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Home My WebLink AboutCO 484 [Fwd: RE: Polaris POD Response] " Co Lf1?f Jody, Please file this e-mail in CO484, else field files for Polaris. Jane -------- Original Message -------- 8ubject: RE: Polaris POD Response Date: Wed, 09 Jun 2004 15:34:27 -0800 From: 8chmohr, Donn R <8chmohDR@BP.com> To: Mary Williamson <jane williamson@admin.state.ak.us>, mike kotowski@dnr.state.ak.us CC: 8enden, Leslie B <8endenLB@BP.com>, Williams, Jonathan D <WilliJD@BP.com>, Huff, Brian D <HuffBD@BP.com>, Ince, Donald W (Phillips) <DWINCE@ppco.com>, Menghini, Mark L. (Conoco Philips) <mlmengh@conocophillips.com>, jeff.e.farr@exxonmobil.com, Reints, Rydell J <ReintsRJ@BP.com>, West, Taylor <WestTL@BP.com> Jane & Mike, Good to talk to both of you on the phone today. I thought it would be worth documenting our discussion and agreed action. polaris 8-pad Currently 8-201 is the only polaris well on production from 8-pad. The other producing wells, 8-200, 8-213 and 8-216 are all 8I due to mechanical or artificial lift problems. If the owners agree to repair 8-213 or 8-216 we will begin injecting in 8-215i for support. No water is currently being injected at 8-pad into the 8chrader Bluff, because there is no injector in the same hydraulic unit as 8-201. 8-201 has produced a total of about 160,000 BO at a current rate of -200bopd on jet pump. We are over-due for a static pressure in 8-201, primarily because the well was not designed for a jet pump and is set up with a straddle packer across a gas lift mandrel, which makes it very difficult to obtain a static. BP ACTION: BP will 8I 8-201 and obtain a static pressure as soon as possible. If the pressure is below or near 1633 psi we will leave 8-201 8I until injection support is available. If it is sufficiently above 1633 psi we will return 8-201 to production after discussing the results with the AOGCC. Polaris 8-pad has proven to be a challenge. We have learned that drilling additional wells with productivity and producibility similar to 8-201, 8-213 and 8-216 would not achieve satisfactory results, and it would be difficult to support the facility expansion necessary at 8-pad for full development. We have chosen to pace development at 8-pad to take advantage of the learning's we are achieving at W-pad Polaris and Orion especially with the multi-lateral wells. 8-pad Polaris is a more difficult area to develop compared to W-pad and much of Orion since it typically is more faulted, has more productive sand layers and the sand layers are thinner. Therefore, gaining the multi-lateral experience at W-pad and Orion is viewed as an important step to a successful 8-pad development. Viscous oil development is challenging on the North 8lope and development pace must be matched with the pace of technical expertise and ability. Polaris W-pad W-pad has had some very good results regarding productivity and producibility of the wells, especially with the two tri-Iateral wells. All producing wells have supporting injectors and we are currently injecting more water than we are voiding through production, to make up for previous production that occurred under Tract Ion 6/10/20047:55 AM [Fwd: RE: Polaris POD Response] 1 . operations, prior to having an injection order. We have not been on injection long enough to have confirmed water flood response in the producers. We expect (based on modeling) that the response will be in the form of a decline abatement, rather than a large production increase. In summary W-pad is performing well and injection is catching up to meet our objective of a VRR equal to 1.0. I hope this answers your questions and provides the additional background you requested. Please let us know if the plan for 8-201 meets with your approval. Thank you, Donn 8chmohr Project Lead Orion/Polaris -----Original Message----- From: Mary Williamson [mailto:jane williamson@admin.state.ak.us] 8ent: Monday, June 07, 2004 12:08 PM To: 8enden, Leslie B¡ 8chmohr, Donn R Cc: mike kotowski@dnr.state.ak.us 8ubject: Re: Polaris POD Response, Part II Leslie and Donn, I think Mike asked some good questions. Rule 7 CO 484 states "Production and injection operations must ensure the reservoir pressure is maintained above 1,633 psi at the datum depth of 5000 feet TVDss." Has this been achieved? I think we should all meet to further discuss this. Jane Mike Kotowski wrote: > Leslie, > > Here's Polaris POD, Part III. What's happening with reservoir pressure > as a result of the voidage make-up situation at 8-Pad? What is > happening to voidage make-up at 8-Pad? > > Also, BPXA needs to elaborate on the statement "8-Pad lacks current > make-up-awaiting development plan (see below)." What development plan? > > Mike K. > > -----Original Message----- > *From:* 8enden, Leslie B [mailto:8endenLB@BP.com] > *8ent:* Monday, June 07, 2004 8:24 AM > *To:* mike kotowski@dnr.state.ak.us > *8ubject:* polaris POD Response, Part II > > Mike, > > Please see our responses below to your latest questions about the > Polaris POD. Call me if you have any questions. > > --Leslie > > > > Please breakout cumm-voidage, cumm-make-up, and VRR by pad area, that > is, for 8 & M-Pad Polaris, then for W-Pad Polaris. How do you get the > current VRR =1.31, run me through the calculation since I do not have > the water injection numbers for Polaris. If I had the A8R, I may be > able to answer this one myself, but what's happening to reservoir > pressure and where given the difference in cumm voidage and cumm make-up? > > Report Date: March 04 20f3 6/10/20047:55 AM [Fwd: RE: Polaris POD Response] ) . > > Cummulative Snapshot for current report month > > Voidage (rb) Make-Up (rb) VRR Voidage (rb) Make-Up (rb) VRR > > S-pad Area 766,870 78,695 0.10 11,907 0 N/A > > W-Pad Area 3,030,375 1,135,022 0.37 130,438 186,360 1.43 > > S-pad lacks current make-up - awaiting development plan (see below) > > Finally, from your response regarding the number of planned wells for > the 4^th POD period, there are no wells planned for S-Pad or M-Pad? > > There are currently no wells planned from S-Pad or M-Pad during the > term of the 4th POD. The polaris owners are investigating horizontal > multi-lateral well development opportunities at S-Pad and M-Pad. > 3 of3 6/10/20047:55 AM INDEX CONSERVATION ORDER NO. PRUDHOE BAY FIELD POLARIS 484 1. September 12, 2002 2. October 1, 2002 3. November 1, 2003 4. November 8, 2002 . 6. 7. 8. 9. December 4, 2002 December 9, 2002 December 9, 2002 December 13, 2002 10. December 18, 2002 11. January 23, 2003 BPXA Application for Pool Rules AOGCC Request for more information and BPXA response October 31, 2002 BPXA request to keep certain exhibits confidential Notice of hearing, Affidavit of publication, bulk mailing list for the Anchorage Daily News Meeting Sign In Sheet Hearing Sign In Sheet BPXA's submittal of Exh. VIII-1 Transcript BPXA's request for certain Exhibits to be held confidential Exhibits 1-6 and 1-7 BPXA's submittal of Supplemental Information E-mail Conservation Order 484 Confidential Exhibits located under expando in confidential room under CO 484 , Ii ~7 ¿'(:L'( ["t:/ rS2. ~/', é':5 \ ~ / " ;z;;. , ("J-:> , /,(7/' A g ? '-= 6'3. Z~ ,:J . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP ) Conservation Order No. 484 EXPLORATION (ALASKA) INC. ) for an order to establish pool rules) Prudhoe Bay Field for development of the Polaris Oil ) Polaris Oil Pool Pool, Prudhoe Bay Field, North) Slope, Alaska ) February 4, 2003 IT APPEARING THAT: 1. By letter dated September 12, 2002, BP Exploration (Alaska), Inc. ("BPXA") in its capacity as Polaris Operator and Unit Operator of the Prudhoe Bay Unit ("PBU") requested an order from the Alaska, Oil and Gas Conservation Commission ("Commission") to define a proposed Polaris Oil Pool within the PBU and to prescribe rules governing the development and operation of the pool. Concurrently, BPXA requested authorization for water and miscible gas injection to enhance recovery from the Polaris Oil Pool. 2. BPXA provided supplemental information at the Commission's request on October 31,2002. 3. By letter dated October 31,2002, BPXA amended its Polaris Oil Pool Rules and Area , Injection Order ("AIO") application and withdrew its request for approval of injection of miscible injectant as part of the current Enhanced Oil Recovery project. 4. Notice of a public hearing was published in the Anchorage Daily News on November 8, 2002. 5. The Commission held a public hearing December 9, 2002 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. 6. On December 18,2002 and January 22, 2003, BPXA submitted for the public record exhibits containing information previously submitted within confidential exhibits. Conservation Order 484 February 4, 2003 Page 2 FINDINGS: Proposed Polaris Oil Pool a. Operator: BPXA is the Operator of the proposed Polaris Oil Pool. b. Pool Area: The proposed Polaris Oil Pool is totally encompassed within the Prudhoe Bay Field. The area of the Polaris Oil Pool conforms to the Participating Area approved by the Department of Natural Resources, Division of Oil and Gas in the Polaris Participating Area Interim Decision dated May 11,2001. c. Wells Drilled: The proposed Polaris Oil Pool was discovered in 1969 with the drilling of the North Kuparuk State 26-12-12 exploratory well. Currently, 64 wells penetrate the Polaris structure, and 59 of those wells are hydrocarbon- bearing. BPXA utilized data from these wells in conjunction with a 3-D seismic survey to delineate the pool limits. d. Pool Definition: The proposed Polaris Oil Pool is an accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("MD") of 5,393 feet and 6,012 feet in the Prudhoe Bay Unit S-200PB1 well. The interval between 5,393 feet and 5,603 feet MD is known as the Ugnu Formation ("Ugnu"). The interval between 5,603 feet and 6,012 feet MD is known as the Schrader Bluff Formation ("Schrader Bluff'). e. Stratigraphy: The proposed Polaris Oil Pool encompasses reservoirs assigned to the Late Cretaceous-aged Schrader Bluff Formation and the Early Tertiary-aged Ugnu Formation. The Schrader Bluff is divided into two stratigraphic intervals that are designated, from deepest to shallowest, the "O-Sands" and the "N-Sands." The overlying Ugnu reservoir intervals proposed as part of the Polaris Oil Pool are informally termed the "M-Sands." The O- and N-Sand intervals were deposited in a marine shoreface and shallow shelf environment. M-Sand sediments were deposited in deltaic and fluvial environments. The O-Sands are divided into seven separate reservoir intervals that are named, from deepest to shallowest, OBf, OBe, OBd, OBc, OBb, OBa, and OA. Each of these intervals coarsens upward from non-reservoir, laminated muddy siltstone 'at the base to reservoir quality, thinly bedded sandstone at the top. The basal portion of the overlying N-Sands interval consists of non-reservoir mudstone and siltstone that forms a regionally extensive hydraulic barrier. This barrier separates lighter, higher quality oil in the O-Sands from heavier, more viscous oil in the overlying N- and M-Sand intervals. Mudstone and siltstone dominate the lower portion of the N-Sand interval, but the sediments coarsen upward, becoming the fine to medium-grained sand that is prevalent in the upper part of the interval. Three reservoir quality sands exist within the N-Sand interval. They are named, from deepest to shallowest, NC, NB, and NA. These sands are unconsolidated, thin, and generally extensive. The Ugnu M-Sands are divided into four reservoir intervals named, from deepest to shallowest, MC, MB2, MB1, and MA. The M-Sands interval consists of unconsolidated, clean sands separated by thin, but extensive, intervals of non- reservoir silty mudstone. These silty mudstones act as hydraulic barriers that 2' Conservation Order 484 ~ February 4, 2003 Page 3 go h. segregate individual hydrocarbon and water-bearing intervals within the M-Sands. MC sands are separated from the underlying NA sands by a 15- to 25-foot thick silty mudstone, which forms a regional seal. A 15- to 35-foot thick mudstone at the base of the MB2 interval forms a regionally continuous hydraulic barrier. A 9- to 15-foot thick silty mudstone overlies the uppermost MA sand and provides a second, regionally extensive upper seal. Structure: The proposed Polaris Oil Pool lies between approximately 4,800 and 5,300 feet true vertical depth subsea ("TVDss"). The Polaris structural dip ranges up to 4 degrees to the east and northeast, and it is broken by three sets of normal faults: one trending northwest, the second trending north, and the third trending west. These faults divide the structure into a series of reservoir compartments. The northwest- and north-trending faults are primary controls for oil distribution in the W-Pad, S-Pad and M-Pad areas, and they range in vertical displacement up to 200 feet. West-trending faults occur most commonly to the east and northeast in the down-dip portions of the pool, but they do trap oil in the center of the pool, near the Term Well C, near N-Pad, and along the southern margin of the pool. These faults range up to 100' in vertical displacement. Reservoir Compartments: Elements of each of the three major fault sets subdivide the Polaris Oil Pool into reservoir compartments. Six main compartments are currently recognized within the pool. They are, from north to south: SWI-Pad North, SLM-Pad Graben, SLM-Pad South, Horst Block, W-Pad \ Term Well C, and K 22-11-12. These compartments are shown on BPXA's Exhibit VIII-1 "Reservoir Static Pressure Acquisition Area Map" submitted December 18, 2002. Hydrocarbon Distribution: The primary reservoirs of the proposed Polaris Oil Pool lie in the O-Sands. Secondary oil accumulations occur in the N-Sands. The M-Sands also contain significant hydrocarbon accumulations, but oil in the M- Sands is biodegraded, making it dense (12 to 14 degrees API) and viscous. Oil distribution within the proposed Polaris Oil Pool is complex. Within the O- and N-Sands, ten hydrocarbon-bearing intervals are recognized. A single oil- water contact of-5226' TVDss was logged in the OBd sand in the W-201 well. Estimated oil-water contacts for the remaining intervals are currently placed at the structural spill points for each sand or at the midpoint between the shallowest water-up-to levels and the corresponding deepest oil-down-to levels observed on well logs. Oil distribution in the M-Sands of the Polaris Oil Pool is better defined because M-Sand oil-water contacts are concentrated in the crestal portions of the structure, where wells are most common. Different apparent oil-water contacts in different M-Sands suggest that each behaves as a separate reservoir unit. Conservation Order 484'{'' February 4, 2003 Page 4 . Rock and Fluid Properties a. Porosity/Permeability: Porosity and permeability values were measured by routine core analyses of core plugs from wells S-200PB 1 and W-200PB 1. b. Water Saturations: Water saturations were derived from air/brine capillary pressure analyses of cores from wells S-200PB 1 and W-200PB1. Relative permeability curves for the Polaris accumulation are based on core experiments and analogy to the nearby Schrader Bluff accumulation at Milne Point. c. Initial Reservoir Pressure: Average initial reservoir pressure is estimated to be 2180 psi at 5000' TVDss in the S-Pad area and 2240 psi at 5000' TVDss in the W-Pad area. Reservoir temperature is about 98 degrees Fahrenheit at this datum. d. Fluid PVT Data: Downhole reservoir PVT analyses were conducted on oil recovered from the OBd and OBe sand in well W-200, and from the OBd, OBb, OBa and OA sands in well S-200. Analyses show significant variations in fluid properties both horizontally and vertically. This may reflect varying levels of bio-degradation of the Polaris oil. Actual measurements from the downhole samples are provided on BPXA's Exhibit 11-3 "Polaris Fluid Properties". 3. Net Pay and Pool Limits go Pool Limits: The limits of the proposed Polaris Oil Pool are defined up-dip to the west and south by fault barriers, and down-dip to the north and east by the intersection of the each reservoir sand with the oil-water contact. bo Net Pay Methodology: Net pay thicknesses were derived using a petrophysical log model based upon well log and core data. Cut-off values of 6 millidarcies permeability and 55% water saturation were used to determine net pay within the pool. 4. Hydrocarbons in Place Based upon current well control and stratigraphic analysis, BPXA estimates oil in place in the proposed Polaris Oil Pool (excluding the MB and MA sands) between 350 million and 750 million stock tank barrels of oil ("stbo"). The large variation is primarily due to uncertainty in the oil-water contact and reservoir net pay interval thickness. Of this volume, 300 to 550 million stbo are estimated within the main target intervals, the O-Sands. The oil is undersaturated, containing between 84 and 250 billion standard cubic feet ("scf") of gas in solution (excluding MB and MA- Sands), with 75 to 195 billion scf attributable to expected oil production from the O- Sands. Conservation Order 484ll~ February 4, 2003 Page 5 5. Pilot Well Performance Pilot production from the proposed Polaris Oil Pool has been attempted in 7 wells: S- 200, S-201, S-213, S-216, W-200, W-201, and W-203. Stable production rates have been attained in wells S-200, S-213, W-200, W-201. Conversion to jet pump operation eliminated hydrate formation in wells S-201 and S-216. Allocated cumulative production through December 2002 is about 1.6 million bah'els of oil, 2.1 billion scf of gas, and 211,000 barrels of water. Average Polaris Oil Pool allocated production in December 2002 was 2,714 bopd, 578 bwpd, and 2,725 mscfd. The majority of the production is from W-Pad, with multi-lateral well W-203 contributing 1,206 bopd and, 1,021 mscfd. Bottomhole pressure measurements suggest W-Pad wells are above bubble point pressure (low of 1,733 psi at 5000' TVD in W-200 on 10/29/02). , Development Plans Reservoir models have been used to evaluate primary depletion, waterflood, and other enhanced recovery options for development of the proposed Polaris Oil Pool. Reservoir predictions are based on fine scale, three-dimensional black oil models using Polaris rock and fluid properties from wells S-200 and W-200. The models included the Schrader Bluff Formation O- and N-Sand intervals. The Ugnu M-Sand intervals have not been evaluated. Model studies performed to date within the developed area show about 5 to 10% recovery of OOIP under primary production and about 15 to 30% under waterflood (inclusive of primary). Initial development of the proposed Polaris Oil Pool is planned in three phases, beginning near the crests of the structure and progressively moving toward the outer margins of the pool. a. Phase I Development: Phase I development targets the O- and N-Sands in two fault blocks. Development of the S/M-Pad North Block includes a sidetrack of well S-200 and conversion to water injection to support production from well S-201. In the W-Pad \ Term Well-C Block, drilling of W-211 is underway and injection well. W-212i is proposed to support existing well W-200. In the K 22-11-12 Block, well W-203, a tri-lateral horizontal producer, is now on production. Additional offset injectors are planned in this area. b. Future Phases of Development: Phase II development targets down-dip areas with higher water saturation, greater structural complexity and higher-risk. Development of these areas is expected to require 12 to 20 addition producers and 9 to 15 injectors. Phase III may include development of extreme down- dip areas and higher risk fault blocks. c. Rate Estimate: Peak production rates are expected to be between 12,000 and 15,000 barrels of oil per day ("BOPD"). Waterflood injection rates are Conservation Order 484 { February 4, 2003 Page 6 do eo estimated to peak between 20,000 and 25,000 barrels of water per day ("BWPD"). Well Spacing: BPXA requests a minimum well spacing of 20 acres to allow for flexibility in well placement because of local faulting and reservoir stratigraphy. Reservoir Management Strategy: Expected producer to injection ratio is about 1.5 or 2 to one. Once water injection begins, voidage replacement ratio will be balanced and reservoir pressure will be maintained above the bubble-point. . Facilities Polaris wells will be drilled from existing S, M, and W-Pads. Production will be commingled with PBU Initial Participating Area ("IPA") fluids on the surface and will be processed at PBU Gathering Center 2 ("GC-2") to maximize use of existing IPA infrastructure, minimize environmental impacts, reduce costs, and maximize recovery. No modifications will be required at GC-2 to process Polaris production. An expansion of existing S-Pad to accommodate additional wells was completed in April 2000. Water for injection will be supplied through exiting IPA injection lines. Existing well test equipment will be utilized at S, M, and W-Pads. Gas lift or jet pumping is the plan for artificial lift. o Drillin~ Polaris development drilling is designed to utilize drilling procedures, well designs, and casing and cementing programs that conform to Commission regulations. Conductors will be spaced 1 $' apart. a. Conductor: A 16" or 20" conductor casing will be set 80 feet to 120 feet below pad level and cemented to surface. b. Surface Hole: In addition to the requirements of 20 AAC 25.030, surface casing will be set at least 500 feet TVD below the base of the permafrost. Because of the potential for coal and hydrate-related shallow gas, the requirements of 20 AAC 25.035 concerning the use of a diverter system and secondary well control equipment will be met. Conservation Order 484i February 4, 2003 Page 7 Ce d, eo Well Logs: Measurement while drilling ("MWD") and logging while drilling ("LWD") will typically begin at surface. MWD will include drilling parameters such as direction and inclination. LWD measurements will typically include ganuna ray ("GR") and resistivity logs throughout the reservoir section. Openhole electric logs may supplement or replace LWD logging when wellbore conditions allow their use. These openhole logs may include GR, resistivity, density, neutron porosity, and/or other tools. Drilling Fluids: Freshwater low solids, non-dispersed fluids will be used to drill the Schrader Bluff and Ugnu well sections. H2S Precautions: No significant H2S has been detected in any Polaris well drilled to date. However, because planned waterflood operations may generate H2S over the life of the field, H2S gas drilling practices will be followed. e Well Completion Design Horizontal, multi-lateral and conventional wells may be drilled at Polaris. The horizontal well sections may be completed with perforated casing, slotted liner, open- hole section, or a combination. All conventional wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8" to 5-1/2" depending upon the estimated production and injection rates, and will rely on premium alloys and corrosion inhibitors as needed. a. Surface Safety Valves: Surface safety valves ("SSV") are included in the wellhead equipment for all Polaris Oil Pool wells. b. Subsurface Safety Devices: BPXA requested that subsurface safety valves not be included because they are relatively low rate oil wells produced by artificial lift. All wells will be equipped with nipples below the permafrost should the need arise for installation of a storm choke or other downhole flow control device. BPXA intends to install such flow control devices if wells are utilized for gas or miscible gas injection c. Producers: Polaris producers will be completed in the Polaris Oil Pool only and will comply with AOGCC regulatory specifications. Artificial lift capability is designed intO each producing well. d. Injectors: Injection wells will have surface casing set below the base of the SV3 sand at about 2,800 feet TVD and cemented to surface. The longstring will be cemented from TD to above the highest significant hydrocarbon- bearing interval in the Ugnu section. Injectors may be completed to enable multi-pool injection where appropriate to the Schrader Bluff, Kupamk, Sag River and Ivishak Formations. Packers will be installed for zonal isolation in multi-pool injectors. Injection valves sized for water injection rate control Conservation Order 484 i February 4, 2003 Page 8 will be mn within mandrels between the packers. Spinner logs will be run to verify injection rates to the separate pools. Stimulation Methods: Fracture stimulation has been used successfully for Polaris producers and may be implemented to mitigate formation damage and stimulate future Polaris wells. Acid or other forms of stimulation may be performed. 10. Reservoir Surveillance Plans An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 5,000 feet TVDss. An initial static reservoir pressure will be measured on each regular production or injection service well. BPXA proposes to report data and results annually from all relevant reservoir pressure surveys and surveillance logs. A minimum of two pressure surveys will be taken each year in the main area S/M-Pad North and the W-Pad \ Term Well-C reservoir compartments. One reservoir pressure will be taken each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments. Spinner logs are planned on multi-pool injection well completions to assist in the allocation of flow splits as necessary. 11. Production Allocation PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 through August 2003, governs satellite production within the Western Operating Area of Prudhoe Bay Unit, including the Polaris Oil Pool. The GC-2 allocation factor is currently applied to adjust total Polaris production. CONCLUSIONS: 1. Pool Rules for the development of the Schrader Bluff Formation and the MC Ugnu Sand within the proposed Polaris Oil Pool are appropriate at this time. 2. The Polaris Oil Pool reservoir is compartmentalized and will require irregular spacing to optimize waterflood and recovery. Minimum well spacing of 20 acres is appropriate for efficient development of the pool. 3. The Polaris Oil Pool is in the early stages of development. Phase I development has focused upon determination of reservoir delivery and well operability. 4. Initial development is limited to the O- and N-Sands of the Polaris (Schrader Bluff Formation). No plan has been provided for development of the oil accumulations within the M-Sands (Ugnu Formation). Conservation Order 484~ February 4, 2003 Page 9 . o . o . Monitoring of reservoir performance on a regular basis will help ensure proper management of the pool. Annual reports and technical review meetings will keep the Commission apprised of reservoir performance results and will ensure that future development plans promote greater ultimate recovery. Water injection into the O- and N-Sands will preserve reservoir energy and increase ultimate recovery from the pool. Completion of water injectors to allow injection in multiple pools within one wellbore is appropriate so long as isolation of the pools is demonstrated and water injection is allocated between pools. Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate provided enhanced recovery operations maintain reservoir pressure above the bubble point pressure. PBU Western Satellite Production Metering Plan that governs allocation of production from the Western Operating Area of the PBU is appropriate for development of the Polaris Oil Pool. NOW, THEREFORE, IT IS ORDERED: 1. Pool Name, Classification, and Definition: The Polaris Pool is classified as an oil pool. This pool is defined as the accumulation of hydrocarbons common to, and correlating with, the intet~,al between 5,544 feet and 6,012 feet measured depth MD in well PBU S-200PB1. 2. