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205-012
• • MtCRt3FILMED 03/01 /2008 ~~~~. .-=r= DO NC.~T PLACE ANY NEW MATERIAL UNDER THIS PAGE F:1L.aserFiche\GvrPgs_InsertslMicrafilm Marker.cbc Pelicnn Hill Oil & Ens, 4141 B Street, Suite 205 Anchornge, AK 99503 907-277-1401, Telephone 907-277-1402, Fox ws--oiz -~'~~~v~r,~~,~~r March 8, 2005 Mr. John Norman Chairman Alaska Oil and Gas Conservation Commission 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 Re: Permit Closeout N. Pretty Creek Exploratory Wells Dear Mr. Norman: ;~ ~~~~ ~li~ ~C,as ~~,, ~!~~~~~ ~~1GNbr3i~3' Pelican Hill is ceasing operations in Alaska and will not be drilling any more wells. Therefore, it is requested that all permits connected with the proposed drilling of the N. Pretty Creek No. 1 and N. Pretty Creek No. 2 gas wells be closed out at this time. Both of these locations were staked and surveyed, but were never occupied by the drilling rig. We wish to thank you and your office for your assistance in the obtaining of permits for the proposed drilling activity, although drilling was not realized. Sincerely, Arlen Ehm Vice President/Alaska Cc: Al Gross, President Jim Rose, Operations Superintendent Pelicna Hill N. Pretty Creek 1, NAD 27 Subject: Pelicna Hill N. Pretty Creek 1, NAD 27 From: Jim Rose <jimrose@ak.net> Date: Mon, 14 Feb 2005 11:25:37 -0900 To: bob fleckenstein@admin.state.ak.us Bob I see that Arlen already sent you the cords in NAD 27. Here is the whole thing from Robert Bell. Jim Content-Type: application/msword Pretty Creek digits from FR Bell.doc Content-Encoding: base64 1 of 1 2/14/2005 11:53 AM • SURVEY DATA N. PRETTY CREEK WELLS N. Putty Gresk No 1: Coordinates: NAD 83 N 2,663,401.34 US FT E 1,486,042.92 US FT NAD 27 N 2,663,640.56 US FT E 346,014.46 US FT LEGAL 1634' FSL, 1677' FWL Sec. 22-T14N-R9W Elevation: NAVD 88 (GEIOD99) 81' GL N. Pretty Creek No 2: Coordinates: N D 83 N 2,666,609.53 US FT E 1,487,327.73 US FT A 27 N 2,666,848.73 US FT E 347,299.17 US FT lE A 50' FSL, 2327' FEL Sec. 15-T14N-R9W Elevation: NAVD 88 (GEIOD99) 88' GL • • ~ ~~~ ~~s ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~"I~ ~ ~ ~ ;~~ ~ ~~ FRANK H. MURKOWSKI, GOVERNOR ~~~~ ~~~~++ ~ta~ ~~~~+ a~ilo-7~ OII/ ~D ~ ,'~y 333 W. 7"' AVENUE, SUITE 100 COI~TSFiRQA'1'IO1K COM1~iISSI011T h ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 " FAX (907) 276-7542 Mr. Jim Rose Pelican Hill Oil and Gas Inc. 4141 B Street, Suite 205 Anchorage, AK 99503 Re: N. Pretty Creek No. 1 Pelican Hill Oil and Gas Inc. Permit No: 205-012 Surface Location: 1677' FWL, 1634' FSL, Sec. 22, T14N, R9W, SM Bottomhole Location: Same Dear Mr. Rose: Enclosed is the approved application for permit to drill the above referenced exploration well. This 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. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. In your application, Pelican Hill requests waivers to five Commission requirements. Attached please find a tabular listing of the requested waivers, a citation for the relevant regulation, and an analysis of each request. Based on the information provided, the Commission approves these waivers. Please note these waiver approvals are specific to N. Pretty Creek No. 1. If other wells are planned following the completion of the operations permitted here, waiver requests for those wells will be evaluated on a case- by-case basis. 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. Please provide at least twenty-four (24 hours notice for a representative of the Commission to witness any required test. Contact the C m'ssion's petroleum field inspector at (907) 659-2714 or 659-3607 (pager). ~"~ ~ Commissioner DATED this ~ day of February, 2005 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section Jr. Pelican Hill Oil and Gas Regulatory Waiver Analysis N. Pretty Creek No. 1 Beluga Area, Cook Inlet Alaska Waiver Requested Regulation Recommendation and Discussion 1--Diverter Line Size 20.035(c)(1)(B) Approval of this waiver is recommended. Requirement is that line size must be equal to or larger than hole size being drilled. Planned hole size is 12-1/4" and diverter line is 10". Waivers have been given fora 12" line size with this hole size. Well records and mud logs have been examined for six offset wells. Based on this information, it is unlikely that the proposed N. Pretty Creek 1 well will encounter gas in significant quantities from the surface to 1,500' MD / TVD, the proposed surface casing setting depth for the well. Mud weight used to drill the surface hole will be higher than normal as mitigation for using 10" diverter line with 12-1/4" hole. 2--Use of X-overs on the 20.035(e)(4)(9)(B) Approval of this waiver is recommended, according to the discretion "drill pipe" safety valve and allowed at 20.035(h)(2). The requirement is for an inside BOP and full- IBOP opening drilling assembly safety valve. The ultimate "drill string" being used by Pelican Hill is casing. This technique has not been previously used in Alaska, although it has been employed at several locations outside. The purpose of the IBOP is to be able to stab a "check valve" like tool that can be run into the well and then pumped through. The full opening valve is specified so such that the valve would not present a size restriction simply by being installed on the "pipe". When "normal" casing is run, it is common practice to obtain a X-over to allow the existing rig safety valve to be employed while running the casing. In this case, casing is being run all the time and unless a trip is done, pipe should be on bottom at all times. 3-Not to employ a manned 25.071(b)(1) and Approval of this waiver is recommended. Two issues were mud logging unit ; waiver of (2) considered: safety (crew and environment) and significant contribution to mud log and sample geologic knowledge. collection requirements. SAFETY -Pelican Hill will be using gas detectors on the rig with audible and visible alarms. They will also have a geologist onsite during all drillin operations within potential as-bearing zones. Pelican Hill will • Page 1 of 3 Pelican Hill Oil and Gas Regulatory Waiver Analysis N. Pretty Creek No. 1 Beluga Area, Cook Inlet Alaska have afull-time technician at the well site to install, monitor and maintain the automated mud analysis equipment. This weN will be located between three existing exploratory wells, and all of them drilled through the same geologic section. No over pressured zones or H2S were encountered. Pelican Hill's mud system design engineer is aware of the offset well and its records. Pelican Hill will also have sufficient weighting material available to control any elevated pressures. As a last resort, Pelican Hill will be drilling with casing, so they can always cement it in place. to control any severe problem. GEOLOGIC KNOWLEDGE - An electronic well information system will be used during drilling that will provide much of the information normally provided by a mud logging unit with crew: depth, ROP, hookload, weight on bit, RPM, torque, stroke counters, pump pressure, mud volume, pit gain /loss, flow, trip tank data, total gas, and H2S. This information will be recorded from surface to TD, and will be provided to the Commission. Regulation 20 AAC 25.071(c) allows the Commission to waive collection of geologic data (samples) if they will not significantly add to the geologic knowledge of the area. Arguably, collection of samples will not add much to existing knowledge as the surrounding exploratory wells have mud logs and samples across the same geologic section. Requiring a mud log or cuttings samples from N. Pretty Creek No. 1 will not substantially increase geologic knowledge of the area 4-Eliminate open hole logs 25.071(a) Approval of this waiver is recommended because there is no practical alternative. Drilling with casing does not permit tripping of pipe; so open hole logging is not possible. As the well is drilled, Pelican Hill will obtain cased hole gamma-ray and resistivity logs through a slotted liner attached to the casing near the bit. Following drilling, pulsed neutron log, gamma-ray and CCL logs will be recorded from TD to surface. Regulation 20 AAC 25.071 (c) allows the Commission to waive collection of geologic data and logs if they will not significantly add to the geologic knowledge of the area. . • Page 2 of 3 Pelican Hill Oil and Gas Regulatory Waiver Analysis N. Pretty Creek No. 1 Beluga Area, Cook Inlet Alaska 5--Waive wellbore survey 20.050(a)(2) Approval of this waiver is recommended, according to the discretion requirements allowed at 20.050(h). For a well not intentionally deviated, surveys must start at 500' and be performed at a maximum of 500' intervals thereafter. Pelican Hill proposes to conduct a wellbore survey after the drilling operation is completed. Given that the well is relatively shallow and there are no spacing issues, their proposal is reasonable. • Page 3 of 3 Re: N. Pretty Creek #1 • Subject: Re: N. Pretty Creek #1 From: Thomas Maunder <tom maunder@admin.state.ak.us> Date: Wed, 02 Feb 2005 15:08:50 -0900 To: Jim Rose <jimrose@ak.net> • Thanks Jim. Don't want to create work, but having a clean copy would probably be best. I know how cut and paste can go. I also agree that 3000 psi is suitable. Tom Jim Rose wrote: Tom In regards to the mud density question, the intent is to drill with 9.5+ mud on surface....same program as NB1. I apologize for the mistakes on the mud program. I see that there are some "cut and paste" mistakes from somewhere in there. I will get that fixed asap. In regards to your question No. 3, there are 5 wells that were reviewed for indications of higher than normal "Cook Inlet" pressures. The list of those wells appears in the waiver request. There isnt any indication that gradients are abnormal for this area. In fact, our results of the testing on the NB1 well indicated a freshwater or lower gradient....which was a _ little suprising. None the less, from a well control point of view, there - isnt any reason a 3000 psi stack isnt sufficient. Of course the surface casing shoe is the weakest point. Number 4: Envirotech is under contract to treat and dispose of all the cuttings as in NB1. This is true of all the wells we will drill in the area. My appologies on the sloppy mud program. I didn't personally review it for_ consistency with the rest of the permit. I will tune it up and bring you a new copy or email it....your call. Jim -----Original Message----- From: Thomas Maunder [ma i..to:to~~i maunder~~a.dmin.state.ak.u.s Sent: Wednesday, February 02, 2005 2:15 PM To: Jim Rose Subject: Re: N. Pretty Creek #1 Thanks Jim. Further ?? 1. In the mud program there appears to be a couple of conflicts. On page 3 in the surface hole section it is stated to "maintain the 8.7 - 9.0 ppg density as required", but on page 4 of the drilling program the density range is given as 9.5 - 10.0. What is/are the planned mud weights in the surface hole. 2. In the table in the middle of page 4 of the mud program the production hole TD is indicated to be 6700'. Is this an artifact from N. Beluga?? Also,. the mud weights in the table do not agree with the weight ranges on page 4 of the drilling program. Again, what are the proper mud weights?? 3. On page 3 of the drilling program, the Berglin X33-12 is cited for reference. Do the other wells in the area also conform to your statement?? 4. What arrangements have you made for handling/disposing of your muds and cuttings?? Thanks in advance. Tom Maunder 1 of 2 2/4/2005 1:14 PM Re: N. Pretty Creek # 1 Jim Rose wrote: • • Surface casing: 14.0 ppg, 1.60 cf/sk Production Lead: 13.5 ppg, 1.83 cf/sk Production Tail: 15.8 ppg, 1.17 cf/sk -----Original Message----- From: Thomas Maunder [mai=to:totn maunder<;zadmin.state.ak.lis] Sent: Wednesday, February 02, 2005 1:55 PM To: Jim Rose2; Arlen Ehm Subject: N. Pretty Creek ##1 Jim I am starting to look at your application. What are the yields of the cement slurries you are planning to use?? Tom 2 of 2 2/4/2005 1:14 PM a ~Pelicun Hill Oil and bus, Inc 4141 B. Street, Suite 205 Anchorage, AK 99503 907-277-1401, Telephone 907-277-1402, Fax January 25, 2005 '1'~Y~nNY~,irk,~~u Mr. John Norman, Chairman Alaska Oil & Gas Conservatpn Commission 333 West 7th Ave., Suite 10Q' Anchorage, AK. 99501 j RE: Application for Permit tb Drill: N. Pretty Creek No. 1 Dear Mr. Norman, Pelican Hill Oil & Gas, Inc. hereby applies for a Permit to Drill a development well near the Pretty Creek Gas Field of the Cook Inlet Basin. The anticipated spud date for the N. Pretty Creek No.1 is February 26, 2005. ' This well will be drilled as a straight hole using casing drilling techniques. The conductor casing will be driven to 120', then a 12%" hole will be rotary drilled to ±1,500' where 9-5/8" casing will be set and cemented to surface. A 7-7/8 hole will then be casing-drilled with 5-1/2" casing to +4,500' and the casing cemented from TD to surface. The well will be completed with 2-7/8" tubing Please find the attached information as required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill as per 20 AAC 25.005 (a). 2) Fee of $100.00 payable to the State of Alaska per 20 AAC 25.005 (c) (1). 3) A Location plat showing the well's proposed surface and bottomhole location as per 20 AAC 25.050 (c) (2). 4) Diagram and description of the BOP equipment (diverter, BOP and choke manifold) to be used are submitted as required by 20 AAC 25.035 (a) (1) and (b). 5) A complete proposed Casing Program is attached as per 20 ACC 25.030. 6) The Drilling Fluid Program as per 20 AAC 25.033. 7) Waiver requests are attached. 8) A Summary of Drilling Hazards is attached. 9) Diagram of the pad layout is attached. 10) Proposed weilbore sketch is attached. 11) Wellhead schematic is attached. ,~ • • If you have any questions or require additional information, please contact me at 277-1408. Sincerely, PELICAN HILL OIL & GAS, INC. James Rose enclosures STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 2n aac: ~~ nn~ 1a. Type of Work: Drill ~ Redrill 1b. Current Well Class: Exploratory ~ Development Oil Multiple Zane Re-entry ~ Stratigraphic Test [] Service ~ Development Gas ~ Single Zone 2. Operator Name: 5. Bond: Blanket ~ Single Well 11. Well Name and Number: Pelican Hill Oil 8~ Gas, Inc Bond No: Ltr of Credit #BOK035DPo1265 N. Pretty Creek No. 1 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 4141 B Street, Suite 205, Anchorage, AK. 99503 MD: 4500' ~ TVD: 4500' N/A -Exploratory 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 1677 FWL and 1634' FSL, $22 - T14N - R9W - SM ADL 390103 ~ Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: Same ADFBG Special Area Permit Feb. 26, 2005 Total Depth: 9. Acres in Property: 14. Distance to Nearest Same 1280 Property: 1634' 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Well Surface:x- 1486985 y- 2663096 Zone- AK-4 (Height above GL): 13 feet Within Pool: N/A 16. Deviated wells: Kickoff depth: feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: degrees Downhole: 2,295 Surface: 686 18. Casing Program: Setting Depth Quantity of Cement Size Spec cations Top Bottom c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD ND (including stage data) 13 3/8 54.4 R-3 Weld 120' surface surface 120' 120' Driven 12 1/4 9 5/8 40 L-80 BTC 1500' surface surface 1500' 1500' 516 sx Type 1 ~ 14.0 ppg 7 7/8 51/2 15.5 K-55 BTC 4500' surface surface 4500' 4500' 420 sx G Lead ~ 73.5 ppg + 302 sx G Tail @ 15.8 ppg 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (tt): Total Depth TVD (tt): Plugs (measured): Effect. Depth MD (ft): Effect. Depth ND (tt): Junk (measured): Casing Length Size Cement Volume MD ND Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ff): 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Time v. Depth Plot Shallow Hazard Analysis ~ Property Plat Q Diverter Sketch Q Seabed Report ~ Drilling Fluid Program Q 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Jim Rose Title ~ £.('~i'7 (at~~ SJF' ~ Signature Phone 277-1408 Date ~ ~ I ~ ©~; Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other ~Gr,j ' (~ ! ~.. Number: 50- Z~ ~ I L~ '" C~~ ~,~ " Date: requirements. Conditions of approval N Y o es ~ S pl s required Yes ~ No ~ Mud log required ydro en sulfide measure Yes ~ No ~ Directional survey required Yes ~ No ~,~ Other. O P " a~ ~9 Q~a~~~~ ~~p'~E-`~~t~~CcVO\ L ~~~5 . -~ r3#fErr.~rf/f~.~~ -'T.~~11:~=r~z~;.,.~~~;~ BY ORDE OF ~ ~ °' Z Approve THE COMMISSION Date: v~~yiv--'~ i~c~~ac~ 1 .,~ ~ A • ~ ~ j a ~/ i . ~? _.. a .. ~ ~ .