,''''''ltl'llll''':'. "'" . IM5An 2:02.:00PM SCALE cr Ikœ.,~ .2 . ..~~..I: .',,~. .,.,~. \,:. "~.~" SENT BY: Bent !:JV: A' 'lit ,', I~ , 277UtlG ) 12-19- 1; 15:33; 11 ~~ / (1 ;j4 I j uec - 1 ~ - U 1 ..... q:Uft....M; :#10/10 96/l3J2e81 12:46 ~ FQJER ) r>age ;j PAæ 01 ALASKA OIL AND GAS CONSERVATION COMMISSION SUPPLeMENT TO FACILITY RePORT OP PRODUCED GAS DISPOSITION Nicol" Creek. UJdt No.3 J'utllty, Oper.1ed by Auror. Gas, LLC Nicolai Creek. field, February 2001 Tho volumfJ of gas vented indicated in item 4. on tb.~ àtttched Fonn 10..42:2,4146 MCF t was vontcd tò the a\moøphcro 4\lri.n¡ the preparation for and tb.e conduçting of tho Multi- Point Gu Well Open Flow 1'cat oftbo reoonUy r~urbd No.3 well. The venting occurred between 1030 Ius on 2123/01 and 1020 bn QX12125fOl. Tb.o results of Ibis ten were reported on the POm'l. 1 ()..421 submitted on 4126/01. Tho rota! volumt Vè2ted waa eoli.t'utod. ftöØ) ro"dings of~ ori.f[oc motor on the test 4epa.rat.or at 1 S.fiO mmut,e intervalS, but aU volumes were not reëordcd 00. the moter cbart SigœlUrfl J &~~~ Title \TiC:! PtosWoqt Dato .O~LQ?/ºl '"V' ..........."