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply 'to the following affected area: Umiat Meridian Township / Range Lease Sections T12N-R12E ADL 28256 Sec 22 S/2 S/2 and NE/4 SE/4 ADL 47448 Sec 23 S/2 NW/4 and SW/4 ADL 28257 Sec 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26,35,36 ADL 28258 Sec 27, 33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 ,__ T12N-R13E ADL 28279 Sec 31 SW/4 NW/4 and SW/4 T11N-R13E ADL 28282 Sec 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4, Sec 7 N/2 and N/2 SW/4 and SE/4 SW/4 and -~, Conservation Order 484 '( February 4, 2003 Page 10 SE/4, Sec 8 W/2 SW/4 T11N-R12E ADL 28260 Sec 1, 2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4 ADL 28261 Sec 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 N£/4 and SE/4, 10 ADL 28263-1 Sec 15, 16 E/2 ADL 28263-2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4 ADL 47451 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 ADL 28264 Sec 26 N/2 N/2 ADL 47452 Sec 27 NE/4 NE/4 Rule 1 Well Spacing Spacing units within the pool shall be a minimum of 20 acres. The Polaris Oil Pool shall not be opened in any well closer than 500' to an external boundary where ownership changes. Rule 2 Casing and Cementing Practices a. In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75' below the surface. b. In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' TVD below the base of the permafrost. Rule 3 Automatic Shut-in Eauioment a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of preventing an uncontrolled flow. b. All wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device. The Commission may require such installation by administrative action. c. Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems are in proper working condition. Rule 4 Common Production Facilities and Surface Comminglin~ Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer. Conservation Order 484''i, February 4, 2003 Page 11 Commission approval of the Prudhoe Bay Unit Western Satellite Production Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined at a hearing to be scheduled no later than July 31, 2003. Until superseded by Commission action, the following rules apply. a. All Polaris wells must use the GC-2 well allocation factor for oil, gas, and water. b. All wells must be tested a minimum of once per month. All new Polaris wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates. c. Technical meetings must be held quarterly to review progress of the implementation of the Western Satellite Production Metering Plan. d. The Operator must submit a monthly report (in printed and electronic form) including well tests and daily allocated production and allocation factors for the Pool. Rule 5 Reservoir Pressure Monitoring a. Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of two pressure surveys shall be taken each year in the main area S/M-Pad North and the W-Pad \ Term Well-C reservoir compartments, and one reservoir pressure each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments. c. The reservoir pressure datum will 'be 5000' TVDss. d. Pressure surveys may be stabilized static pressure measurements at bottom- hole or extrapolated from surface (single phase fluid conditions), pressure fall- off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 6 Gas-Oil Ratio Exemption Wells producing from the Polaris Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240(b) are met. Conservation Order 484{ February 4, 2003 Page 12 Rule 7 Enhanced Oil Recover3' or Reservoir Pressure Maintenance Operations Waterflood is required for purposes of pressure maintenance and enhanced oil recovery in strata correlative to PBU well S-200PB1 between the measured depths of 5,603 feet and 6,012 feet (within the Schrader Bluff Formation of the Polaris Oil Pool). Production and injection operations must ensure the reservoir pressure is maintained above 1,633 psi at the datum depth of 5000 feet TVDss. Rule 8 Multiple Completion of Water Iniection Wells a. Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of co-mingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 9 Annual Reservoir Review An annual report must be filed on or before April 1 of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. Voidage balance by month of produced, and injected fluids and cumulative status. b. Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool. c. Results and, where appropriate, analysis of production and injection surveys, tracer surveys, observation well surveys, and any other special monitoring. d. Review of pool production allocation factors and issues over the prior year. e. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation studies. By June 1 of each year, the Operator shall schedule and conduct a technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. The Commission may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans. Conservation Order 484 {' February 4, 2003 Page 13 Rule 10 Administrative Action Unless notice and public heating is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated February 4, 2003. Cammy Oec!~li Taylor, Chair Alaska Oil and Gas Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Michael L. Bill, P.E., Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaetion of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., l0th day after the application for reheating was filed). ALAS~ OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE ACTION NO. 457A.02 ADMINISTRATIVE ACTION NO. 471.02 ADMINISTRATIVE ACTION NO. 484.02 ADMINISTRATIVE ACTION NO 452.02 Mr. Gil Beuhler PBU Satellite Engineering Manager BP Exploration (Alaska) Inc. P. 0. Box 196612 Anchorage, AK 99519-6612 Re: PBU Western Satellite Production Metering Plan Amendment of Conservation Orders 457A, 471,484, and 452 Dear Mr. Beuhler: By letter dated April 23, 2002, BPXA requested approval of the Prudhoe Bay Unit Western Operating Metering Plan for allocation of production from satellite oil pools in the Western region of the Prudhoe Bay Unit. The Commission conditionally approved this plan for one year beginning August 1, 2002. Rule 4 of Conservation Order No. 471 for the Borealis Oil Pool, Conservation Order No. 457A for the Aurora Oil Pool, and Conservation Order No. 484 for the Polaris Oil Pool addresses the metering and allocation of production under this plan. Continued authorization of metering and allocation procedures was to be determined at a hearing to be scheduled no later than July 31, 2003. BPXA provided the Commission with a detailed metering and allocation procedures document on August 1, 2002. BPXA provided the Commission with a thorough review of the allocation performance of the Prudhoe Bay Unit Western Operating Metering Plan at technical meetings held on May 22 and June 5, 2003. In addition, well test and allocation information of all production flUids within the GC1 and GC2 areas were provided as required. The Commission finds that continued use of the Prudhoe Bay Unit Western Operating Metering Plan is appropriate and that a further hearing is unnecessary. In addition, the Commission finds that technical process review meetings, required by the Commission to take place quarterly, need only take place annually. Accordingly, the Conservation Orders 471, 457, 484,. and 452 are amended as follows. Borealis Oil Pool {CO 471)~ Aurora Oil Pool {CO 457A) and Polaris Oil Pool (CO 484) AUG g ,1 21]D3 Mr. Gil Buehler August 11, 2003 Page 2 of 2 Rule 4 of Conservation Orders Nos. 471,457A, and 484 is amended to provide that approval of the Prudhoe Bay Unit Western Operating Metering Plan is permanent. Rule 4 of Conservation Orders Nos. 471,457A, and 484 is amended to require technical process review meetings to be held at least annually. Midnight Sun Oil Pool (CO 452) Rule 7 of Conservation Order No 452 ("CO 452"), approved November 15, 2000, requires revision to conform to the allocation procedures of the approved Prudhoe Bay Unit Western Operating Metering Plan, and is amended as follows: CO 452 - Rule 7 Common Production Facilities and Surface Commingline ao bo co do eo Production from the Midnight Sun Oil Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan - Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Midnight Sun Wells. All Midnight Sun wells must use the Gathering Center 1 well allocation factor for oil, gas, and water. All wells must be tested a minimum of once per month. All new Midnight Sun wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates. Technical process review meetings shall be held at least annually. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. DATED at Anchorage, Alaska, nunc pro tune August 1 1, 2003. Chair BY ORDER OF THE COMMISSION DATED August 19, 2003 Randy drich Commissioner ~' o ~ :¢~ '~, .,.' '.'- · ',.:.ii.;..':.' ,.,.~ ALASKA OIL AND GAS CONSI~RVA~ION COMMISSIO1V ADMINISTRATIVE ACTION NO. 457A.01 ADMINISTRATIVE ACTION NO. 471.01 ADMINISTRATIVE ACTION NO. 484.01 ADMINISTRATIVE ACTION NO 452.01 FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'~ AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Gil Buehler PBU Satellite Engineering Manager BP Exploration (Alaska) Inc. P. 0. Box 196612 Anchorage, AK 99519-6612 Re: PBU Western Satellite Production Metering Plan Amendment of Conservation Orders 457A, 471,484, and 452 Dear Mr. Beuhler: By letter dated April 23, 2002, BPXA requested approval of the Prudhoe Bay Unit Western Operating Metering Plan for allocation of production from satellite oil pools in the Western region of the Prudhoe Bay Unit. The Commission conditionally approved this plan for one year beginning August 1, 2002. Rule 4 of Conservation Order No. 471 for the Borealis Oil Pool, Conservation Order No. 457A for the Aurora Oil Pool, and Conservation Order No. 484 for the Polaris Oil Pool addresses the metering and allocation of production under this plan. Continued authorization of metering and allocation procedures was to be determined at a hearing to be scheduled no later than July 31, 2003. BPXA provided the Commission with a detailed metering and allocation procedures docUment on August 1, 2002. BPXA provided the Commission with a thorough review of the allocation performance of the Prudhoe Bay Unit Western Operating Metering Plan at technical meetings held on May 22 and June 5, 2003. In addition, well test and allocation information of all production fluids within the GC 1 and GC2 areas were provided as required. The Commission finds that continued use of the Prudhoe Bay Unit Western Operating Metering Plan is appropriate and that a further hearing is unnecessary. In addition, the Commission finds that technical process review meetings, required by the Commission to take place quarterly, need only take place annually. Accordingly, the Conservation Orders 471, 457, 484, and 452 are amended as follows. Borealis Oil Pool (CO 471)~ Aurora Oil Pool (CO 457A) and Polaris Oil Pool (CO 484) Mr. Gil Buehler August 11, 2003 Page 2 of 2 Rule 4 of Conservation Orders Nos. 471,457A, and 484 is amended to provide that approval of the Prudhoe Bay Unit Western Operating Metering Plan is permanent. Rule 4 of Conservation Orders Nos. 471,457A, and 484 is amended to require technical process review meetings to be held at least annually. Midnight Sun Oil Pool {CO 452) Rule 7 of Conservation Order No 452 ("CO 452"), approved November 15, 2000, requires revision to conform to the allocation procedures of the approved Prudhoe Bay Unit Western Operating Metering Plan, and is amended as follows: CO 452 - Rule 7 Common Production Facilities and Surface Commingling bo C. do Production from the Midnight Sun Oil Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 and detailed within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan- Policies and Procedures Document" dated August 1, 2002 is approved for allocation of production from Midnight Sun Wells. All Midnight Sun wells must use the Gathering Center 1 well allocation factor for oil, gas, and water. All wells must be tested a minimum of once per month. All new Midnight Sun wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates. Technical process review meetings shall be held at least annually. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. DATED at Anchorage, Alaska and dated August 11, 2003. ~ Palin ~k Daniel ~./Seamount, Jr. Chair/ \~J Commissioner BY ORDER OF THE COMMISSION John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Alfred James 200 West Douglas, Ste 525 Wichita, KS 67202 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 W. Allen Huckabay ConocoPhillips Petroleum Company Offshore West Africa Exploration 600 North Dairy Ashford Houston, TX 77079-1175 T.E. Alford ExxonMobil Exploration Company PO Box 4778 Houston, TX 77210.4778 Corry Woolington ChevronTexaco Land-Alaska PO Box 36366 Houston, TX 77236 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 James White Intrepid Prod. Co./Alaskan Crude 4614 Bohill SanAntonio, TX 78217 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oilln~rmation Se~ice, lnc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Julie Houle State of Alaskan DNR Div of Oil & Gas, Resource Eval. 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Robert Mintz State of Alaska Department of Law 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Duane Vaagen Fairweather 715 L Street, Ste 7 Anchorage, AK 99501 Jim Arlington Forest Oil 310 K Street, Ste 700 Anchorage, AK 99501 Tim Ryherd State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Williams VanDyke State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Cammy Taylor 1333 West 11th Ave. Anchorage, AK 99501 Richard Mount State of Alaska Department of Revenue 500 West 7th Ave., Ste 500 Anchorage, AK 99501 Ed Jones Aurora Gas, LLC Vice President 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Susan Hill State of Alaska, ADEC EH 555 Cordova Street Anchorage, AK 99501 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 John Harris NI Energy Development Tubular 3301 C Street, Ste 208 Anchorage, AK 99503 Rob Crotty CIO CH2M HILL 301 West Nothern Lights Blvd Anchorage, AK 99503 Jack Laasch Natchiq Vice President Government Affairs 3900 C Street, Ste 701 Anchorage, AK 99503 Mark Dalton HDR Alaska 2525 C Street, Ste 305 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Mark Hanley Anadarko 3201C Street, Ste 603 Anchorage, AK 99503 Judy Brady Alaska Oil & Gas Associates 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503-2035 Aden Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Bill Bocast PACE Local 8-369 cio BPX North Slope, Mailstop P-8 PO Box 196612 Anchorage, AK 99519 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,Inc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw- MS 575 Anchorage, AK 99515 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Dudley Platt D.A. Platt & Associates 9852 Little Diomede Ct. Eagle River, AK 99577 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Shannon Donnelly Phillips Alaska, Inc. HEST-Enviromental PO Box 66 Kenai, AK 99611 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 Penny Vadla Box 467 Ninilchik, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 John Tanlgawa Evergreen Well Service Company PO Box 871845 Wasllla, AK 99687 Claire Caldes US Fish & Wildlife Service Kenal Refuge PO Box 2139 Soldotna, AK 99669 Charles Boddy Uslbelll Coal Mine, Inc. 100 Cushman Street, Suite 210 Fairbanks, AK 99701-4659 Kenal National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Richard Wagner PO Box 60868 ' Fairbanks, AK 99706 Cliff Burglln PO Box 131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 Lt Governor Loren Leman State of Alaska PO Box 110015 Juneau, AK 99811-0015 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 Bernie Kad K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Kurt Olson State of Alaska Staff to Senator Tom Wagoner State Capitol Rm 427 Juneau, AK 99801 #11 [Fwd: Polaris Area Injection Order Information] t" Subject: [Fwd: Polaris Area Injection Order Information] Date: Thu, 23 Jan 2003 14:30:46 -0900 From: Jane Williamson <Jane_Williamson~admin.state.ak.us> To: Jody J Colombie <jody_colombie~admin.state.ak.us> CC: Stephen F Davies <steve_davies~admin.state.ak.us>, Camille O Taylor <cammy_taylor~admin.state.ak.us> Jody, Please put this in the Polaris Area Injection Order file. Jane Subject: Date: From: To: CC: Polaris Area Injection Order Information Wed, 22 Jan 2003 17:44:55 -0600 "Schmohr, Donn R" <SchmohDR@BP.com> '"Jane_Williamson@admin.state.ak.us'" <Jane_Williamson@admin. state.ak.us> "Rodgers, James T (Phillips)" <jtrodge@ppco.com>, "Jacobsen, Rosanne M" <JacobsRM~BP.com>, "Von Tish, Douglas B" <VonTisDB~BP.com>, "Bemaski, Greg E" <BemasGE~BP.com>, "Beuhler, Gil G" <BeuhleGG~BP.com>, "Smith, Russell" <SmithR8~BP.com>, "':jeff. e. farr~exxonmobil.com'" <:jeff. e. farr@exxonmobil.com>, "'Steve_Davies@admin.state.ak.us'" <Steve_Davies~admin.state.ak.us>, "Gustafson, Gary G" <GustafGG~BP.com> Jane, The following is in response to your request for some additional information regarding shale (mud stone) thickness' in each of the injection wells mentioned in the Polaris Area Injection Order Application. We understand that this information may be used in the AIO and is not considered confidential. Listed below are shale thicknesses from the two main shales which lie at or near the top of the Polaris Pool in the Polaris proposed injection wells - S-200, S-215, W-207 (not drilled yet) and W-212. The list below includes a shale which overlies the Ma sand at the top of the Polaris Pool, and a basal Mb2 shale which lies 120 to 150' below the top of the Polaris Pool. Well Lower Mb2 Thickness Shale above Ma Thickness S-200 14' 10' S-215 23' 9' W-207 25'* 15'* W-212 18' 11' * - Note: well W-207 has been proposed but has not been drilled; W-207 shale thicknesses are taken from the nearest offset well K241112 located -600' feet to the northeast of W-207 location. Please let us know if you require any additional information. Thank you, Dorm Schmohr bp Alaska Polaris Sr. Petroleum Engineer 1 of I 1/24/2003 9:22 AM #10 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, ALaska 995196612 (907) 561-5111 December 18, 2002 BY U.S. MAIL Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Polaris Pool Rules and Area Injection Order Supplemental Information . 4oefiora~ C°mmiSsior Dear Commissioners: We would like to provide the Commission with the attached supplemental information, "Reservoir Static Pressure Acquisition Area Map" (Exhibit VIII- 1). We understand this Map may be placed in the public domain and used to better define the static pressure acquisition requirements as defined in our September 12, 2002 Polaris Pool Rules and Area Injection Order Application(Rule 7, Page 54). Sincerely, Gil Beuhler GPB Satellites Team Leader Cc: R. Smith (BP) M.M. Vela (Exxon/Mobil) J.P. Johnson (ConocoPhillips) S. Wright (Chevron Texaco) P. White (Forest Oil) P~,aris Pool/Injection Ar~,~ Reservoir Static Pressure Acquisition Area Map Minimum One (1 Static Pressure per Annum \ I Minimum Two (2) Minimum One (1) Static Pressures Static Pressure -- per Annum per Annum / ' . U-02 J -5257 ', 1~ \. Minimum One (1 Static Pressure perAnnum Minimum One (1 Static Pressure per Annum Schrader Bluff reServoir static pressure acquisition areas. · ~/-200J Polaris Production Well ~) ,JK221112J Key Regional Polaris Definition Well Exhibit VIII-1 Polaris Pool and Proposed Participating Area Boundary #9 bp December 13, 2002 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 BY FAX AND U.S. MAIL Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED RE: Polaris Pool Rules and Area Injection Order Application Confidentiality of Exhibits 1-6 and 1-7 Dear Commissioners: !'" ':.C 13 2002 ~laska Oi~ r~ qa, Cons. Commission At the hearing on December 9, 2002, you asked if the applicants consider Exhibits 1-6 and 1-7 to the Polaris Pool Rules and Area Injection Order Application ("Application") to be confidential because the exhibits contain trade secrets. The answer is "yes," the Polaris Owners do consider Exhibits 1-6 and 1-7 to be confidential because they contain trade secrets. AS 45.50.940(3) provides that information qualifies as a trade secret if it "(A) derives independent economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use, and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy." These exhibits include interpretations of geological and geophysical data, including reservoir compartments and polygons, reservoir characteristics, faults, structure and isopach maps, and the like, from which the Polaris Owners derive independent economic value. These exhibits also reflect our use and application of the information, which provides us with a competitive advantage over others who do not have it. This information is not generally known to or ascertainable by other persons, and other persons would obtain economic value from it. The Polaris Owners take significant and reasonable measures to maintain its secrecy. For these reasons, the exhibits are required to be held confidential by the Commission. In addition, as you know, the Polaris Owners also consider these exhibits to be confidential because they contain engineering, geological and other information that is being voluntarily provided to the Commission that is not required to be provided under AS 31.05.035(a). Therefore, these exhibits must also be held confidential under AS 31.05.035(d). We are somewhat at a loss about why the Commission is requesting this further explanation. We are unaware of any request for public disclosure of these exhibits, and there was no adverse party at the hearing, thus completely obviating any due process basis for disclosure. Moreover, in our view these two exhibits go above and beyond what the Commission needs to rule on the application. Therefore, we question the basis and procedure for any action by the Commission relating to the confidentiality of these exhibits in the present context. Consequently, if the Commission is considering issuing an order making these exhibits public, please let us know, for we may wish to withdraw them from the application. We understand that, with the submission of this letter, the AOGCC will consider the record to be closed. Sincerely, Gil Beuhler GPB Satellites Team Leader Cci R. Smith (BP) M.M. Vela (Exxon/Mobil) J.P. Johnson (ConocoPhillips) S. Wright (Chevron Texaco) P. White (Forest Oil) #8 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: Application by BP Exploration For Polaris Pool Rules and an Area Injection Order. TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska December 9, 2002 9:00 o'clock a.m. COMMISSIONERS: CAMMY OECHSLI TAYLOR, DAN SEAMOUNT MIKE BILL Chairperson RECEIVED DEC 1 3 2002 ~ Oil & Gas Cons uommisslon Anchoraoe METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 i m~ ,%, 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 P R O C E E D I N G S (On record) CHAIR TAYLOR: Good morning, I'd like to call this hearing to order. Today is Tuesday, December 9th, 2002. The time is approximately 10 minutes after 9:00. We're at the AOGCC offices at 333 West Seventh, Suite 100. The subject of the hearing today is BP's application for Polaris Pool Rules and Area Injection Order. I would like to introduce to my left Commissioner Mike Bill, to my right Commissioner Dan Seamount. My name is Cammy Taylor. To my very far right is Julie Gonzales, she is here from Metro Court Reporting. This will be recorded and transcribed. Anybody wishing to secure a copy of that transcript may do so directly through Metro Court Reporting. The notice of the public hearing was published in the Anchorage Daily News on November 8th, 2002. We will conduct these proceedings today in accordance with our regulations, 20 AAC 25.540. We would like the applicant to present testimony first. If there are any others wishing to present testimony, we'll hear from them after that. We would ask that all persons wishing to testify be sworn and that each witness state their name and if they would spell it for the record so that it can be transcribed correctly. If you'd identify who you represent. Any person wishing to provide expert testimony today, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-$876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 we will ask that you state your qualifications and the Commission will make a determination about your qualifications and for what field you're wishing to be sworn as an expert. Any persons wishing to make an unsworn statement, we'll take those after all of the testimony is taken today. We also ask that if persons in the audience have questions, they not direct questions directly to the witnesses, but if you would write them down, state the question, your name, and who you would like the question directed to, you may give that piece of paper to one of the Commission members. And we have four people, I think, sitting in the audience who could take those. If you would just raise your hands. If you want to have a question passed to them, they will make sure that it comes up to the front. The Commission will review them and make a determination about asking the question. We would like to invite the applicant to introduce themselves and proceed with their presentation today. MR. BEUHLER: Thank you. Good morning, thank you for your time today. My name is Gil Beuhler. My surname is spelled B-e-u-h-l-e-r. I am the Greater Prudhoe Bay satellite resource manager for BP Exploration Alaska. I received a Bachelor of Science Degree in Petroleum Engineering from the University of Kansas in 1983. CHAIR TAYLOR: Mr. Beuhler, could I interrupt you for just a second? Do you want to go ahead and proceed with your METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 testimony and your sworn statement at this time? MR. BEUHLER: Yes, ma'am. CHAIR TAYLOR: Why don't I swear you in. (Oath administered) MR. BEUHLER: I do. CHAIR TAYLOR: Thank you. MR. BEUHLER: Thank you. I've worked in the oil industry for over 19 years with a variety of experience in the Lower 48 and Alaska. I've been in Alaska since 1997 and have been with BP since 1998. I joined the Greater Prudhoe Bay satellite team in 1998 and I have testified as an expert witness in Texas before the Railroad Commission, in New Mexico before the New Mexico Oil Conservation Division, and in Alaska before this Commission at the Borealis Pool Rules Hearing. And I would like to be acknowledged today as an expert witness. CHAIR TAYLOR: Commissioner Bill, do you have any questions or any objections? COMMISSIONER BILL: No questions, no objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: I have no questions nor objections. CHAIR TAYLOR: You can proceed with your testimony as an expert witness. MR. BEUHLER: Okay, thank you. We have prepared the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3s76 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Polaris Pool Rules and Area Injection Order application submitted on September 12, 2002, and revised as of this date, October 31st of 2002, and we ask that the Commission enter in its entirety this application into the record. CHAIR TAYLOR: The Commission will do so. MR. BEUHLER: Thank you. And for the purposes of this hearing, we offer excerpts from that application, if it pleases the Commission. Thank you. And the first section, entitled geology, will be presented by Greg Bernaski. CHAIR TAYLOR: Greg, do you wish to be sworn in as an expert witness today? MR. BERNASKI: I do. CHAIR TAYLOR: Would you raise your right hand, please? (Oath administered) MR. BERNASKI: I do. CHAIR TAYLOR: And you wish to be sworn as an expert in the field of petroleum geology? MR. BERNASKI: Yes. CHAIR TAYLOR: Please proceed. MR. BERNASKI: My name is Greg Bernaski. My surname is spelled B-e-r-n-a-s-k-i. I am a geologist with BP Exploration Alaska. I received a Bachelor of Science degree and a Master