~ '~ f ~ • AOGCC Waivers Requested in the N. Pretty Creek No. l Permit to Drill Approval is requested to use a diverter with a 10" outlet and diverter line for drilling the 12-1/4" surface hole. Since the need to use the 10" diverter line will be present in all of Pelican Hill's planned wells in this area, we looked at all the offset wells in the area for any indications of conditions or gas that could give a reasonable indication of the need for a full 12" or 13" diverter line. The wells examined are: Alaska Energy Development BW X33-12 Chevron Pretty Creek 224-28 Union Pretty Creek #2 Cities Service E. Lewis River #1 Cities Service Lewis R. B-1 While the records in the shallow portions of some of these wells is sparse, nothing was found in any of them to indicate the presence of gas in significant quantities and none of the well operators had the need or opportunity to use their diverters. Pelican Hill is of the opinion that it will experience similar conditions. As a further precaution, since Pelican Hill has no economic interest in the contents of the formations above the planned surface casing setting depth of 1500', the Operator is willing to carry a significantly higher mud weight while drilling this interval than is strictly required for well control, thus giving an additional margin of safety. Pelican Hill recently drilled the N. Beluga No. 1 without indications of shallow ~ gas hazards or abnormal pressures. 2. The use of crossovers on the TIW and IBOP in lieu of full opening valves is requested. The planned casing drilling operation is not conducive to utilizing a 5- 1/2" TIW or IBOP. Approval of the use of drill pipe size equipment is requested. 3. A waiver from manned mud logging and from sample catching is requested. Section 20AAC 25.071 (b)(2) of the regulations requires that a complete set of washed and dried, legibly identified samples of all drill cuttings. This requirement is designed to provide a library of cutting samples in all province areas where oil and gas drilling occurs. However, there are numerous wells that have been drilled near this particular well. From a geologic standpoint, there is no reason to believe that collecting another set of samples in this area will provide any new or different data to the already large sample collection for the area. Although a waiver of this section is being requested, a manned mud gas analysis system will be in place to analyze and log any gas that is encountered. • • Subsection 20 AAC 25.071 (b)(2) states, "The commission will, in its discretion, waive or modify the requirements of this section for a well if those requirements would not significantly add to the geologic knowledge of the area in light of the information that is available from other wells in the area". This well is located very close to previous wells where samples have already been collected. Therefore, a waiver of section 20 AAC 25.071 (b}(2) is hereby requested as allowed in subsection 20 AAC 25.071 (h). 4. A waiver from open-hole logging requirements is requested. The casing drilling techniques planned for use on this well do not normally provide for tripping the pipe during or after drilling which leaves no opportunity to run open-hole logs. In lieu of open-hole logs, Pelican proposes to run cased-hole logs with which to identify gas-bearing intervals. An exception from taking directional surveys during the normal course of drilling is requested. Section 20 AAA 25.050 (a)(2) of the regulations requires inclination surveys beginning at 500 feet and then every 500 feet thereafter until total depth has been reached. This survey is designed to detect and monitor deviation of the wellbore that occurs when a standard drilling assembly is used. This well will be drilled by the casing drilling method instead of the standard drilling assembly. Where this method has been in use in other areas, it has been evidenced that little deviation from the vertical occurs and that a much straighter hole is drilled. One bit will be used to drill from the surface casing shoe, set at an approximate depth of 1,500 feet, to total depth at approximately 4,500 feet. Since there are no trips for new bits planned, the normal practice of dropping a survey tool for retrieval when the drilling assembly is brought to the surface is precluded. Because of the large ID of the casing used in the casing drilling method, the wireline method of conducting this survey is also precluded. Casing drilling produced a very straight hole at Pelican Hill's, N. Beluga No. 1 well that was recently drilled to a depth of 5,122 feet with a deviation of only 2 '/2 degrees. A complete continuous directional survey will be run after total depth of the well has been reached. This will be filed with the final reports and logs for the well. Therefore, a waiver of section 20 AAC 25.050 (a)(2) is hereby requested conditional upon a complete continuous directional survey being run at the end of the well. • • N. PRETTY CREEK NO. 7 NARRATIVE AND CALCULATIONS N. Pretty Creek No. 1 Page 1 of 7 2/ 1 /2005 • General: The N. Pretty Creek No. 1 will be a grass-roots well drilled as a stepout to the north from the Pretty Creek Gas Field. The N. Pretty Creek No.1 will be drilled using the Water Resources International, Rig #7 (WR-7) on a newly constructed drillsite between the Pretty Creek Gas Field to the south and the Lewis River Gas Field to the north, the ~ intent being to test the Beluga and Sterling Formations for gas production potential. Drilling Program: Prior to rig arrival, drive 13-3/8", 54.4 #Jft conductor to ~ 120 feet or refusal. 2. MIRU WRI Rig #7. Install 13-5/8", 5M x 13-3/8" Slip Lok head. N/U and test diverter. Test and calibrate all PVT and gas sensor equipment. 3. Prepare spud mud system, weight up to ~9.5 ppg. 6% KCI / PHPA. 4. Drill 12-1/4" hole to 1,500' using 3-1/2" drill pipe. 5. Rig up casing drilling tools to run 9-5I8" casing to TD. 6. Cement 9-5/8", 40 #/ft, L-80, BTC surface casing from 1,500' to surface. Cement will be a single stage 14.0 ppg gas-block type cement slurry. Cement volume will include 75% excess. 7. ND diverter and install 11", 3M x 9-5/8" SOW casing head. 8. NU 11", 3M BOP stack and 2", 3M choke manifold. Install 5-1/2" pipe rams. Test stack and surface equipment to 2,500 psi. Pressure test casing to 1500 psi. 9. PU 7-7/8" bit on 5-1/2° casing drilling tools. Drill out cement and 20' of new hole. Pull back into shoe and perform a formation integrity test to 11.5ppg EMW, recording test on chart recorder. 10. Casing-drill 7-7/8" hole to 4,500' TD. Run memory resistivity logging tools as needed while drilling Beluga sands. 11. Cement 5-1/2" casing from TD to surface using a13.5ppg lead slurry followed by a 15.8 ppg tail slurry. 12. Install 11", 3M X 7-1/16",3M tubing head, 7-1/16" X 11" DSA and mud cross and reinstall BOP stack. Install 2-7/8" rams and pressure test BOPE. RIH and clean out. Swap mud system over to clean, filtered KCI Brine. POH. 13. R/U slickline and run cased hole memory logs (pulsed neutron w/gamma ray). 14. M/U perforating guns on tubing. Note: Depending on rat hole and other considerations, the completion may be changed to a more conventional TCP operation where the perforating guns are run in, the packer is set and the tree is installed before firing the guns. N. Pretty Creek No. 1 Page 2 of 7 1 /31 /2005 15. TIH. 16. R/U slicktine unit and RIH with GR to verify perforating depth. Adjust as necessary and close pipe rams. 17. Drop bar to perforate well. 18. Monitor well for pressure. Open pipe rams and CBU. TOOH. 19. RIH with packer and tubing. 20. Space out, circulate in packer fluid, set packer and tree up. 21. Swab in well to tanks and clean up. 22. Suspend weN until spring by setting a plug in the profile nipple and installing a BPV in the tubing hanger. Pressure Considerations: The maximum mud weight used in the nearby Berglin X33- 12well was 10.4 ppg. This mud weight was sufficient to not only maintain well control, but it kept trip gas suppressed to the point where, in Pelican Hill's evaluation, the indicated actual pore pressures were probably in the 9.0 - 9.8ppg EMW range. Pelican Hill is taking a conservative approach with the assumption that the maximum pore pressure to be encountered will be 9.8ppg EMW at 6,700' TD which equates to a pressure gradient of 0.510 psi/ft. Maximum Anticipated Surface Pressure: The maximum anticipated surface pressure (MASP) for the 7-7/8" hole section in this well will be the lesser of the formation pore pressure (less a full gas column to the surface) at the 5-1/2" casing point (TD) or the formation fracture pressure at the 9-5/8" surface casing shoe (less a full gas column to the surface). Based on offset well data, the highest formation pressure expected in this 7-7/8" hole section is 2,295 psi at the section TD of 4,500' TVD (or 0.510 psi/ft). Documented fracture gradient data for this area indicates that the fracture gradient at 1,500'TVD (the 9-5/8" surface casing shoe) is 0.567 psi/ft. Complete evacuation of the wellbore, except fora 0.11 psi/ft gas gradient, is assumed. 7-7/8" hole section MASP (pore pressure) _ (4,500 ft)(0.510 - 0.11) = 1,800 psi MASP (fm breakdown) _ (1,500 ft)(0.567 - 0.11) = 686 psi Therefore, MASP in the 7-7/8" hole section is 686 psi and the 3,000 psi ROPE system to be used will be adequate. Wellbore Surveys: The N. Pretty Creek No.1 well will be casing-drilled as a vertical well. Pelican Hill Oil & Gas requests that wellbore surveys obtained at 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2) be waived. For rationale see attachment, "AOGCC Waivers Requested in this Permit to Drill". N. Pretty Creek No. 1 Page 3 of 7 1 /31 /2005 • Mud Logging: Pelican Hill Oil & Gas requests that manned mud logging requirements laid out in 20 ACC 25.072 (c) be waived. For rationale see attachment, "AOGCC Waivers Requested in this Permit to Drill". Drilling Fluids: The drilling fluids are being furnished by Baroid Drilling Fluids. There will be a mud engineer on site at all times during drilling operations. Mud properties will be maintained as follow: Hole Section from 0' to 1,200': Stirling and Beluga Formations Base Fluid Density PV YP API Filtrate Total Solids Gel & Polyrr 6% KCL 9.5-9.7ppg 6-16 35 - 45 <g 15 - 25 % or less ier mud system Hole Section from 1,200' to 1,500': Beluga Formation Base Fluid Density PV YP API Filtrate Total Solids Polymer mud system 6% KCL 9.5-10.Oppg ~ 6-15 15-25 <g 15 - 25 °lo Hole Section from 1.500' to 4.500': Beluga and Tyonek Formations Base Fluid 6% KCL Density 9.5 - 10.5 ~ PV 6-15 YP 15 - 25 API Filtrate <8 Total Solids 15 - 25 Polymer mud system Drilling Fluid Handling System: Shale Shaker, De-sitter, Centrifuge, PVT monitors Casing /Cementing Program: All casing is new. Analysis (below) indicates the casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the driven 13-3/8" conductor will be cemented in place. 13-3/8" Conductor Analysis and Cementing Program N. Pretty Creek No. 1 Page 4 of 7 1 /31 /2005 • • The conductor for the North Beluga No.1 will be driven to ~ 120' or refusal. Joints will be welded and a drive shoe will be welded to the bottom joint. No cementing is required. 9-5/8" Surface Casing Analysis and Cementing Program The 9 5/8" surface casing will be cemented in fully from the proposed set depth of 1,500' to surface with a 14.0 ppg Gas-Block type cement system. Cement System Type Cement Weight (pgca) Volume CZ % Excess Primary Gas-Block enhanced 14.0 147 bbls @ 75% Where: 13-13/8" x 9-5/8" Capacity = .0646 bbl/lt 9-5/8'; 40# Csg x 12-1/4" OH capacity = .0558 bbl ! ft 9-5/8'; 40# Csg capacity = .0787 bblfft » 13-13/8" x 9-5/8"~ 88 ft x .0646 bbl / ft = 5.7 bbls OH x 9-518": 1, 412 ft x .0558 bbl / ft x 75 % excess = 137.9 bbls » Shoe Jt: 35ft x .0787 bbl/ft = 2.8 bb/s Total Volume Cmt (07 surface = 147 bbls Actual volumes to be re-calculated at time of running casing due to potential variation in actual depth from planned. The surface cement system will utilize alias-Block type additive to minimize potential for gas entrainment and or channeling. 5-112" Production Casing Analysis and Cementing Program The 5-1/2" production casing will be cemented in fully from proposed set depth of 4,500' to surface. A 13.5 ppg lead "G" cement followed with a 15.8 ppg "G" tail cement system will be used. This program is designed to ensure the intended perforating /production intervals are isolated with 15.8 ppg "G" cement. Cement System Type Cement Weight (ppC]) Volume (a?_ % Excess Lead "G" 13.5 137 bbls @ 35% OH Tail "G" 15.8 63 bbls @ 35% OH Where: 5-%'; 15.5# csg X 7-7/8" OH capacity = .0309 bbl%ft 5-%'; 15.5# csg X 9-5/8'; 40# annular capacity = .0493 bbl/ft Lead System: 5-%" X 9-5/8": 1, 500 ft x .0493 bbl / ft = 74.0 bbls OH x 5-%": 1,500ft x .0309 bbls/ft x 35% excess = 62.6 bbls Total Lead Cmt Volume = 137 bbls N. Pretty Creek No. 1 Page 5 of 7 1!3112005 • ~ Tail System: OHx5%"~ 7, 500ft x . 0309bb1/ft x 35 % excess = 62.6 bbls Total Tail Cmt Volume = 63 bbls Actual volumes to be re-calculated at time of running casing due to potential variation in actual depth from planned. N. Pretty Creek No. 1 Page 6 of 7 1 /31 /2005 • • N. Pretty Creek No. 1 Summary of Drilling Hazards THIS NOT{CE TO BE POSTED IN DOGHOUSE ~ There is potential for abnormally pressured gas deeper in the well. ~ ~ There is potential for stuck pipe in coals encountered while drilling from surFace to TD. Be extra vigilant, keep pipe moving and maintain mud properties as specified. ~l There is no H2S risk anticipated for this well. ~ Due to potential for an unexpected gas kick, PVT and gas ,~ detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE "N. Pretty Creek No.1" Drilling PROGRAM FOR ADDITIONAL INFORMATION. N. Pretty Creek No. 1 Page 7 of 7 1 /31 /2005 N. Pretty Creek #1 Casing Prouerties and Design Verification Casing Performance Properties Size Weight in. 1( b/ft) Grade Cnxn 9-5/8 40 L-80 BTC 5-1/2 15.5 K-55 BTC Internal Collapse Yield Resistance si si 5,750 3,090 4,810 4,040 Tensile Strength Joint Body 1 000 lbs 916 979 248 366 TVD MD ~~ ~~ 1,500 1,500 4,500 4,500 Design Safety Factor* T B C 18.09 8.38 5.15 4.17 7.01 2.24 * Tensile design factors are calculated using pipe weight less buoyancy. Burst design factors are calculated using MASP. Collapse design factors use formation pressure at the shoe on the outside and full evacuation (except for a gas gradient) inside. Casing Setting Denth Rationale 9-5/8" 1,500' MD, TVD Surface casing to provide an anchor for BOPE, sufficient formation strength at the shoe for containing deeper formation pressures and to cover shallow formations, allowing deeper drilling to the producing interval. 5-112" 4,500' MD, TVD Production casing to provide hole stability for production operations. FOUND ,' \ CLEARING LIMITS STAKED ;'~~; PAD LIMITS/ ;' 11677' FWL '~ ,' c ,' , j ~ ~ .' ~ ' ,' ~ ~' 21 / ~',; 250' 0 500 ' 22 ~' ~' GRAPHIC SCALE ~' 1 "= 500' . / ~' ~ . : ~ ~`ti/ / Sd O ~ i ~~ ~' i , P i' i OO '~ ~ O\'/ 7 ,\ i 7 i i ~ ~. P~ i' i ~~ O ~~ O i i i / i '~ i i ~ ~ ~ i i i ~ i i I ~ ~ i i 7 i / i i ,/ , 28 ,' ~ , HORIZONTAL AND VERTICAL COORDINATES WERE GENERATED FROM A POST PROCESSED STATIC GPS SURVEY THAT USED NGS CORS STATIONS (ZAN1, KEN1, POT3) TO GENERATE NAD83 COORDINATES. ADDITIONAL DATA WAS ALSO COLLECTED USfNG RTK GPS SURVEY PRACTICES. THE RTK DATA IS REFERENCED TO THE COORDINATES FROM STATIC SURVEY. UNITS: U.S. SURVEY FEET BEARINGS: GRID HORIZONTAL DATUM: NAD 83 COORDINATE SYSTEM: ALASKA STATE PLANE (ZONE 4) VERTICAL DATUM: NAVD88 (GEIOD99) SECTION L4NE5 ARE PROTRACTED. WELL NAME NORTHING FASTING ELEV N. PRETTY CREEK 1 2663096.20 1486485.45 80.83 F. Robert o ~~ ~ ~~~©~0 ENGINEERS AND LAND SURVEYORS 801 WEST FIREWEED LANE SUITE 201 ANCHORAGE, ALASKA 99503-1801 PHONE (907)-274-5257 PREPARED FOR: LEGEND © STAKED GAS WELL LOCATION FWL FROM WEST LINE FSL FROM SOUTH LINE STAKED GAS WELL AND PAD LOCATIONS NORTH PRETTY CREEK 1 & NORTH PRETTY CREEK 2 (WITHIN PROTRACTED SEC. 15 8c 22, T14N, R9W, S.M., AK) PELICAN HILL OIL AND GAS INC. FIELD BOOK: 2005-O1 1 DCHECKED BYCCBS JOB NUMBER:2004-607.01 DATE: 01 /24/2005 27 SCALE: 1" = 500' SHEET:2 OF 3 ~" N. Pretty Creek No. 1 ,rt~~u~~wL~~,~~` Well Planning Sketch Beluga River Area, Alaska Rig: Water Resurces No. 7 ELEV 81' AMSL Sec 22, SM Twp 14N Rng 9W Proposed Spud: Feb 26, 2004 RT 13.0' AGL 1877' FWL 1634' FSL 13 3l8, 54.4 ppf, R-3, ' ~~ ''' Conductor Casing Driven to 120' ;'' ~ . 