of Science degree in geology from the University of Wyoming. I've been employed as a geologist by BP, and the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-$876 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Sohio Petroleum Company, for 17 years. I've worked on a variety of Alaskan projects since 1993, including Prudhoe Bay, Ivishak, and Sag River reservoirs, and the Polaris and Orion Schrader Bluff reservoirs. I've been working with the Greater Prudhoe Bay satellites team since December, 1998. Prior to joining BP in Alaska, I worked on deep water field appraisal and development projects for BP in the Gulf of Mexico. I would like to be acknowledged today as an expert witness in geology. CHAIR TAYLOR: Commissioner Bill, do you have any questions? COMMISSIONER BILL: No questions nor objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: No questions, no objections. CHAIR TAYLOR: We'll consider you an expert witness for your testimony today. Go ahead and proceed. MR. BERNASKI: Thank you. The area for which the Polaris Pool Rules are proposed is located within the Prudhoe Bay Unit, or PBU, on Alaska's North Slope, as illustrated in Exhibit I-1. The Polaris Pool overlies the PBU Sadlerochit reservoir in the vicinity of PBU S, M and W Pads and overlies the Aurora Pool Kuparuk River formation reservoir in the vicinity of PBU S Pad. The reservoir interval for the Polaris Pool is the Schrader Bluff and the lower Ugnu formations. Within the Polaris Pool, the Schrader Bluff and lower Ugnu METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 formations are divided into 14 distinct sand units encompassed by the O and N intervals, 0 sand intervals of the Schrader Bluff, and the M sand interval of the lower Ugnu. The North Kuparuk state 26-12-12 well, drilled in 1969, was the first well to penetrate and log hydrocarbons in the Polaris Pool. Since 1969, the Polaris Pool interval has been logged in 64 Schrader Bluff penetrations in PBU Ivishak, Kuparuk, and Schrader Bluff development and appraisal wells in the Polaris Pool area. Polaris Pool hydrocarbon presence is recognized from log data from 59 Polaris Pool wells which have at least gamma ray and resistivity log data. Exhibit I-2 shows the location of the Polaris Pool area. Exhibit I-2 also shows that the boundaries of the Polaris Pool area coincide with the boundaries of the Polaris Participating area. Two boundaries are the same. The Polaris Pool hydrocarbon accumulation is bounded by faults on the updip west and south sides and by dip closure into the regional aquifer on the north and the east side. As shown on the Schrader Bluff structure map in Exhibit I-3, the Polaris pool -- excuse me, the Polaris structure crests at W Pad in the southwest Polaris Pool region, minus 4800 feet TVD subsea at the mid Schrader Bluff OA mapping horizon, and trends down dip to the north and to the east through faulting and regional dip. North-south, east-west, and northwest-southeast trending faults subdivide METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 the Schrader Bluff reservoir into discrete high-standing and low-standing fault blocks within the Polaris Pool area. Sealing faults are predicted in the Schrader Bluff reservoir based on the prevalent low net to gross reservoir lithologies. At this point, I'll make a comment on a matter of procedure. The Polaris Pool Rule document contains a number of confidential exhibits. We will refer to these exhibits during the course of our testimony, but do not intend to display them on the overhead projector. For your reference, these confidential exhibits do exist in the Polaris Pool Rules copy which I believe each of the Commissioners has in front of you. So we'll proceed in that fashion. Confidential Exhibit I-4 shows the Polaris Pool fluid limits in relation to regional structure features along a cross section line connecting the W and S Pad areas. Based on differences in rock quality and potential spill points for the various sand units, it is believed that oil-water contacts vary by depth -- excuse me, contact depths vary by sand unit and by fault block within the Polaris Pool. Ail current Polaris Pool production is from the N and 0 sands at S Pad, and from the OB sands only at W Pad. Exhibit I-5 shows the open-hole wireline log character of the Schrader Bluff and lower Ugnu M, N, and O sands in a type log from the S-200PB1 well and illustrates the vertical stratigraphic extent of the Polaris Pool. As shown in Exhibit METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 8 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 I-5, the Polaris Pool M, N, and 0 sands are further subdivided into seven O sands, three N sands, and four M sands. The O, N, and M sand intervals are present across the entire Polaris Pool area and, as a package, thin slightly from southwest -- south-southwest to north-northeast across the Polaris Pool area. Reservoir quality sand units within each interval are regionally extensive but can be locally characterized by substantial thickness and net to gross variations between wells spaced less than 1000 feet apart. The contact between the basal Schrader Bluff O sands and the underlying Colville section is gradational from the Colville mudstones to the basal Schrader Bluff low permeability sands. Colville mudstones and muddy siltstones, ranging up to 1100 feet thick at Polaris, form the basal confining unit of the Polaris Pool. The top of the Ugnu M sand interval is characterized by an upward gradation from a silty fining upward Ma sands to a regionally continuous 10 to 25 foot thick mudstone which isolates the M sands from overlying fluvial Ugnu sands. This upper mudstone forms the upper confining layer of the Polaris Pool. The lowermost Polaris Pool unit, the Schrader Bluff O sand interval, forms the primary development target in the Polaris Pool and is subdivided into seven -- seven separate reservoir horizons, from deepest to shallowest, the OBf, the OBe, the OBd, OBc, OBb, OBa, and OA. The total 0 sand METRO COURT REPORTING, I.NC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 10 interval thickness ranges from 300 to 340 feet at Polaris. In general, each of the 0 sand intervals clean upward from basal non-reservoir laminated muddy siltstone to reservoir quality laminated and thin-bedded sand units at the top. The Polaris Pool N sand interval overlies the O sand interval and ranges between 100 and 160 feet thick in the Polaris Pool area. Polaris Pool N sands are subdivided into three reservoir units, from deepest to shallowest, Nc, Nb, and Na. The N sand interval consists mainly of non-reservoir muds and siltstones interbedded with a limited number of thin, but generally extensive, unconsolidated reservoir sands. Thick, regionally extensive mudstones within the lowermost N sand interval form an important regional vertical barrier which segregates the lighter, higher quality oil in the 0 sands from -- from heavy oil and extensive wet sands in the N and the M sand interval. The Polaris Pool M sand interval overlies the N interval and ranges between 180 and'250 feet thick in the Polaris Pool area. Polaris Pool M sands are subdivided into four reservoir units, from deepest to shallowest Mc, Mb2, Mbl, and Ma. The M sand interval consists of very high quality unconsolidated clean sands separated by generally thin, but extensive non-reservoir mudstone units. Mudstones within the M sand interval vertically separate individual hydrocarbon and METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 11 water-bearing M sand units, even in highest net to gross units, and provide competent top seals to the Polaris Pool development interval. M sand hydrocarbons consist of heavy, biodegraded crude, 12 to 14 degree API gravity, based on fluids extracted from sidewall and conventional core plug samples. To date, no M sand production has been attempted and no M sand downhole oil sampling has been successful. Schrader Bluff formation Structure. Exhibit I-3 is a structure map on the top of the Schrader Bluff OA sand in the Polaris Pool area, with a contour interval of 20 feet. Although the Schrader Bluff interval generally dips eastward and northward at gentle dips of 0 to 4 degrees in the western portion of the Prudhoe Bay unit, it is -- it is broken up into a series of distinct fault blocks, as indicated by 3D seismic data. The structural character of the Schrader -- at the Schrader Bluff level in the vicinity of the Polaris Pool is dominated by three different fault trends. Northwest- southeast, north-south, and east-west. Structure in the S Pad and M Pad area consists of a complexly faulted structural high, which plunges to the southeast, where it is truncated by a large east-west fault near M Pad -- N Pad, sorry. The structure is dominated by northwest-southeast striking pair of antithetic faults which intersect a large north-south trending, west-dipping fault system. The northwest-southeast antithetic pair subdivides METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 12 the S and M Pad structure into three major fault -- three major fault sub-blocks. A crestal area and northeast-dipping flank, with S-200 and S-201 in the fault block. A crestal graben located between the two northwest-southeast faults, which runs from just south of the S Pad surface location to just south of the M Pad surface location. A fault-bounded structural high south of the graben, with development wells S- 213 and S-216 situated in the third fault block. Term Well C Area. Term Well C, or TW-C, is located in a saddle downdip from the structural high at W Pad to the south, and down thrown by faulting from the southern S and M Pad fault block. A long, north-south fault lies to the west. TW-C appears to be separated from the V-200 fault block by small offset faults, some of which are inferred from fluid contact data. A fault system separates the Term Well C block from the southern S Pad' fault block. The structural trap at W Pad is formed by the intersection of a major northwest-southeast oriented fault with a large-offset north-south trending fault system, with dip closure to the east and north -- northeast. The downdip extent of the structural closure to the southeast is dependent up the juxtaposition of several sand intervals across, and clay smearing along a small east-west trending fault. The W Pad trap appears to be less intensely faulted than the $ and the M Pad areas. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 13 Reservoir compartments. Elements of each of the major area fault systems were used to subdivide the Polaris Pool into reservoir compartments for development planning purposes. The location and areal extent of these reservoir compartments is marked by the polygon boundaries shown in Confidential Exhibit I-7. Each compartment was defined along mapped fault trends and was assumed to be hydraulically isolated by sealing faults from adjacent compartments. The sealing character of the faults forming the compartment boundaries is inferred from both limited fluid contact and pressure data at Polaris, and from analog studies which show a high probability of clay smear seals forming along faults in the Polaris low net to gross reservoirs. Polygon nomenclature is summarized below. S and M Pad North, S and M Pad Graben, S and M Pad south, W Pad slash Term Well C polygon, K 22-11-12 polygon, and the Horst Block polygon. Confidential Exhibits I-8 and I-9 show the depths of the interpreted oil/water contacts, or OWCs, in the M, N, and O sands in the Polaris Pool in the S and M and W Pad areas. M sand oil-water contacts are relatively well defined by existing well control. N and O sand oil-water contacts are less well defined due to the lack of well control in down structure areas. No gas/oil contacts have been logged in any Polaris sand nor is the presence of free gas in the Polaris Pool -- any of the Polaris Pool intervals predicted from oil METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 PVT test results. Each sand in the Polaris N and 0 interval was assumed to be vertically isolated from overlying and underlying sand sands and was assumed to have a different associated oil-water contact depth. 14 The N and 0 sand expected case oil column heights at S and M Pad range between 210 feet at the OBf to 290 feet at the Nc interval. W Pad expected case oil column heights range from 35 feet in the OA sands to 290 feet in the OBc sands. In contrast to the minimal number of Polaris N and O sand fluid contacts logged, Mb and Mc oil-water contacts have been logged in numerous wells in the S, M, and W Pad areas. Ma sand oil- water contacts have not been logged in any Polaris well. Similar to the Polaris N and 0 sand intervals, M sand oil- water contact levels logged in different M sand intervals indicate that each sand behaves as a separate reservoir unit. The limits of the Polaris Pool are defined by updip fault boundaries and downdip at the zero foot limits of M, N, and O sand expected case net pay. Polaris is bounded on the west and south by northwest and northwest-southeast faults where the reservoir is juxtaposed against impermeable silts and mudstones of the upper Schrader Bluff formation and the overlying Ugnu. To the east and north, the Polaris Pool limit is defined by the downdip intersection of the top of the reservoir with the expected case O, N, and M sand oil-water contacts. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 15 Confidential Exhibits 1-10, 1-11, and 1-12 show the location of the proposed Polaris Pool Rules area in relation to the Polaris Pool fault boundaries and expected case limits of O, N, and M sand net pay. Confidential Exhibit 1-10 is a Polaris Pool composite 0 sand net pay map showing the combined thickness and extent of the Polaris area OA through OBf sand net pays in relation to the proposed Pool Rule and participating area boundary. This map has a contour interval of 10 feet. Confidential Exhibit 1-11 is a Polaris Pool composite N sand net pay map showing the combined Na through Nc sand net pay thickness, with a contour interval of five feet. Confidential Exhibit 1-12 is a Polaris Pool composite M sand net pay map showing the combined Ma through Mc sand net pay thickness, with a contour interval of 10 feet. Confidential Exhibits 1-13, 1-14, and 1-15 show the limits of the Polaris Pool Rule area in relation to the O, N, and M sand oil pore-foot thickness contours, respectively. Similar to the net pay maps in Confidential Exhibits 1-10 through 1-12, the O, N, and M oil pore-foot thickness maps represent the combined oil pore-foot thickness for all of the 0 sands, in Confidential Exhibit 1-13, all of the N sands, Confidential Exhibit 1-14, and all of the M sands, Confidential Exhibit 1-15. This concludes my testimony. CHAIR TAYLOR: Commissioner Seamount, do you have any METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 16 questions? COMMISSIONER SEAMOUNT: Not at this time. CHAIR TAYLOR: Commissioner Bill, do you have any questions? COMMISSIONER BILL: Not at this time. CHAIR TAYLOR: Thank you. Raise your right hand. (Oath administered) MR. REINTS: I do. CHAIR TAYLOR: Would you please proceed, identify yourself by name and spell your last name for the court reporter, please. MR. REINTS: My name is Rydell Reints. That's spelled -- my surname is spelled R-e-i-n-t-s. I am a reservoir engineer for BP Alaska, Inc., working as a reservoir engineer for the Polaris development project. I received a Bachelor of Science Degree in petroleum engineering from the Montana College of Mineral Science and Technology, or Montana Tech, in 1988. In that year I joined ARCO Alaska, which was later acquired by BP. I worked as operations engineer, both field- based and town-based, in Prudhoe Bay. In May of '95 I began my career as a reservoir engineer and have worked on -- as a reservoir engineer on a variety of Alaska projects, including Prudhoe Bay, Midnight 'Sun, Borealis, Polaris, and Orion fields. I have been working in the Greater Prudhoe Bay satellites team since April of 1998. I would like to be METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 17 acknowledged today as an expert witness in reservoir engineering. CHAIR TAYLOR: Commissioner Bill, do you have any questions or any objections? COMMISSIONER BILL: No questions, no objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: No questions, no objections. CHAIR TAYLOR: We'll accept you as an expert witness in reservoir engineering. Please proceed. MR. REINTS: Reservoir management and developed scenarios for Polaris have been evaluated using pattern and partial field reservoir simulation models. Analysis of well spacing and pattern configuration were performed with the simulation models to identify well locations. Evaluations of Polaris using the Polaris log model and reservoir simulation models have identified water flooding as a viable development option. Low recovery estimates for primary depletion are influenced by low solution gas oil ratio, low initial reservoir pressure, and viscous oil. Porosity and permeability values were measured by routine core analysis from S-200PB1 and W-200PB1. Confidential Exhibit II-1 shows values for porosity and horizontal permeability by zone that were used in the reservoir simulation model. Water saturations were characterized using a Leverett METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Azzchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 18 J-function to capture the variations in water saturation with variations in porosity and permeability. Each interval was assumed to have a separate oil/water contact. The contacts were varied in the model to represent various structural locations within the reservoir. Relative permeability curves for the Polaris accumulation are based on unsteady state relative permeability experiments on S-200PB1 and W-200PB1 core. The range of results was narrowed to a single curve that is nearly identical to the curve used to model the Schrader Bluff Pool in the Milne Point Unit. Confidential Exhibit II-2 shows the relative permeability curve used in the reservoir simulation. Initial reservoir pressure is somewhat Variable. Average initial reservoir pressure is estimated at 2,180 psi at 5,000 feet TVD subsea in the S Pad area, and 2,240 psi at 5000 feet TVD in the W Pad area. Reservoir temperature is approximately 98 degrees Fahrenheit at this datum. Reservoir fluid PVT studies were conducted on down- hole samples from the OBd, OBa slash OBb, and OA sands in S- 200 well, and from the OBd/OBe sand in W-200. PVT samples show significant variations in fluid properties both horizontally and vertically. Exhibit II-3 shows a summary of fluid properties in the Polaris accumulation. The PVT properties used in reservoir simulation were derived from measured values. The PVT tables used to represent the S Pad METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 19 area are shown in Confidential Exhibit II-4. Estimates of hydrocarbon in place for Polaris are derived from net oil pore-foot maps and reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. The current estimate of oil and gas in place are as follows. For the Mc sand, 25 million to 120 million barrels of oil in place, stock tank barrels. For the N sand, 25 to 80 million barrels stock tank. For the O sands, 300 to 550 million stock tank barrels. For a total for the Schrader in the Polaris area of 350 to 750 million barrels stock tank. Original gas in place is estimated at 84 to 250 bcf. Two wells, S-200 and W-200, have been tested long- term. Stable production has been established in W-201 and S- 213. Since the submittal of this application, stable production has been established in S-201, W-211, and W-203 as well. Exhibit IV-1 shows a representative well test results for all Polaris wells. Several reservoir models using data from the Polaris Pool were constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. Development options evaluated for the Polaris Pool include primary depletion and water flood. Preliminary screening of miscible gas flooding is also in progress. Model results indicate that primary depletion would recover METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 2O approximately five to 10 percent of the developed area oil in place. Low primary recovery is a result of a combination of low GOR, low initial reservoir pressure, and viscous oil. Water flood has been identified as a viable development option for Polaris. It is anticipated that overall field development will involve 15 to 25 injectors and 25 to 35 producers. Water flood recovery ranged from 15 to 30 percent of OOIP, inclusive of primary recovery, in the developed area at one and a half hydrocarbon pore volumes injected. Polaris water flood oil and water production and injection forecasts are shown in Exhibit II-5. Simulation and development planning efforts show that horizontal wells have the potential to enhance rate and recovery in some areas while reducing development costs and minimizing facility expansion requirements. Horizontal well potential is currently being evaluated in the W Pad area where the target has been narrowed to three sands, the OBa, OBc, and OBd. A tri-lateral well, W-203, that targeted approximately 3,500 feet of horizontal section in'each of these three sands has been drilled and is currently on production. Initial development will take place in a step-wise approach, working from the crests towards the outer limits of the Pool, incorporating data gathering necessary to refine development plans. Phase I development focuses on developing and establishing water flood operations in select portions of METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 21 three primary areas. Phase I development will be used to validate the development assumptions and refine Phase II and III development plans. S and M Pad north block development includes sidetracking S-200 to repair a split liner, then converting the well to injection to support wells S-201 and other potential wells. Aurora well S-104i will provide additional crestal production -- will provide support for additional crestal producers through commingled injection in the Schrader Bluff and Kuparuk. Development of the S and M Pad south block consists of two existing producers, S-213 and S-216, and planned supporting injector S-215i. Phase I development in the W Pad area consists of drilling one producer, W-211, and supporting injector, W-212i, which will also support existing well W-200. A tri-lateral horizontal well, W-203, in the downdip area of the W Pad polygon, has recently been drilled. It is anticipated that offset injectors will be planned once horizontal well performance has been evaluated and incorporated into the development plans. Phase II development is directed at completing development in the -- development in the north, graben, and south S Pad polygons, and W Pad polygon, and the K22-11-12 polygon. The Phase II drilling program is designed to access down-dip areas with higher water saturation as well as higher METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 22 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-$876 risk, structurally complex areas. Polaris Phase III development would involve developing areas that require improved understanding of fault transmissibility and presence, or refinements in drilling techniques to reach the targets. Phase II results and performance data will be key in moving forward with Phase III areas. Due to faulting, the patterns are expected to be irregular and wells may be areally very close to adjacent wells, but will be isolated due to reservoir compartmentalization. To allow for future flexibility in developing the Polaris Pool and tighter well spacing across fault blocks, a minimum well spacing of 20 acres is requested. The objective of the Polaris reservoir management strategy is to operate the Pool in a manner that will maximize recovery consistent with good oil field engineering practices. The reservoir management strategy for the Polaris Pool will continue to be evaluated throughout the life of the field. CHAIR TAYLOR: Would you raise your right hand? (Oath administered) HR. MATTISON: I do. CHAIR TAYLOR: Could you please state your full name for the record and spell your last name for the court reporter? HR. MATTISON: Hy name is Scott Hattison, and my 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 23 surname is spelled M-a-t-t-i-s-o-n. I'm an Engineer with BP Exploration Alaska, currently working as a facility engineer for the Polaris Project. I received a Bachelors degree in science in chemical engineering from Louisiana State University. I joined BP in June 2000 via the acquisition of ARCO. I had worked for ARCO in Alaska on a variety of projects since 1981. I've been with the Greater Prudhoe Bay satellite team since July 2001, and I have testified as an expert witness in Alaska before the AOGCC in previous hearings. CHAIR TAYLOR: Do you wish to be qualified as a facilities engineer? MR. MATTISON: Yes, I do. CHAIR TAYLOR: Okay. Commissioner Bill, do you have any questions or any objections? COMMISSIONER BILL: No questions, no objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: I have no questions nor objections. CHAIR TAYLOR: Okay. Please proceed, we'll consider you an expert witness for purposes of this hearing. There's water in that pitcher, too, if you'd like. MR. MATTISON: I hope my whistle will hold out. Polaris wells will be drilled from existing IPA drill sites, M Pad, S Pad and W Pad, and will utilize existing IPA pad METRO COURT REPORTING, INC. 745 West Fou~h Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 24 facilities and pipelines to produce Polaris fluids to Gathering Center 2 for processing and shipment to Pump Station 1. Polaris fluids will be commingled with IPA fluids on the surface at the respective well pads to maximize use of existing IPA infrastructure, minimize environmental impacts, and reduce costs, and maximize recovery. The GC-2 production facilities to be used include separating and processing equipment, inlet manifolds and related piping, flare systems, and onsite water disposal. M Pad, S Pad and W Pad have been chosen as surface locations for Polaris wells to reach the expected extent of the reservoir while minimizing new gravel placement, minimizing well step out, and allowing the use of existing facilities. An expansion of existing S Pad to accommodate additional wells was completed in April 2000. A schematic of the S Pad drill site layout, including contemplated Polaris facilities, is shown in Exhibit III-2. And there's space for one additional Polaris well on the northern pad. Schematics of existing M Pad and W Pads are included as Exhibits III-3 and III-4. A trunk and lateral production facility capable of accommodating up to 20 Polaris wells is planned as an extension to an existing S Pad manifold system. The size and type of well tie-in manifold system required at M Pad and W Pad have not been determined. Water for the water flood METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 25 operations will be obtained by extending an existing 6 inch water injection supply line at S Pad. Should water injection pressures be insufficient, injection pressure will be boosted locally. Artificial lift will be performed either with artificial lift gas or with jet pumps using injection water as the power fluid. It is anticipated that the water for water flood operations, artificial lift gas, and MI, if needed, can be supplied to Polaris wells at M Pad and W Pad from the existing pipeline infrastructure. Should injection pressure be insufficient for Polaris requirements, it could be boosted locally. Wells will be tested using existing well test facilities at $, M and W Pads. Wells will be put into test using either automated or manual divert valves. And this is a slight modification to the document as submitted, which said automated divert valves. The divert valves on north S Pad are manual. Well pad data gathering will be performed both manually and automatically. The data gathering system will be expanded to accommodate the Polaris wells and drill site equipment. No modifications to the GC-2 production center will be required to process Polaris production. And that concludes my discussion of the facilities. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 26 CHAIR TAYLOR: questions? hand? Commissioner Bill, do you have any COMMISSIONER BILL: Not at this time. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: No questions. CHAIR TAYLOR: Thank you. Would you raise your right (Oath administered) MR. SCHMOHR: I do. CHAIR TAYLOR: Thank you. Would you please provide your name and spell your last name for the court reporter? MR. SCHMOHR: Okay. My name is Donn Schmohr. My surname is spelled S-c-h-m-o-h-r. I'm an engineer for BP Alaska Exploration, currently working as a petroleum engineer for the Polaris development project. I received a Bachelor of Science Degree in mechanical engineering in 1977 from the University of Nebraska. I joined Sohio, which was acquired by BP, in March of 1980, and have worked in Alaska on various projects since 1980. I have taken postings in Dead Horse; Midland, Texas; London, England; Bogota, Colombia; and Anchorage. I've been working with the Greater Prudhoe Bay satellite development team since March 1999. I'd like to be acknowledged today as an expert witness in petroleum engineering. CHAIR TAYLOR: Commissioner Bill, do you have any METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 27 questions or objections? COMMISSIONER BILL: No questions, no objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: I have no questions nor objections. CHAIR TAYLOR: Please proceed, we'll consider you an expert in the field of petroleum engineering. MR. SCHMOHR: Okay, thank you. A number of exploration and appraisal wells, and development wells, that targeted the deeper Kuparuk and Ivishak production have been drilled and logged in the Schrader Bluff formation. However, only the recently drilled S-200, S-201, S-213, S-215i, S-216, W-200, W-201, W-203, W-211 and W-212i have been drilled and completed in the Polaris Pool. These well locations are shown in Exhibit I-2. They're the -- they're the wells -- the wells located with the squares here are the existing wells. Polaris development wells will be directionally drilled utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in the Prudhoe Bay Unit and other North Slope fields. Surface hole will be drilled no shallower than 500 feet TVD below the base of permafrost level. The production hole will be drilled below surface casing to a target depth in the Schrader Bluff formation, allowing sufficient rathole to facilitate logging. Production METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 28 casing will be set from the surface and cemented. Multi- lateral, horizontal and conventional wells may be drilled at Polaris. The horizontal and multi-lateral well completions could be perforated casing, slotted liner, barefoot section, or a combination. Ail conventional wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Polaris wells will be completed in a single zone, the Schrader Bluff formation. Injectors may be single or multi- zone, Kuparuk, Schrader Bluff, Sag and/or Ivishak Formations, utilizing a single string and multiple packers as necessary. As shown in the typical well exhibits, IV-2, for conventional producers, and Exhibit IV-3 for a conventional injection well, and Exhibit IV-4 for a multi-zone injector. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Additionally, jewelry will be installed so that jet pumps can be utilized, providing further flexibility for artificial lift. The injectors will be designed to enable multi-formation injection where appropriate to the Kuparuk, Schrader Bluff, Sag or Ivishak formations. Open hole electric logs may supplement or replace logging well drilling, logging, including gamma ray, resistivity, density and neutron porosity and other logging tools when wellbore conditions allow their use. The METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 29 horizontal wells and multi-lateral wells will typically utilize seven inch intermediate casing set in the Schrader Bluff formation. The reservoir section will be drilled with a six and one-eighth inch horizontal production hole, completed with a four and a half inch or three and a half inch slotted or solid liner, and cemented and perforated as necessary. Ail well completions will be equipped with a nipple profile at a depth just below the permafrost should the need arise to install a downhole flow control device or pressure operated safety valves during maintenance operations or for future MI service. Fracture stimulation has been implemented for all vertical Polaris producers drilled to date and may be implemented in the future to mitigate formation damage, for sand control, and to stimulate Polaris wells. An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 5,000 feet TVD subsea. An initial static reservoir pressure will be measured on each producer or injection service well. A minimum of one reservoir pressure will be taken each year in each of the six Polaris reservoir polygon areas when at least one Polaris production well has been completed in the respective polygons. Surveillance logs may be periodically run to help determine reservoir performance, for example, production METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 3O profile and injection profile evaluations. Surveillance logs will be run on commingled injection wells annually to assist in the allocation of flow splits. Approval is requested to complete commingled injectors where deemed prudent, including approval for commingled water injection in well S-104i in the Aurora and Polaris pools. Well S-104i is completed with isolation packers and injection mandrels, which will allow multi-zone water injection. Installing a restrictive orifice in the injection mandrels will control injection rates. Polaris production allocation will be done according to the PBU Western Satellite Production Metering Plan, described in the letter dated April 23rd, 2002. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor will be applied to adjust the total Polaris production. Ail new Polaris wells will be tested a minimum of two times per month during the first three months of production. A minimum of one well test per month will be used to tune the performance curves and to verify system performance. Regarding the area injection operations. This application requests authorization for water injection to enhance recovery from the Polaris Pool. The proposed area of injection operations is the Polaris Participating area outline. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 31 BP Alaska -- BP Exploration Alaska is the operator of the Polaris Participating area. The application contains an affidavit showing that the operators and surface owners within a one-quarter mile radius of the area and within the Polaris Participating area have been provided a copy of this application for injection. Fluids requested for injection for the Polaris Oil Pool are: produced water from the Polaris or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance enhanced -- and enhanced recovery; tracer survey fluid to monitor reservoir performance; fluid injected for purposes of stimulation; source water from the seawater treatment plant. Now I'd like to speak to the mechanic integrity of wells within a quarter mile of the injectors. Exhibit VII-2 shows all Schrader bluff penetrations at the Ma sand, and a quarter mile radius is shown around the location of the point at which each existing and currently-planned injection well is estimated to intersect the top of the MA sand. So these are each one of the injectors with a quarter mile radius. And these are all the penetrations in the MA sand. Currently, there are three Polaris injection wells that have been drilled and cased, W-212i, S-215i and S-104i, which is the dual Kuparuk and Schrader Bluff injector. This application also provides information on the area of review for two additional proposed injection wells, W-207i and S- METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 32 200i, which are planned to be drilled in the near future. Standards of mechanical integrity. The following application or this application assumes that the standards in the Commission's regulations apply to the operations described in the Application. In particular, a Polaris Pool injection well is considered to have mechanical integrity if it satisfies the requirements provided in 20 AAC 25.412, and a Polaris production well is considered to have mechanical integrity if it is cased and cemented in accordance with 20 the regulations. Standards of Confinement. A penetration not completed within the Polaris Pool is considered to provide confinement if injection fluids within the Polaris Pool if calculations show the top of cement is above the top of the Ma sand and the cement job appears to have been pumped successfully, or if cement evaluation logs are available that show cement above and below the Schrader formation, or if the penetration is far enough from the injector that it is reasonable to assume the reservoir pressure at that point will not rise above original reservoir pressure. Zonal isolation in the Schrader Bluff at the W-17 Schrader Bluff penetration needs to be addressed. W-212i, is located 255 feet from the W-17 penetration. W-17 is currently a low rate, shut-in, and secured Ivishak producer that has confirmed holes in the tubing. There are conceptual plans to METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 33 use this well in the future as an Ivishak injector. That's W- 17. After extensive review of the W-17 completion, we cannot provide assurance that there will be zonal isolation since the calculated top of cement on the nine and five-eighths casing is very close to the Schrader Bluff. There is no cement evaluation tool available that can log through tubing and casing to determine if there is cement and zonal isolation in W-17. We propose to perform a baseline temperature survey on W-17 prior to injecting in W-212i and perform subsequent temperature surveys at two, five and eight months after initiating water injection. In addition, we will provide the AOGCC evidence of zonal isolation within 12 months of commencing water injection, or shut in W-212i. Evidence of zonal isolation will either be in the form of conclusions resulting from the temperature logging program, a cement integrity log in W-17 across the Schrader Bluff interval, or plans to execute an alternative plan that is approved by the Commission that would eliminate the risk of injected fluids from moving out of zone. If the temperature logs indicate fluid movement out of the pool, W-212i will be shut in until an engineered solution is complete to eliminate the fluid movement. W-17 does have evidence that the cement job on the 13 and three-eighths casing was successful. A reservoir simulation model of the W Pad area has METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 1 been used to estimate how the reservoir pressure dissipates 2 )~ between the injector, W-212i, and the producer, W-200. 34 Exhibit VIII-1 shows the maximum observed pressure between W- 212i and W-200, which occurs after approximately four years of water injection. The reservoir pressure at various points between the two wells were extracted from the simulation model and plotted as a function of distance from the injector. This evaluation shows that at a range of 1,000 feet to 1,500 feet from an injector, the pressure has dissipated to near reservoir pressure. This shows that the one-quarter mile area of investigation is a reasonable -- is reasonable for water injection in the Polaris pool. So at zero here, this would be the injector, this would be the distance away from the injector to the producer over here. And the pressures at each point along there. Maximum fluid injection requirements at the Polaris Pool are estimated at 20,000 to 25,000 barrels of water per day. The expected average surface water injection pressure for the project is 2,300 psi. The estimated maximum surface injection pressure us 2,800 psi. The expected maximum injection pressure for Polaris Pool injections will not propagate fractures through the confining strata. Each Schrader Bluff O, N, and M sand is separated from the adjacent overlying and underlying sand by 10 to 75 feet thick non- reservoir silty mudstones which provide effective fluid METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 35 isolation. Reservoir simulation studies indicate incremental recovery from waterflooding to be approximately 10 to 20 percent of the original oil in place, relative to primary depletion. BP Exploration, in its capacity as Polaris operator and unit operator, respectfully requests that the Commission adopt Pool Rules and Area Injection Order as proposed in the application. This concludes our prepared testimony and we'd be happy to answer any questions you have. CHAIR TAYLOR: Thank you. MR. SCHMOHR: That final exhibit, we've got some copies here for you, that we'd like added to the application. CHAIR TAYLOR: We'll do that. It looks like a handful of them here. MR. SCHMOHR: Yeah, I think there's 10 there. CHAIR TAYLOR: Okay, thank you. Let's make sure that one gets in each file. Commissioner Bill and Commissioner Seamount, would you like to start with questions now or would you like to take a break first? COMMISSIONER BILL: I'd prefer a~ break. CHAIR TAYLOR: Okay. What if we take a 15 minute break. COMMISSIONER SEAMOUNT: Are we going to call each of the witnesses back then to answer questions? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-$876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 36 CHAIR TAYLOR: If they could be available, they're still under oath and ..... COMMISSIONER SEAMOUNT: Okay. CHAIR TAYLOR: We can do it however you want. We can pose the questions to individual people or we can pose the question and you can decide who would most appropriately respond to it. MR. SCHMOHR: Okay. (Indiscernible - background conversation) MR. BEUHLER: Yeah, I'd also like to swear in Doug Von Tish. CHAIR TAYLOR: Were you going to provide testimony or just be prepared to answer questions? MR. VON TISH: Just for questions. CHAIR TAYLOR: Okay. Would you raise your right hand, please? (Oath administered) MR. VON TISH: Yes. CHAIR TAYLOR: And do you wish to be qualified as an expert witness? MR. VON TISH: CHAIR TAYLOR: Yes. Well, why don't you state your name for the record, spell your last name, and then provide your qualifications for us. MR. VON TISH: My name is Doug Von Tish. My surname METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 37 is spelled V as in Victor, o-n, space, T as in Tom, i-s-h. I'm a geophysicist with BP Exploration Alaska, Incorporated. I received Bachelor of Arts degree and Master of Science degrees in geological science from Cornell University. I have been employed as a geophysicist by BP and Sohio Petroleum for 19 years. I have worked on a variety of Alaskan projects since 1994, including the Prudhoe Bay field, and the Midnight Sun, Polaris, and Orion Pools. I have been working with the Greater Prudhoe Bay satellites team since August 1998. Prior to joining BP in Alaska, I worked on field development and appraisal projects for BP in Australia, and on exploration projects in the Gulf of Mexico for BP and Sohio. I would like to be acknowledged today as an expert witness in geoscience. CHAIR TAYLOR: Commissioner Bill, do you have any questions or any objections? COMMISSIONER BILL: No questions, no objections. CHAIR TAYLOR: Commissioner Seamount? COMMISSIONER SEAMOUNT: No questions, no objections. CHAIR TAYLOR: Thank you,. we'll consider you an expert for purposes of answering questions then this afternoon -- or I mean this morning when we return. Mr. Beuhler, there will be actually one thing we should take up, at least for you to consider during the break. There were a number of exhibits that BP submitted and requested that they be held confidential. Two of them in particular, I-6 and I-7. The METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 38 Commission is not clear on what the basis for the trade secret request is. If you're not able to take it up when we return, we can certainly give you time to provide something in writing back to us, but what the Commission is looking for is some support for the finding that it is entitled to confidentiality under the trade secret standard that would indicate that the information derives independent economic value as a result of it being held confidential, and that by release of that you would lose that. MR. BEUHLER: Okay. We can certainly answer that when we come back from break. CHAIR TAYLOR: Great. Thank you very much. MR. BEUHLER: Thank you. CHAIR TAYLOR: We'll take a break, it's approximately 12 minutes after 10:00. (Off record - 10:13 a.m.) (On record - 10:45 a.m.) CHAIR TAYLOR: We're back on record, the time is approximately 10:45. And once again, we've demonstrated that we're not very good at keeping track of time. We apologize for the longer than 15 minute break. I think we'll start with some questions. Commissioner Seamount will start with the first set of questions. COMMISSIONER SEAMOUNT: Okay, I've only got a few questions. I'd like to put Exhibit I-2 up on the screen. And METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Ancltorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 39 don't know who wants to answer this question, I'm assuming it would be Mr. Bernaski, Mr. Reints, or Mr. Von Tish. I don't know which one wants to answer it, or whether you're willing to answer it. In the area to the west of the proposed pool rules boundary, it looks like it's about, oh, a mile wide swath, give or take. Am I to interpret this area as an area of no potential for Polaris Pool type production? MR. VON TISH: In the area west of this fault and south of this fault, we interpret that as being an area of no potential production, at least in this area. In this northern area, wells drilled to date have no indicated pay in this area. However, these blocks are high standing Horst blocks that have not been penetrated that could potentially have pay. COMMISSIONER SEAMOUNT: Okay, thank you, Mr. Von Tish. Let's see. Is -- within that -- the area of the pool, is there any known areas of shallow free gas? MR. BERNASKI: No. No, there's no indication of free gas in the Polaris Pool. The sand's (indiscernible) ..... COMMISSIONER SEAMOUNT: Okay, thank you, Mr. Bernaski. COMMISSIONER BILL: We may need to have you say the same thing on the -- for the tape. MR. BERNASKI: There is no indication of free gas in any sand in the Polaris Pool. CHAIR TAYLOR: What about the shallower zones? MR. BERNASKI: Above the top of the Ma? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 4O CH_AIR TAYLOR: Yes. MR. BERNASKI: The -- the nearest indication of free gas in the Polaris Pool area would be in what we call the Sv sands, which are roughly 12 to 1,500 feet shallower than the -- excuse me, in the uppermost Ug4 and Sv sands, roughly 1,200 feet shallower than the Polaris Pool. There is some indication of potential coal gas, or methane, in the Ug4, and certainly gas hydrates up in the Sv sands at a depth of roughly 2,000 to 3,000 feet TVD subsea. COMMISSIONER SEAMOUNT: In regards to shallow gas, have you accounted for drilling rig equipment such as diverter lines when applying for drilling permits? MR. BEUHLER: Excuse us one moment. MR. SCHMOHR: We have, it's done a case by case issue on -- with the off- -- what we've seen from the offset wells in that particular block that we're drilling in. COMMISSIONER SEAMOUNT: Okay. I have one last subject I'd like to talk about, and that would be fracture stimulation. It might be helpful if you put Exhibit I-5 up. Do you typically fracture stimulate most of the wells in this pool? MR. SCHMOHR: Typi- -- well, all of the vertical wells have been fracked (ph) and we frac them for a couple of reasons. One is for sand control, it's an effective sand control method, in addition to the stimulating benefits of METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3s76 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 41 getting paths in your wellbore damage. So we've done, you know, all -- all producing wells except for one, the tri- lateral, that we've drilled have been fracture stimulated. And most of them have either two or three fracs per well. COMMISSIONER SEAMOUNT: Okay. Is there a zone that you typically frac more than the others? Or do -- I mean, what would be, you know, a typical frac job on -- to -- are you -- do you ever frac the M sands? MR. SCHMOHR: No, we -- so far we've fracked the N sands and the 0 sands. The OA is wet in the W Pad area, so, of course, we haven't fracked that. We have no production from the Mc or above. That's -- the Mc's an area that we may look at in the near future. COMMISSIONER SEAMOUNT: Okay, so you haven't fracked the Mc then? MR. SCHMOHR: No. COMMISSIONER SEAMOUNT: Okay. What's a typical size? MR. SCHMOHR: They varied a lot as we've gone through the learning curve. Anywhere from -- the initial wells were about 20,000 pounds range. We've done some recent ones that are as high as -- over 100,000 pounds. So there's quite a range that we've gone through. COMMISSIONER SEAMOUNT: What's the propint (ph) type? MR. SCHMOHR: It's a 1620, and it's resin -- we've used both resin and non-resin coded carbolite. It's a polar METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 42 prop designed for low temperature. We try and tail in with the resin coated propint (ph) to help us for sand production. COMMISSIONER SEAMOUNT: What's the carrying fluid? MR. SCHMOHR: We use a -- it's a cross-link gel. Ail wells have were using a water based cross-link gel, and it's a borate (ph) system. The last well we fracked, which was W-211, we were trying to get tip screen out sand. We went to a straight HEC (ph) system to try and increase our leak off rate so we could initiate a tip screen out. So that's the only one that wasn't a cross-linked system. COMMISSIONER SEAMOUNT: Do you have any feel for how much of that gel that you get back? MR. SCHMOHR: We pretty much get back most of our load, although I can't really -- we haven't really gone in and looked at our -- compared our total load pumped versus what we get back to see if we're actually leaving some. In almost -- in wells like this, almost any time you frac you won't get, you know, 100 percent of your fluids back. You know, there -- a lot of times there is some minor remedial fluids that are left. COMMISSIONER SEAMOUNT: Okay. And finally, do you feel that fracture height is contained within the -- I mean, is it contained where you want it to be contained? MR. SCHMOHR: Yes. Of course, the size of the job is one of the reasons the sizes have varied so much is that we METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 43 are trying to stay within zone during the fracs, as well as optimize the frac itself. We use several different modeling techniques, one is produced by Nolty Smith (ph), NSI, which is stim (ph) planned, and we also use one of the vendor models to do our modeling work as a backup to each other. So yeah -- yes, I think we do stay fairly much within zone. We also do a post-analysis where we look at the net pressures during the job to see, you know, if they're following a PKN type frac or if they're radial. The majority of them seem to be PKN, or rectangular, which means they're constrained. COMMISSIONER SEAMOUNT: Okay. Thank you, Mr. Schmohr. I have no further questions. CHAIR TAYLOR: Commissioner Bill? COMMISSIONER BILL: I have a number of questions, and they're not very well organized, so bear with me. But they could switch around between various people. The first question, the injection pressure seems rather high to me, and so could you comment on why you would need that level of pressure? I believe you said something -- a maximum of 2,800 pounds surface? MR. SCHMOHR: Yeah, the 2,800 pound figure comes from -- that's what the actual manifold pressure will be at a maximum. I think we had 2,300 in there as an expected average. Right now we don't know exactly what our injectivity will be. Most of our producers we frac, so we get binear (ph) METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276~3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 44 wellbore damage. We don't know exactly what kind of damage we'll have, what pressure requirements there will be. We have done step rate tests on our producers pre-frac, which indicate that we initiate a frac at about one and a half to two barrels per minute. So in the 2,500 to 3,000 barrel per day range at a wellhead pressure of approximately 1,000 psi. So that's, I think, where we'll initiate, you know, fractures when we're injecting. And I think that, you know, somewhere in the 1,000 to, oh, 1,500 is the average range that will be on a wellhead pressure. COMMISSIONER BILL: So you anticipate that the numbers that you've quoted are high side? MR. SCHMOHR: Yes. COMMISSIONER BILL: How many individual well injection rates do you anticipate? MR. SCHMOHR: Anywhere from 1,000 to 5,000 barrels per day. COMMISSIONER BILL: Okay. So the 20 -- 25,000 number that you quoted was -- that's for the project -- the initial portion of the project? MR. SCHMOHR: Yes. COMMISSIONER BILL: Okay. There -- the area to the north of W Pad, that polygon area, seems rather large, and it doesn't appear that you -- my guess is that you couldn't reach the entire area from the current pads. How do you intend to METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 45 develop that area? I believe it's the W -- TW-C area. MR. REINTS: As you can see S Pad sits right here, W Pad sits down here, and this Term Well C area in the middle, which is about in between those two pads. From existing facilities, this area could be a significant challenge to drill just due to the departure we're dealing with, 12 to 14,000 for the departure. So right now our primary development does not cover this area, it's considered a Phase III type development where we have to get understanding of what our technical limits in drilling are, as well as understanding of what type -- or well types are going to be. Obviously, if you're drilling vertical fracked wells, this is not an opportunity for those types of wells where it may lend itself to horizontal well development just due to the sheer departure. The other issue we face is the rock quality deteriorates as you get into this area. And at this stage of the game, we're not real sure which sands are going to be productive and which aren't. The Term Well C has some interesting things that happened that makes you question whether it's really a pay target in a couple of intervals. COMMISSIONER BILL: Okay. Ail right, thank you. You've provided information on the variation in permeability and porosity with the individual sands. It appears that profile control, vertical profile control, might be a problem. Can you address how you might go about achieving good METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 injection into all of the individual sands? Or sufficient injection, I should say. MR. SCHMOHR: As I mentioned in my testimony, we'll be doing frequent spinner surveys to monitor the control. On the conventional well design that we have, it lends itself to coil tubing squeezes. And, you know, if we have thief zones -- we use a similar technique as