12 1 /4" Hole Surface Casing 9-5/8", 40 ppf, L-80 BTC Casing @ 1500' Note: All referenced depths MD/TVD RT 9 5/8" casing cmtd to surtace 7 7/8" Hole Top of Tail Cement @ 3,000' 5 1 /2" 15.5 ppf, K-55 BTC Casing Cmtd to Surf ~'~ TD 4,500 TVD/MD ~. @ Bit Jlm Rose •" N. Pretty Creek No. 1 ~ ~'~'~ ~~~~~'"~' ~ Diverter Detail Beluga River Area, Alaska Rig: Water Resurces No. 7 ELEV 81' AMSL Sec 22, SM Twp 14N Rng 9W Proposed Spud: Feb 26, 2004 RT 13.0' AGL 1677' FWL 1634' FSL RT Bell Nipple I Flow Line ~~--- 13 5/8 5M Shaffer NL Annular BOP as° 10" Full-Opening Knife Valve 90' of 10" Dia Diverter Line 13 5/8 5M x 13 5/8 5M x 10" ANSI Series 150 Diverter Spool 13 5/8 5M x 13 3/8 Vetco VG LOC Casing Head Jlm Rose i N. Pretty Creek No. 1 ' Or, i ~~~~ n. (a~~r BOPE Detail `~ Beluga River Area, Alaska Rig: Water Resurces No. 7 ELEV 81' AMSL Sec 22, SM Twp 14N Rng 9W Proposed Spud: Feb 26, 2004 RT 13.0' AGL .1677' FWL 1634' FSL RT 11" 3M Shaffer Spherical BOP 11" 3M Shaffer LWS Double Gate BOP ~' 11" 3M x 11" 3M Spool 2 1/16" 3M Manually Operated Gate Valve Jlm Rose ~~" N. Pretty Creek No. 1 `"~'' ~~~ BOPE Detail Beluga River Area, Alaska Rig: Water Resurces No. 7 ELEV 81' AMSL Sec 22, SM Twp 14N Rng 9W Proposed Spud: Feb 26, 2004 RT 13.0' AGL 1677' FWL 1634' FSL RT 11" 3M Shaffer Spherical BOP 11" 3M Shaffer LWS Double Gate BOP ..,............., I y ~ 11"3Mx71116"3MDSA / 11"3Mx71/16"3MTbgHd~ 11" 3M x 9 5/8 SOW Braden Head ~ -- '~ 2 1/16" 3M Manually Operated Gate Valve Jlm Rose •"' N. Pretty Creek No. 'I `~~~~~~ Choke Manifold Detail Beluga River Area, Alaska Rig: Water Resurces No. 7 ELEV 81' AMSL Sec 22, SM Twp 14N Rng 9W Proposed Spud: Feb 26, 2004 RT 13.0' AGL 1677' FWL 1634' FSL 1 3 1/8" 3M Manually Adjustable Choke a - ~ a Inlet 1 3 1/8" 3M Manually Adjustable Choke Jlm Rose To Shaker Panic Line To Gas Buster N. Pretty Creek No. 1 Pad Layout Beluga River Area, Alaska Rig: Water Resurces No. 7 ELEV 81' AMSL Sec 22, SM Twp 14N Rng 9W Proposed Spud: Feb 26, 2005 RT 13.0' AGL 1677' FWL 1634' FSL W Jlm Rose '~ • • 70-i/2' 24,00' A6 17.00' P ALL DIMENSIONS ARE APPROX. J L! C. UL VJV 1 11 B12 „- 1! 1! SWE & FCE ENGINEERING ACAD +~~~~ ABB Veboo Qt~ry 9-5/8 X 5-1/2 X 2-718 ^D, SM MSP ASSY DRAMM BY: C. RICE DgTE; 05 SEP 2003 FIE REFERENCE: A309o13B~ PELICAN HILLS ALASKA PROJ. DRAWING N0. XIV-G SP-5265-1 cti-r_ e~cQ • naTF• SCALE: NA PROJECT NO.: _ __ _ _ _ Halliburtan BaROIo Pelican Hill Mud Program r; _`~-, ~ Ah..,~~ Pelican Hill Oil and Gas N. Pretty Creek #1 West Cook Inlet, Alaska Baroid Mud Program Ha~li~urtan Baroid Name (Printed) Signature Date Originator Dave Higbie Reviewed by Don Shaw Customer Approval Jim Rose Version No: Date: 1.0 February 3, 2005 N. Pretty Ceeek # 1 ~1 I.0 i 02/03/05 ~ Ha[liburton BAROID Pelican Hill _ Mud Program N. Pretty Creek #1 Introduction: The following mud program was prepared for a vertical well accessing the Beluga gas sands as part of an exploration program on the west side of Cook Inlet, Alaska. This well will be spudded with a 6-8% KCI drilling fluid and drilled vertically to the 1,500' MDlTVD range. It will be drilled with a 12 '/4" hole size, 9 5/8" casing run and cemented. The surface casing will be drilled out with the existing mud system. The 7 718" interval will then be drilled using 5 '/2" casing to TD at 4,500' MD and cemented at this depth. The well bore may be displaced and production tubing run depending on logging results. Spud the well with a 6-8% KCI, 9.5 ppg mud. The mud weight will then be held in the 9.5-10 ppg mud weight range to the surface hole TD unless hole conditions dictate otherwise. Our primary focus for surface hole drilling operations will be adequate mud weight for well control and sufficient mud viscosity for efficient hole cleaning. This same 6-8% KCI mud will be maintained through the production interval. This mud offers good LCM responses if losses are encountered. Special emphasis should be placed on maintaining low ECD's and surge/swab pressures to minimize the potential for lost circulation. Primary Drilling Objectives: • Zero fluid related HSE incidents • Achieve wellbore stability • Achieve good hole cleaning considering hole angle, geometry and anticipated ROP rates • Lost circulation mitigationlcontrol • Achieve good Zonal Isolation as per plan • Achieve minimal formation damage in Beluga sands • Minimize fluids related NPT • Minimize drilling wastes Critical Fluid Issues: • Eliminating/controlling losses. • Maintaining a low ECD in the production zone to reduce risk of lost returns. • Maintaining a stable wellbore through coal seams. • Reducing drilling wastes with the inhibited drilling fluid system. Well Specifics: Casing Program MD ND Footage 12 %" hole 9 5/8" casin 1500' 1500' 1500' 7 7/8" hole 5.5" casin 4500' 4500' 3000' Surface Hole Recommendations Mud Type: 6-8°I°KCI Properties: Densi Viscosi PV YP API FL ~H CI 0 -1200' 9.5-9.7 50 - 70 6 -16 17-25 <8 8.5-9.0 40K 1200-1500 9.5-10.0 50 - 70 6 -16 35-45 <8 8.5-9.0 40K-80K N. I'rett~% Creels ~r 1 v 1.0 ._~ 02/03105 ~ Halliburton BAROIO Pelican Hill Mud Program System Formulation: 8%KCI polymer Product Concentration Water 0.905 bbl KCI 30 ppb (40K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.0 -2 ppb (as required 17-25 YP) PAC L .5 ppb Dextrid 1-2 ppb Aldacide G 0.15 ppb Baracor 700 1 ppb Barascav D 0.5 pb (add as the welts uds Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimize fisheyes. Concerns and Continctencies Surface Interval - (0 -1,500' MD ) Mud Type: 6-8 %KCI 1. Mud weight: Maintain the 9.5-10.0 ppg density or as required. 2. Rheology: Maintain a YP between 17 - 25 above 1200' and 35-45 from 1200-1500' or as needed to achieve adequate hole cleaning. These ranges were adequate on N. Beluga #1 and reduced problems at the shaker. 3. Filtrate control: Maintain filtrate control in the <8 range with PAC/Dextrid. The Dextrid will also help coat cuttings and reduce the waste stream/dilution requirements. Additions of Drill-N-Slide may be required to control screen blinding/bit balling. Operations Summary: This section will drill a 12 '/4" hole. Build the 8% KCI fluid in the proper order of addition. This higher KCI concentration will reduce dilution requirements and offset not adding EZ Mud (problems at the shaker). Be prepared for sloughing gravels in the upper interval; increasing the system rheology with BARAZAN-D will assist in bringing this material out of the well, as will pumping dedicated high-viscosity or Barolift sweeps. It is recommended that the pump rate be increased to the maximum practical rate while the hole is unloading gravel. Sweep Formulation: 30 barrels mud, add ca. 1.0 ppb BARAZAN D to achieve a tau0 > 25 or .25 ppb of Barolift. When penetrating high-clay content sections additions of Drill-N-Slide ester are recommended to reduce the incidence of bit balling and shaker blinding. Use the centrifuge to maintain the 9.5 ppg mud weight. Maintain a minimum 17 YP at all times. Be prepared to increase the YP if hole cleaning becomes an issue. This YP is lower than normal but will help at the shakers. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based on current rheology, flow rates and cuttings size. Losses where noted on N Beluga #1 while drilling out of the conductor. Be prepared to add Micatex F or Wallnut F should this occur. These losses appeared to be seepage losses in a sand so these two products should seal this zone. At TD, a Wallnut "flag" (20 bbl pill with 15 ppb of WALLNUT FINE) should be pumped to gauge hole washout and to calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. ~. Pretty Creek t~l vl .Q _, 02i03/OS ~ Halliburton BAROIO Pelican Hill Mud Program Hazards 1 Concerns -Surface Interval: • Preventing lost circulation through ECD management. • Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. • Maintain YP between 17-45 to optimize hole cleaning and to control ECD. • Pump high vis/Barolift sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness. • Successfully cement casing. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM--~ 200 300 400 80r m 56 97 132 100r m 56 97 132 Baroid's recommended flowrate for this interval is 400 gpm to maximize hole cleaning at these penetration rates. RPM's make no difference in this vertical wellbore. Production Hole Recommendations Mud Type: 6-8%KCI Properties: Densi Viscosi Plastic Viscosity Yield Point API FL ~ CI 1,500 - 4500' 9.5-10.5 40-53 6 - 15 13 - 20 <7 8.5-9.5 40-100K System Formulation: 8%KCI Product Concentration Water 0.905 bbl KCI 30 ppb (40K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.25 ppb (as required 35 YP) Dextrid 1-2 ppb Aldacide G 0.1 ppb Baracor 700 1 ppb Barascav D 0.5 b maintain er dilution rate Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimize fisheyes. Concerns and Contingencies Mud TVpe: 6-8 %KCI 1. Mud weight: Maintain a 9.5-10.5 ppg density or as directed. 2. Rheology: Maintain a YP between 13-20 or as needed to achieve adequate hole cleaning. 3. Filtrate control: Filtrate control in the <7 range is required for this interval. Maintain additions of Dextrid and Pac L to reduce filtrate to this range. Additions of Drill-N-Slide will be required to control screen blinding/BHA balling. Losses in this interval can be controlled with additions of 1-2 ppb BAROFIBRE and 1-2 ppb of Wallnut F or by dedicated LCM pills; see appendix for LCM decision tree. Operations Summary: N. t'retty G~~elc #7 v1.0 ~i 02/Q3/OS HalliburkOn BaROI~ Pelican Hill Mud Program Drill out the cement/casing with the existing mud system. Bicarb or soda ash and citric acid should be used to pretreat for any negative effects of the cement. BARAZAN-D should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Use the centrifuge at all times until barite is added. Then use as needed to maintian the mudweight with low dilution. Should sweeps be required a BAROLIFT sweep is recommended. This sweep will help clean the hole with no negative impacts on rheoloay. Communicate with the casing drillers to come up with a sweep strategy. This wil{ most likely involve periodic Wallnut M or F sweeps. Daily additions of X-Cide 207 or Aldacide G MUST be made to control bacterial action. Sweep Formulation: 15 bbl of mud with 0.25 ppb of Barolift added. Shear thouroughly prior to pumping. Sweep Formulation: 5 bbl of mud with 15 ppb Wallnut added. Dextrid and/or PAC L should be used for filtrate control. Use Dextrid as much as possible to help coat cuttings and reduce dilution requirements. While drilling, monitor the torque and drag to determine if liquid lubricant is required. When penetrating high-clay content sections, additions of Drill-N-Slide ester are recommended to reduce the incidence of bit balling and shaker blinding. Maintain the pH in the 8.5 - 9.5 range with caustic soda or KOH. By 2000' TVD the system rheology may be relaxed as hole conditions allow. This will also lower the ECD for any possible loss zones which might be found. However, be prepared to increase the YP if hole cleaning becomes an issue. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based on current rheology, flow rates, angle and cuttings size. Consider stringing in 10-15 sx/hr of Baracarb 25 as the payzone is drilled. This will help seal the pore throats and reduce formation damage. Ensure that the mud weight is maintained at 9.5 - 10.5 ppg through this interval, unless hole conditions dictate otherwise. Stress slow pipe movement to the drillers to reduce surge/swab. Stage pumps on slow{y after connections and begin rotation prior to pumping (this will break the gels and reduce the pressure required to break the gels). If large losses occur, allow the system to break back to an LSND system. Run the fluid loss and rheology as with the inhibited system. When running the LSND, stop addtions of Baracor and Barascav D when the chlorides drop below 6,000 ppm's. If any trips are required, consider spotting a 20 bbl, 20 ppb pill across the loss zone. The pill should consist of base mud with 10 ppb Baracarb 50 and 10 ppb STEELSEAL added. This pill would reduce the effects of tripping back in and allow time for the LCM to "soak" into the zone. STEELSEAL and Baracarb will not dehydrate the mud which will allow for lower ECD's on the first bottoms up after TIH. All pit monitoring devices should be watched closely at all times. Reduce the system rheology prior to cementing to a YP < 20 (check with the cementers to see what yp value they have targeted). Hydraulics Optimization Chart Maximum Acceptable ROP in fph at Specified GPM and RPM with casin GPM--> 150 200 250 60 r m 104 162 231 80 r m 104 162 231 Baroid recommends a flowrate in the 200 gpm range to maximize hole cleaning efficiencies at these high penetration rates. The rotational effect does not apply in this vertical wellbore. The pump rate can be lowered to 150 gpm and still acheive good hole cleaning. Hazards /Concerns -Production Interval: N. Pretty Creek #1 ~~l.t~ 5 0(03105 ~ Halliburtan BaROID Pelican Hill Mud Program • Preventing lost circulation. • Optimize solids control equipment to maintain density and sand content. • Maintain YP between 13-20 to optimize hole cleaning and to control ECD. • Pump high viscosity or Barolift or Wallnut sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness. Sweeps Supplement the hole cleaning of the drilling fluid as dictated by hole cleaning indications. Monitor all sweeps pumped and report on their effectiveness. The objective of the sweep is to change the flow characteristics /carrying capacity that is inherent with the mud system. Select sweep type accordingly. Coal Drilling The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The hole stability risks when drilling coal seams are often high, and the fluid design and drilling operations have been optimized to combine reduced risk with reduced costs. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal seams. • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROt_ pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss (based on ECD values using the DFG software ). System density increases can also be employed in increments of 0.5 ppg. Solids Control Equipment Maximize the use of all solids control equipment to ensure that the solids content of the system is kept to a minimum during this interval. Run the shale shaker with as fine a screen size as possible. • Size shaker screens with coarse mesh initially • Adjust screen size as solids loading, mud rheology and flowrates allow • Inspect the shaker frequently, taking time to repair /replace damaged screens 2. Maximize the use of the centrifuge, keeping the fluid as clean as possible. Running Casing /Cementing Preparation Monitor hole fill/returns closely while running the liner to insure losses haven't occurred. Refer to Baroid's DFG+ program if calculated surge/swab values are needed. Condition the mud prior to the cement job. Production Hole -Hazards /Concerns: • Optimize solids control equipment to minimize colloidal solids build up and dilution requirements. • Maintain flow profile based on PV, YP and tauo flow parameters. • Pump sweeps as required to enhance hole-cleaning efforts. Monitor the effectiveness of any sweeps pumped. • Follow the hole cleaning guidelines to assist in drilling parameter selection. Use connections for high RPM and pump rate support when these parameters are limited during drilling operations. • Follow the coal drilling guidelines. Fluid Volumes: N. Prettu Creek # I vl.~J E~ 02I03r`~5 ~ Ha{{iburton BAROID Pelican Hi11 Mud Program Surface Interval: At spud approximately 300 barrels of new fluid will be needed. Dilution rates for the 12 %" section are anticipated at .54 bbls/ft. Estimated Fluid Disposal Volumes: P10 P50 P90 Initial build 200 300 400 Dilution 420 810 1020 Re-use next interval 350 300 100 Total 270 810 1320 Estimated Drill Solids Disposal Volumes: P10 P50 P90 Cuttin s Volume 175 192 265 Wettin Fluid 125 200 400 Total 300 392 665 7 7/8" Interval to TD: Approximately 350 barrels will be re-used for this interval. Dilution rates for this section are anticipated at 0.28 bbls/ft. Estimated Fluid Disposal Volumes and: P10 P50 P90 Initial Build 0 50 300 Dilution 450 815 980 Com letion 0 280 550 Total 450 1145 1830 Estimated Drill Solids Disposal Volumes: P10 P50 P90 Cuttin s Volume 180 199 240 Wettin Volume 90 199 480 Total 270 398 720 Estimated Fluid Costs P14 P50 P90 12'/4" Surface 16,000 27,500 35,000 7 7/8" Intermediate 19,500 35,000 64,000 9.5 com letion 4,000 12,000 18,000 Total $39,500 $74,500 $117,000 Use of the centrifuge should lower both the costs and dilution rates. N. Pretty creek#1 v1.C1 i' 02i03/0~ ~ Halliburton BaROi~ Pelican Hill Mud Program Losses Seepage 5-10 bbltfir Static Treat Active System wOh 5 sxlhr Barofibre Losses < 15 Yes bbllhr Drill Ahead No 5 sxlhr Barofibre Lasses < 15 Yes bbllhr Drill Ahead No 40 ppb LCM1Mud Pill: 10 ppb Baroseal F 10 ppb Baroseal M 10 ppb Barofibre 10 ppb Wallnut M Losses < 15 Yes bbllhr Drill Ahead No Proceed to'Partial Losses' Pill Pelican Hills Lost Circulation Decision Tree fl Inhibited Mud Systems Parhat Severe Total 15.60 bbuhr 60•Z~ bbllhr Static > 200 bbllhr Static Static Treat Active System 60-150 bblltlr Static 150-200 bblhr Static Drill Aaoss Fault with 10 sxltlr Micatex Losses < 25 Yes bbl~lr Drill Ahead No TO ppb LCMIMud Pill: 20 ppb Baroseal F 20 ppb Baroseal M 20 ppb Barofibre 10 ppb Wallnut M Drill Across Fault Drill Across Fault Pump Gunk Squeeze pill to allow POH 100 ppb LCMrtilud Pi11: (VOIUme t0 be 20 ppb Baroseal F determined based 20 ppb Baroseal M 30 ppb Barofibre Contact Drilling ngineer upon losses 20 ~ WaNnutM or En ineer on call 10 ppb Wallnut F Contact Drilling Engineer or Engineer ntact Drilling Engineer or on call Engineer "On Call" Pump Gunk POH, PU dumb iron Squeeze pill SHA (Volume to be determined based upon losses) Consider cement 1 plugback contingency Losses < 15 Y~ bblhr Pump Gunk Drill Ahead Squeeze pill No Contact Drilling Engineer or Engineer on call to determine if additional LCM treatments are to be made or to proceed to Gunk Squeeze pill Notes: 1) Drill gross fault or loss zone 1.5 - 2.0 times the length of the throw before spotting Gunk Squeeze. 