what's used -- was used at Prudhoe Bay, the Prudhoe Bay unit. And we can minimize perforating in thief zones, squeeze it and re-perforate control. That's going to be probably the primary methodology. Do you have anything to add? MR. REINTS: I think based on past experience in both Weisak and Milne that the flood is controlled on the injection side, not on the producer side, just because of the interventions in a fracked well is very difficult. And at this stage of the game, we don't really know what to inspect for -- expect from injection conformance, but it is a very difficult issue when you're dealing with four or five sands with the performance -- you know, getting conformance in all of those sands. COMMISSIONER BILL: Now on your multi-zone injectors, you may ~ot have access to all of those sands to do profile control, remedial work. Is that true? MR. SCHMOHR: Yes. Yeah, that is a concern on -- well, on wells like S-104 for example, we did run multiple METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 47 packers there. So we do have some control within the -- the top three packers were installed to give us zonal control in the Schrader Bluff for these three sets of perforations. So we will be able to control the split between those. And then this is the, of course, Kuparuk down here. So we can run spinners down and find out what fluids are going where in this particular well. And we'll control rate by changing the orifice in the injection mandrel, the orifice size. So in a well like this, we do have quite a bit of control that can be mechanically done rather than cement squeezing. So -- now it's always a tough decision on how many packers to put in. Naturally the more packers you have, the more control you have. But likewise, the more chance of a packer failure and, you know, problems with integrity there. MR. REINTS: And I'd like to make an additional comment, too. The simulation work that's been done captures that variability in permeability, and basically shows that the variation really isn't that bad. I mean, if you're looking at the OA sand, for example, or the OBa where you have really good rock as opposed to, say, the OBc or the OBb which has fairly poor rock, the injection is mimicked by the production. Those low quality sands are usually low quality producers. So it really hasn't been observed to be really a problem in the model with ..... COMMISSIONER BILL: Okay. You're talking in terms of METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 48 voidage replacement? MR. REINTS: Right, yeah. COMMISSIONER BILL: I'd like to speak for a moment about W-17 and your proposal to run temperature logs. Could you explain how you would see an upward movement from the temperature logs? What sort of temperature contrast do you expect and what you might see? MR. SCHMOHR: Okay. Like I mentioned, W-17 has been shut in for a considerable amount of time. So what we propose to do is prior to injection we'll run a baseline temperature survey, which I'd expect to follow very closely to the geothermal gradient. And what we'd be looking for in the subsequent surveillance would be deviations from that baseline. My experience in Prudhoe, where you see a channel or a swept zone, a lot of times you can see swept zones. In Prudhoe's case, it'll be a cooling. And typically we can see one to two degree variation Fahrenheit. It's fairly accurate, especially if you have a baseline that you're going from. In W-17's case, if we had a channel going up, for example, we're injecting fluids at about 120 degrees Fahrenheit. Of course there's -- the reservoir temperature is at about 100 degrees. So we're working with about a 20 degree delta T. There -- if there's considerable movement behind pipe, you can see the -- usually it'll diverge from the geothermal gradient and usually it's a straight line temperature profile up to where it either METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 49 departs into another zone or, you know, where it ends. COMMISSIONER BILL: So from the native fluids, that would be the first indication. You believe that there's enough temperature contrast vertically to be able to detect a problem within a few months? MR. SCHMOHR: I think we can see a temperature deviation within a degree or two. The -- probably the -- whether we would see it within two months, you know, depends on how that zone is taking fluids. I guess we expect to have fluids at that well within three months. MR. REINTS: Three to six months. MR. SCHMOHR: Three to six month range is where we'd expect to see it. And that's why I kind of picked the two -- the frequency of monitoring that I did. COMMISSIONER BILL: Okay. The plan for a downhole safety valve that -- the nipple that was going to be installed into the tubing string, was that just for injectors or was that for producers also? MR. SCHMOHR: We installed it in producers also. Every well has a nipple just below the permafrost. COMMISSIONER BILL: And could you speak to what valves that -- should it be necessary, what sort of -- what type of valves that you would be placing in that nipple? MR. SCHMOHR: Well, for injectors they're a check valve type injection valve, K valves. If we need to do it. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 SO Of course, for MI we would install an injection valve. But this application isn't requesting MI. So it'd be a through tubing safety valve that we would run. COMMISSIONER BILL: Well spacing on the pad, distance between wells? MR. SCHMOHR: Fifteen feet. COMMISSIONER BILL: Okay. And ..... (Indiscernible - away from microphone) COMMISSIONER BILL: Okay. Kind of a nominal producer to injector ratio, it appeared like it'd be a little over one? Is that just taking the gross numbers or ..... MR. REINTS: Yeah, it ranges between one and a half to one, to two to one. And it will be dependent upon which types of wells we actually drill in Phase II and Phase III, whether they're horizontal wells or vertical wells. As you move towards a horizontal well development, you're minimizing the number of producers and increasing the number of injectors. Whereas in a vertical well development, to get the through- puts, you need more producers. So ..... COMMISSIONER BILL: Now from reading the application, I'd understood that you were looking at initial development primarily using vertical wells and stimulation treatments. Is that still the plan? MR. REINTS: Yes. But like I said in my testimony, we have drilled the one triple lateral well, and we're evaluating METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 51 drilling another one here in the next few months. COMMISSIONER BILL: You mentioned that water was coming -- your injected water was coming from the existing infrastructure. Is there sufficient water to provide for Polaris's needs and also for the other developments? MR. REINTS: Yes. COMMISSIONER BILL: Okay. You don't see that you're starved for water by adding another development? MR. REINTS: No more starved than we are for water. COMMISSIONER BILL: Already. MR. REINTS: Polaris actually -- as we ramp up, the injection rates could get up to 25,000 barrels a day. But initially we're dealing with four to 5,000 barrels a day probably. So pretty small volumes. COMMISSIONER BILL: Okay. I believe that's all my questions for now. CHAIR TAYLOR: Any other questions? COMMISSIONER SEAMOUNT: No. CHAIR TAYLOR: Mr. Beuhler, I guess my only question was with -- following up with respect to those two exhibits, Exhibit I-6 and I-7. MR. BEUHLER: Yes. And if it pleases the Commission, what I would suggest is that the operator provide -- we would suggest providing a written response documenting our reasons for declaring those confidential. And that's specifically METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 52 Exhibits I-6 and I-7. CHAIR TAYLOR: That's correct. And how much time should we leave the record open for that? MR. BEUHLER: My desire would be as short as possible, so this week? Would that be appropriate? CHAIR TAYLOR: You can pick the time and ..... MR. BEUHLER: Okay, let's make it this week. CHAIR TAYLOR: By Friday? MR. BEUHLER: By Friday. CHAIR TAYLOR: By Friday, 4:30. So we'll leave the record open until Friday at 4:30. Do either of you want to take a break before closing? COMMISSIONER BILL: Have no need to. CHAIR TAYLOR: Okay. Thank you very much, we appreciate the testimony and everybody's participation this morning. We'll keep the record open until Friday at 4:30 for a response to the confidentiality of Exhibit I-6 and I-7. We'll close the hearing, thank you. (END OF PROCEEDINGS) METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 53 CERTIFICATE SUPERIOR COURT STATE OF ALASKA I, Cari-Ann Ketterling, Notary Public in and for the State of Alaska, do hereby certify: THAT the foregoing pages numbered 02 through 52 contain a full, true and correct transcript of the Public Hearing before the Alaska Oil and Gas Conservation Commission, taken by and transcribed by Julie O. Gonzales; THAT the Transcript has been prepared at the request of the Alaska Oil and Gas Conservation Commission, 333 West Seventh Avenue, Anchorage, Alaska. DATED at Anchorage, Alaska this 12th day of December, 2002. SIGNED AND CERTIFIED TO BY: /~ ' , Notary Public in an~ for-Alaska} Hy Commission Exp~es: 7/19/0~/ METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 #7 Exhibit VIII- 1 4000 350O 30O0 250O 20OO W-Pad Model Reservoir Pressure vs. Distance W-200/W-212i Well Pair Mode~ Time = 2385 da, of ~n Average pressure 1500 1000 0 500 1000 1500 2000 2500 3000 Distance from injector(feet) #6 C STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION POLARIS POOL RULES AND AREA INJECTION HEARING DECEMBER 9, 2002 at 9:00 am NAME - AFFILIATION ADDRESS/PHONE NUMBER (PLEASE PRINT) TESTIFY (Yes or No) -iff 3-I ~3~ ~O STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION POLARIS POOL RULES AND AREA INJECTION HEARING DECEMBER 9, 2002 at 9:00 am NAME - AFFILIATION (PLEASE pRINT) ADDRESS/PHONE NUMBER TESTIFY (Yes or No) #5 ALASKA OIL AND GAS CONSERVATION COMMISSION Date: Time '1 ..~.~- MEETING - Subject NAME - AFFILIATION (PLEASE PRINT) TELEPHONE #4 STATEADvERTiSiNGOF ALASKA ~,_ NOTICE TO PUBLISHER ~"..-- A.,,.,.,.ADVERTISING ORDER._ NO. INVOI ,,~UST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., ,.,ERTIFIED AFF,OAV.T OF PUBL,CAT,O. (P~.T2 OF TH,S l:O..~ W,TH A~ACHED COP~ OF ~U'UZO'~ 4021 ORDER ADVERTISEMENT MUST BE SUBMI'I-rED WITH INVOICE F AOGCC AGENCY CONTACT DATEOF R 333 W 7th Ave, Ste 100 Jody Colombie November 7, 2002 o Anchorage, AK 99501 ~.OU[ PC~ ~ - (907~ 793--1221 ~ AnChorage Daily News November 8, 2002 o P O Box 149001 Anchorage, AK 99514 Ta~ ~,~ ~.nV~.N T.t ~OtJ~,.~,.~.S ~UST ENTIRETY ON THE DATES SItOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 Advertisement to be published was e-mailed Typ~ of Ad¥~rtis~m~nt X Legal [--I Display ~'] Classified [~Oth~r SEE ATTACHED PUBLIC HEARING · I ITOTALOF I :SEND.INvOICE..INTRIPEICA~E'I AOGCC, 333 W. 7th Ave.. Suite !00 PAGE1 OF i ALL PAGES$I !ii';..}}::..' !~; ~;!"...~::.i,:~ .i""'": . TO ".i-! '::' 'i. :' .~':":.?'!? '.i~I'1 An ehorage~ AK 99501 2 PAGES RI=l: TYpI: NOMB~R AMOUNT DATE COMMENTS z alm 02910 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIQ 1 03 02140100 73540 2 -- 4 RE~I-T~ E D~BY: ~ I DIVISION APPROVAL: ., 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM Re: Ad Order Subject: Re: Ad Order Date: 07 Nov 2002 10:39:44 -0900 From: Amy Heath <aheath~adn.com> To: Jody Colombi¢ <jody_colombi¢~admin.state.ak.us> __ Account Number: STOF0330 Legal Ad Number: 632788 (Public Notice) Run Dates: November 8, 2002 Total Amount: $101.38 Thanks Jody! :) Amy L. Heath __ Legal Customer Service Representative Phone: (907) 257-4296 Fax: (907) 279-8170 Office Hours 8:00am - 5:00pm legalads@adn.com 1 of 1 11/7/2002 1:46 PM '~chorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 11/8!2002 AD # DATE PO ACCOUNT 632788 11/08/2002 02314021 STOF0330 PRICE OTHER OTHER PER DAY CHARGES CHARGES $101.38 $101.38 $0.00 $0.00 OTHER OTHER CHARGES #3 CHARGES g4 OTHER GRAND CHARGES #5 TOTAL $0.00 $0.00 $0.00 $101.38 STATE OF ALASKA THIRD JUDICIAL DISTRICT Amy Heath, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in ' Anchorage, Alaska, and it is now and during all saidtime was printed in an office maintained at the aforesaid place of . publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska .v~.. .... ... STATE OF ALASKA Alaska 0il and.,G..,a.s Conservation commission Re: Polaris Oil Pool, Prud~o~ Ray. Field · Pool Rules and Area Inie. ction Order BP E~pl~ration ('~la-~ka), Inc ~l~ka, In~. by ap- plication dated October 31, 2002,.' has' applied for an area iniection order and pool rules under 20-AAC 25.460 and 20 AAC 25.520, respectively, to govern development of the Polaris Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. :The Commission.ha~"set a public hearing on this application for December 9, 2002 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite ~00, Anchorage, Alaska In addition,"a PersOn ma9 submit' v~'r'itt;en com- .ments regarding this application to the Alaska Oil and Gas Conservation Commlssiori.at 333 .West 7th' Avenue, Suite 100, Anchorage, Alaska.99501. Writ- ten comments must be received no later than 4:30 pm on December 9, 2002. If you are a person with a disability who may need a special, modification in order to comment or to attend the public hearing, please contact Jody Co- Iombie at 793-1221 before December 4, 2002· Is/Cammy Oechsli Taylor, Chair RECEIVED NOV 2002 Alaska Oil & Gas Cons. Commismo~ Anchoraoe Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re~ Polaris Oil Pool, Prudhoe Bay Field Pool Rules and Area Injection Order BP Exploration (Alaska), Inc Alaska, Inc. by application dated October 31, 2002, has applied for an area injection order and pool rules under 20 AAC 25.460 and 20 AAC 25.520, respectively, to govern development of the Polaris Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. The Commission has set a public hearing on this application for December 9, 2002 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. In addition, a person may submit written comments regarding this application to th the Alaska Oil and Gas Conservation Commission at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on December 9, 2002. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before December 4, 2002. , Cammy Oechsli Taylo~ Chair Published Date: November 8, 2002 ADN AO 02314021 . ADVERTISING OI~)ER NO. STATE OF ALASKA NOTICE TO PUBLISHER {" ADVERTISING INVOI ,vlUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED 02314021 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF AD' ORDER ADVERTISEMENT MUST BE SUBMI'FFED WITH INVOICE '~' ' · ':"' ' ':.i).' :'" "'i '".!~"'.' F AOGCC AGENCY CONTACT DATE OF A.D. ~ 333 West 7t~ Avenue, Suite 100 Jodv Colombie November 7. 2002 o Anchorage, AK 99501 PHOI~E PCN ~ - (907~ 793 -1221 I~ATE~ ADVERTISEMENT REQUIRED: T Anchorage Daily News I November 8, 2002 o P O Box 149001 Anchorage, AK 99514 T.~ MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 AFFIDAVIT OF PUBLICATION Ur, d Am ,c REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMI'I-I'ED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of :'ublished at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2002, and thereafter for __ consecutive days, the last publication appearing on the __ day of ,2002, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This __ day of 2002, Notary public for state of My commission expires 02-901 (Rev. 3/94) AO.FRM Page 2 PUBLISHER Re: Legals Subject: Re: Legals Date: Thu, 07 Nov 2002 17:25:54 -0900 From: Jody Colombie <jody colombie@admin.state.ak.us> To: Amy Piland <classifieds@gci.net> Amy, Please publish the attached. Thank you. Jody Amy Piland wrote: Hi Jody- Do you have any new legals for me to list in the paper? I have not heard from you in awhile, just wanted to touch base with you. Looking forward to hearing from you] __ Amy Piland, Classifieds dept. Petroleum News Alaska -- Alaska's weekly oil & gas newspaper ph: (907) 644-4444, fax: (907) 522-9583 email: classifieds@gci.net http://www. PetroleumNewsAlaska.com Name: Notice Polaris.doc ~Notice Polaris.doc Type: WIN~ORD File (application/msword) I 1 of I 11/7/2002 5:26 PM John Katz State of Alaska Alaska Governor's Office 444 North Capitol St., NW, Ste 336 Washington, DC 20001 Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Alfred James 107 North Market Street, Ste 1000 Wichita, KS 67202-1822 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Mir Yousufuddin US Department of Energy Energy Information Administration 1999 Bryan Street, Ste 1110 Dallas, TX 75201-6801 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 Michael Nelson Pun/in Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe St. Houston, TX 77056-2799 T.E. Alford ExxonMobil Exploration Company PO Box 4778 Houston, TX 77210-4778 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Corry Woolington ChevronTexaco Land-Alaska PO Box 36366 Houston, TX 77236 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 W. Allen Huckabay Phillips Petroleum Company Exploration Department PO Box 1967 Houston, TX 77251 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Shelia McNulty Financial Times PO Box 25089 Houston, TX 77265-5089 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 James White Intrepid Prod. Co./Alaskan Crude 4614 Bohill SanAntonio, TX 78217 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Tim Ryherd State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Cammy Taylor 1333 West 11th Ave. Anchorage, AK 99501 Richard Mount State of Alaska Department of Revenue 500 West 7th Ave., Ste 500 Anchorage, AK 99501 Jim Arlington Forest Oil 310 K Street, Ste 700 Anchorage, AK 99501 Duane Vaagen Fairweather 715 L Street, Ste 7 Anchorage, AK 99501 Williams VanDyke State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Ed Jones Aurora Gas, LLC Vice President 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Julie Houle State of Alaskan DNR Div of Oil & Gas, Resource Eval. 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Robert Mintz State of Alaska Department of Law 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Susan Hill State of Alaska, ADEC EH 555 Cordova Street Anchorage, AK 99501 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 John Harris NI Energy Development Tubular 3301 C Street, Ste 208 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., ~t4 Anchorage, AK 99503 Rob Crotty C/O CH2M HILL 301 West Nothern Lights Blvd Anchorage, AK 99503 Jack Laasch Natchiq Vice President Government Affairs 3900 C Street, Ste 701 Anchorage, AK 99503 Mark Hanley Anadarko 3201 C Street, Ste 603 Anchorage, AK 99503 Mark Dalton HDR Alaska 2525 C Street, Ste 305 Anchorage, AK 99503 Judy Brady Alaska Oil & Gas Associates 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503-2035 Aden Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,Inc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 BP Exploration(Alaska),lnc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Dudley Platt D.A. Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Bob Shavelson Cooklnlet Keeper PO Box 3269 Homer, AK 99603 Peter McKay 55441 Chinook Rd Kenai, AK 99611 Shannon Donnelly Phillips Alaska, Inc. HEST-Enviromental PO Box 66 Kenai, AK 99611 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 Penny Vadla Box 467 Ninilchik, AK 99639 Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 John Tanigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box131 Fairbanks, AK 99707 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 Senator Loren Leman State Capitol Rm 113 Juneau, AK 99801-1182 #3 11/04/2002 17:58 FAX November 1, 2002 GPB RESOURCE DEV RECEIVED NOV 0 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 198612 Anchorage, Afaska 99519-6612 (907) 561-5111 BY FAX AND U.S. MAIL ~002 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7~ Avenue, Suite 100 Anchorage, AK 99501 Polaris Pool Rules and Area Injection Order Application Confidentiality of Certain Exhibits Dear Commissioners: The letter confirms and explains the basis for our request for confidentiality for certain Exhibits to the Polaris Pool Rules and Area Injection Order Application ("Application"). Our initial request for confidentiality was made in the cover letter to the Application dated September 12, 2002. Each of the confidential exhibits and documents that we have provided contain trade secrets. AS 45.50.940(3)provides that information qualifies as a trade secret if it "derives independent economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from.its disclosure or use, and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy." These exhibits include interpretations of geological and geophysical data or computer modeling methodologies. This information is used by the Polaris Owners to make development, exploration and leasing decisions, and is maintained as confidential. It cost substantial amounts of money to develop this information, and it has commercial value. Thus, under the applicable constitutional, statutory and common law doctrines that protect trade secrets, we request confidentiality' of this information be maintained by the Commission. In addition, in the interest of providing the Commission with a full view of Polaris development, the Polaris Owners have voluntarily provided a wide scope of information that is not required to be filed with the Commission under AS 31.05.035(a)J AccOrdingly, we also request confidentiality as to the marked exhibits pursuant to AS 31.05.035(d) and 20 AAC 25.537(b). These exhibits have been voluntarily submitted to the Commission, and are independently to be held confidential pursuant to AS 31.05.035(d) and 20 AAC 25.537(b). t The period of confidentiality applicable to the information in the Application that was required to be filed under AS 31.05.035(a) - i.e. certain well and flow test information - has expired. The exhibits containing that information is not marked "Confidential." 11/04/2002 17:59 FAX GPB RESOURCE DEV ....... ~003 We request that confidentiality be maintained indefinitely. To the extent any question is raised at the hearing for a limited need to disclose any of the confidential information, we assume that the Commission will follow the procedures specified in 20 AAC 25.540(c)(10). Please consider this letter as part of the Application and issue the notice of hearing without delay. If you would like more dialogue on these issues prior to issuing the notice, please contact Rosy Jacobsen (564-4151) as soon as possible so that we can schedule a meeting with you. Thank you. Sincerely, Gil Beuhler GPB Satellites Team Leader Cc: R. Smith (BP) M.M. Vela (Exxon/Mobil) J.P. Johnson (ConocoPhillips) S. Wright (Chevron Texaco) P. White (Forest Oil) ALASKA OIL AND GAS CONSERVATION COMMISSION. 333 WEST 7TH AVENUE, SUITE 100 ANCHORAGE ALASKA 99501-3539 FACSIMILE TRANSMITTAL SHEET TO: FROM: DATE: Rob Mintz Assistant Attorney General Total No. Of Pages Including Cover: q Re: NOTES/COMMENTS Phone No. (907) 793-1221 Fax No. (907) 276-7542 11/04/2002 17:58 FAX GPB RESOURCE DEV ~001 BP EXPLORATION BP Exploration (Alaska) Inc. PO Box 196612 Anchorage, Alaska 99519-6612 Date: TO: Name: FROM: Company: Location: TELECOPY COMMUNICATIONS CENTER NOTES: PAGES TO FOLLOW (~' (Does Not Include Cover Sheet) ' SECURITY CLASSIFICATION PRIVATE SECRET ~ONFIDENTIAL For Communications Center Use Only Telecopy # 564-5016 Time In , Time Sent Confirm # 564-5095 Time Confirmed Confirmed By ' ' _ NOV 0 4 ?~'~.,! AllkaOii &Gar, Cons. Commission A~lc~rage #2 October 31, 2002 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 RECEIVED OCT 31 2002 An p nlD RE: Polaris Pool Rules and Area Injection Order Application Dear Commissioners: This letter responds to your October 1, 2002 Email, which is attached to this letter and marked as Exhibit VII-1 to the Polaris Pool Rules and Area Injection Order Application ("Application"), requesting additional information. Please consider this letter and attachments as part of the Application and issue the notice of hearing without further delay. Miscible iniection {MI).' The Application includes a request for approval of injection of miscible injectant ("MI") to implement an Enhanced Oil Recovery ("EOR") project. By this letter, we withdraw that at this time. If the Polaris Owners decide to institute an MI-based EOR project in the future, an amendment of the Area Injection' Order and Pool Rules will be sought, as appropriate. Wells within the ¼-mile Area of Review (AOR) Your October 1, 2002 Email stated, "The Area of Review ("AOR") for the Polaris waterflood project extends a radius of ¼ mile from the base of the confining layer for each proposed injection well. Mechanical integrity must be demonstrated for each well within the AOR. Please provide a listing of every well within each AOR." After receiving this Email we clarified with Jane Williamson that the "confining layer" for each injection well would be defined as the top of the Ma sand. Exhibit VII-2 shows all Schrader Bluff penetrations at the Ma sand, and a ¼ mile radius is shown around the location of the point at which each existing and currently-planned injection well is estimated to intersect the top of the Ma sand. Currently, there are 3 Polaris injection wells that have been drilled and cased, W- 212i, $-215i and S-104i (dual Kuparuk and Schrader Bluff injector). This Application also provides information on the AOR for two additional proposed injection wells, W-207i and S-200i, which are planned to be drilled in the near future. Well bore diagrams for W-212i, S-215i and S-104i are attached as Exhibits VII-3, VII-4 and VII-5. Since W-207i and S-200i have not been drilled the well bore diagrams are not included, but will be provided with the AOGCC 10- 403 Form for each well. For any additional future injection well, information on the AOR and the well bore diagram will be provided with the AOGCC 10-403 Form. The following wells are within the AOR of these injection well locations: W-212i S-215i W-207i S-200i S-104i W-17 None Kuparuk State 22-11-12 S-03 None Kuparuk State 24-11-12 S-24A S-31A S-200 PB1 The Application as originally filed indicated the W-15 well was within the AOR of the W-212i well. Because of the clarification that the AOR should be determined by reference to the top of the Ma sands, this well is no longer within the AOR, while the Kuparuk State 22-11-12 is now within the AOR. Accordingly, attached as Exhibit VII-6 is a well bore diagram for Kuparuk State 22-11-12. Mechanical Inteqrit¥ Exhibit VII-7 provides references to the mechanical integrity standards used~in the preparation of the Application. Exhibits VII-8 to VI1-14 are data sheets constituting the "report on the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well, "by 20 AAC 25.402(c)(15). In addition, a summary of the AOR Schrader Bluff penetrations is shown as Exhibit VI1-15 as well as a comment on each penetration regarding confinement of fluids within the Schrader Bluff formation. Fracture Pressure Your October 1,2002 Email includes the following statement: "It is our understanding that fracture conditions discussed in the application were the result of injecting highly viscous fluids at high rates (15 barrels per minute) for the purpose of stimulating the well. During our discussion, you stated that these conditions represented a worst-case scenario, whiCh did not result in net pressures, sufficient to frac through the confining layer. 'Conditions for planned waterflood will be at lower rates (about 2 bpm) and result in lower net pressures, and are unlikely to cause fracturing through the confining layer. Should fracturing occur, fluids will remain within the Polaris Pool. In the unlikely event that the Mb2 mudstones above the planned injection interval is fractured, the water will preferentially enter the highly permeable Mb sands, which you are requesting as part of the Polaris pool. Please verify if we understood correctly." Your understanding is accurate. The following provides some additional technical information. The fracture conditions discussed in the Application were the results of data fracs, which were pumped prior to well stimulation treatments with a high viscosity (non-newtonian, cross-linked polymer) fluid at approximately 15 barrels per minute (bpm). Net Pressure, which is defined as the pressure above the closure pressure, is Pn-(E3/4/H)(uQL)I/4 where E-Young's Modulus, H= Frac height, u-viscosity, Q= Rate and L-frac length. Since we will be injecting water with a viscosity near 1 and at rates of approximately 2 bpm, it is unlikely that we can develop net pressures that approach what was measured during the data fracs. The net pressures developed during the data frac were below the confining stress barriers, measured during a stress test and validated with a DiPole Sonic Log. Even if fracturing did break through the Mb2 mudstones the water will enter the highly permeable Mb sands, which we have requested to be included in the Polaris Pool, where the pressure would dissipate. Other Information (from an earlier data request) Also enclosed are Exhibits V11-16, 17 and 18, three poro-perm crossplot figures (poro-perm from core data) - one each for the M, N, and 0 sands. 'questions or comments regarding this response. Sincerely, Please contact me at 564-5143, or Donn Schmohr at 564-5494 with any Gil Beuhler GPB Satellites Team Leader Attachments CC: R. Smith (BP) M.M. Vela (Exxon/Mobil) J.P. Johnson (CPAI) S. Wright (Chevron Texaco) P. White (Forest Oil) Exhibit VII-l, I of 2 ..... Original Message ..... From: Jane Williamson [mailto:Jane_Williamson@admin.state.ak. us] Sent: Tuesday, October 01, 2002 9:35 AM To: Schmohr, Dorm R Cc: Beuhler, Gil G; James B Regg; Stephen F Davies; John D Hartz Subject: Polaris Application - Outstanding Items within Area Injection Order Don, We would like to thank you for meeting with us yesterday to discuss outstanding issues concerning the Polaris Pool Rules and Area Injection Order. While your application submitted on September 12, 2002 was very well constructed, the Commission needs additional information within the Area Injection Order application before we can deem it complete. We recommend that BP make separate application for an MI-based Enhanced Oil Recovery project to prevent delay of the .current Polaris project. Miscible injection ("MI") presents numerous technical and regulatory challenges that have not been fully addressed in this application. Assuming that MI is excluded from this application, the following are clarifications and items we need within the Area Injection Order application. As noted in Jack Hartz's e-mail to Gil Buehler (September 17, 2002), confidentiality of exhibits will also need to be sorted out prior to deeming the application complete. Area of Review : The Area of Review ("AOR")for the pOlaris waterflood project extends a radius of ¼ mile from the base of the confining layer for each proposed injection well. Mechanical integrity must be demonstrated for each well within the AOR. Please provide a listing of every well within each AOR. Future injection wells not identified in the current application, will require submittal of a 10-401 (new Well permit) or 10-403 (conversion to injection) form, establishment of an N-mile AOR, and investigation of the mechanical integrity of each well within that AOR. Mechanical Integrity This issue is important at Polaris because of the presence of many older wells that may not have cement across the Schrader Bluff interval. You presented in spreadsheet that provides basic data on casing and cementing for wells within the AOR. This is an excellent starting point. For each well within' the ¼ mile AOR, please provide a copy of this spreadsheet, supplemented with following additional information: 1) A conclusion stating whether mechanical integrity has been established for the .subject well. 2) The basis' for that conclusion, which includes BP's definition of integrity. 3) If integrity cannot be demonstrated, a plan for repair or proposed surveillance must be provided. This plan must discuss limitations due to well construction and any integrity concerns that would trigger additional surveillance or repair. Exhibit VII-l, 2 of 2 A copy of the most recent schematic diagram for the subject well is required. Directional survey information and daily operations reports need not be included within the application. Fracture Pressure It is our understanding that fracture conditions discussed in the application were the result of injecting highly viscous fluids at high rates (15 barrels per minute) for the purpose of stimulating the well. During our discussion, you stated that these conditions represented a worst-case scenario, which did not result in net pressures which would be sufficient to frac through the confining layer. Conditions for planned waterflood will be at lower rates (about 2 bpm) and result in lower net pressures, and are unlikely to cause fracturing through the confining layer. Should fracturing occur, fluids will remain within the Polaris Pool. In the unlikely event that the Mb2 mudstones above the planned injection interval is fractured, the water will preferentially enter the highly permeable Mb sands, which you are requesting as part of the Polaris pool. Please verify if we understood correctly. Jane Williamson- 'Reservoir Engineer Steve Davies - Petroleum'Geologist Jim Regg -' Petroleum Engineer Alaska Oil and Gas Conservation Commission i~'.~laris Pool/Injection Ai~'..a Exhibit VII-2 Schrader Bluff Top ~a Sand Well Penetration Locations ~ s~os ~, ~, / Auro~Polaris InJector)f ~ ~ - 6 ~ ' 15 1 ~ 13 18 17 _ ~ ..... ~ Q . . . .5000F°ot X,. w ~~ j 0 ~ .5 Miles . -~ ~ .... . Red Outline - Polaris Pool/Injection Area and Polaris PaAicioatin~ Area Polads Well Polaris ~ 1/4 Mile Radius Circle around · Pene~'ation at top · Injection Well Existing or Proposed Polaris Ma Sand ~ InJeclion wells Exhibit VII-3 TREE = Rvl( IWR LHEAD = 11" FMC L~?U_~T_°E_=.. ............... IKB. ELEV = 84.1' IB~=. ELEV = 50' IKOP = __ 700' IMax Angle = 39 @ 2750' JDatum IvO = 5878' J9-5/8" CSG. 40#. L-80, ID = 8.835" JMinimumID = 3.725" (~ 5tt4' I 4-112" HES XN NIPPLE I I W-212 J SAFETY NOTES 9-518" TAM PORT COLLAR J 4-1/2" HES X I~IP, ID = 3.813" J GAS LIFT MAI',E)RELS 4-112" HES XNIP, ID = 3.813" J J 4.1/2" TBG, 12.6#. L-80. TQI, 0.0152 bpf, ID= 3.958" 5126' PERFORA'IION SUMMA RY RB: LOG: ANGLE AT TOP PERF: Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE ~-I 62"12' I 17.' csc'' 26#' L'8°' ID= 6.'276.' Id 6320' 4-1/2" X 7-5/8" BKR S-3 PKR. ID= 3.875" J 4-112" HESX NIP, ID = 3.813" J HFS ~ NIP, ID = 3,725" J H ELIvD TT NOT LOGGED J !---{ 5733' I'-I 7" FLIP,.IT W/RA TAG J DATE REV BY COIVlvlENTS DATE REV BY COMMENTS 04113/02 JLM/KK iORIGINAL COMFLETION PRUOHOE BAY UNIT WELL: W-212 FERMT No: 2020660 APl No: 50-029-23078 SEC. 21, T11N, R12E 906' SNL, 1185'WEL BP Exploration (Alaska) Exhibit VII-5 TREE = 4-1116" OW WFI LHEAD = FMC SAFETY NOTE~: .^ S 104 KB. B_EV = 64.50' KO~ = 750' Max ^nglo = 57 ~ 3230' IX~tum bt~ = 0100' Datum TVD = 7000' SS I I-- - -C~~-I 4-112" HES X NIP' ID = 3'813" I [9-~" cs,. 40#. L-80. ID= 6.835" Mini.m,,um ID = 3.725" (~ 8724' I FRODUCTIONMANDRELS 4-1/2 HES XN NIPPLE , ST IVO ' TVD . DEV TYPE VLV LATCH PORT DATE 3 6920 5046 29 KBG-2-T/L DMY BK 0 02/07101 17"MARK~(20')W/RATA~I~'I 2 7117 5218 30 KBG-2-T/L DMY: BK 0 02/07/01 1 7266 5347 30 KBG-2-T/L DMY : BK 0 02/07/01 14-1/2" TBG JT #40 W/RA TAG ]'-~~~ I I--~-I4'1/2" HES X ~P' ID = 3'813" I PERFORATION SUIVIMARY "]-"j--' --"J 7035' 4-1/2" B~R ClVlU SLICING SLV___~, OT'_~S PROF..____~, ID__~= 3.812___~" ANGLE AT TOP I:ERF: 29 Note: Refer to Production DB for historical perf data SIZE SFF INTERVAL !Opn/Sqz DATE ~ m~ 4-5/8" 6 7114- 7124 O ' 02104101 ~____ 4-1/2"BKRCMUSLI~INGSL¥,OIISFt~OF, lD=3,612" 4-5/8" 6 7162- 7182 0 02/04/01 4-5/8" 6 7216- 7266 O 02/04101 ' J 4-5/8" 6 7280. 7302 O 02/04101 4-518" , 6 7325- 7346 O 02104/01 3-3/8" I 6 8810- 8840 O 03/26/01 I , I ::g:: iB --~d 7"X4-1/2"BKRSABL'3R<R'ID=3'875" I I I'~-J 4" 1/2" HES X r',lP. ID = 3.813"I I J--~--[ 4-1t2" HES XN NIP, ID = 3.725" ] , , , JlI J-J ELMDTT NOT LOGGED I , DATE REV BY COMMENTS DATE REV BY COMMENTS FRUDHOEBAY UNIT/AURORA FIFID 02/09/01 ORIGINAL COIVlPLETION WFIL: S-104 02/10/01 Cismoski CORRECTIONS I F~RMT No: 200-1980 06/11101 GRC/~lh F:~RF CORRECTION , APl No: 50-029-22988-00 09/03/01 KSB/tlh NIPPLE ID CORRECTION ~ SEC 35, T12N, R12F_. 4646' NSL & 4494' WB_ 04/09/02 RN/CH/TP CORRECTIONS IBP Exploration (Alaska) ST IVO TVD DEV TYPE VLV LATCH PORT DATE 3 6920 5046 29 KBG-2-T/L DMY BK 0 02/07101 2 7117 5218 30 KBG-2-T/L DMY BK 0 02/07/01 1 7266 5347 30 KBG-2-T/L DMY BK 0 02/07/01 SIZE SFF INTERVAL Opn/Sqz DATE 4-518" 6 6920 - 6980 O 02/04101 4-5/8" · 6 7018- 7050 O 02/04/01 4-5/8" 6 7070- 7094 O 02/04/01 4-5/8" 6 7114- 7124 O 02/04/01 4-5/8" 6 7162- 7182 O 02/04/01 4-5/8" 6 7216- 7266 O 02/04101 4-5/8" 6 7280. 7302 O 02/04101 4-518" 6 7325- 7346 O 02104/01 3- 3/8" 6 8810- 8840 O 03/26/01 DATE REV BY COMMENTS DATE REV BY COMMENTS 02/09/01 ORIGINAL COIVlPLErlON 02/10/01 Cismoski CORRECTIONS 06/11101 GRC_Jtlh FERFCORRECTION 09/03/01 KSB/tlh NIFPLE ID CORRECTION 04/09/02 RN/CH/TP CORRECTIONS Well K221112 Observation Well 3O", 156 ppf 2O", 94 ppf 13-3/8", 72 ppf Top Ma Top Kuparuk Packer 4-1/2" 12.75 ppf 7", 29 pPf 71' 735' 2,723' 4813' 6236'? 9579' 9657' 10,172' 1991' 2257' 1496'? 2925' 2869'? 4051' 4198' 5749' 6633' 9621' 9832' 9935' Exhibit VII-6 Arctic Pack to surface in 7"x13- 3/8" annulus Downsqueeze of 13-3t8" x 20" annulus Unknown TOC. Calculated to surface, but lost returns X Profile Halliburton FO Collar 260 sx Permafrost cmt (Used 0.97 yield) Halliburton .FO Collar 218 sx Pei'mafrost cmt (used 0.97 yield, 30% excess) Halliburton FO Collar 227 sx class G cmt (Calc TOC w/3()°,~, ex(;oss') Hallibudon FO Collar Calculated TOC w/30% excess taken into account. XN Top Perforations Base Perforations Exhibit VII-7 Standards of Mechanical Inteqrity The following Application assumes that the standards in the Commission's regulations apply to the operations described in the Application. In particular, a Polaris Pool injection well is considered to have mechanical integrity if it satisfies the requirements provided in 20 AAC 25.412, and a Polaris Pool production well is considered to have mechanical integrity if it is cased and cemented in accordance with 20 AAC 25.030 and complies with the requirements of 20 AAC 25.200. Standards of Confinement A penetration not completed within the Polaris Pool is considered to provide confinement of injection fluids within the Polaris P0ol if calculations show the top of cement is above the top of the Ma sand and the cement job appears to have been pumped successfully, or if cement evaluation logs are available that show cement above the lower Ugnu and below the Schrader Bluff Formations, or if the penetration is far enough from the injector that it is reasonable to assume the reservoir pressure at that point will not rise above original reservoir pressure. Participating Area(s) Covered Well: IS-03 I ~]Polaris PA Status: ~GL-O I I x IAurora PA Nearest Polaris Injection Well:I . S-200iI Distance from Polaris Injector:! 5491Feet Hole angle at Ma:I 55.06JDegrees - Top Ma Sand:~ 4644~TVDSS MD at Top Ma Sand:~ 5580~MDBKB Intermediate Casin.q Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure 73021feet 12.251inches 9.625~inches 154~BBL 5264~MDBKB 46531MDBKB !es I(revised) ~'es 13000 psi I30001psi IPSi no see note no no n/a n/a Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Schrader: 2200 psi Pri at Datum depth of.' Kuparuk: 3400 psi Pri at Datum depth of: X Y 617495 5981327 615468 5983163 617349 5981856 617425 5985037 Schrader Kuparuk S-200i: S-104i Surface Casinq Data Bond Log ? Nearest Aurora Injection Well:I Distance from AUrora Injector:l Hole angle at Kuparuk:I 6700' TVDss Datum:il INo 5000 TVDSS 6700 TVDSS Exhibit VII-8, 1 of 2 Completed: 11982 S-1041;Degrees 2,7101Feet 8797JMDBKB 47Ppf, L-80I 8'6811inches I 862.51CF 11.15 7501sacks (Yield) 2,649]linear feet cement Tag Cement ! 71781feet CMT type Class G Wt Slurry IPPg 151minutes Iminutes Comments IThis well had an extra string of pipe run after 9-5/8" wouldn't go down. Has 7" across Kuparuk. lpsi IOA min psi psi Comments rises above 600 psi, but bleeds quickly. ID IConclusions: OA has been downsqueezed ft land IA is on gas lift, so normal monitoring ft iprogram might not work. Based on TOC Icalculations, cement should be above the ISchrader Bluff. Recommend sidetracking S- J200i further away from this well prior to linjection in Schrader Bluff nearby. TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe lrack, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? INOA Pressures 26941feet 17.5~inches 13.375~inches __~.~BBL -13521MDBKB -25661MDBKB 47ppf, L-80 I 12'3751inches 3720.251CF 11.15 3235~sacks (Yield) 5,2601linear feet cement Tag CementI 26381feet CMT type IArcticset II I Wt Slurry I 15~21Ppg 151minutes 301minutes 2000 psi 30001psi 875~psi I Comments 13-3/8" x 9-5/8" was downsqueezed with 280 CF Arcticset I followed by 120 bbls Arctic Pack. TBG IA OA WHT S-03 Pressures no no note Isee note Ino Date · · eTBG m · ~lm II IA &OA · && & & 12/7/92 12/7/93 12/7194 12/7/95 12/6/96 12/6/97 12/6/98 12/6/99 12/5/00 12/5/01 ID Participating Area(s) Covered Polaris PA Aurora PA Well: IS-03 Status: IGL, O IS-03 was drilled in 1982. The 9-5/8" casing did not go to:bottom and once it was cementedin Place, a 7' liner was run to Intermediate hole TD. The OA was downsqueezed with 280 CF cement in order to ensure the Arctic Pac held. The well is currently flowing on gas lift. Exhibit VII-8, 2 of 2 Intermediate Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casir~g Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Planned ! Actual Injectors Kuparuk S-101i HAW S- 104i S-107i (HAW) S-112i (HAW) S-114i Schrader S-104i(S) Existing S-200 S-215i In/a I IThis well had an extra stdng of pipe I Irun after 9-5/8" wouldn't go dOwn. IHas 7" across Kuparuk. 118401feet T°P°f liner I 67891feet . 9.6251inches 71inches 26 ppf, L-80 6.2761inches ID 4101BBL I 2300 CF {1.15 I 44621MDBKB*** J sacks (Yield) 2249JMDBKB*** 9,591 linear feet cement **Calculates to above top of liner, so number invalid *** These depths don't include 200 sX liner lap squeeze. (revised) Tag CementI 67081feet * See Notes CUT type IClassG I . Wt Slurry I IPPg - 3000 psi Ips~ note 151minutes * See Notes Iminutes Comments IThis well had an extra string of pipe run after 9-5/8' wouldn't go down. Has 7" across Kuparuk. *Initially did not tag cement and liner lap broke down, so squeezed liner lap with 200 sks Class G. After that, pressure tested to 3000 psi and tagged cement as noted. Distance from this well to planned injectors X Y TVDSS MDBKB 614,153 5,979,739 617,425 5,985,037 612,115 5,986,558 619,614 5,980,537 607,096 5,986,083 Incline Distance 618235 5984886 617349 5981856 617648 5977425 W-207i 619324 5957278 W-212i 614095 5959817 Top -6619 8,516 65 -6700 8,797 8 -6564 11,707 59 -6559 6,766 48 -6700 15,503 26 Ma -4743 6,941 29 -4629 5,889 20 -4655 6,256 46 3,668 feet 2,710 feet 4,772 feet 4,908 feet 8,866 feet 3,635 feet 549 feet 3,905 feet -4638 -4520 5,852 30 24,118 feet 21,777 feet Participating Area(s) Covered Well: IS'24A I [~]Polaris PA Status: ~INJ-MI ~ I x IAurora PA Nearest Polaris Injection Well:I S-200iI Distance from Polaris Injector:I 1,287~Feet Hole angle at Schrader:I 39.86~Degrees Top Ma Sand:I 46891TVDSS MD at Top Ma Sand:~ 5257~MDBKB Intermediate Casing Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT (New S-24A wellbore) 101801feet 9.8751inches 71inches 2501BBL I 60991MDBKB 48751MDBKB Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze /Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations/Restrictions Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Schrader: 2200 psi Pri at Datum depth of: 5000 TVDSS Kuparuk: 3400 psi Pri at Datum depth of: 6700 TVDSS X Y ~18260 .5980947 617111 5982221 617349 5981856 617420 5985036 Schrader Kuparuk S-200i: S-104i: 14031CF 11.15 Isacks (Yield) 5,305llinear feet cement I~Yes I. Tag Cement CMT type 101001feet IYes I Wt Slurry IPPg lYes 13000 psi I i .oool.s I 301minutes Ipsl Iminutes Comments l Yes I 18_24 was sidetracked above Schrader. 9- No I 15/8" csg was cut and pulled to 13-3/8" shoe I land cemented off prior to kick-off. No ! No No 3/15/20021 30001psi Imin 13251 psi 1050Jpsi Comments 3/15/02, MITOA failed, OA shoe not competent (seals passed). LLR = 4 bpm @775 psi. Plan is to MITIA and re-MITOA. n/a Jft n/a Jft Yes Conclusions: S-24A is an Ivishak WAG injector, and therefore is monitored on a regular basis. No additional monitoring program is recommended, Gauge hole calcs show that cmt would be above the Schrader Bluff, but 30% excess calcs do not. The well is considerable distance from the planned injector so no problems are expected. Exhibit VII-9, 1 of 2 Completed: J 1999 J 11990 I Nearest Aurora Injection Well:lS-104i I Distance from Aurora Injector:I 2,832[Feet Hole angle at Kuparuk:i 34.311Degrees 6700' TVDSS Datum:I 79021MDBKB Surface Casinq Data (original S-24 completion in 1990) Bond Log ? JNo J TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze ! Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IA/OA Pressures lYes Yes Yes Yes lyes ISee Note See Note No No No No 2694Jfeet 17.5Jinches 13.375Jinches 47ppf, L-80 5881BBL I 32991CF I I '9591MDBKB I Isacks (Yield) -2055~MDBKB 4,7491linear feet cement Tag CementJ Jfeet JCMT type JArcticset II & III Wt Slurry J12.1 to 15.2Jppg 2000 psi J 3000Jpsi Jminutes IPsi I Iminutes Comments IS-24 was sidetracked above Schrader. 9.I 5/8" csg was cut and pulled to 13-3/8" shoe and cemented off prior to kick-off. Date TBG IA O.._~A WHT 8-24A Pressures &OA al · 12/6/98 12/6/99 12/5/00 12/5/01 12/5/02 Participating Area(s) Covered E P olaris PA Aurora PA Well: IS-=4^ I Status: lIN J-MI I IS-24 was drilled in 1990 as a producer and sidetracked above the Schrader Bluff interval in 1999 as a WAG injector. The original hole was completely abandoned below the surface casing shoe. Intermediate Casing Data Bond Log across Schrader? Bond Log across KuParuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess.* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above InjeCtion Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? -' Rig Squeeze? RWO to repair csg (cut & pull)? Planned ! Actual Injectors Kuparuk S-101i HAW S-104i S-107i (HAW) S-112i (HAW) S-114i Schrader S-104i(S) Existing S-200 S-215i IIThis is for the odginal 9-5/8" casing in S-24. It was I labandoned in 1999. 98431feet 12.251inches 9.6251inches 3631BBL 48321MDBKB 33291MDBKB Top of liner I Ifeet 26 ppf, L-80 20401CF 11'151 Isacks. (Yield) 6,5141linear feet cement J3000JPsi IPSi Tag Cement CMT type Wt Slurry Jminutes Jminutes Comments feet ppg IThis is for the original 9-5/8" casing in S-24, An EZSV Iwas set at 3020' and the 9-5/8" csg was cut and labove 2669'. . pulled I Distance from this well to planned injectors X Y TVDSS MDBKB 614,153 5,979,739 617,425 5,985,037 612,115 5,986,558 619,614 5,980,537 607,096 5,986,083 618235 5984886 617349 5981856 617648 5977425 Top Incline Distance -6619 8,516 65 3,861 feet -6700 8,797 8 2,834 feet -6564 11,707 59 6,616 feet -6559 6,766 48 3,017 feet -6700 15,503 26 '10,734 feet Ma -4743 6,941 29 3,939 feet -4629 5,889 20 1,287 feet -4655 6,256 46 3,575 feet Exhibit VII-9, 2 of 2 W-207i- 619324 5957278 W-212i 614095 5959817 -4638 23,693 feet -4520 5,852 30 21,537 feet Participating Area(s) Covered ]Polaris PA Aurora PA Nearest Polaris InJection Distance from Polaris Injector: Hole angle at Schrader:~ Top Ma Sand: MD at Top Ma Sand:l Intermediate Casing Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor INOA Pressures? Well intervention required? Okay for water injection? Well: IS'31A I Status: ~Sl-W ' S-200iI 1,2851Feet 42.751Degrees 4674~TVDSS 53641MDBKB Schrader: 2200 psi Pri at Datum depth of: Kuparuk: 3400 psi Pri at Datum depth of: X Y 618395 5981109 617038 5982428 617349 5981856 617425 5985037 Schrader Kuparuk S-200i S- 104i Surface Casin,q Data Bond Log ? I107831feet 12.25Jinches 9.625~inches 47ppf, NT-80 4171BBL 23431CF I 50281MDBKB Isacks (Yield) 33021MDBKB 7,48111inear feet cement 106091feet Class G I 13.SlpPg 15.81ppg minutes minutes Tag Cement CMT type Lead Cmt Tail Cmt 30001psi IPSi I No No No No Comments Comments I6/1/20021 ISlow TxlA communication (below failing 35001PSi Irate). Currently being monitored for Iow OA 301min Iflu'id level (120', 7 bbls on 6/24/02). Will be 2375~psi ~H20 onlydue to Sag not taking MI. 3801psi I Conclusions I n/a Ift IShould monitor IA and OA on a regular n/a Ibasis once S-200Ai is put on injection IsNeOo Note I I (-1100' away)' Probably has'cement Nearest Aurora Injection Well: Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: Exhibit VII-10, 1 of 2 5000 TVDSS Completed: 12002 6700 TVDSS (original) ~1990 Feet Degrees MDBKB INo TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? IBumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IA/OA Pressures 26941feet 17.51inches 13.3751inches 47ppf, L-80 6631BBL I 3723JCF I ! -1429]MDBKB I Isacks (Yield) -26661MDBKB 5,3601linear feet cement lYes I Tag Cement126647 Ifeet ICMT type IArcticset II I iWt Slurry I 15.2jppg 30001psi Iminutes 15.21EMW I Iminutes No No No No No Comments Date TBG IA OA WHT S-31A Pressures · TBG [] IA · OA [] · ® · , 12/7/95 12/6/96 12/6/97 12/6/98 12/6/99 12/5/00 12/5/01 12/5/02 Participating Area(s) Covered Polaris PA- Aurora PA Status: ISI-W The.original S-31 well was drilled in 1990 as a producer. In 2002, it was coiled tubing sidetracked below the 9-5/8' casing as a Sag River WAG injector. Although the well passed its original MITIA for MI, the Sag would not take MI. In future, well will inject water'only. Also, there is a slow leak between tbg and IA - below fail rate. Exhibit VII-10, 2 of 2 Intermediate Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size . Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? - Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Planned ! Actual Injectors Kuparuk S-101i HAW S- 104i S-107i (HAW) S-112i (HAW) S-114i Schrader S-104i(S) Existing S-200 S-215i W-207i W-212i No intermediate liner I I Ifeet Top of liner I Ifeet 9~6251inches 71inches 26 ppf, L-80 CF 01MDBKB _ sacks (Yield) 01MDBKB 01linear feet cement (revised) Tag Cement~ I feet CMT type ! ] Wt Slurry / IPPg I IPsi I Iminutes Comments Distance from this well to planned injectors X Y TVDSS MDBKB InCline Distance 614,153 5,979,739 -6619 8,516 65 617,425 5,985,037 -6700 8,797 - 8 612,115 5,986,558 -6564 11,707 59 619,614 5,980,537 -6559 6,766 48 607,096 5,986,083 -6700 15,503 26 Top Ma 618235 5984886 -4743 6,941 29 617349 5981856 -4629 5,889 20 617648 5977425 -4655 6,256 46 .. · 619324 5957278 -4638 614095 5959817 -4520 5,852 30 3,944 feet 2,638 feet 6,426 feet 3,196 feet 10,592 feet 3,780 feet 1,285 feet 3,759 feet 23,849 feet 21,722 feeti Participating Area{s) Covered Well: Polaris PA Status: IP&A Aurora PA Nearest Polaris Injection Well:I S-200iI ' Distance from Polaris Injector:l 2791Feet Hole angle at Schrader:~ 0.76lDegrees Top Ma Sand:l 46521TVDSS MD at Top Ma Sand:~ 5394~MDBKB Intermediate Casin,q Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Retums? Floats Held? Bumped Plug? Casing Pressure Test FIT 44761feet 8.51inches 71inches 481BBL 29451MDBKB 24861MDBKB Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure CA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor INCA Pressures? Well intervention required? Okay for water injection? S-200 ISchrader: 2200 psi Pri SI-P ~Kuparuk: 3400 psi Pri X Y 617566 5981681~ 617349 5981856 at Datum depth of: at Datum depth of: Nearest Aurora Injection Well: Distance from Aurora Injector: Hole angle at Kuparuk: 6700' TVDSS Datum: nla Schrader Kuparuk S-200i Surface Casin.q Data Bond Log ? Exhibit VI1-11, 1 of 2 5000 TVDSS Completed: 11998 6700 TVDSS 01F¢;gtrees IMDBKB 26 ppf, L-80 I 6'2761inches I ICE. 11.15 Isacks (Yield) 1,990~linear feet cement lYesI Tag Cement ' ~4412?lfeet Slurry ! 15-81Ppg CMT type IClass lYes 3500 psi Iwt I 35001psi 301minutes ! 12.5~ppg EMW ~ lminutes Comments l Yes I IDrilled and cored original well to 6150' MD. Yes ~ ~Plugged back to 4471' with two stages of cmt Yes ~ l(each 83 bbls 17ppg Class G) and dressed off No ~ itc 4488' (Wt test 15k). Ran and cemented 7" No J Icsg. Then drilled final hole to TD. No r i/26/2002i : 35001psi - [min lpsi - iPsi Comments ID ~fffflC°nclusi°ns: ~)riginal °penh°le plugback lappears acceptable for injection nearby. No In/a IISurface casing I°°ks °kay and intermediate I Icement job seems adequate for injection near IyNe°s I'this well' Rec°mmend g°°d plugback °f s' ' 1200 liner prior to sidetrack to new injector Ilocation, to confine fluids. TOC Calculation Shoe Depth Hole Size Csg Size · lVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze / Top Job? ' Rig Squeeze? RWO to repair csg (cut & pull)? IA/CA Pressures 31581feet 12.251inches 9.625~inches 5841BBL -48151MDBKB -72071MDBKB 47 ppf, L-801 8.6811inches ID ICE 11.15 lsacks (Yield) 10,3651linear feet cement lYes Yes Yes I Tag CementI ICMT type ICo~d Lead Cmt ~ 1500 psi JTail Cmt I 30401feet Set III / Class G 12.21Ppg 15.8Jppg 35001psi |psi 30Jminutes Iminutes Comments Yes Yes 2 stage cement job thru HES ES Cementer Yes (-2172'). 1st stage 100 bbls cmt, circulated No out above the ES and saw 61 bbls cmt No return. 2nd stage put red dye in and saw at No surface. Date TBG IA CA WHT S-200 Pressures ·TBG I IA [] &CA [] · , , , & ,,& , ,& , , 12/6/99 3/15/00 6/23/00 10/1/00 1/9/01 4119/01 7/28/01 11/5/01 2/13102 PartiCipating Area(s) Covered Well: JS-200PB1 ~ S-200 I ~]Polaris PA Status: I Sl-P I IAurora PA. - IThis well was originally named SB-01. It was drilled as an S-Pad data gathering and pilot produciton well. IThe well was cored in the S,200PB1 leg, open hole plugged back with cement and then sidetracked to Ithe current S-200 bottom h01e location which now has a collapsed liner which was milled thrOugh during I remedial attempts. S-200 is being considered for sidetrack as an injector. Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess*, ** Calculated TOC, gauge hole*, ** '~Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? .Casing Pressure Test FIT Other Issues Side[racked above InjeCtion Zone? I= P&A Well? I No MultiPle Stages? No Downsqueeze / Top Job? n_../a Rig Squeeze? I No RWO to repair csg (cut & pull)?I~° Planned / Actual Injectors Kuparuk S-101i HAW S-104i S-107i (HAW) S-112i (HAW) S-114i Schrader S-104i(S) Existing S-200 · S-215i 3-1/2' production liner ~s across the I Schrader Bluff formation. ' I I 63101feet Top of liner I 43271feet 61inches . 3.51inches 9.3 ppf, L-80 2.9921inches ID 691BBL I CF 11.15 I 40321MDBKB I sacks (Yield) 33491MDBKB 2,961 linear feet cement **Calculates to above top of liner, so number invalid .... Tag Cement CMT type Wt Slurry feet PPg iminutes Iminutes Comments IPossible'collapsed liner at 5746' MD. While trying to mill through restriction, went out the liner with mill assembly. Considering sidetrack to injector location. DiStance from this well to planned injectors X . 'Y TVDSS MDBKB Incline DistanCe 614,153 5,979,739 -6619 8,516 617,425 5,985,037 -6700 8,797 612,115 5,986,558 -6564 11,707 619,614 5,980,537 -6559 -6,766 607,096 5,986,083 -6700 15,503 Top Ma -4743 -4629 -4655 618235 5984886 6,941 . 