2) PBL sub should be run in BHA to spot pills if'Partial Loss' cases or above are anticipated prior to drilling to allow the spotting of LCM pills. 3) LCM pill volume =300'-1i00' column based upon actual hole diameter. 4)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR PLUGGING THE DRILL STRING. N. Pretty Creek ;# 1 v t .0 ~ 02/03/05 Halfiburtan BaROi~ Pelican Hill Mud Program Losses Pelican Hills Lost Circulation Decision Tree fl Payzone Mud Systems Partial Seepage 2Ofii0 bbllhr Severe Total 5-20 bbllhr Static Static 60.200 bblhr Static > 200 bbllhr Static Treat Active System Treat Active System with 5 sxlhr Baracarb with 10 sxlhr Baraarb 60-150 bbllhr Static 150-200 bbllhr Static Drill Across Fault 501150 150 Losses < 15 Yes bbllhr No Drill Ahead Increase Treatment to 10 sxlllr Baraarb 501 150 namic Uses < 15 Yes bbllhr Drill Ahead No 20 ppb LCMIMud Pill: 20 bbls base mud 10 ppb Baraarb 50 10 ppb Baraarb 150 Losses < 15 Yes bbllhr Drill Ahead No Proceed to'Partial Losses' Pi11 Losses < 15 Yes bbl~lr Drill Ahead No 50 ppb LCMOYIud Pill: 20 bbls Base mud 10 ppb Baracarb 25 20 ppb Baraarb 50 20 ppb Baracarb 150 Drill Across Fault Drill Across Fault Pump gunk squeeze pill to allow POH (Volume to be goo pit LCMIMud PiN: 20 ppb Baroseal f Pump gunk determined based z0 p~ ~~~~ ~ squeeze pill to upon losses 30 ppb Barofibre allow POH 20 ppb SteelSeal Volume to be Contact Drilling 1o ppb Baracarb 150 determined based E meer or En Ineer n9~ 9~ upon losses) on call itad Drilling Engineer or Engineer "On Call" Contact Drilling ngineer or Enoineer on call Plan to pump a second Losses < 20 Y~ b~lhr Drill Ahead No Contact the Engineer on all to determine if additional LCM treatments are to be made or to proved to gunk squeeze pill 50-80 bbl gunk squeeze pill if massive losses continue. Pump gunk Consider cement squeeze pill plugback contingency (Volume to be determined based upon losses 1)Pelican Hills must approve any steps past PARTIAL losses. 2) Drill aaoss fault or loss zone 1.5 - 2.0 times the length of the throw before spotting reverse gunk squeeze pills. 3) PBL sub should be Nn in BHA to spot pills rf'Partial Loss' cases or above are antiapated prior to drilling to allow the spoiling of LCM pills. d) LCM pill volume =300'-600' column based upon actual hole diameter. 5)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR PLUGGING THE DRILL STRING. lv~. Pretty Creek #t v LC1 ~>~ O2/O~iOS ~ Halliburtoln BaROID Pelican Hill Mud Program Gunks (WBM) Description The basic system forms a fairly soft plug. The addition of cement produces a firmer set which can withstand differential pressure and has a longer lifetime -this is known as DOB2C. Essentially the gunk treatment involves mixing bentonite, bentonite/polymer, or bentonite/cement powder blends into an oil such as diesel. This mixture is pumped down the drill pipe whilst water based mud is pumped down the annulus. When the two streams meet, a thick gunk (gel) is formed as the bentonite or other additives hydrate. This is then squeezed into the formation. The hardness of the gunk depends on the relative pump rates and the concentration of the pill (as well as the pill type). Typically the mud and pill would be pumped at similar rates and the pill would contain around 200-400ppb bentonite. In some situations environmental regulations may preclude the use of diesel oil. Low toxicity oils such as synthetic oils may be used in place of diesel but should be tested in the laboratory first. A cement unit is used for displacing the gunk squeeze. The pumping unit displaces the mixture down the drill string and the mud pump pumps fluid down the annulus. The slurry reacts with water so that precautions to keep water from prematurely contacting the slurry are needed. An oil spacer is pumped in front of and behind the pill. Benefits: Limitations: • Temperature is not very important • Soft set avoids sidetracking problems (easy to wash/drill out) • Slurry will pass through most BHAs • Procedures are well established • Suited to large fractureslvoids • Placement -need to generate gunk in the right place • Flow rate and mix is important to achieve suitable consistency • Suitable experience required • Avoid premature mud contamination • Possible environmental restrictions dealing with oily returns • Effect can be short-lived due to softness of the plug (simple gunk) • May not work with high salt muds (>50,000 mg/I chlorides) N. PretCy Creels # I v I.0 1 ~;~ 02/03/05 ~ Halliburton BAROID Pelicaln Hill Mud Program Gel Gunk Squeeze Procedure Formulation -1 barrel • 0.7 bbl Diesel • 400 Ibs bentonite (density is approx. 10 Ib/gal) Mixing Procedure Mix in a cementing batch tank, not in the pits 0 Ensure the cement unit, batch tank and all associated pipework is completely drained and then flushed through with diesel 0 Add the bentonite to the diesel. Preferably add the bentonite through a mixing jet (not directly into the tank) to avoid lumps. 0 1f the mixture becomes too thick to add the required quantity of bentonite, stop mixing and use the slurry as it is. 0 Test the gunk by mixing a sample of it 50/50 with the mud. Check the quality - it should be a consistency similar to chewing gum within 30 seconds. NOTE: if a highly inhibitive Mud does not allow the Gunk Squeeze to hydrate, then Freshwater, not the Mud, should be used to pump down the annulus AND to displace the Diesel Spacer -Gunk Squeeze-Diesel Spacer combination in the drill pipe. See below procedure, Suggested Procedure 1. Place the bit about 50-60' above the loss zone. 2. Line up mud pumps to pump simultaneously down the drillpipe and annulus. 3. Line up cement unit to pump down the drillpipe. 4. With the cement unit pump 10 bbls fresh water then10 bbls diesel followed by 40+/- bbls gunk and a further 10 bbls diesel then 10 bbls fresh water, down the drillpipe. 5. Displace with the mud pump until diesel at the bit. Close annular. 6. Pump at 5 bpm down the drillpipe and 10 bpm down the annulus (use freshwater, if mud is too inhibitive) simultaneously until half of the gunk is out of the bit. 7. Pump at 5 bpm simultaneously down both the drillpipe and annulus until the gunk has been over displaced from the drillpipe by 5 bbls. 8. Squeeze gunk into the loss zone. Leave at least 5 bbls gunk inside the wellbore to prevent over- displacement. Try to establish ashut-in pressure at the end. 9. If successful, leave the gunk to firm up for 30 minutes prior to washing out. Comments The gunk pill is inert until it is mixed with water or water based mud. IT MUST ONLY CONTACT WATER BASED FLUIDS AS IT EXITS THE BIT. The purpose of initially pumping down the annulus at twice the rate down the pipe is to initially produce a slower reacting product that can penetrate the formation more easily. The last part of the gunk is mixed 50/50 and plugs the loss zone quickly. These flow rates are designed to get the gunk to the loss zone quickly after the gunk has been mixed with the mud (or fresh water). The progress of the job should be determined and monitored by the volume of displacement mud pumped down the drillpipe. N. Preiay Creek # i v 1.0 1 1 02/03; OS ~ f~)li~t,t~°~:~~t~l BAROID Pelican Hill brad Program N. Beluga #1 -Surface 1000 ~Operatot: Pelic.~l H ell: N Pretl Creek ~ #1 Riq WR : 7 : ~ 8% KCI polymer fbw Rate = 351 gallmin RO P =100 ftlhr Cuttings Load, X Transpo Eff av rt X Averag V, It1m e m Hole An le ECD Ibl I Mud Weight = 9.51hlgal Cut R•1 s@ 100 ftlhr80 rpm ! HC• 60 rpm•5 ting Dia. m ! C=3 =,25 in m ! 3.96 .~ w!o Cut _ ~_ _ 12.25 in w! Cut 1.0 (" !]) ft 9.582 ! 9.582 Iblgal 3.5 x 2.602 >e 1102.0 ft __ `_ .~ fi.75 x 2.813 x 398.0 ft H C - 1560 0 12.25 in 0 ( ) ft 1500 5 1015 20 2 5 0 50 10 00 41 82 30 60 9 0 T 9.50 1D.00 1 . 0.50 . 3.h~~- ! Ihlgal ~ ~ rl Ir Imiv The hole cleaning model indicates that 400 gpm will provide the best hole cleaning support at p rates of 100'/hr. If these flowrates can not be maintained, remedial action such as high viscosity sweeps and circulating on connections will be required. Please note that the model indicates cuttings trying to build at the top of the collars. Circulating on connections to move these cuttings up hole is recommended. N. Prettv Creek # 1 v I.0 H~~ I I b U rt0 I'1 BAROID Pelican Hill Production hole modeling with 5:5" casing ~Ope~ator. Pelican Hin Rig WR 7 ell: N P~ett Creek #1 Cuttings Transport Average Hod Load. X Eff avq X V, ftlm~ AnalE 1 D00 Mud Proctram 8%KCI polymer Fbw Rate = 22fi galJmin RDP =180 ft1h~ ECD M1ud Weight = 9.5 Iblgal Cuing aia. _ .2 in Ihlgal R-1 s@ 180 ftJhr60 rpm 1 HC~ 40 ~pm~5m t C=5m t ;,.,i 8.835 in at 3 84f1 lJ ft Iblaal ~.~~~ in 15ao.o ( ~ ft 9.848 J IblQal 2000 4DaD r.~r~m ~• •~ -T~-~ X4626.0 45.0 ( J ft 5 1D 15 20 25 0 50 1000 87 174 30 60 90 9.50 10.00 10.50 10.04fi t Ib1g~ F hr f I IT lima The recommended flowrate is 200 gpm. If needed the pump rate can be decreased to 150 gpm and still obtain good hole cleaning at 100'/hr. - I HaII~bUrton BAROID Pelican Hills Mid Pr r~ ~Ti ~ 4 .~: ~~ ~~ ~~ Pelican Hills North Pretty Creek #1 West Cook Inlet, Alaska Baro~d Mud Program ~~ ~ Hailil~-urton Baroid ~' ,- Name (Printed) ,, Signature Date Originator Dave Higbie %~ Reviewed by Don Shaw Customer Approval Jim Ro Version No: Date: 1.0 January 31, 2005 N. Pretty {,reek #k i v 1.4 ~ 01 /31/54 • ' hIaIIlbUrtOn BAROID Pelican Hills Mud Pr ram North Pretty Creek #1 Introduction: The following mud program was prepared for a vertical well accessing the Belkiga gas sands as part of an exploration program on the west side of Cook Inlet, Alaska. This well will,be spudded with an 8% KCI drilling fluid and drilled vertically to the 1,500' MD range. It will be drilled with a 12 %4" hole size, 9 5/8" casing run and cemented. The surface casing will be drilled out with the existing mud system. The 7 7/8" interval will then be drilled with 5 '/2" casing to TD at 4,500' MD and cemented at this depth. The well bore may be displaced and production tubing run depending on logg~g results. Spud the well with a 8% KCI mud ~ 8.6 ppg. The mud weight ~I then be held in the 8.6 - 8.9 ppg mud weight range to the surface hole TD unless hole conditions, dictate otherwise. Our primary focus for surface hole drilling operations will be adequate mud weight for well control and sufficient mud viscosity for efficient hole cleaning. This same 8% KCI mud will be maintained through the' production interval. This mud offers good LCM responses if losses are encountered. Special empha~s should be placed on maintaining low ECD's and surge/swab pressures to minimize the potential for lost circulation. Primary Drilling Objectives: • Zero fluid related HSE incidents • Achieve wellbore stability • Achieve good hole cleaning cons • Lost circulation mitigation/control • Achieve good Zonal Isolation as i • Achieve minimal formation damp • Minimize fluids related NPT • Minimize drilling wastes Critical Fluid Issues: ~, ~~`~ ~, hole angle, geometry and anticipated ROP rates plan in Beluga sands • Eliminating/controlli .glosses. • Maintaining a low CD in the production zone to reduce risk of lost returns. • Maintaining a sta le wellbore through coal seams. • Reducing drillin wastes with the inhibited drilling fluid system. Well Specifics: Casing Program MD ND Footage 12 '/4" hole 9 5/8" casin 1500' 1500' 1500' 7 7/8" hole (5.5" casin 4500' 4500' 3000' Surface Ho Mud Type: ~~.,.,o.t~o~ Densi Viscosi PV YP API FL ~H CI 0 -1500' 8.7 - 9.0 50 - 70 6 - 16 17-25 <8 8.5-9.0 40K N. Pr°etty Creels # 7 v I .~ a. 0 U31/5~4 Halliburton BAROID Pelican Hills System Formulation: 8%KCI pol mer Mind Program Product Concentration Water 0.905 bbl KCI 30 ppb (40K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.0 -2 ppb (as required 17-25 YP) PAC L .5 ppb Dextrid 1-2 ppb Aldacide G 0.15 ppb Baracor 700 1 ppb Barascav D 0.5 ppb (add as the wells uds Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimize fisheyes. Concerns and Contingencies Surface Interval - (0 -1,500' MD ) ~~~~ ~ ~ Mud TVpe: 8 %KCI ~ i 1. Mud weight: Maintain the 8.7 - 9.0 ppg density or as directed. ~~ ~O~ ~r ~,~~t~~ sus ~~ ~ '~', ~" '"" f~. p ~ ~~,-;~l .,r~ +~ ~'~~ ~ 2. Rheology: Maintain a YP between 17 - 25 or as needed to achieve adequate hole cleaning. This range was adequate on N. Beluga #1 and redaced problems at the shaker. 3. Filtrate control: Maintain filtrate control in the <8 r~+`~ge with PAC/Dextrid. The Dextrid will also help coat cuttings and reduce the waste str am/dilution requirements. Additions of Drill-N-Slide may be required to control screen blin~Jing/bit balling. Operations Summary: This section will drill a 12 '/4" hole. Build the %KCI fluid in the proper order of addition. This higher KCI concentration will reduce dilution requireme is and offset not adding EZ Mud (problems at the shaker). Be prepared for sloughing gravels in the upp r interval; increasing the system rheology with BARAZAN-D/N- Vis will assist in bringing this material o t of the well, as will pumping dedicated high-viscosity or Barolift sweeps. It is recommended that the p mp rate be increased to the maximum practical rate while the hole is unloading gravel Sweep Formulation: 30 barrels mucJ~add ca. 1.0 ppb BARAZAN D to achieve a tau0 > 25 or .25 ppb of Barolift. When penetrating high-clay c tent sections additions of Drill-N-Slide ester are recommended to reduce the incidence of bit balling an~haker blinding. Use the centrifuge at all times while drilling. Maintain a minimum 17 Y,p at all times. Be prepared to increase the YP if hole cleaning becomes an issue. This YP is lowerjthan normal but will help at the shakers. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based on current rheology, flow rates and cuttings size. Losses where noted on N Beluga #~~ while drilling out of the conductor. Be prepared to add Micatex F or Wallnut F should this occur. ~~iese losses appeared to be seepage losses in a sand so these two products should seal this zone. At TD, a Wall t "flag" (20 bbl pill with 15 ppb of WALLNUT FINE) should be pumped to gauge hole washout and calculate the required cement volume. The cement will then be pumped and drilling mud will be used bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. ~. Prett;-~ (C;reek ~r 9 v l .tJ ~~ 01 /31/51 Ha~llburton BAROID Pelican Hills Mud Program Hazards /Concerns -Surface Interval: • Preventing lost circulation through ECD management. • Optimize solids control equipment to maintain density, sand content, and reduce the waste stream • Maintain YP between 17-25 to optimize hole cleaning and to control ECD. • Pump high vis/Barolift sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness.: • Successfully cement casing. Maximum Acceptable ROP in fph at Specified GPM and RAM GPM 200 300 400 80r m 56 97 132 100r m 56 97 132 Baroid's recommended flowrate for this interval is 400 gpm to maximize hole cleaning at these penetration rates. RPM's make no difference in this vertical wellbore. ,' Production Hole Recommendations Mud Type: 8%KCI Prenerties~ ,.. ~~ Densi Viscosi Plastic Viscosity i Yield Point API FL ~H CI 1,500 - 2000' 9 - 9.5 40-53 6 - 15 ' 13 - 20 <7 8.5-9.5 40K 2000 - 6700' 9.2 - 9.5 40-50 6 - 15 13 - 20 <7 8.5-9.5 40K System Formulation: 8%KCI ~/ Product Concentrati6n Water 0.905 bbl , KCI 30 ppb (40K chlorides) KOH 0.2 ppb ' (9 pH) Barazan D 1.25 pp'b (as required 35 YP) Dextrid 1-2 p b Aldacide G 0.1 pb Baracor 700 1 b Barascav D 0. b maintain er dilution rate r ~ 77 ~~ ~~1 ~~~~ ,,. Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimiz~ fisheyes. Concerns and Contin~tencies Mud Tvpe: 8 %KCI;' 1. Mud weight: Maintain a 9.0-9.5 ppg density or as directed. Ensure the mudweight is 9.5 ppg prio~to cutting the pay sands. 2. Rheology: ~aintain a YP between 13-20 or as needed to achieve adequate hole cleaning. 