617349 5981856 5,889 -617648 5977425 6,256- 65 8 59 48 26 29 20 46 6,011,195 feet 6,016,800 feet 6,017,771 feet 6i012,549 feet 6,016,789 feet 3,274 feet 279 feet 4,257 feet W-207i 619324 5957278 -4638 W-212i 614095 5959817 -4520 5,852 30 24,466 feet 22,138 feet Exhibit VI1-11,2 of 2 Participating Area(s) Covered [Polaris PA Aurora PA Nearest Polaris Injection Well: Distance from Polaris Injector: Hole angle at Schrader: Top'Ma Sand: MD at Top Ma Sand: Intermediate Casin,q Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? Well: K221112 J Status: Observation W-207iI proposed 771 ~ Feet 39.11Degrees 45801TVDSS 48'I31MDBKB JNo ICBL from TD to 8700' Schrader: 2200 psi Pri Kuparuk: 3400 psi Pri X Y at Datum depth of: at Datum depth of: Schrader ~'18629 5956944 Kuparuk W-207i 619324 5957278 Surface Casino Data Bond Log ? Nearest Aurora Injection Well:ln/a Distance from Aurora Injector:~ Hole angle at Kuparuk: 6700' TVDSS .Datum JNo Exhibit V11-12, 1 of 2 5000 TVDSS 6700 TVDSS 01Feet 24.471Degrees 72641MDBKB P&A:C°mpleted: 11976/80i TOC Calculation 101721feet 8.5linches 71inches 1071BBL 66331MDBKB 55721MDBKB lYes psi psi 29 ppf S-95 ! 6'1821inches 6001CF 11.2 5001sacks (Yield) - 4,6001linear feet cement Tag CementI Ifeet CMT type Class G VVt Slurry ~16-17 IPPg I minutes minutes Yes No See Note No Yes No Comments: Left fish in hole and ST around it (cemented back from 4831-5575'). Original cement job did not cover Schrader, but when well-was suspended, cemented behind 7" csg through FO collars at 5749' (227 sx class G), 4051' (218 sx Permafrost), and 2925' (260 sx Permafrost). 5/4/1980 I 15001psi . Imin IPSi IPSi J n/a Jrt n/~ Jft Comments: Tested without tubing, before running 4-1/2" to complete as an observation well. Conclusions ID Well appears to have cement isolation around Schrader. Visually inspect location and record pressures prior to injection start-up. Check again 6 months after start-up and yearly afterwards until well is suspended or abandoned. Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IA/OA Pressures r~l~ ~1~ k~rz~ 27_.~feet 17_~.5inches 13.3_:.~.Jinches 10_.9.~ BBL -38471MDBKB -58181MDBKB J 12.375Jinches 60001CF 11.2 50001sacks (Yield) 8,541 ~linear feet cement Jsee No Yes No Note Tag CementJ Jfeet JCMT type JArcticset II Wt Slurry J IPPg I 3000Jpsi Ipsi J Jminutes Jminutes Comments ILost retums when 4800 sx in, observed slight traces of cement with return. Ran 2-3/8" tbg.. in 13-3/8"x20" annulus to 240' and cement~ to surface with 150 sx Permafrost cement. Return good cmt to surface. Date TBG IA OA WHT No Pressures Available for K221112 · TBG al IA · OA 110100 110100 110100 110100 110100 111100 111100 Participating Area(s) Covered Well: IK221112 I [~Polaris PA Status: IObservation L..JAurora PA This exploration well was drilled and suspended in 1976. Suspension placed cement above and I below Schrader Bluff (see diagram). Well was recompleted as an ObservatiQn Well in 1980, when I Icement plugs were drilled out, perforations were squeezed in order toget a good test on the 7' casing,[ Ithe well was reperf°rated and 4'1/2" tubing was run' ' ' I Initial Surface Casinq Bond Log across Schrader? Bond Log acrOss Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped' Calculated TOC, 30% excess*, ** Calculated TOC, gauge hole*, ** *Assume 80' shoe track, all cases - Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues lin this w~ll, an extra string of surface casing was run initially, to only 735 feet. Have summary data only. 7351feet 261inches 20linches 691 IBBL -1166~MDBKB -17361MDBKB Ipsi psi Top of liner I Ifeet 94 ppf, H-401 19.!241inches ID 38801CF I0-97 '1 40001sacks (Yield) 2,471 Jlinear feet cement Tag Cemenl~ Ifeet CMT type /Permafrost Wt Slurry ] ]ppg minutes. minutes Comments Sidetracked above Injection Zone? i P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Planned / Actual Injectors Kuparuk S-101i HAW S - 104i S-107i (HAW) S-112i (HAW) S-114i Schrader S'104i(S) Existing S-200 S-215i Distance from this well to planned injectors X Y TVDSS MDBKB 614,153 5,979,739 -6619 8,516 617,425 5,985,037 -6700 8,797 612,115 5,986,558 -6564 11,707 619,614 5,980,537 -6559 6,766 607,096 5,986,083 -6700 15,503 . Top Ma 618235 5984886 -4743 6,941 617349 5981856 -4629 5,889 617648 5977425 -4655 6,256 Incline 65 8 59 48 26 29 20 46 Distance 6,011,195 feet 6,016,800 feet 6,017,771 feet 6,012,549 feet 6,016,789 feet 27,945 feet 24,945 feet 20,504 feet Exhibit VI1-12, 2 of 2 ~1976 Suspension: The well was suspended with cement plug at 9936' (27 sx cmt, tagged at 9810'). Set another plug at 8575' (18 sx cmt, tagged at 8460'). Cemented behind 7' casing through FO collar at 5749' w/227 sx class G (16.2 ppg) and closed and tested to 1000 psi. Cemented behind 7" csg through FO collar at 4051' w/218 sx Permafrost. Tested closed FO collar to 1000 psi. Set EZ drill bridge plug on wireline at 3420' with 40 sx Permafrost, tagged at 3312'. Cemented behind 7" casing through FO collar at 2925' w/ 260 sx Permafrost. Tested closed FO collar to 800 psi. Set BP at 2429', cmt w/40 sx Permafrost and tagged at 2406'. Displaced 7" x 13-3/8" annulus w/260 bbls Arctic Pac through FO collar at 2257'. Displaced 7" from 2203'. to surface w/120 bbls Arctic Pack. 1980 Recompletion: In 1980, drilled thru cement plugs, squeezed and reperforated. Ran 4-1/2" tubing to 9657', with packer at 9579'. Recompleted as Observation Well. W-207i 619324 5957278 -4638 W-212i 614095 5959817 -4520 5,852 30 771 feet 5,368 feet Participating Area(s) Covered Well: IK241112 Polaris PA Status: IP&A I IAuroraPA Nearest Polaris Injection Well:I - W-207iIproposed Distance from Polaris Injector:I 5451 Feet Hole angle at Schrader:I 51.891Degrees Top Ma Sand:l 4639rrvDss MD at Top Ma Sand:l 49881MDBKB Intermediate Casina Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT ' Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (Cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do not inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? I117131feet 12.51inches 9.625Jinches 107~BBL 10457~MDBKB 100801MDBKB Schrader Kuparuk W-207i Schrader: 2200 psi Pri Kuparuk: 3400 psi Pri X Y 6"~9,852 5,957,413 623,614 . 5,958,t38 619324 5957278 i 43.5 ppf, RS-~ : 8.7551inches 6001CF 11.2 5001sacks (Yield) 1,6331linear feet cement JNo I Tag Cement see note I CMT type see note { Wt Slurry see note I I Class G Ifeet 161PPg iminutes ~minutes No Yes No qo Yes No ID Comments: The initial job was meant only to seal off Sag and Ivishak. Could not break cimulation with 4000 psi. Drilled out float collar, still couldn't circulated. Drilled out shoe at 11,695 and established circulation. Ran retainer to 11,600 and cemented 9-5/8" casing with 500 sx.Class G w/18% salt. Casing later P&A'd adequately (see other notes). This well was P&A'd in 1976. 16/??/76 I 10001psi 151min iPsilpsi IC°mments: Conclusions ftff. JThis well was P&A'd in 1976, with cement Iplaced behind pipe betWeen the Sag River land Kuparuk, the Kuparuk and Schrader IBluff, and above the Schrader. No monitoring Jpossible. 9-5/8" casing appears to have good Icement post P&A. n/a n/a Yes Exhibit V11-13, 1 of 2 at Datum depth of: 5000 TVDSS at Datum depth of: 6700 TVDSS Nearest Aurora Injection Well:lnla ' I Distance from Aurora Injector:I 5,990~6851Feet Hole angle at Kuparuk:I 64.201Degrees 6700' TVDSS Datum:l 94021MDBKB Surface CaSing Data Bond Log ? INo I Completed: ~ J P&A: 11976 TOC Calculation Shoe Depth Hole Size Csg Size IVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, ali cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT Other Issues Sidetracked above Kuparuk? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? IA/OA Pressures 1 2OO IThis was a tapered string with 24961feet 11742' 13-3/8" and 747' 16" casir,~. I 17.51inches Jinches I linches ID 3~51BBL I 1768.51CF !~.3~ I '2151MDBKBI 13501sacks (Yield) -10281MDBKB Ilinear feet cement INo lYes Tag Cement CMT type iWt Slurry Arcticset II Ipsi Iminutes psi I Iminutes Comments Ifeet PPg IThis cement job was probably pumped above frac gradient Date TBG IA O.._~A WHT No Pressures Available for K241112 --., e'I'BG B IA · OA 110100 110100 110100 110100 110100 111100 111100 Participating Area(s) Covered Well: IK241112 I Polaris PA Status: ~P&A I i IAuroraPA ... IThis exploration well was drilled in 1976 and P&A'd in 1976. Actual daily drilling reports no longer available, just summaries. IDuring the P&A of this well, BP set at 11,412, Retainer at 9414 and 9243'. 37 sacks of cement were squeezed at 9600' MD I(below Kuparuk) and 50 sx were squeezed at 9300' MD (above Kuparuk). Set retainer at 2700', shot at 2750 & circulated out 9- J5/8" x 16" 16" x 20" Retainers set at 2400' and 2058' with cemented perfs at-2503' and 2100'. . Initial Surface Casinq Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess*, ** Calculated TOC, gauge hole*, ** *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? - P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Planned / Actual Injectors Kuparuk S-101i HAW S-104i S-107i (HAW) S-112i (HAW) S-114i Schrader S-104i(S) Existing S-200 S-215i W-207i W-212i lin this well, an extra string of 'i sudace casing was run initially, to only 750 feet. I 7501feet . ToP of liner I : Ifeet 241 inches 201inches . 94ppf, H-40~ 19.1241inches ID 14°IBBL I 78flCF 11.31 I 24SIMDBKB I 6001sacks (Yield) 971MDBKB I 6531linear feetcement TagCement~ :-' ifeet CUT type ! I Wt Slurry ! IPPg I Comments Iminutes minutes ICould not break circulation with 700 psi, 20" csg pumped out of hole. Conditioned hole and re-ran 20" csg. Cemented as planned after that. Distance from this well to planned injectors _[ [ TVDSS 614,153 5,979,739 -6619 617,425 5,985,037 -6700 612,115 5,986,558 -6564 619,614 5,980,537 -6559 607,096 5,986,083 -6700 Top Ma 618235 5984886 -4743 617349 5981856 -4629 617648 5977425 -4655 619324 5957278 -4638 614095 5959817 -4520 MDBKB Incline 8,516 65 8,797 8 11,707 59 6,766 48 15,503 26 6,941 29 5,889 20 6,256 46 5,852 30 Distance 23,582 feet 27,602 feet 30,658 feet 22,753 feet 32,461 feet 27,521 feet 24,571 feet 20,133 feet 545 feet 6,239 feet Exhibit VI1-13, 2 of 2 Participating Area(s) Covered Well: IW-17 Polaris PA Status: ~SI-O gJAurora PA Nearest Polaris InJection Well:I W-212iI Distance from Polaris Injector:~ 255~Feet Hole angle at Schrader:I 45.011Degrees - Top Ma Sand:~ 4520FVDSS - MD at Top Ma Sand:~ 5375~MDBKB Intermediate.Casino Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size. Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (cut & pull)? Annulus Information Last MITIA, Date Pressure Time Tbg pressure OA pressure Recommendations Schrader: Do nOt inject within Kuparuk: Do not inject within MITIA before injecting in well(s) Monitor IA/OA Pressures? Well intervention required? Okay for water injection? ' 14171feet 12'251inches 9'6251inches 4391BBL 5'4431MDBKB 3,6511MDBKB Schrader: 2200 psi Pti Kuparuk: 3400 psi Pd X Y lyes 3000 No No ~? Yes 614326 5959710 616,539 5~959,760 614095 5959817 at Datum depth of: at Datum depth of: Schrader Kuparuk W-212i Surface Casing Data Bond Log ? 47ppf, L-80I 8.6811inches 24651CF ' I Isacks (Yield) 7,766~linear feet cement Tag Cement I CMT type lClass G wt S~urry 3000 psi I psi Iminutes psi Iminutes Ifeet PPg ID Comments: 1000 sx 13.5 ppg lead, 500 sx 15.8 ppg tail. RWO in i990 cut and pulled -2100' of 9. 518, csg. Found cmt as high as 411'. Either primary cmt went up that high, well was downsqueezed after original 9/88 drill but before 9/90 RWO (no record except a wellbore diagram was revised on 7/31/91 to show downsqueeze but was later dropped)i or CTU squeeze ,sOmehow got cmt down OA. I 2/11/19941 .... 1500 ps~' Comments-. . 1994 MITIA.passed. , showed I I m i n I (~,~; umi'; ntp ~ked. OA pressured up to 1200 I I si I psi during test (bled 3 bbl diesel). Probably P I : Ipsi Ij-u-;t-d-u'~'~'°-~-i';ermalexpansi°nwhile ' - ' Ipumping down IA. Nearest Aurora Injection Well: Distance from Aurora Injector: Hole angle at Kupamk: 6700' TVDSS Datum: Exhibit V11-14, 1 of 2 5000 TVDSS Completed: J 1988 J 6700 TVDSS RWO: ~ 1990 J n/a I 5r991,566JFeet 391 Degrees 8486.78~MDBKB !No I ft IConclus'ions: Need a baseline temp log ff Iprior to injection, then again after injection Ireaches producer. If logs show poor Iconfinement, use best engineering practices Jto come up with a solution. MonitOr IA/OA - Ipressures after injection start-up. TOC Calculation Shoe Depth Hole Size Csg Size lVolume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test LOT 28541feet 17.51inches 13.375Jinches 47ppf, L-80 J 12.3751inches ID 7351BBL I 41281CF I I -1,6431MDBKB I 44381sacks (Yield) -2,993JMDBKB ~ 5,847Jlinearfeet cement (If negative number, excess cmt to above surface, so depth invalid) lYes Yes Tag CementI 28151feet ICMT type IArcticset II I Wt Slurry I IPPg 2000 psi I 20001psi Iminutes 600lpsi Iminutes 13.9 EMW Other Issues DownsqueezeMultipleSidetrackedP&A Well? Stages? above / TopKUparuk? Job? ! IO No . o Rig Squeeze? RWO to repair csg (cut & pull)? 9-5/8" INOA Pressures Date Comments lEnd of well noted could not pump down 13-3/8" x 9-5/8" annulus - held 2000 psi. Would not have been able to downsqueeze with rig then. But during RWO, rig was able to pump 125 bbl dead crude down OA. TBG IA O....~A WHT W-17 Pressures 12/23/88 12/23/90 12/22/92 12/22/94 12/21/96 12121/98 12/20/00 12/20/02 Participating Area(s) covered Polaris PA Aurora PA Well: Iw- ? I Status:' ISI-O I Exhibit VI1-14, 2 of 2 Intermediate Liner Data Bond Log across Schrader? Bond Log across Kuparuk? TOC Calculation Shoe Depth Hole Size Csg Size Volume Pumped Calculated TOC, 30% excess* Calculated TOC, gauge hole* *Assume 80' shoe track, all cases Cement Job Pumped Per Plan? Returns? Floats Held? Bumped Plug? Casing Pressure Test FIT Other Issues Sidetracked above Injection Zone? P&A Well? Multiple Stages? Downsqueeze / Top Job? Rig Squeeze? RWO to repair csg (Cut & pull)? Planned ! Actual Injectors Kuparuk S-101i HAW S-104i S-107i (HAW) S-112i (HAW) S-114i Schrader S-104i(S) Existing S-200 S-215i t: Ifeet Top of liner I ' Ifeet linches linches 26 ppf, L-801 6,2761inches ID OIBBL 1 ICF I I #DIV/0! IMDBKB***I Isacks i (Yield) #DIV/0! IMDBKB***I #DIV/0!llinear feet Cement **Calculates to above top of liner, so number invalid (revised) Tag Cement~ Ifeet · CMT type / I .Wt S~urry / IPPg I Comments Iminutes minutes Distance from this well to planned injectors X Y TVDSS MDBKB Incline 614,153' 5,979,739 -6619 8,516 65 617,425 5,985,037 -6700 8,797 8 612,115 5,986,558 -6564 11,707 59 619,614 5,980,537 -6559 6,766 48 607,096 5,986,083 -6700 15,503 26 ' Top Ma 618235 5984886 -4743 6,941 29 617349 5981856 -4629 5,889 20 617648 5977425 -4655 6,256 46 W-207i 619324 5957278 -4638 W-212i 614095 5959817 -4520 5,852 30 Distance 20,121 feet 25,293 feet 27,161 feet 21,003 feet 27,965 feet 25,478 feet 22,351 feet 18,024 feet 5,558 feet 255 feet Exhibit VI1-15 Polaris PA Area Injection Order ApplicatiOn O Injector S-104i no penetrations within 1/4 milo Penetrations within 1/4 mile of proposed injectors ~Ox c) i- uJ I= =_ I ~: I"E I *~ O--E ~ = ~,. Comments In ector S-200Ai distances based on existin¢ S-200 location no XY for planned S-200Ai'sidetrack chosen yet/ S-03 Ivishak GL-O 549 4,644 5,580 5,264 N Yes yes CA downsqueezed, so normal monitoring might not work. Based on TOC calculations, cement should be above the Schrader Bluff. Sidetrack S-200Ai further away from this penetration. S-24A Ivishak IN J-MI 1,287 4,689 5,257 6,099 Y Yes No Gauge hole calcs show that cmt would be above the Schrader Bluff, bu't 30% excess calcs do not. The well is considerable distance from the planned injector so no problems are expected. Monitor IA/CA after : H20 start-up. S-31A Sag River SI-W 1,285 4,674 5,364 5,028 Y Yes No Monitor IA and OA after injection start-up. Probably has cement above the Schrader Bluff, based on TOC calcs. S-200 SChrader SI-O 0 4,629 5,889 2,945 Q No Yes Will Sidetrack to injectorloCation. Make sure good cement across Bluff --- Schrader when P&A for sidetrack. S-200PB1 Schrader~ P&A 279 4,652 5,394 2,945 Y No No IWell had good P&A across Schrader. Bluff Note: For S-200Ai, would recommend choosing bottomhole location as far from existing penetrations as possible, without comprom~mng reservoir performance. Iniector S-215i Y = No action required prior to injection start-up. no penetrations within 1/4 mile Q = Okay for injection in area, with some qualifications or restrictions. N = Not okay for injection as is. Needs action prior to start-up. All pre-injection action requirements in boldt in Comments. In ector W-207i IIIJt;;'k~,Lt./I 11f-&lJI I K221112 Ivishak~Observation 771 4,580 4,813 See Note Q Yes No Suspension placed cement across Schrader behind 7". Need a visual check of this well prior to injection (record pressures). Check again 6 months from start of injection, then yearly until abandoned. K241112 Ivishak P&A 545 4,639 4,988 See Note Y No No Adequate cement placed across Schrader during P&A procedure, via rig squeezes. Injector W-212i I W-17 Ivishak Sl-OI 2551 4,5201 5,3751 5,4431 .N. JYesJ ? JNeeda baselinetemp Icg prior to injection, then again after injection I 'I-I - Ireaches producer. If logs show poor confinement, use best engineering I I I Ipractices tocome up with a solution. Monitor IA/CA after injection start- I I I lup. [Fwd: Polaris Application - Outstanding Items within. Area Injection Order] Subject: [Fwd: Polaris Application - Outstanding Items within Area Injection Order] Date: Tue, 01 Oct 2002 09:57:42 -0800 From: Jane Williamson <Jane_Williamson@admin.state.ak.us> To: Jody J Colombie <jody_colombie@admin.state.ak.us> Jody, Please put this in the Polaris Pool Rules file (when you put it together). Don't notice yet till we get their revisions back. Thanks Jane Subject: Date: From: To: CC: Polaris Application - Outstanding Items within Area Injection Order Tue, 01 Oct 2002 09:34:59-0800 Jane Williamson <Jane_Williamson~admin.state.ak.us> "Schmohr, Donn R" <SchmohDR@BP.com> "Benhler, Gil G" <BeuhleGG~BP.com>, James B Regg <jim_regg~admin.state.ak.us>, Stephen F Davies <steve_davies~admin. state.ak.us>, John D Hartz <jack_hartz~admin.state.ak.us> Don, We would like to thank you for meeting with us yesterday to discuss outstanding issues concerning the Polaris Pool Rules and Area Injection Order. While your application submitted on September 12, 2002 was very well constructed, the Commission needs additional information within the Area Injection Order application before we can deem it complete. We recommend that BP make separate application for an MI-based Enhanced Oil Recovery project to prevent delay of the current Polaris project. Miscible injection ("MI") presents numerous technical and regulatory challenges that have not been fully addressed in this application. Assuming that MI is excluded from this application, the following are clarifications and items we need within the Area Injection Order application. As noted in Jack Hartz's e-mail to Gil Buehler (September 17, 2002), confidentiality of exhibits will also need to be sorted out prior to deeming the application complete. Area of Review The Area of Review ("AOR") for the Polaris Waterflood project extends a radius of ¼ mile from the base of the confining layer for each proposed injection well. Mechanical integrity must be demonstrated for each well within the AOR. Please provide a listing of every well within each AOR. Future injection wells not identified in the current application, will require submittal of a 10-401 (new well permit) or 10-403 (conversion to injection) form, establishment of an ¼-mile AOR, and investigation of the mechanical integrity of each well within that AOR. Mechanical Integrity This issue is important at Polaris because of the presence of many older wells that may not have cement across the Schrader Bluff interval. You presented in spreadsheet that provides basic data on casing and cementing for wells within the AOR. This is an excellent starting point. For each well within the ¼ mile AOR, please provide a copy of this spreadsheet, supplemented with following additional information: 1) A conclusion stating whether mechanical integrity has been established for the subject well. 2) The basis for that conclusion, which includes BP's definition of integrity. 3) If integrity cannot be demonstrated, a plan for repair or proposed surveillance must be provided. This plan must discuss limitations due to well construction and any integrity concerns that would trigger 1 of 2 10/1/2002 11:29 AM [Fwd: Polaris Application - Outstanding Items within Area Injection Order] additional surveillance or repair. A copy of the most recent schematic diagram for the subject well is required. Directional survey information and daily operations reports need not be included within the application. Fracture Pressure It is our understanding that fracture conditions discussed in the application were the result of injecting highly viscous fluids at high rates (15 barrels per minute) for the purpose of stimulating the well. During our discussion, you stated that these conditions represented a worst-case scenario, which did not result in net pressures which would be sufficient to frac through the confining layer. Conditions for planned waterflood will be at lower rates (about 2 bpm) and result in lower net pressures, and are unlikely to cause fracturing through the confining layer. Should fracturing occur, fluids will remain within the Polaris Pool. In the unlikely event that the Mb2 mudstones above the planned injection interval is fractured, the water will preferentially enter the highly permeable Mb sands, which you are requesting as part of the Polaris pool. Please verify if we understood correctly. Jane Williamson- Reservoir Engineer Steve Davies - Petroleum Geologist Jim Regg - Petroleum Engineer Alaska Oil and Gas Conservation Commission 2 of 2 10/1/2002 11:29 AM #1 BP Exploration (Alaska), Inc..,;,, 900 East Benson Boulevard ~ Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 ObP September 12, 2002 DELIVERED BY HAND Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Polaris Pool Rules And Area Injection Order Application Dear Commissioners: for the Polaris Oil Pool. We look forward to discussing this with you fu,-thcr. QP Exploration (Alaska) Inc., in its capacity as Polaris Operator and Unit Operator, respectfully requests that a hearing commence as early as possible in order to gain approval of an Area Injection Order. BP requests, as operator, that those certain exhibits labeled "CONFIDENTIAL" be treated as confidential in accordance with the provisions of AS 31.05.035 and 20 AAC 25.537. Please contact me (564-5143) or Donn Schmohr (564-5494) if you have any questions or comments regarding this request. Sincerely, Gil Beuhler GPB Satellites Team Leader Attachments CC: R. Smith (BP) J. P. Johnson (PAl) S. Wright (ChevronTexaco) M. M. Vela (ExxonMobil) P, White (Forest Oil) Polaris Pool Rules and Area Injectior! ...der Application September 12, 2002 Polaris Pool Rules and Area Injection Order Application September 12, 2002 1/60 Polaris Pool Rules and Area Injectior! ..~er Application September 12, 2002 Table of Contents I. Geology .......................................................................... 3 Introduction ..................................................................................................................... 3 Stratigraphy ..................................................................................................................... 5 Schrader Bluff Formation Structure .............................................................................. 15 Fluid Contacts ............................................................................................................... 18 Net Pay and Pool Limits ................................................................................................ 21 II. Reservoir Description and Development Planning ..... 23 Rock and Fluid Properties ............................................................................................. 23 Hydrocarbons in Place .................................................................................................. 25 Reservoir Performance .................................................................................................. 26 Development Planning .................................................................................................. 28 Development Options .................................................................................................... 28 Development Plan ........... ,.: ........................................................................................... 31 Reservoir Management Strategy ................................................................................... 33 III. Facilities .................................................................... 35 General Overview ......................................................................................................... 35 Pad Facilities and Operations ........................................................................................ 36 Gathering Center ........................................................................................................... 37 IV. Well Operations ......................................................... 38 Existing Wells ............................................................................................................... 38 Drilling and Well Design .............................................................................................. 38 Reservoir Surveillance Program .................................................................................... 42 V. Production Allocation ................................................. 46 VI. Area Injection Operations ......................................... 47 Plat of Project Area ....................................................................................................... 47 Operators/Surface Owners ............................................................................................ 47 Description of Operation ............................................................................................... 47 Geologic Information .................................................................................................... 47 Injection Well Casing Information ................................................................................ 48 Injection Fluids .............................................................................................................. 48 Mechanical Integrity of Wells ....................................................................................... 49 Injection Pressures ......................................................................................................... 50 Fracture Information ..................................................................................................... 50 VII. Proposed Polaris Pool Rules .................................... 52 VIII. Proposed Area Injection Order ............................... 56 IX. List of Exhibits ......................................................... 