3. Filtrate control: ~ filtrate control in the <7 range is required for this interval. Maintain additions of Dextrid and Pac L to reduce filtrate to this range. Additions of Drill-N-Slide will be required to control screen blinding/BHA balling. Losses in this interval can be controlled with additions of 1-2 ppb BAROFIBRE and 1-2 ppb of Wallnut F or by dedicated LCM pills; see appendix for LCM decision tree. ti. Prptt}% t;~'eek ~` l vl .{} ~ 0113 i; 54 I HaI~IbUrtOn BAROID Pelican Hills Mud Program Operations Summary: Drill out the cement/casing with the existing mud system. Bicarb or soda ash and citric acid sho be used to pretreat for any negative effects of the cement. BARAZAN-D should be used to intain rheological parameters. Maintain the mud as clean as possible while drilling. Use the centrif eat all times until barite is added. Then use as needed to maintian the mudweight with low dilutiq~'~. Should sweeps be required a BAROLIFT sweep is recommended. This sweep will help clean the hole with no negative impacts on rheology. Communicate with the casing drillers to come up with a sweep strategy. This will most likely involve periodic Wallnut M or F sweeps. Daily additions of X-Cide 207 or Aldacide G MUST be made to control bacterial action. Sweep Formulation: 15 bbl of mud with 0.25 ppb of Barolift added. Shear thoroughly prior to pumping. Sweep Formulation: 5 bbl of mud with 15 ppb Wallnut added. / Dextrid and/or PAC L should be used for filtrate control. Use Dextrid a much as possible to help coat cuttings and reduce dilution requirements. While drilling, monitor th torque and drag to determine if liquid lubricant is required. When penetrating high-clay content sec ~ons, additions of Drill-N-Slide ester are recommended to reduce the incidence of bit balling and shaker linding. Maintain the pH in the 8.5 - 9.5 range with caustic soda or KOH. By 2000' TVD the system rheology may be relaxed as hol conditions allow. This will also lower the ECD for any possible loss zones which might be found. Ho ever, be prepared to increase the YP if hole cleaning becomes an issue. Run DFG (Drilling Fluid Gra ics) to confirm hole cleaning efficiency based on current rheology, flow rates, angle and cuttings size. Consider stringing in 10-15 sx/hr of Baracarb 25 as the payzone is drilled. This will help seal the pore t oats and reduce formation damage. Ensure that the mud weight is maintained as low a possible through this interval down to the pay zone. The mud weight should be a 9.5 ppg by this de th -unless hole conditions dictate otherwise. Stress slow pipe movement to the drillers to reduces ge/swab. Stage pumps on slowly after connections and begin rotation prior to pumping (this will bre the gels and reduce the pressure required to break the gels). If large losses occur, allow the syste to break back to an LSND system. Run the fluid loss and rheology as with the inhibited system. Wh running the LSND, stop addtions of Baracor and Barascav D when the chlorides drop below 6,000 pp 's. If any trips are required, consider spotting a 20 bbl, 20 ppb pill across the loss zone. The pill sh uld consist of base mud with 10 ppb Baracarb 50 and 10 ppb STEELSEAL added. This pill would r duce the effects of tripping back in and allow time for the LCM to "soak" into the zone. STEELSEAL and Baracarb will not dehydrate the mud which will allow for lower ECD's on the first bottoms up after IH. All pit monitoring devices should be watched closely at all times. Reduce the system rheology Dior to cementi g o YP < 20 (check with the cementers to see what yp value they have targeted). Hydraulics Optimization Chart ~~ Maximum Acceptable ROP in fph at Specified GPM and RPM with casin GPM- 150 200 250 60 r m 104 162 231 80r m 104 162 231 Baroid recom ends a flowrate in the 200 gpm range to maximize hole cleaning efficiencies at these high penetration ates. The rotational effect does not apply in this vertical wellbore. The pump rate can be lowered t 150 gpm and still acheive good hole cleaning. N. Pretty Creek#l v1.J Ol/31/5~4 HaIIlbUrtOn BAROID Pelican Hills Mud Program Hazards /Concerns -Production Interval: • Preventing lost circulation. • Optimize solids control equipment to maintain density and sand content. • Maintain YP between 13-20 to optimize hole cleaning and to control ECD. • Pump high viscosity or Barolift or Wallnut sweeps to enhance hole-cleaning efforts. Monitor eep effectiveness. Sweeps ,'°~ Supplement the hole cleaning of the drilling fluid as dictated by hole cleanirt` indications. Monitor all sweeps pumped and report on their effectiveness. The objective of the ~~ ep is to change the flow characteristics /carrying capacity that is inherent with the mud system. Sete sweep type accordingly. Coal Drilling The following lessons were learned from extensive experience drilling I seams in Cook Inlet. The hole stability risks when drilling coal seams are often high, and the fluid~~esign and drilling operations have been optimized to combine reduced risk with reduced costs. Thg~ need for good planning and drilling practices is also emphasized as a key component for success... • Keep the drill pipe in tension to prevent a whipping ef,Pect which can disturb coal sections. • Use asphalt-type additives to further stabilize coal ams. • Increase fluid density as required to control their Wing coal. • Emphasize good hole cleaning through hydrau~s, ROP and system rheology. In the event that sloughing coal is encountered, cons er spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely usqueezed" into coal by closing the bag and applying pressure not to exceed the total annular pressure loss (bas on ECD values using the DFG software ). System density increases can also be employed in incre; nts of 0.5 p v C Solids Control Equipment / 5 c~'~ ~-- Maximize the use of all solids control equip, nt to ensure that the solids content of the system is kept to a minimum during this interval. 1. Run the shale shakers with as fine a s reen size as possible. • Size shakers screens with c arse mesh initially • Adjust screen size as soli loading, mud rheology and flowrates allow • Inspect the shakers fre ently, taking time to repair /replace damaged screens 2. Maximize the use of the cent ~ ge, keeping the fluid as clean as possible. Running Casing / Monitor hole fill/returns clo y while running the liner to insure losses haven't occurred. Refer to Baroid's DFG+ program if calcula ~ surge/swab values are needed. Condition the mud prior to the cement job. rrc~uu~u~n ncnC - • Optimize solid • Maintain flow/D s /Concerns: equipment to minimize colloidal solids build up and dilution requirements. le based on PV, YP and tauo flow parameters. • Pump swe~p as required to enhance hole-cleaning efforts. Monitor the effectiveness of any sweeps pumped. • Follow th hole cleaning guidelines to assist in drilling parameter selection. Use connections for high RPM a pump rate support when these parameters are limited during drilling operations. • Folloy6~4he coa{ drilling guidelines. N. Pretty Creels. #i vLt~, ~ Ol/3 USa4 Halliburtan BaROID Pelican Hills Mud Program Fluid Volumes: Surface Interval: At spud approximately 300 barrels of new fluid will be needed. Dilution rates for the 12 ' 4' section are anticipated at .54 bbls/ft. Estimated Fluid Dis osal Volumes: P10 P50 P90 Initial build 200 300 400 Dilution 420 810 1020 Re-use next interval 350 300 100 Total 270 810 1320 Estimated Drill Solids Disposal Volumes: P10 P50 P90 Cuttin s Volume 175 192 265 Wettin Fluid 125 200 400 Total 300 392 665 7 7/8" Interval to TD: Approximately 350 barrels will be re-used for this ' terval. Diluti rates for this section are anticipated at 0.28 bbls/ft. 5 ~3pE Estimated Fluid Disposal Volumes and: L P1 P50 P90 Initial Build 50 300 Dilution 450 815 980 Com letion 0 280 550 Total 450 1145 1830 Estimated Drill Solids Di osal Volumes: P10 P50 P90 Cuttin s Volume 180 199 240 Wettin Volum 90 199 480 Total 270 398 720 Estimated FI~Costs P10 P50 P90 12'/' Surface 16,000 27,500 35,000 7 7/ Intermediate 19,500 35,000 64,000 9. com letion 4,000 12,000 18,000 Total $39,500 $74,500 $117,000 r ~. Pretty Creek ~' ~ v I .U % Oll3l /54 HalllburtOn BAROID Pelican Hills Mud Program losses Pelican Hills Lost Circulation Decision Tree fl Inhibited Mud Seepage 5-10 bblhr Static Treat Active System with 5 sxlhr Barofibre Losses < 15 Yes bbllhr Drill Ahead No 5 sxltlr Barofibre namic Losses < 15 Yes bbllhr Drill Ahead No 40 ppb LCMIMud Pill: 10 ppb Baroseal F 10 ppb Baroseal M 10 ppb Barofibre 10 ppb Wallnut M Losses < 15 \ bbllhr / No Proceed 'Partial L s' Pill Partial 15.60 bblhr Static Treat Active System with 10 sxlhr Miatex Losses < 25 Yes bbf/hr Drill Ahead ~! 70 ppb LCIYpMud Pill: 20 ppb Baroseal F 20 ppb Baroseal M 20 ppb Barofibre 10 ppb Wallnut M Sv 15 }-Yes Dull Ahead No Contact Dulling Engineer or Engineer on all to determine if additional LCM treatments are to be made or to proceed to Gunk Squeeze pill Severe 60.200 bbtiftr Static 60-150 bblltrr Static Total > 200 bbllhr Static Static I I Drill Across Fault Drill Across Fault I I /Drill Across Fault 100 ppb LCM1Mud Pill: 20 ppb Baroseal F 20 ppb Barosea 30 ppb Ba re Contact Drilling Engin zo ppb nut M or En ineer on call 10 ppb Ilnut F l ~ Drilling Engineer or Engineer "On Calf Pump Gunk Squeeze pill (Volume to be determined based upon losses) G ~~ Pump Gunk Squeeze pill Pump Gunk Squeeze pill to allow POH (Volume to be determined based upon losses Contact Dulling Engineer or Engineer on call POH, PU dumb iron BHA Consider cement 1 plugback contingency Nees: 1) Dnll across fault or lass zone 1.5 - 2.0 times the length of the throw before spotting Gunk Squeeze. 2) PBL s~ should be run in BHA to spot pills if'Partial Loss' cases or above are anticipated prior to drilling to allow the spoiling of LCM pills. 3) LCM pill volume = 300'600' column based upon actual hale diameter. 4)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR PLUGGING THE DRILL STRING. N. Prett}- (reek ~` ~ t-1.U g. U 1!31.!54 Halliburton BaROI~ Pelican Hills Mud Program Losses Pelican Hills Lost Circulation Decision Tree fl Payzone Mud Systems Seepage 5-20 bbllhr Static Treat Active System with 5 sxlhr Baraarb 501150 Losses < 15 Yes bbVhr No Drill Ahead Increase Treatment to 10 sxlhr Baraarb 501 150 namic Losses < 15 Yes bbllhr Drill Ahead No 20 ppb LCMIMud Pill: 20 bbls base mud 10 ppb Baraarb 50 10 ppb Baraarb 150 Losses < 15 Yes bbllhr Drill Ahead I Pr to'Partial I Losses' Pill Partial 20.60 bblOhr Static Treat Active System with 10 sxlllr Baraarb 150 Losses < 15 Yes bbl/hr Drill Ahead No 50 ppb LCMIMud Pill: 20 bbls Base mud 10 ppb Baraarb 25 20 ppb Baraarb 50 20 ppb Baraarb 150 ~ < 2Q Yes bbllhr Drill Ahead No Contact the Engineer on all to determine if add0ional LCM treatments are to be made or to proceed to gunk squeeze pill Severe 60.200 bbllhr Static 60-150 bbllhr Static I 1150-200 bb~r Static I Drill Across Fault I 100 ppb LCMftrlud Pill: 20 ppb Baroseal f 20 ppb Baraarb 30 ppb Ba re 20 ppb S " ISeal toppb rararbf5o I Ddtl Across Fault I Pump gunk squeeze pill to allow POH (Volume to be determined based upon losses) Drilling Engineer or ineer "On Call" Contact Dn ling Engine or Enoineer on call ~~r, Pump gunk squeeze pill (Volume to be determined based upon losses ~ Total > ZO0 bbllhr Static I Drill Across Fault I Pump gunk squeeze pill to allow POH (Volume to be determined based upon losses Contact Dulling Engineer or Engineer on call Plan to pump a second 50-80 bbl gunk squeeze pill if massive losses continue. Consider cement 1 plugbadc contingency 1)Pelican Hills rrarst approve any steps past PARTIAL losses. 2) Dell acxoss fault or loss zone 1.5 - 2.0 times the length of the throw before spoiling reverse gunk squeeze pills. 3) PBL sub should be run in BHA to spot pills'rf'Partial Loss' cases or above are aniiapated prior to drilling to allow the spotting of LCM pills. 4) LCM pill volume = 300'-600' column based upon actual hole diameter. 5)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR PLUGGING THE DRILL STRING. N. Pretty Creel: ~ i v I ,0 cr 01/31!4 ~Halliburtor>t BaROiD Pelican Hills Mud Program Gunks (WBM) Description The basic system forms a fairly soft plug. The addition of cement produces a firmer set which n withstand differential pressure and has a longer lifetime -this is known as D0B2C. Essen ~ ly the gunk treatment involves mixing bentonite, bentonite/polymer, or bentonite/cement powder ble s into an oil such as diesel. This mixture is pumped down the drill pipe whilst water based mud is mped down the annulus. When the two streams meet, a thick gunk (gel) is formed as the bentonite r other additives hydrate. This is then squeezed info the formation. The hardness of the gunk dep ds on the relative pump rates and the concentration of the pill (as well as the pill type). Typically t e mud and pill would be pumped at similar rates and the pill would contain around 200-400ppb bento ' e. In some situations environmental regulations may preclude the use of diesel oil. Low toxicity o' such as synthetic oils may be used in place of diesel but should be tested in the laboratory first. A cement unit is used for displacing the gunk squeeze. The pumpin nit displaces the mixture down the drill string and the mud pump pumps fluid down the annulus. The rry reacts with water so that precautions to keep water from prematurely contacting the slur are needed. An oil spacer is pumped in front of and behind the pill. Benefits: • Temperature is not very important • Soft set avoids sidetracking problems easy to wash/drill out) • Slurry will pass through most BHAs • Procedures are well established • Suited to large fractures/voids ~'`~ ~~ Limitations: • Placement -need to gen ate gunk in the right place • Flow rate and mix is im rtant to achieve suitable consistency • Suitable experience re wired • Avoid premature mu contamination • Possible environm ntal restrictions dealing with oily returns • Effect can be sh -lived due to softness of the plug (simple gunk) • May not work ~ h high salt muds (>50,000 mg/I chlorides) ~;,/1''retty Creek #~ v1.0 ; ~ O1/~ U:54 ' HaI1lbUrtOn BAROID Pelican HiIIS Mud Program , Gel Gunk Squeeze Procedure Formulation -1 barrel • 0.7 bbl Diesel • 400 Ibs bentonite (density is approx. 10 Ib/gal) Mixing Procedure Mix in a cementing batch tank, not in the pits 0 Ensure the cement unit, batch tank and all associated pipework is complete drained and then flushed through with diesel 0 Add the bentonite to the diesel. Preferably add the bentonite through a fixing jet (not directly into the tank) to avoid lumps. 0 If the mixture becomes too thick to add the required quantity of be onite, stop mixing and use the slurry as it is. 0 Test the gunk by mixing a sample of it 50/50 with the mud. Ch k the quality - it should be a consistency similar to chewing gum within 30 seconds. NO E: If a highly inhibitive Mud does not allow the Gunk Squeeze to hydrate, then Freshwater, t the Mud, should be used to pump down the annulus AND to displace the Diesel Spacer - G nk Squeeze-Diesel Spacer combination in the drill pipe. See below procedure. ~j Su ested Procedure ~~ t g9 ~ 1. Place the bit about 50-60' above the loss zone. 1 2. Line up mud pumps to pump simultaneously down a drillpipe and annulus. 3. Line up cement unit to pump down the drillpipe. 4. With the cement unit pump 10 bbls fresh water hen10 bbls diesel followed by 40+/- bbls gunk and a further 10 bbls diesel then 10 bbls fresh water; down the drillpipe. 5. Displace with the mud pump until diesel at the bit. Close annular. 6. Pump at 5 bpm down the drillpipe and 10I~pm down the annulus (use freshwater, if mud is too inhibitive) simultaneously until half of tk~e gunk is out of the bit. 7. Pump at 5 bpm simultaneously down both the drillpipe and annulus until the gunk has been over displaced from the drillpipe by 5 bbls" 8. Squeeze gunk into the loss zone. ,Leave at least 5 bbls gunk inside the wellbore to prevent over- displacement. Try to establish ashut-in pressure at the end. 9. If successful, leave the gunk ta'firm up for 30 minutes prior to washing out. Comments The gunk pill is inert until it is fixed with water or water based mud. IT MUST ONLY CONTACT WATER BASED FLUIDS IT EXITS THE BIT. The purpose of initially pu ping down the annulus at twice the rate down the pipe is to initially produce a slower reacting produ that can penetrate the formation more easily. The last part of the gunk is mixed 50/50 and plug he loss zone quickly. These flow rates are esigned to get the gunk to the loss zone quickly after the gunk has been mixed with the mud (or fr h water). The progress of the job should be determined and monitored by the volume of displac ment mud pumped down the drillpipe. N. Pretty ~:reek~l vL~ 1 1 Q1/31/.`.i4 ~ ~~~ ~;~~~b~; ~~~ BaROr~ Pelican Hills Mud Program ~ N. Beluga #1 -Surface 1000 Operator. Pelican H~ Rig WR 7 : 8% KCI polyrrrer ell: N Prekt Creek #1 : ~ Flaw Rate = 351 galtmin RO P =1 00 ftlhr ~ Cuttings Transpa t Average Hok ECD MudWeight=8.91b1gal Cutt ing Dia =. Load, X Eff av X V, fttmin An Ib! I R•1 s@ 100 ftlhr80 rpm t HC• 80 rpm•5 m I C=5 3.4fi .00 w!o Cut 12.25 in wt Cut 1.0(~ ~~)ft 8.9821 '- IhJ i i 3.5a2.602x1102.Oft 1 .~ - ~ 6.25x2.813x398.0ft HC 'i 12.25 in ---- 1560 0 0 ( j ft 1500 . . 5 1fl 15 20 25 0 50 1 ~0 3<4 !8 30 60 90 8.90 9.40 9 .~1 8.998 ! Ibtg~ - ~ - ~ - -- -- -~ ~ ri It fop The hole clea ng model indicates that 400 gpm will provide the best hole cleaning support at p rates of 125'/hr. If th se flowrates can not be maintained, remedial action such as high viscosity sweeps and circulating connections will be required. N. Pretty Creek #1 vl.~ Halliburton BAROi~ Pelican Hills Production hole modeling with 5.5" casing Aerator. Peli~r HiR Rig WR 7 ell: N Prett Creek #1 Cuttings Transport Average Hole Load, X Eff avq X V, ftlmin Anglr 100D Mud Program 8% KCI polymer Fbw Rate = 226 galtmin ROP =180 ftlhr ECD Mr~Weight=9.51b1gal Cutting Dia. =.2 in Iblgal _ R•1 s@ 180 fklhrfiD rpm ! HG 40 rpm•5m t C=Sm t ~, :ut 8.835 in ut 9.84' J) ft IbJ~ ~.~3~ m 1500.0 ( ) ft 9.848 t II 2DOo 3000 ~i~ l ~~ ~~~ ~`Zj 15.5 R 4.y~ x ~oUU.ur[~ 7.815 in ~ 4fi2fi.0 4500.0 ( ) h 5 10 15 20 25 D 0 1000 81 174 30 fi0 90 9.50 10.00 10.50 10.04~~! IbJgal F f'I IT r~ The recommende flowrate is 200 gpm. If needed the pump rate can be decreased to 150 gpm and still obtain good hol cleaning at 100'/hr. J_ Prettv Creelfi ~ I v 1.0 Pelican Hill Oil & bas, Inc. 4141 B Street, Suite 205 Anchorage, AK 99503-5940 907-277-1401, Telephone 907-277-1402, Fax January 2s, zoos Mr. Tom Maunder Petroleum Engineer AOGCC 333 W. 7~` Ave. Suite 100 Anchorage, AK 99501 Mr. Steve Davies Petroleum Geologist AOGCC 333 W. 7~' Ave. Suite 100 Anchorage, AK 99501 f- Re: Withdrawal of Request Waiver of Well Spacing Requirement N. Pretty Creek No. 1 & No. 2 Gas Wells Gentlemen: On December 20, 2004 Pelican Hill Oil and Gas Inc. applied for a spacing exception for two N. Pretty Creek wells. The proposed locations for these two straight holes at that time were as follows: N. Pretty Creek No. 1 Sec.22-14N-9W 1,705' FWL & 1790' FS N. Pretty Creek No. 2 Sec.22-14N-9W 350' FNL & 2,530' FWL As proposed, both wells would have been in the same governmental section and a spacing exception would have been required. The request for a spacing exception addressed that issue. Since filing that request for an exception, Jim Rose and I visited the sites again and examined the proposed surface areas in more detail. Also along on that trip were Mark Fink, Department of Fish and Game, Bruce Webb, Division of Oil and Gas and Ben Greene, Alaska Coastal Management Program. Since both of these proposed sites are within the Susitna Flats State Game Refuge, we were most interested in obtaining the views of Mr. Fink. Foremost, we found that the proposed location for the N. Pretty Creek No. 2 not to be within the vegetation designation as transferred from the vegetation map to the aerial photo. Instead of being in "deciduous mixed forest, 40-80 years old', it is actually in "sphagnum bog". Therefore, the original reason for selecting the above location for the Pretty Creek No. 2 well no longer exists. With the concurrence of Mr. Fink, this proposed well was been moved to the north such that it is now located in section 15. These two sites have now been surveyed and platted and the survey plats are attached herewith. The surveyed locations for these two straight holes are: N. Pretty Creek No. 1 N. Pretty Creek No. 2 Sec. 22-14N-9W Sec. 15-14N-9W 1,677' FWL & 1,634' FS 50' FSL 8~ 2,327' FEL Mr. Tom Maunder Mr. Steve Davies December 20, 2004 Page Two • Medrick Northrop of the US Corps of Engineers has been notified of this change of location for the N. Pretty Creek No. 2 well. Pelican Hill anticipates that full approval by the COE will be forthcoming. Pelican Hill hereby withdraws that the above referenced request for a spacing exception. Sincerely, G~'~''~'`"~ Arlen Ehm Vice President/Alaska Enc. Cc: Jim Rose, Operations Superintendent Mark Fink, ADEF Bruce Webb, DOG Ben Greene, ACMP/JPO Medrick Northrop • • SURVEY DATA N. PRETTY CREEK WELLS N. Pretty Creek No 1: Coordinates: NAD 83 N 2,663,401.34 US FT E 1,486,042.92 US FT NAD 27 N 2,663,640.56 US FT E 346,014.46 US FT LEGAL 1634' FSL, 1677' FWL Sec. 22-T14N-R9W Elevation: NAVD 88 (GEIOD99) 81' GL N. Pretty Creek No 2: Coordinates: NAD 83 N 2,666,609.53 US FT E 1,487,327.73 US FT NAD 27 N 2,666,848.73 US FT E 347,299.17 US FT LEGAL 50' FSL, 2327' FEL Sec. 15-T14N-R9W Elevation: NAVD 88 (GEIOD99) 88' GL 5 ~ I 3 ~ 2 I ~~ ~~ ~- 8 a i i 0 ~ ~~Or~~ii ~ ~ I ^~~ ~ o ~~ ~~o~/ 1 ~ I ~~ `ll~s' ,~ , I ? ~ 1 0 15 ~~'~~ 14 N. RETTY ,~~' ~ C EEK 2 ~~^ ^~ / I / ~ . .^~ j N. PR TTY ~ ~ ~ ~, I ----!------I-- q ( 28 I L? I ?G I CENTERLINE OF / ~ TRANSMISSIION LINE • T15N ~ , T14N 1 ~'~ /~ ~ I~ 1~ 1J ~4 AsLS ~ 2007-7 SN RBW iioa°i ° 1 6 i ~. 5 ~ i 8 0.5 ~ 0 1.0 GRAPHIC SCALE 1"=1 mi -- ~ ,~ / ~ sad / /. P/ o~' /~°/ i,~o°~ . P ia`~i i /o ~ ~ ~ ~ ~~ ~/ i ~ETAII-TRANSMISSION LINE EASEMENTS 5 SCALE: 1"=200' ~ ~ ~ i i ~ ASLS I I I ~ L ,~, - - 2007-t I I -' I Pt 74 T14N _ Ls 9020 T13N zool --- --_- -- ; I I I HORIZONTAL AND VERl1CAL COORDINATES WERE GENERATED FROM A POST PROCESSED STATIC GPS SURVEY THAT USED NGS CORS STA1lONS (ZAN1, LEGEND KEN1, POT3) TO GENERATE NAD83 COORDINATES. ADDITIONAL DATA WAS ALSO COLLECTED USING RTK GPS SURVEY PRACTICES. THE RTK DATA IS ~ FOUND 2 1/2" ALUMINUM CAP REFERENCED TO THE COORDINATES FROM STAl1C SURVEY. (R) RECORD PLAT 2003-153 UNITS: U.S. SURVEY FEET (RECORD OF SURVEY of THE BELUGA TO BEARINGS: GRID p01NT MACKENZIE TRANSMISSION LINE) HORIZONTAL DATUM: NAD 83 COORDINATE SYSTEM: ALASKA STATE PLANE (ZONE 4) ~M) MEASURED VERTICAL DATUM: NAVD88 (GEIOD99) SECl10N LINES ARE PROTRACTED. © STAKED GAS WELL LOCATION ~~~ STAKED GAS WELL AND PAD LOCATIONS F. Robert 1~, N. PRETTY CREEK 1 & N. PRETTY CREEK 2 (WITHIN PROTRACTED SEC. 15 & 22, T14N, R9W, S.M., AK) D ,~ ~,~ PREPARED FOR: ~~ PELICAN HILL OIL AND GAS INC. ~ DRAWN BY: JCS FIELD BOOK: 2005-01 ~ ~~~0~0 CHECKED BY: CBS ENGINEERS AND LAND SURVEYORS JOB NUMBER:2004-607.01 SCALE: 1" = 1 mI 801 WEST FlREWEED LANE SUITE 207 ANCHORAGE, ALASKA 99503-1801 PHONE (907)-274-5257 DATE: 01 /24/2005 SHEET:1 OF 3 • fl FOUND CLEARING LIMITS "~ ~ ~'~`` I ' ~ ~ i Cp^ii i ~ ~; / i ~ ~~~ i / i ~ ~' i ~ i i i i ~0i i /Q~i / ,, / i i / ~ P' /~ / ~ ~ ~ i / / / '~~ ' i I i i / ~ i i i i i i i / i i i i ~ ~ ~ ~ , j i i ~~~ i i i i i i i i i i i i i i ~~ ~' / , i I ~ ~ i i i i i i i i //, / ' i i i i i i HORIZONTAL AND VERTICAL COORDINATES WERE GENERATED FROM A POST PROCESSED STATIC GPS SURVEY THAT USED NGS CORS STATIONS (ZAN1, KEN1, POT3) TO GENERATE NAD83 COORDINATES. ADDITIONAL DATA WAS ALSO COLLECTED USING RTK GPS SURVEY PRACTICES. THE RTK DATA IS REFERENCED TO THE COORDINATES FROM STATIC SURVEY. UNITS: U.S. SURVEY FEET BEARINGS: GRID HORIZONTAL DATUM: NAD 83 COORDINATE SYSTEM: ALASKA STATE PLANE (ZONE 4) VERTICAL DATUM: NAVD88 (GEIOD99) SECTION LINES ARE PROTRACTED. WELL NAME NORTHING FASTING ELEV N. PRETTY CREEK 1 2663096.20 1486485.45 80.83 F. Robert ~I ' ~f 1 O ~ ~~~O~D ENGINEERS AND LAND SURVEYORS 801 WEST FIREWEED LANE SDITE 201 ANCHORAGE, ALASKA 99503-7801 PHONE (907)-274-5257 PREPARED FOR: ~~ ~ LEGEND © STAKED GAS WELL LOCATION FWL FROM WEST LINE FSL FROM SOUTH LINE STAKED GAS WELL AND PAD LOCATIONS NORTH PRETTY CREEK 1 & NORTH PRETTY CREEK 2 (WITHIN PROTRACTED SEC. 15 & 22, T14N, R9W, S.M., AK) PELICAN HILL OIL AND GAS INC. DRAWN BY: JCS FIELD BOOK: 2005-01 ' CHECKED BY: CBS ~ JOB NUMBER:2004-607.01 ~ SCALE:1" = 500' ~ DATE: 01 /24/2005 i \ STAKED ,' ,~; PAD LIMITS/ ~' ' . ~ . ./ ./ . . ~ ~ , '~/ : ~ .'~ 250' 0 500 .. ~/' '~ =~~ GRAPHIC SCALE ~/ 1 "= 500' ~-I SHEET:2 OF 3 • ~5 PREPARED FOR: HORIZONTAL AND VERTICAL COORDINATES WERE GENERATED FROM A POST PROCESSED STATIC GPS SURVEY THAT USED NGS CORS STATIONS (ZAN1, KENT, POT3) TO GENERATE NAD83 COORDINATES. ADDITIONAL DATA WAS ALSO COLLECTED USING RTK GPS SURVEY PRACTICES. THE RTK DATA IS REFERENCED TO THE COORDINATES FROM STATIC SURVEY. UNITS: U.S. SURVEY FEET BEARINGS: GRID HORIZONTAL DATUM: NAD 83 COORDINATE SYSTEM: ALASKA STATE PLANE (ZONE 4) VERTICAL DATUM: NAVD88 (GEIOD99) SECTION LINES ARE PROTRACTED. WELL NAME NORTHING FASTING ELEV N. PRETTY CREEK 2 2666773.73 1487805.72 87.64 F. Robert ~~~O~o ENGINEERS AND LAND SURVEYORS 801 WEST FlREWEEO LANE SUITE 201 ANCHORAGE, ALASKA 99503-1807 PHONE (907)-274-5257 ,~ .~ / 250' 0 500' GRAPHIC SCALE 1 "= 500' .' 1 i' ~ i i i / R'O~cp/~/ / // i p, ~ ~ ~~i i ?~ ~ ~~ ~ Qv~ ~ i ~i ~ ~ 7 i ~ 00 , ~ Ov ~ i ~ ~ i F. i ~ i i i i ~ i i 00 i i ~ / ~ ~ ~ ~ 7 / 7 7 i i 7 i i i LEGEND © STAKED GAS WELL LOCATION FEL FROM EAST LINE FSL FROM SOUTH LINE STAKED GAS WELL AND PAD LOCATIONS NORTH PRETTY CREEK 1 & NORTH PRETTY CREEK 2 (WITHIN PROTRACTED SEC. 15 & 22> T14N, R9W, S.M., AK) PELICAN HILL OIL AND GAS INC. FIELD BOOK: 2005-01 DCHECKED BYCCBS JOB NUMBER:2004-607.01 DATE: 01 /24/2005 SCALE: 1 " = 500' SHEET:3 OF 3 Re: Waiver of Sampling Requirements for Proposed lAl. Creek l'do. 1 and No. 2 Dear Mr. Ehm: On December 1, 2004, the Alaska Oil and Gas Conservation Commission ("Commission") received a request from Pelican Hill Oil and Gas Inc. ("Pelican Hill") that the Commission waive the requirements of 20 AAC 25.071 (b)(2) for a collection of a complete set of washed and dried samples of drill cuttings from the proposed N. Pretty Creek No. 1 and No. 2 wells in Section 22 of T14N, R09W, Umiat Meridian. Regulation 20 AAC 25.071 (c) allows the Commission discretion to waive cuttings sampling requirements, if such sampling would not significantly add to the geologic knowledge of the area in light of information available from offset wells. The proposed N. Pretty Creek No. 1 and No. 2 exploratory wells will lie between three existing wells that have cuttings samples and mud logs through the same geologic section. However, because of the distance to the offset wells (up to 3 miles), collecting some additional cuttings samples from N. Pretty Creek No. 1 and No. 2 will add to geologic knowledge of the area. In lieu of washed and dried cuttings samples, the Commission requests Pelican Hill to provide bagged, wet, unwashed, legibly identified drill cuttings samples of one cup volume, taken at approximately 30-foot intervals beginning about 200 feet measured depth above the projected top of the Sterling Formation and ending at the total depth of the well. The Commission understands that in lieu of standard mud logging services, Pelican Hill plans to utilize an automated mud analysis system. This mud analysis system must be operational during all drilling operations conducted in N. Pretty Creek No. 1 and No. 2. The Commission will not require conventional mud logs from N. Pretty Creek No. 1 and No. 2; however,. a fmal compilation of data acquired by the automated mud analysis system must be provided to the Commission within the 30-day filing period set out ~2Q AAC 25.071. Please call Steve Davies at (907) 79~if y6 av /any questions. Pelican Hill Oil $ bas, Inc. 4141 B Street, Suite 205 Anchorage, AK 99503 907-277-1401, Telephone 907-277-1402, Fax December 1, 2004 Mr. Steve Davies Mr. Tom Maunder Petroleum Geologist Petroleum Engineer AOGCC AOGCC 333 W. 7t'' Ave. Suite 100 333 W. 7~` Ave. Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 Re: Waiver of Mud Logging Requirement Gentlemen: Pelican Hill Oil and Gas Inc. is preparing to drill two gas wells in the onshore area between the Pretty Creek and Lewis River gas fields. Section 20AAC 25.071 (b)(2) of the regulations requires that a complete set of washed and dried, legibly identified samples of all drill cuttings. This requirement is designed to provide a library of cutting samples in all province areas where oil and gas drilling occurs. However, there are numerous wells that have been drilled in and around these particular wells. From a geologic standpoint, there is no reason to believe that collecting another set of samples in this area will provide any new or different data to the already large sample collection for the area. erator Well Location Distance Chevron Pretty Creek U. 224-28 Sec. 28-T14N-R9W 1+ miles SSW Unocal Pretty Creek U. No. 2 Sec. 33-T14N-R9W 2+ miles SSW Unocal Pretty Creek U. No. 4 Sec. 33-T 14N-R9W (surd 2+ miles SSW Unocal Pretty Creek U. No. 4 Sec. 4-T13N-R9W (btm) 3-miles SSW Cities Service Lewis River No. B-1 Sec. 10-T14N-R9W 2+miles N Cities Service E. Lewis River No. 1 Sec. 18-T14N-R8W 3± miles ENE The most recent well to be drilled in this area was the Unocal Pretty Creek No. 4, a directional hole drilled in 2001. The surface location for that well was in Sec. 33-T14N-R9W and the bottom hole location was in Sec. 4-T14N-R9W. The permit for that well did not require mud logging or the collection of samples. These two proposed wells are in the same area and roughly three miles north-northeast of the Fretty Creek No. 2 and No. 4 wells. That places them midway between the Pretty Creek and Lewis River Gas Fields. Although a waiver of this section is being requested, a complete mud analysis system will be in place to analyze any gas that is encountered. This system will combine reliable computers, advanced wireless networking and astate-of--the-art display that will provide the driller and other key personnel around the rig site with instant access to critical drilling data. It can also be sent to any other remote site such as an office in Anchorage. This system will. provide all of the needed drilling information in real time and the data will also be stored for retrieval at the end of the well. • Mr. Steve Davies Mr. Tom Maunder December 1, 2004 Page Two Additionally, we plan to run the following suite of conventional logs: J A Memory Propagation Resistivity with gamma ray will be run as an LWD tool and retrieved by slick line before cementing the 5 %Z" casing. This tool provides Deep Velocity, Deep Attenuation, Shallow Velocity and Shallow Attenuation, all recorded through a slotted liner that will be run at the end of the drill string and cemented in. A Memory Pulsed Neutron with Gamma Ray will be run on wireline after TD has been reached and the casing has been cemented in. This tool provides near and far neutron readings and the near/far ratio crossover indicates the presence of gas. It provides a sigma values which can be used to indicate the presence of gas. Temperature and Pressure curves are also provided and the temperature curve can be used to show gas movement behind pipe. Simultaneous interpretation of the resistivity and pulsed neutron data allow for calculations of water saturations. Subsection 20 AAC 25.071 (b)(2) states, "The commission will, in its discretion, waive or modify the requirements of this section for a well if those requirements would not significantly add to the geologic knowledge of the area in light of the information that is available from other wells in the area". Therefore, a waiver of section 20 AAC 25.071 (b)(2) is hereby requested as allowed in subsection 20 AAC 25.071 (h). It is important to our operations to receive an early decision in this matter as we do not have a mud logging unit on the west side of the inlet. If our request is denied, we would need to barge a unit over there before the inlet freezes over. This could be imminent. Sincerely, Arlen Ehm Vice President/Alaska Cc: Jim Rose, Operations Superintendent Al Gross, President Pelican Hill Oil & Gas, Inc. - .;,~,__ __ _ _ A ' Proposed Locations for - ice, .a:._ ~'~ `,. ~ _ N. Pretty Creek Nos. 1&.2 ~,,. _- - '~~'~ y ~''•~ ~,..,;,le . ~, ~ ~~ f• ~ ~~ S22 T14N R9W 'I'~;.-_ f `~ - - -_ . ~ -- ~ ~ +~ -- ...,~ - / ~''~' .' -- - Novem ber 1, 2004 ,, ..`. ~'`~..-; ,'r , ~ ~- tl ~d;4. ~ t i Proposed Farm-In .~- :,' ' ~f` ,,_ -~ ~ ~_ ,. ~y ~r~~i ";~•- . "~ - --/ f,~ ~~ , .~ . ADL 3$9934 "~~- ~r `"11` _,._ `~ '- '' ~'---' ~ ~ ~ ~ ~ Chugach Power Line ~'~-_ "r-~' `'~= - •.`-'- -' -- ~- (digitized from air pl~to) ADL 390101 ..~, • . ~_. _ ~~~•~•.t4. _ / .' t ~ '~ ~ ~.~ ..~_, -~ .. N. Pretty C k:~ p o.2 +~ ~ "N ''- ADL 390102 '~~~``~ - `.I-`"`~ - ~ -` ADL 390103 _ ~ ~ _ _ ~ _ ~`.~'' ~~:, "- ~ ~``-. _ --~ - is I J Ir ADL 390104 ,,;,~ `_ -•.:.,~, _,~_ ,,:,` ..s.,x~. r~ /,~ ~ ~ J ~ Well Locations - - -. ~ ~ --~-w ' - ::~ .,.r. R '; i i .. ~~ ~tit- ~~` }A~1 `~. ~: -~-' ~. ~~, ~.' ' ~. , ~-I Figure 1 -~_ - j , .._ - ~i,~ Enstar Gas Line ® ~ ~'r• ,_._,- ~ "~` (digitized from air photo) ~' ~* '~ .. -- ~- -`'~-- ' r ` "' ~ ~ '~ •' ~` - ^~ ADL 290102 ADL 389934 ® ,~~ ~~.~, ~ ADL 39010, -`-~J' ~ - .--- -`'~'"- ~~ PRETTY CREEK UNIT ~~ .' +~ ~ 1+.- ~,,, -ADL 39(104 ', -~ ~/ ~ - ~~ Road _.. - ' .a!~_ - .T~ _~ ~_ ' ` '' (digitized from air photo) =~ ~~ - A,;~..- y"'' _ _ - - - - - ,~' ,~ fJ - ' '~ i '~ r}~ 'fj• 1000 0 1000 2000 Feet Pelican Hill Oil & Gas, Inc. Proposed Locations for N. Pretty Creek Nos. 1&2 S22 T14N R9W November 1, 2004 Proposed Farm-In ADL 389934 ADL 390101 ADL 390102 ADL 390103 ADL 390104 ~ Well Locations Vegetation Codes 24 Deciduous Mixed Forest, 40-80 yrs 34 Deciduous Mixed Forest, >80 yrs 41 Coniferous Forest, <30ft 68 Spagnum Bog 69 Spagnum-Shrub Bog 92 Lakes, 100 acres Taken from: ~usitna River Basin Land Cover ype Map Atlas, USDA, 1986 ~ ~. '. '. „ _, , ,. .: __ ~;: ,. ;,, .4 ~', p+' ~ `' ~ ~ }~= 4~.~y~,~ b ~~ g` ,,~ a s ,~~. ~~w `~ ~ ~ . r . ~ `4P . a tih ~"": u~_. ~> ~ " _ r ~' ,~ ,~ `/ ~ -~ /J ;PRETTY ~~ . -- ~ ,~ ~=:~4;F .:w p ~ .~ -~' ~ ~ '4:': ,T ~,~ r -~-{ Figure 2 ~~. ~~.~%! Lydia Miner Department of Environmental Conservation 555 Cordova Street Anchorage, Alaska 99501 Subject: Pelican Hill Oil and Gas, Inc.'s request for exemption from an oil spill contingency plan f or the N. Pretty Creek Na.;1 and 2 exploratory natural g as wells, western Cook Inlet Basin, Alaska. Dear Ms. Miner: In correspondence to your Department dated December 7, 2004, a copy of which has been provided to the Alaska Oil and Gas Conservation Commission, Pelican Hill Oil and Gas, Inc. ("Pelican Hill") requested exemption from the requirements of AS 46.04.030 Oil Discharge Prevention and Contingency Plans for onshore drilling, testing and production of the proposed N. Pretty Creek No. 1 and 2 ("N. PC 1 and 2") wells in the Sterling and Beluga Formations to a maximum depth of 5,000'measured depth and true vertical depth. I understand that the Department's exemption decision turns on whether there is sufficient information to conclude that the likelihood of these wells encountering an on-bearing formation is no greater than if the wells were to be drilled solely to produce gas from a known productive gas pool. In order to evaluate Pelican Hill's request for an exemption, I have reviewed geologic information submitted by Pelican Hill and the Commission's well files and log files associated with offset wells Pretty Creek Unit No. 224-28 ("PCU 224-28"), East Lewis River No. 1 ("ELR 1 "), Lewis River No. B-1 ("LR B-1 "), and Pretty Creek State No. 1 ("PC St 1 "). Determination Based on examination of submitted information and Commission records, it is highly unlikely that Pelican Hill's exploratory drilling, testing or production activities in N. PC 1 and 2 will encounter oil or oil-bearing formations from the surface to the proposed depths of the wells. The apparent structural position of N. PC 1 and 2 and drilling records from offset wells indicate the risk of an oil spill from the N. PC 1 and 2 well bore is negligible. Although these are exploratory wells according to Commission regulations, nearby offset wells provide excellent control for these locations. In my opinion, the level of oil-spill risk from the N. PC 1 and 2 well bores, as proposed, is equivalent to the level of risk for a typical gas development (i.e., producing) well. Lydia Miner • i Page 2 of 5 January 7, 2005 A detailed discussion is presented below. All depths presented are measured depths, unless otherwise noted. Discussion The proposed N. PC 1 and 2 wells are offset by four existing wells: PCU 224-28, which is 1-1/2 miles southwest, ELR 1 that lies 3 miles to the east-northeast, LR B-1, which lies 2-1/4 miles to the north, and PC St 1 that lies 5 miles to the northwest. The geologic section encountered by these wells consists of, from youngest to oldest, alluvium, Sterling Formation, Beluga Formation, and Tyonek Formation. Pretty Creek Unit 224-28 PCU 224-28, is a deviated, gas development well that was drilled to 5,182' (5,010' true vertical depth), then plugged and abandoned in 1986. The mud log recorded for the well begins at 300'. The first indication of methane gas in the drilling mud occurs at 1,000', and the first significant methane in cuttings occurs at 1,980' near the top of the Sterling Formation. No occurrences of ethane and heavier gases are recorded on the mud log. The mud-logging geologist did not record any oil shows, and the mud log does not record any occurrences of oil staining, fluorescence, solvent cut or cut fluorescence. Three production tests were attempted on the Beluga Formation. Tests 1 and 2 recovered only water from 4,642' to 4,651' and 4,310 to 4,320'. Test 3 from 4,162' to 4,175' yielded formation water with gas to surface in quantities that were "too small to measure." Based on mud log and well test information, PCU 224-28 encountered only methane gas. East Lewis River 1 ELR 1 is a vertical exploratory oil well that was drilled and then plugged and abandoned in 1975. The mud log from ELR 1 begins at 2,375', and it records the presence of varying quantities of methane gas in mud and cuttings at 3,285' (within the Sterling Formation) to the total depth of the well. Ethane first occurs in the Tyonek Formation at 10,375', and it becomes significant only below 10,655'. Propane occurs below 10,675'; butane is recorded sporadically below 10,990', and pentane is recorded at 11,250'. Two oil shows are recorded on the mud log: a "fair" quality show from 11,245' to 11,270', and a "trace" quality show from 11,380' to 11,415'. There are no oil indicators above 11,245' recorded on the mud log. Fifty-three sidewall cores were acquired in the Beluga and Tyonek Formations between 5,948' and 11,306'. Only the core from 11,253' contained any residual oil saturation (2.3% of pore volume) in the Tyonek Formation. Twelve drill stem tests ("DSTs") were conducted between 6,280' and 11,478', recovering mostly water with occasional gas in amounts that were to small to measure. There are no records of oil being recovered during any DST. Based on mud log, sidewall core and well test information, ELR 1 only encountered methane gas in the interval that will be drilled and tested by N. PC 1 and 2. Lydia Miner ~ • Page 3 of 5 January 7, 2005 Lewis River B-1 LR B-1 is a vertical gas development well that was drilled to a depth of 10,319', tested, then plugged and abandoned during 1976. The well was mud logged from 380' to its total depth. Methane gas is recorded in the drilling mud from 380' to the total depth of the well. The first significant occurrence of methane in drill cuttings occurs in the Sterling Formation at 1,900'. Small amounts of ethane and propane are first detected in the mud in the Tyonek Formation at 8,835' and 9,395', respectively, several thousand feet below the interval that will be drilled and tested in N. PC 1 and 2. No heavier gases are reported. The mud-logging geologist did not record any oil "shows" on the mud log. Eleven instances of trace oil indicators were observed during drilling of LR B-1. These are slight indications of the presence of oil that are not significant enough to be classified as "oil shows." Three oil indicators were observed within or near the interval that will be tested by N. PC 1 and 2: 1. Coal at 2,000' in the Sterling Formation is noted as having a trace of milky yellow, slow solvent cut fluorescence. 2. Dolomite and conglomerate at 4,200' in the Beluga Formation is described as having dead, tarry oil stain, no fluorescence, weak milky yellow solvent cut fluorescence, and no visible solvent cut. 3. Sandstone at 5,665' in the Beluga Formation yielded a slight pale yellow-white solvent cut fluorescence. These three instances indicate only the presence of minor amounts of residual oil, which is not movable. Eight other oil indicators were observed in the Tyonek Formation at depths greater than 6,945', which is more than 2,000' below the planned total depths of N. PC 1 and 2. None of these indicators were classified as oil shows by the mud-logging geologist, and none of them signify the presence of movable liquid hydrocarbons. A total of 26 sidewall cores were recovered from the Sterling, Beluga and Tyonek Formations between 2,662 and 8,480', but none of them contained any oil. There is no mention of any shows, solvent cuts or fluorescence in the sidewall core analysis report. Five DSTs were conducted in the Beluga and Tyonek Formations between 3,516 and 6,655', but there. are no records of any oil being recovered during any of these tests. Based on mud log and well test information, LR B-1 encountered only methane gas in the interval that will be drilled and tested by N. PC 1 and 2. Pretty Creek State 1 PC St 1 is a vertical oil exploration well that was drilled in 1974, then plugged and abandoned in 1975. Mud-logging operations began at 175', and methane gas was present in the mud from that depth to the total depth of the well. Ethane is recorded sporadically in association with coal beds between 240' and 550', and again from 2,150' to the total depth of the well. Propane occurs sporadically from 3,175' to the total depth of the well, and butane is recorded from 5,500' to 5,530' and from 5,940' to 5,950'. / • Lydia Miner • Page 4 of 5 January 7, 2005 Three oil shows are noted on the mud log from PC St 1. The shallowest of these is a "trace" show in coal from 3,680' to 3,700' that was described as a trace of tarry oil stain with dull gold fluorescence and bleeding solvent cut fluorescence. Associated gases were methane, ethane and propane. Oil show 2 is a trace show in sand from 3,750' to 3,770, that displayed a trace of dull gold fluorescence win association with a slight trace of tarry oil stain. Only methane is associated with this show. Oil show 3 consisted of sand from 3,795' to 3,825' that displayed dull gold fluorescence with slow bleeding milky yellow translucent fluorescence. The mud-logging geologist described this show as "probably dead oils." Again, only methane is associated with this show. Five other oil indicators were recorded on the mud log: 1. Sandstone between 2,750' and 2,810' contained a trace of spotty dull gold fluorescence with faint crushed cuts, but no solvent cut and no visible oil staining. Associated gases were methane and ethane. 2. Sandstone from 4,000' to 4,025' displayed a faint trace of dull gold fluorescence, trace of staining, but no visible cuts. Associated gases were methane, ethane and propane. 3. Coal from 5,490' to 5,525' had scattered dull gold fluorescence and slow bleeding cut fluorescence. Associated gases were methane, ethane, propane and butane. 4. Sandstone at 6,000' displayed a poor cut fluorescence. Associated gases were methane, ethane, propane and butane. 5. Sandstone at 6,200', displayed bleeding cut from scattered tarry oil specks. Associated gases were methane, ethane and propane. The well history file indicates 86 sidewall cores were taken, but no descriptions or analyses are available in the file. Well was perforated from 6,009 to 6,014', and produced a small amount of gas to surface and 210' of gas cut mud. The operator concluded that the test was of a limited reservoir. The well was then plugged and abandoned. Based on mud log and well test information, PC St 1 encountered methane, ethane and propane gas and some small amounts of residual oil within the interval that will be drilled and tested by N. PC 1 and 2. Although small amounts of residual oil were present, Commission records do not indicate that PC St 1 encountered any movable oil. Structural Position Pelican Hill was unable to provide the Commission access to any seismic information in-this area, but Pelican Hill has represented to the Commission .that there are no major structural complexities between the N. PC. 1 and 2 wells and nearby offset wells LR B-l, ELR 1 and PCU 224-28. A structure map provided by Pelican Hill indicates that the prospective reservoir interval in N. PC 1 and Z will be structurally shallower than nearby well PCU 224-28, which encountered only methane gas. Structure maps provided by operators of the nearby Pretty Creek and Lewis River Units are published in the Commission's 2003 Annual Report. These maps suggest N. PC. 1 and 2 will lie on the same geologic trend, and at approximately the same structural elevation, as offset wells PCU 224-28 and LR B-1. Both of these wells encountered only methane gas in the section that will be penetrated by N. PC 1 and 2. Lydia Miner • Page 5 of 5 January 7, 2005 Conclusion Of the four offset wells, only the most distant, PC St 1, encountered small amounts of non- movable, residual oil. The other three offset wells encountered only methane gas in the portions of the Sterling and Beluga Formations that will be drilled and tested by N. BP 1 and 2. These proposed wells will lie along the same structural trend as offset wells PCU 224-28 and LR B-1, and will be shallower than PCU 224-28, which encountered only methane gas. Therefore, it is highly unlikely that N. PC 1 and 2 will encounter oil or oil-bearing formations. If you have any questions, please call me at (907) 793-1224. Sincerely, ,~ Steve Davies Petroleum Geologist • January 7, 2004 Lydia Miner Department of Environmental Conservation 555 Cordova Street Anchorage, Alaska 99501 • Subject: Pelican Hill Oil and Gas, Inc.'s request for exemption from an oil spill contingency plan for the N. Pretty Creek No. 1 and 2 exploratory natural gas wells, western Cook Inlet Basin, Alaska. Dear Ms. Miner: In correspondence to your Department dated December 7, 2004, a copy of which has been provided to the Alaska Oil and Gas Conservation Commission, Pelican Hill Oil and Gas, Inc. ("Pelican Hill") requested exemption from the requirements of'AS 46.04.030 Oil.Discharge Prevention and Contingency Plans for onshore drilling, testing and production of the proposed N. Pretty Creek No. 1 and 2 ("N. PC 1 and 2") wells in the Sterling and Beluga Formations to a maximum depth of 5,000'measured depth and true vertical depth. I understand that the Department's exemption decision turns on whether there is sufficient information to conclude that the likelihood of these wells encountering an oil-bearing formation is no greater than if the wells were to be drilled solely to produce gas from a known productive gas pool. In order to evaluate Pelican Hill's request for an exemption, I have reviewed geologic information submitted by Pelican Hill and the Commission's well files and log files associated with offset wells Pretty Creek Unit No. 224-28 ("PCU 224-28"), East Lewis River No. 1 ("ELR 1 "), Lewis River No. B-1 ("LR B-1 "), and Pretty Creek State No. 1 ("PC St 1 "). Determination Based on examination of submitted information and Commission records, it is highly unlikely that Pelican Hill's exploratory drilling, testing or production activities in N. PC 1 and 2 will encounter oil or oil-bearing formations from the surface to the proposed depths of the wells. The apparent structural position of N. PC 1 and 2 and drilling records from offset wells indicate the risk of an oil spill from the N. PC 1 and 2 well bore is negligible. Although these are exploratory wells according to Commission regulations, nearby offset wells provide excellent control for these locations. In my opinion, the level of oil-spill risk from the N. PC 1 and 2 well bores, as proposed, is equivalent to the level of risk for a typical gas development (i.e., producing) well. Lydia Miner • • Page 2 of 5 January 7, 2005 A detailed discussion is presented below. All depths presented are measured depths, unless otherwise noted. Discussion The proposed N. PC 1 and 2 wells are offset by four existing wells: PCU 224-28, which is 1-1/2 miles southwest, ELR 1 that lies 3 miles to the east-northeast, LR B-1, which lies 2-1/4 miles to the north, and PC St 1 that lies 5 miles to the northwest. The geologic section encountered by these wells consists of, from youngest to oldest, alluvium, Sterling Formation, Beluga Formation, and Tyonek Formation. Pretty Creek Unit 224-28 PCU 224-28, is a deviated, gas development well that was drilled to 5,182' (5,010' true vertical depth), then plugged and abandoned in 1986. The mud log recorded for the well begins at 300'. The first indication of methane gas in the drilling mud occurs at 1,000', and the first significant methane in cuttings occurs at 1,980' near the top of the Sterling Formation. No occurrences of ethane and heavier gases are recorded on the mud log. The mud-logging geologist did not record. . any oil shows, and the mud log does not record any occurrences'of oil-staining, fluorescence, solvent cut or cut fluorescence. Three production tests were attempted on the Beluga Formation. Tests 1 and 2 recovered only water from 4,642' to 4,651' and 4,310 to 4,320'. Test 3 from 4,162' to 4,175' yielded formation water with gas to surface in quantities that were "too small to measure." Based on mud log and well test information, PCU 224-28 encountered only methane gas. -East Lewis River 1 ELR 1 is a vertical exploratory oil well that was drilled and then plugged and abandoned in 1975. The mud log from ELR 1 begins at 2,375', and it records the presence of varying quantities of methane gas in mud and cuttings at 3,285' (within the Sterling Formation) to the total depth of the well. Ethane frst occurs in the Tyonek Formation at 10,375', and it becomes significant only below 10,655'. Propane occurs below 10,675'; butane is recorded sporadically below 10,990', and pentane is recorded at 11,250'. Two oil shows are recorded on the mud log: a "fair" quality show from 11,245' to 11,270', and a "trace" quality show from 11,380' to 11,415'. There are no oil indicators above 11,245' recorded on the mud log. Fifty-three sidewall cores were acquired in the Beluga and Tyonek Formations between 5,948' and 11,306'. Only the core from 11,253' contained any residual oil saturation (2.3% of pore volume) in the Tyonek Formation. Twelve drill stem tests ("DSTs") were conducted between 6,280' and 11,478', recovering mostly water with occasional gas in amounts that were to small to measure. There are no records of oil being recovered during any DST. Based on mud log, sidewall core and well test information, ELR 1 only encountered methane gas in the interval that will be drilled and tested by N. PC 1 and 2. Lydia Miner Page 3 of 5 January 7, 2005 Lewis River B-1 LR B-1 is a vertical gas development well that was drilled to a depth of 10,319', tested, then plugged and abandoned during 1976. The well was mud logged from 380' to its total depth. Methane gas is recorded in the drilling mud from 380' to the total depth of the well. The first significant occurrence of methane in drill cuttings occurs in the Sterling Formation at 1,900'. Small amounts of ethane and propane are first detected in the mud in the Tyonek Formation at 8,835' and 9,395', respectively, several thousand feet below the interval that will be drilled and tested in N. PC 1 and 2. No heavier gases are reported. The mud-logging geologist did not record any oil "shows" on the mud log. Eleven instances of trace oil indicators were observed during drilling of LR B-1. These are slight indications of the presence of oil that are not significant enough to be classified as "oil shows." Three oil indicators were observed within or near the interval that will be tested by N. PC 1 and 2: 1. Coal at 2,000' in the Sterling Formation is noted as having a trace of milky yellow, slow solvent cut fluorescence. 2. Dolomite and conglomerate at 4,200' in the Beluga Formation is described as having dead, tarry oil stain, no fluorescence, weak milky yellow solvent cut fluorescence, and no visible solvent cut. 3. Sandstone at 5,665' in the Beluga Formation yielded a slight pale yellow-white solvent cut fluorescence. These three instances indicate only the presence of minor amounts of residual oil, which is not movable. Eight other oil indicators were observed in the Tyonek Formation at depths greater than 6,945', which is more than 2,000' below the planned- total depths of N. PC 1 and 2. None of these indicators were classified as oil shows by the mud-logging geologist, and none of them signify the presence of movable liquid hydrocarbons. A total of 26 sidewall cores were recovered from the Sterling, Beluga and Tyonek Formations between 2,662 and 8,480', but none of them contained any oil. There is no mention of any shows, solvent cuts or fluorescence in the sidewall core analysis report. Five DSTs were conducted in the Beluga and Tyonek Formations between 3,516 and 6,655', but there are no records of any oil being recovered during any of these tests. Based on mud log and well test information, LR B-1 encountered only methane gas in the interval that will be drilled and tested by N. PC 1 and 2. Pretty Creek State 1 PC St 1 is a vertical oil exploration well that was drilled in 1974, then plugged and abandoned in 1975. Mud-logging operations began at 175', and methane gas was present in the mud from that depth to the total depth of the well. Ethane is recorded sporadically in association with coal beds between 240' and 550', and again from 2,150' to the total depth of the well. Propane occurs sporadically from 3,175' to the total depth of the well, and butane is recorded from 5,500' to 5,530' and from 5,940' to 5,950'. ` Lydia Miner . • Page 4 of 5 3anuary ?, 2005 Three oil shows are noted on the mud log from PC St 1. The shallowest of these is a "trace" show in coal from 3,680' to 3,700' that was described as a trace of tarry oil stain with dull gold fluorescence and bleeding solvent cut fluorescence. Associated gases were methane, ethane and propane. Oil show 2 is a trace show in sand from 3,750' to 3,770, that displayed a trace of dull gold fluorescence win association with a slight trace of tarry oil stain. Only methane is associated with this show. Oil show 3 consisted of sand from 3,795' to 3,825' that displayed dull gold fluorescence with slow bleeding milky .yellow translucent fluorescence. The mud-logging geologist described this show as "probably dead oils." Again, only methane is associated with this show. Five other oil indicators were recorded on the mud log: 1. Sandstone between 2,750' and 2,810' contained a trace of spotty dull gold fluorescence with faint crushed cuts, but no solvent cut and no visible oil staining. Associated gases were methane and ethane. 2. Sandstone from 4,000' to 4,025' displayed a faint trace of dull gold fluorescence, trace of staining, but no visible cuts. Associated gases were methane, ethane and propane. 3. Coal from 5,490' to 5,525' had scattered dull gold fluorescence and slow bleeding. cut fluorescence. Associated gases were methane, ethane, propane-and butane. 4. Sandstone at 6,000' displayed a poor cut fluorescence. Associated gases were methane, ethane, propane and butane. 5. Sandstone at 6,200', displayed bleeding cut. from scattered tarry oil specks. Associated gases, were methane, ethane and propane... The well history. file indicates 86 sidewall cores were-taken, but no descriptions or analyses. are available in the file. Well was perforated from 6,009to 6,014', and produced a small amount of gas to surface and 210' of gas cut mud: The operator concluded that the test was of a limited reservoir. The well was then plugged and abandoned. Based on mud log and well test information, PC St 1 encountered methane, ethane and propane gas and some small amounts of residual oil within the interval that will be drilled and tested by N. PC 1 and 2. Although small amounts of residual oil were present, Commission records do not indicate that PC St 1 encountered any movable oil. Structural Position Pelican Hill was unable to provide the Commission access to any seismic information in this area, but Pelican Hill has represented to the Commission that there are no major structural complexities between the N. PC. 1 and 2 wells and nearby offset wells LR B-1, ELR 1 and PCU 224-28. A structure map provided by Pelican Hill indicates that the prospective reservoir interval in N. PC 1 and 2 will be structurally shallower than nearby well PCU 224-28, which encountered only methane gas. Structure maps provided by operators of the nearby Pretty Creek and Lewis River Units are published in the Commission's 2003 Annual Report. These maps suggest N. PC. 1 and 2 will lie on the same geologic trend, and at approximately the same structural elevation, as offset wells PCU 224-28 and LR B-1. Both of these wells encountered only methane gas in the section that will be penetrated by N. PC 1 and 2. Lydia Miner ~ • Page 5 of 5 January 7, 2005 Conclusion Of the four offset wells, only the most distant, PC St 1, encountered small amounts of non- movable, residual oil. The other three offset wells encountered only methane gas in the portions of the Sterling and Beluga Formations that will be drilled and tested by N. BP 1 and 2. These proposed wells will lie along the same structural trend as offset wells PCU 224-28 and LR B-l, and will be shallower than PCU 224-28, which encountered only methane gas. Therefore, it is highly unlikely that N. PC 1 and 2 will encounter oil or oil-bearing formations. If you have any questions, please call me at (907) 793-1224. Sincerely, °Steve Davies Petroleum Geologist PRETTY CREEK UNIT AREA MUD WEIGHT ryVG) B.5 9 D.5 iD 10.5 - 0 ~ 200 ri. ~ ~ ~ t • ~' ~. f00 ~ .. ~ / ~ o°D .~ ; ~ 4 MM ~~ Prett eek St 1 - , ~ 1200 _ um - ~--~~ ~ LewiaR er 8~4% .. I. ~ re°D ~ reoD S ~ ~~; , zooD ----- _ _ 1~°° = N. Pretty 2f00 Cree f I 2 ~ wla River t :MID ~ ~0° ~ 1 ON, Prett Cree 1 30°° 0 D2W TsoD ~ ~ t n. ,,, 1:,,-Pr ....- l6tDl ~ F.~ra, r.n ~ x+e.. ~ P 224-28 I!mr , De°o +~~„~ ~ mw ., aaru ~' ~ o.,...M,,, ~ a~DD } of :now, ~ ~' X600 i ~ ~e°D I ~ 5W0 .PC SII 51110 ~ • Pl'V 13<~~ •Lmn6 RB~1 :3efllr/.i Ti~C~ ~ 5100 • E L.wvs R I ~~ ~.._.e 1~ /; /' ki . i :~ ~ • P ` _ ~~ wars . F,.~ c,«~ ~ .,.e .. se„rm,...F+olm.o. SFD - - tr3~13/l00~ N. Pretty Creek 1 and 2 Public Domain Structure Maps :~ ARLEN EHM 10 4 8 0 ,. ~ GEOLOGICAL CONSULTANT ADL 0396544 2420 FOXHALC DR. PH: 907-333-8880 ANCHORAGE; AK 99504. `89-6/1252- PAY DATE ~ ` ~ 'O ~~ TO THE ,-., 2 ORDER OF ~ ~' f7~~~~1 Fd,. ~,~C? ~«..~~~. D ® DOLLARS ~ ~v a.~« O ~ first National Bank ALASKA ~a~a role FOR /1/1^ ~. L ~` ~ ,~ ~~ ~~ ~~~ / T ----------- ----=-----------------"P n'0 L048O~i' 'i: L 25 200060: L4 L L i43 9ii^ • • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~t/r~,~~~ C,~ I PTD# ~~-~%Z... Development Service ~ Exploration Stratigraphic CHECK WA.A.T ADD-OHS "CLiTE"~ APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well Permit No, ~ API No. (lf API number Production. should continue io be reported as . last two. (2) digits a function~of the original API number. stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(f), all (PIS records, data and logs acquired for the pilot hole must be clearly differentiated ~in both name (name on permit plus PIS and API number (50 - 70/80) from records, data aad logs acquired . for well (name on permit). SPACING The permit is approved subject •to full EXCEPT]ON compliance ~vitb 20 AAC 25.055. Approval io perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. SCompanv Name) assumes the liability of any protest to the spacing .exception that may occur. . DRY DITCH ~ All dry ditch sample seas submitted to ibe SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 0' sample intervals through target zones. WELL PERMIT CHECKLIST Field & Pool Well Name: N PRETTY CK 1 Program EXP Well bore seg ^ PTD#:2050120 Company PELICAN HILL OIL AND GAS INC Initial ClasslType EXP / PEND GeoArea 820 Unit OnlOff Shore On Annular Disposal ^ Administration 1 Permit fee attached____________________--.-_.- _____ __-__---. Yes __---_-_.--_____, 2 Lease number appropriate- - - Yes - - - - ------------- 3 Uniquewell.n_ameandnumber--- -- -- --- -- - -- -- -- -- -- - Yes ------._----------- - - ------ - - ---------------------------------- 4 Well located inadefinedpool---------------------------__ _.______- No-_ -Exploratorygaswell___ - - -- - 5 Well located proper distance-from drilling unit_boundary_ - - - - - - _ - . _ _ _ _ _ Yes - _ _ _ _ _ More than 1500' $om lease boundary_ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 6 Well located proper distance from other wells- - - . - - Yes - - - - - Nearest well_is 1.112 miles to SW _ - - - - - _ - - - - 7 Su_fficientacreage.ayailablein_dril_lingunit______---- - Yes_ ______OnlywellinSection22--------------------------------------- ----- -- 8 If_deviated,is-wellboreplat-included---______________________ _________ NA-_ ____ _Verlicalwell----_____-_-.--___ - - 9 Operator only affected party--_________________________ _________ Yes- ______Pelican-HiIlDesignation of Operator_fo~filed11-16.2004-____----_______----- 10 Oper-atorhas-appropriate-bond infQrce------------------------ --------- Yes_ ._._-1,ette[ofGredit_._-___--_-__.-__.______. ---------------------------------- 11 Pe[mit-eanbeissuedwithoutconservationorder_--------- ------- --------- Yes_ _____----_-_______------_______- Appr Date 12 Permitean be issued without administrative-approval _ - - - - Yes - - - - - - - -- -- SFD 2/2!2005 13 Can permit be approved before 15-day wait Yes 14 Well.located within area and strata authorized by Injection Order # (put_1O# in-comments)_(For_ NA_ - - - - - - - - _ - - - - - - - - 15 All wells within 114-mile area of r-eyiew identified (For service well only) _ - _ - - - _ - - NA. - - - _ - - - - - - - - - _ - - _ - - - - - - _ - 16 Pre-produced injector; duration_of pre production less than_ 3 months(For service well on-ly) N_A_ - - - - _ . I 17 AC_M_P_Finding of Consistency-has been issued_for_this pro)ect- - - - . NA- - - -- - Drillingpermit approval no longer contigent_upon ACMP determination. - Engineering 11 18 Conductorstring_provided______________________ _____ __ ______-„ Yes- - --- ________ - 19 Surface casing-protects all-knpwn_ USOWs Yes Surface casing point is well below depths_where-water wells_would be reasonably drilled.. 5 3000,ppm may- 20 CMT-vol-adeguate_to circulate_o_n conductor & surf-csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - . - . - -exist belowthe surface eosin shoe. g -' - 21 CMT_voladequate-totie-in long string to surfcsg__________________ _________ Yes_ ___--__-___ -- - - 22 CMT-will coverall know_nproductiye horizons_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ . - _ _ _ _ _ 23 Casing designs adequate for C,TB&-permaf[ost__ Yes_ ______________________ _______-_---___--__---- -__-- ----_-.-__-_ 24 Adequate tankage_o_r reserve pit - - - - - - - - _ Yes . - - - - . Rig is_equipped with steel_pits:-Capacity is_lim_ited, however_rig successfully has_drilled_2_wells.- _ _ - 25 If a-re-drill-, hasa-10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ . - . - - _ Drilling waste to-Envirotech per-email from PH, _ _ _ . - - _ _ _ _ 26 Adequatewellboreseparation-proposed.._._----------------- --------- Yes_ .-__-_NOOther wells proximate._...------_--_-.__------_ 27 If diverter required, does it meet regulations_ - - - - - - - - - Yes Waiver_requestedfgr 12.2.5" hole with-10" line.- Offset evaluation-reveals no gas-in surface interval-proposed- _ - - Appr Date 28 Drilling fluid.prpgram schematic & equip list adequate- - - - - _ - . - - - Yes - - - -Maximum BHP estimated at 9.8 EMW. -9.51010.0ppg planned for surface, 9:5 -10.5 ppg planned for 8-1l2" hole- TEM 71712005 29 BOPEs, do they meet regulation - - - - - - - - Yes MW in surf_a_ce hole planned to_be hgher than normal as mitigation for 10" diverter line, - _ - 30 BOPS-press rating appropriate; test to_(put prig in comments)_ - - - - - - - . - Yes - - - - - - MASP w/o shoe breakdown-at 1800-psi, 3000_psi system and 2500psi test pr-oposed._ ---------- 31 Chgke_manifoldcomp_IieswlAPI-RP-53(May84)___________________ _________ Yes- -______-.------_____---.- ------------------------------------------------- 32 Work will occur without operation shutdown__________ ___________ ______-- Yes_ _-____-_---_-_____-.--.-- - - 33 Is presence of H2S gas-probable_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ _ _ _ _ _ _ H2S is not knownin the formations thatwill be-penetrated. Rig_has sensorsand alarms._ . - _ _ _ _ - - - - _ _ 34 Mechanical condition of wells within AOR yerifled (Forservice well onlya _ - . _ - NA. - _ - _ - - - - - - - - - - - - - - - - - Geology 35 Permit_can be issued w/o hydrogensulfide measures Yes - None rep-orted in adjacentwells grilled through same-geologic section, - - - - - - - - - - . 36 Data_presented on potential overpressure zones - - - _ Yes Maximum expected gradient is 0.51 psilft-(9.8 ppg),will drill with 9.5 to 10.5 ppg mud, Gas detection equip, _ . - _ Appr Date 37 Seismic analysis of shallow gas-zones - - _ _ - . - - - - No- - - - be utilized during drilling, Offset wells encountered gas-at shallow depths, but no kicks were reported, & mud- _ _ _ SFD 2!2/2005 38 Seabed condition survey-(if off_-shore) - - - - - - - - - --------- --------- NA- - _ - - - . - weights of 10.2 ppg an_d less were sufficient to maintain well control._ Well will be drilled with casing. _ , - .. - . 39 Contact name/phone-for-weekly progress_reports [exploratory only]_ - Yes - - - - _ .Jim Rose 277.1408 - - - - - - - - Geologic Commissioner: r~' Engineering Public Date: Commissioner: Date Co er Zf d~ Date ~D~ Recommend waivin re uirement for mud to and sam les as nearb wells rovide ode uate eolo is information. A 9 q 9 P Y P q 9 9~ manned mud gas analysis system will be used to monitor and record gas. Recommend waiving open-hale logs as this is a casing- drilling operation, and cased hole logs will be run after drilling. Recommend waiving recording of directional survey / ~ 4 0 ~ta during drilling. Casing drilling produces near vertical well bares, and a directional survey will be run after drilling. r