59 2~60 Polaris Pool Rules and Area I, an Order Application September 12, 2002 I. Geology Introduction The area for which the Polaris Pool Rules are proposed is located within the Prudhoe Bay Unit (PBU) on Alaska's North Slope, as illustrated in Exhibit I-1. The Polaris Pool overlies the PBU Sadlerochit Group reservoir in the vicinity of PBU S, M and W Pads and overlies the Aurora Pool Kuparuk River Formation reservoir in the vicinity of PBU S Pad. The reservoir interval for the Polaris Pool is the Schrader Bluff and lower Ugnu Formations. Within the Polaris Pool, the Schrader Bluff and lower Ugnu Formations are subdivided into fourteen distinct sand units encompassed by the O and N sand intervals (Schrader Bluff) and the M sand interval (lower Ugnu). Hereafter, this application will refer to the Polaris Pool as including all of the hydrocarbon bearing sands within the Schrader Bluff and Ugnu Formations M, N, and O sand intervals within the described area. The North Kuparuk State 26-12-12 well, drilled in 1969, was the first well to penetrate and log hydrocarbons in the Polaris Pool. Since 1969, the Polaris Pool interval has been logged in 64 Schrader Bluff penetrations in PBU Ivishak, Kuparuk, and Schrader Bluff development and appraisal wells in the Polaris Pool Rules area. Polaris Pool hydrocarbon presence is recognized from log data from 59 Polaris Pool wells which have at least Gamma Ray (GR) and Resistivity log data. Polaris Pool rock properties were derived using conventional core data from two Polaris wells, S-200PB 1 and W-200PB 1. Rock properties were distributed regionally across the Polaris Pool area using log model transforms on well log data from 27 regional wells which have full suite (GR, Resistivity, and Porosity) log data. Exhibit 1-2 shows the location of the Polaris Pool area. Exhibit 1-2 also shows that the boundaries of the Polaris Pool Rules area coincide with the boundaries of the Polaris Participating Area (PPA). The Polaris Pool hydrocarbon accumulation is bounded by faults on the updip west and south sides and by dip closure into the regional aquifer on the north and east sides. 3/60 Polaris Pool Rules and Area Injectioi. ,ter Application September 12, 2002 As shown on the Schrader Bluff structure map in Exhibit 1-3, the Polaris structure crests at W Pad in the southwest Polaris Pool region (-4800 feet TVDSS at the mid Schrader Bluff OA mapping horizon) and trends down dip to the north and east through faulting and regional dip. North-south, east-west, and northwest-southeast trending faults subdivide the Schrader Bluff reservoir into discrete high-standing and low-standing fault blocks within the Polaris Pool area. Fluid isolation between several fault blocks is indicated by log data from adjacent fault separated wells that show water lying structurally higher than oil in the same sands on opposites sides of faults. Sealing faults are predicted in the Schrader Bluff reservoir based on the prevalent low net to gross reservoir lithologies. Exhibit 1-4 shows the Polaris Pool fluid limits in relation to regional structural features along a cross section line connecting the W and S Pad areas. Oil-Down-To (ODT) limits and Water-Up-To (WUT) limits in PBU M and N Pad wells constrain northern Polaris Pool S and M Pad area oil column heights to between 200 and 320 vertical feet. Oil-Down-To limits and a structural spill point in the Polaris W Pad area constrain southern Polaris Pool oil column heights to between 210 and 360 vertical feet. A single OBd sand Oil-Water contact penetrated in well W-201 (-5226 feet TVDSS) represents the only O sand Oil-Water contact logged in a Polaris Pool well. Based on differences in rock quality and potential spill points for the various sand units, it is believed that Oil-Water contact depths vary by sand unit and by fault block within the Polaris Pool. Polaris Pool commercial production was confirmed in 2000 following the fracture- stimulated completion and production of the Schrader Bluff O and N sands in well S-200 and the Schrader Bluff O sands in well W-200 in late 1999. Wells S-201, S-213, and S- 216 were drilled and completed as conventional fracture stimulated O sand production wells in December, 2000 and January, 2001. Well S-104 is an injection well drilled in 2001 which was completed to allow water injection in both the Polaris and Aurora Pools. Well W-201 was completed as the first Polaris high-angle development well at W Pad and began production from the O sand interval in July, 2001. Wells W-211 and W-212i, 4/60 Polaris Pool Rules and Area I: )n Order Application September 12, 2002 an O sand conventional injector-producer well pair downdip of the W-200 production well, were drilled in March and April, 2002 and were completed in May, 2002. Well W- 203 was completed in June, 2002 as the first Polaris Pool high-angle trilateral well in the W Pad area OBa, OBc, and OBd sands. All current Polaris Pool production is from the N and O sands at S Pad, and from the OB sands only at W Pad. There are currently no Polaris Pool producing wells on M Pad. The N sands at W Pad have not been targeted to date due to the presence of heavy oil (14 API gravity) based on core-derived fluid samples, as well as the presence of several thin wet intervals in close proximity to oil pay relatively high on structure. The M sands at both S and W Pads contain heavy oil (12 to 14 AP1 gravity) based on core-derived fluid samples and are not considered to be economic development targets due to production complications related to heavy oil and unconsolidated sands. The M sands may be a future development target at Polaris. Stratigraphy Exhibit 1-5 shows the open-hole wireline log character of the Schrader Bluff and lower Ugnu Formation M, N, and O sands in a type log from the S-200PB 1 well and illustrates the vertical stratigraphic extent of the Polaris Pool. In the S-200PB 1 well, the top of the Polaris Pool occurs at -4,651 feet TVDSS (5,393 feet MD) and the base occurs at -5,269 feet TVDSS (6,012 feet MD). As shown in Exhibit 1-5, the Polaris Pool M, N, and O sands are further subdivided into seven O sand, three N sand, and four M sand intervals. A general desCription of the thickness and character of each of the Polaris sands follows. A detailed description of the rock properties associated with individual sands is given in Section II. In general, the O, N, and M sand intervals are present across the entire Polaris Pool area and, as a package, thin slightly from south-southwest to north-northeast across the Polaris Pool area. Reservoir quality sand units within each interval are regionally extensive but can be locally characterized by substantial thickness and net to gross variations between wells spaced less than 1000 feet apart. 5/60 Polaris Pool Rules and Area Injectioi .~er Application September 12, 2002 The Schrader Bluff Formation N and O sand intervals were deposited between 65 and 72 million years ago during the Late Cretaceous geologic time period and are composed of a set of marine shoreface and shelf deposits that are transitional between the underlying open marine Late Cretaceous Colville mudstones, and the overlying deltaic and fluvial sands, silts, and mudstones of the Early Tertiary Ugnu Formation M sands. The contact between the basal Schrader Bluff Formation O sands and the underlying upper Colville section is gradational from the Colville mudstones to the basal Schrader Bluff low permeability silty sands. Colville mudstones and muddy siltstones, ranging up to 1100 feet thick at Polaris, form the basal confining unit of the Polaris Pool. The contact between the upper Schrader Bluff Formation N sands and the overlying Ugnu M sand section is generally abrupt and lies at the base of a regionally continuous 10 to 30 foot thick muddy siltstone layer. The top of the Ugnu M sand interval is characterized by an upward gradation from silty fining upward Ma sands to a regionally continuous 10 to 25 foot thick silty mudstone which isolates the M sands from overlying fluvial Ugnu sands, silts, and mudstones. This upper silty mudstone forms the upper confining layer of the Polaris Pool. O Sands The lowermost Polaris Pool unit, the Schrader Bluff O sand interval, forms the primary 'development target in the Polaris Pool and is subdivided into seven separate reservoir horizons, from deepest to shallowest - the OBf, OBe, OBd, OBc, OBb, OBa, and OA. In general, each of the O sand intervals clean upward from basal non-reservoir laminated muddy siltstones to reservoir quality laminated to thin-bedded sand units at the top. Within the reservoir quality, sand intervals, several O sand intervals show an abrupt transition from lower net to gross coarsening upward reservoir facies to high permeability blocky to fining upward facies above regionally extensive erosion or scour surfaces. The fining upward facies above the erosion surfaces comprise the highest quality reservoir section in the Polaris O sand interval. The upper limit of each O sand horizon is marked by an abrupt upward transition from reservoir quality sands to non-reservoir muddy siltstones at the base of the overlying O sand interval. Bioturbation disrupts layering throughout both the reservoir and non-reservoir sections, but is most prevalent in the lowest net to gross lithologies. 6/60 Polaris Pool Rules and Area I, on Order Application September 12, 2002 OBe and OBf Sands The OBf and OBe intervals, each ranging in thickness from 30 to 50 feet, comprise the basal Polaris O reservoir units and exhibit the lowest net to gross sand facies in the O sand section. Both intervals are characterized by basal muddy siltstones that grade upward into thin very fine-grained and laminated sands. Abundant lithic feldspar grains are present in both the OBf and OBe intervals, which result in an abnormally high GR response in the highest net to gross sand layers. OBe and OBf sands also contain abundant pore-filling zeolites, which significantly reduce reservoir porosities and permeabilities. Zeolite-related porosity and permeability reduction is suspected as the main reason that the OBe and OBf sands do not appear to contribute significant production in hydraulically fractured and commingled completions in wells S-200 (OBe) and W-200 (OBf). OBd Sands The OBd sand interval ranges between 50 and 70 feet thick and forms one of the primary Polaris reservoir target horizons in both the S Pad and W Pad areas. OBd sands are thickest in the W Pad area, ranging up to 47 feet net sand in well K 22-11-12, and thin gradually northward to between 10 and 30 feet net sand in the S and M Pad areas. The OBd interval grades upward from a basal muddy siltstone to a faintly laminated to cross- bedded upper sand unit. Lower quality laminated and bioturbated reservoir sands regionally overlie the basal mudstone and gradually clean upward to a regionally extensive erosion/scour surface. A 10 to 30 foot thick blocky to fining upward sand unit overlies the regional erosion surface and caps the OBd interval over most of the Polaris Pool area. This upper blocky to fining uPward sand forms the highest quality OBd reservoir unit. Reservoir quality OBd sands are unconsolidated and almost entirely very fine to fine-grained. Production logs have shown that OBd sands contribute between 60 and 80% of the total well production in Polaris hydraulically fractured and commingled O sand completions at both S and W Pads. OBc Sands The OBc sand interval, ranging between 40 and 50 feet thick, comprises a minor Polaris 7/60 - _ Polaris Pool Rules and Area Injectio~~', .ler Application (" September 12, 2002 reservoir unit with reservoir quality sands present mainly in the W Pad area. The OBc interval grades upward from basal muddy siltstones to a low net to gross silty sand around S and M Pads, and a moderate net to gross laminated to layered very fine-grained sand around W Pad. The upper OBc interval at W Pad consists of two thin distinct sand lobes, each 5 to 10 feet thick, separated by a <5 to 10 foot thick low permeability sandy siltstone. Up to 20 net feet of OBc sand is mapped in the eastern W Pad area. S Pad area OBc net sand thicknesses are typically less than six feet. Polaris Pool OBc sands contribute minor production in a commingled hydraulically fractured completion in the W-200 well, in a well W-203 high angle trilateral completion, and have not been individually completed in recent S Pad wells due to limited net sand presence. OBb Sands The OBb sand interval, also a minor Polaris Pool reservoir unit, has a thickness range of between 30 and 55 feet with between 'five and 20 feet of net sand present in both the S Pad and W Pad areas. Regionally, the OBb interval typically contains less than 15 net feet of sand. The OBb interval comprises a moderately coarsening upward section that exhibits a lower net to gross character than the overlying OBa and the underlying OBc intervals. Individual clean OBb sand layers in core samples are typically less than one foot thick and are separated by silts and muds of comparable or greater thickness than the sands. OBb sands in both the S-200 and W-200 wells were hydraulically fractured and produce commingled with the overlying OBa sands. OBa Sands The OBa sand interval, with a 25 to 40 foot thickness range, cleans gradually upward from a basal siltstone into interbedded thin sands and mudstones to an upper cross- laminated sand unit. A 10 to 15 foot thick, blocky to fining upward high permeability sand (1000 md. +) caps the OBa interval regionally from southern S Pad wells S-18 and S-216 southward across the W Pad area. This high permeability OBa'sand interval thins from south to north across the Polaris region and comprises a primary development target in the middle and southern Polaris Pool area. OBa sand quality, in general, diminishes in the central and northern S Pad area. Hydraulically fractured OBa sands produced at initial rates of approximately 65 BOPD in well W-200 and 35 BOPD in well S-200. 8/60 Polaris Pool Rules and Area I: :)n Order Application September 12, 2002 OBa sands have produced at rates of trilateral completion. >1000 BOPD in the well W-203 high angle OA Sands The OA sand interval is composed of a 10 to 25 foot thick basal silty mudstone that coarsens upward, gradually to abruptly, into stacked set of cleaning and fining upward reservoir sand units. As a package, the middle to upper OA net sand interval ranges up to 30 feet thick. The OA sands at S and M .Pad consist of at least two cycles of alternating coarsening upward, then fining upper sand units. The thickest and highest quality OA sands at S and M Pads generally occur at the base of the lower fining upward section. The middle coarsening upward section at S and M Pad is generally poor to non-reservoir in. quality and may form a vertical reservoir "baffle" between higher permeability units at the top and base of the OA sand. Upper OA sands at S and M Pad generally exhibit a thin (< 10 foot thick) moderately permeable sand unit near the top of the OA sand section. OA sands at W Pad show a dominantly coarsening upward log profile with the highest quality sands present in the upper third of the OA gross interval. The OA sand interval is typically capped at W Pad by a very thin (<5 foot thick), high quality, fining upward sand which is truncated abruptly at the top OA sand contact. W Pad basal and middle OA sands are generally poor to non-reservoir in quality. Regionally, OA net sands thin slightly to the east and south from 18 net feet at S Pad to 10 to 15 net feet at W Pad and 7 to 12 net feet at M Pad. OA sands are very fine to fine- grained, faintly laminated to massive and moderately to strongly bioturbated, particularly in the upper fining upward sand section. OA sands are oil-bearing and productive in hydraulically fractured completions in S Pad area wells (12% of total production in S- 200). OA sands show high water saturation throughout nearly all of the W Pad area except for small attic oil accumulations localized in high standing fault block corner traps along the southern margin of the W Pad fault block. 9/6O Polaris Pool Rules and Area InjectiOI'. .der Application September 12, 2002 N Sands The Polaris Pool N sand interval overlies the Schrader Bluff O sand interval and ranges between 100 and 160 feet thick in the Polaris Pool area. Polaris Pool N sands are subdivided into three reservoir units, from deepest to shallowest - Nc, Nb, and Na. The N sand interval consists mainly of non-reservoir muds and siltstones interbedded with a limited number of thin, but generally extensive, unconsolidated reservoir sands. Thick, regionally extensive silty mudstones in the lowermost N sand interval form an important regional vertical reservoir barrier which segregates lighter, higher quality, oil in the main development horizon O sands at Polaris and Milne Point (D, B, and A sands at West Sak) from heavy oil and extensive wet sands in the overlying N and M sands (Lower Ugnu sands at West Sak). Nc Sands The Nc interval, ranging from 50 to 95 feet thick, is dominated by mudstone and muddy siltstone, in the Polaris Pool area and contains thin interbedded reservoir quality sands only in the upper 10 to 20 feet of the interval. Up to 15. feet of Nc net sand is locally present at the top of the Nc interval in the western S Pad area. However, elsewhere in the Polaris Pool area, Nc net sand thicknesses typically total less than five feet. Individual sands are generally unconsolidated and interbedded with thicker non-reservoir muddy siltstones. Nc sands are very fine grained, laminated and moderately to highly bioturbated. In the S-200 well, Nc sands are hydraulically fractured along with Nb sands and produce oil at low rates (50 BOPD). Nc sands have not been completed in the W Pad area due to thin sand development and minimal standoff from water in overlying Nb sands. , Nb Sands The Nb sand interval ranges from 30 to 45 feet thick and comprises the primary N sand interval completion target. Nb net sand character is highly variable in the S and M Pad areas with net sand thicknesses ranging from 6 to 31 feet. Most individual Nb sands around S Pad are less than 5 feet thick and are interbedded with similar or greater thicknesses of mud and silt. Nb sand thicknesses are greater around W Pad (15-21 feet) than S Pad, and individual Nb sands are typically higher net to gross in W Pad wells than 10/60 Polaris Pool Rules and Area Ir ')n Order Application September 12, 2002 in S Pad wells. Limited core-extracted oil fluid data from W Pad Nb sands suggests that W Pad Nb oil is relatively low quality compared with S Pad (14 APl gravity at W Pad vs. 17-19 API gravity at S Pad). In addition, basal Nb sands in well W-200 appear to be wet in a relatively crestal reservoir position in the W Pad fault block. No Nb sand completions have been made to date in the W Pad area due to the apparent poor oil quality and the presence of water in the basal Nb section. Nb sands were hydraulically fractured along with Nc sands in the S-200 well and produced oil at commingled rates of 50 BOPD. Na Sands The Na sand interval is a thin, very low net-to-gross interval, which lies at the top of the Polaris Pool N sand section. The Na section thins from 25 feet around W Pad to 15 feet in the S and M Pad areas. Na reservoir sands are generally very fine-grained, laminated, and bioturbated. Individual Na sands are two to four feet thick, exhibit a spiky log character, and are interbedded with thicker non-reservoir siltstones. Thicker Na sands are developed only in the down structure eastern W Pad area. No Na sand completions have been made to date due to poor sand development in recently drilled Polaris Pool wells. M Sands The Polaris Pool M sand interval overlies the N sand interval and ranges between 180 and 250 feet thick in the Polaris area. Polaris Pool M sands are subdivided into four reservoir units, from deepest to shallowest - Mc, Mb2, Mb l, and Ma. Appearance of the clean and coarser grained Ugnu M sands marks a north to northeast regional progradation of the Schrader Bluff shoreline and a regional shift in deposition from Schrader Bluff marine shelf and shoreface sediments to Ugnu deltaic and fluvial deposits in 'the Polaris area. The M sand interval consists of very high quality unconsolidated clean sands separated by generally thin, but extensive, non-reservoir silty mudstone units. Mudstones within the M sand interval vertically separate individual hydrocarbon and water-bearing M sand 11/60 Polaris Pool Rules and Area Injecti .ler Application September 12, 2002 units, even in high net to gross sand units, and provide competent top seals to the Polaris Pool development interval. M sand hydrocarbons consist of heavy, biodegraded crude (12 to 14 degree API gravity) based on fluids extracted from sidewall and conventional core plug samples. To date, no M sand production has been attempted and, no M sand downhole oil sampling has been successful. Mc Sands The lower Ugnu Mc sand interval, ranging in thickness from 50. to 70 feet, is the lowermost M sand interval and the uppermost reservoir interval included in the Polaris Participating Area. Mc sands are highly variable in log profile, ranging from thick- bedded and blocky to very thin bedded and spiky. Conventional core samples in the Mc interval show that the sands are typically fine grained and highly unconsolidated. Mc sands are thickest along a narrow north-south trend in the western Polaris Pool area extending from western S Pad to W Pad. Significant thinning occurs in the Mc sands eastward across S Pad and eastward between W Pad and well K 22-11-12, the nearest offset well to the east of W Pad. The elongate Mc isopach trend suggests channelized deposition in a north-south direction, possibly as incised valley fill, cut into the top of the underlying marine mudstone section. Mc sands are separated from the underlying Na sands by a 15 to 25 foot thick silty mudstone, which forms a regional seal separating the Polaris N sands from the M sand reservoirs. Evidence of the sealing capacity of the lower Mc mudstone is seen in the W Pad and TW~C areas, where oil-bearing N sands are separated from overlying water- bearing Mc sands across the lower Mc mudstone interval (Exhibit 1-4). The productive potential of the Mc sands is unknown due to the presence of heavy oil (13 to 14API gravity from core samples), the unconsolidated sand character, and the lack of a Mc sand production test. Any future testing of Mc hydrocarbons would likely occur in the crestal S Pad area where Mc pay sands are thickest. Relatively low net to gross Mc sands are present over most of the downdip S, M, and W Pad areas.. 12/60 Polaris Pool Rules and Area h on Order Application September 12, 2002 Mb2 Sands The Mb2 sand interval ranges in thickness from 35 to 70 feet, and together with the overlying Mb l sands, form the highest net to gross intervals in the Polaris Pool. The Mb2 section is thickest along a broad east-west trending band in the southern Polaris W Pad area, and along a narrow northwest-southeast trending graben in the northern Polaris central S and M Pad area. The thicker Mb2 interval present in the S/M graben feature suggests that Mb2 deposition in the central S and M Pad area may have been influenced by localized syndepositional faulting. Mb2 sands, generally cleaning upward to blocky in log profile, range in thickness from 20 to 55 feet above a 15 to 35 foot thick silty mudstone base. Similar to the Mc sands, Mb2 sands are typically fine-grained, highly unconsolidated, and very high permeability (up to 1200 md. in S-200PB 1 core plugs). The 15 'to 35 foot thick basal Mb2 mudstone forms a regionally continuous vertical reservoir barrier separating the high net to gross Ugnu Mb and Ma sand units from the underlying lower net to gross Polaris O, N, and Mc sand reservoirs. An isopach map showing the regional thickness and extent of the lower Mb2 mudstone is shown in Exhibit I-6. In the crestal S Pad area, the basal Mb2 mudstone separates a 30 foot oil column in the underlying Mc sands from water in high net to gross Mb2 sands above the mudstone unit (Exhibit 1-4). In updip W Pad well penetrations, the lower Mb2 mudstone separates oil-bearing Mc and M'b2 sands, each with different OWC levels Based on the evidence of regional continuity and sealing capacity, the lower Mb2 mudstone unit is expected to be a competent vertical barrier, along with the other M, N, and O interval mudstones, which will contain fluid movements resulting from Polaris reservoir development in the O, N, and Mc intervals within the Polaris Pool. The mechanical properties of mudstone units as vertical reservoir barriers within the Polaris Pool are discussed in the Fracture Information segment of the Area Injection Operations section. Mb2 sands are largely wet, or contain thin intervals of heavy residual oil based on core samples, in the central and northern S and M Pad and in the downdip W Pad areas. Mb2 sands contain heavy oil in the southern S Pad fault block and in the crestal W Pad area. 13/60 Polaris Pool Rules and Area Injectio{~ .,der Application September 12, 2002 No Mb2 sand live oil fluid samples or production tests have been acquired in any Polaris area well. Mbl Sands The Mb 1 sand interval ranges in thickness from 40 to 60 feet and is the highest individual net to gross sand unit in the Polaris Pool interval (.84 net to gross in cored well S- 200PB 1). The Mb 1 section thins gradually from southwest to northeast across the Polaris area, but demonstrates local thickness variations of up to 16 feet between closely spaced wells in the northern Polaris M Pad area. Unlike the Mb2 interval, the Mb 1 section does not show any clear evidence of depositional thickening or thinning influenced by syndepositional faulting. Mb l sands are mainly cleaning upward in log profile above a two to ten foot thick silty mudstone base. The Mbl sand section is generally layered in less than one fOot to five foot thick sand units separated by thinner finer grained layers (down to silt size). Overall, Mb 1 sand layer thicknesses and grain size increases toward the top of the Mb 1 interval. The highest quality Mbl sands generally occur in the upper 10 to 15 feet of the section. Mb l sands are typically fine grained and highly unconsolidated. The thin basal Mb 1 mudstone forms a vertical reservoir barrier at S Pad where downdip Mb 1 sands often contain oil at structural depths where Mb2 sands are wet in offset updip wells. It is less clear at W Pad whether the thin Mb l mudstone hydraulically separates the Mb l and Mb2 sands due both to the thin character of the mudstone at W Pad and due to an absence of closely spaCed well data showing conflicting fluid levels in the Mb 1 and Mb2 sands. In general, Mbl sands are oil bearing in many crestal Polaris :fault block areas where the underlying Mb2 sands are wet. Mbl sands contain heavy oil (12 to 14 API gravity) in crestal wells S-200PB1 and W- 200PB1 based on conventional core samples. Mb l oil quality in downdip areas is expected to be poorer than the crestal wells, due to increased exposure to fresh(er) water and biodegradation near the M sand oil/water contact. 14/60 Polaris Pool Rules and Area I ,on Order Application September 12, 2002 Ma Sands The Ma sand interval ranges between 45 and 55 feet thick across the Polaris area and forms the uppermost Polaris Pool reservoir interval. Ma sand log profiles show a basal 5 to 15 foot thick basal mudstone grading upward into 35 to 40 foot thick sand interval consisting of a lower cleaning upward and an upper fining upward sand unit. Ma sands are typically very fine to fine grained, unconsolidated, and exhibit a moderate net to gross appearance relative to the underlying high net to gross Mb sands. Unlike the underlying Mb sand intervals, Ma sands are thickest and cleanest in the northern Polaris area and thin significantly to the south toward the W Pad area. A 5 to 20 foot thick sil.ty mudstone overlies the uppermost Ma sand and forms the regional topseal to the Polaris Pool interval. Ma sands contain 12 degree AP1 gravity oil based on core derived fluid samples in the Polaris S Pad area. No Ma sand live'oil fluid samples or production tests have been acquired in any Polaris area well. Schrader Bluff Formation Structure Exhibit I-3 is a structure map on the top of the Schrader Bluff OA Sand in the Polaris Pool area, with a contour interval of 20 feet. Although the Schrader Bluff interval generally dips eastward and northeastward at gentle dips of 0 to 4 degrees in the western portion of the Prudhoe Bay Unit, it is broken up into a series of distinct fault blocks, as indicated by 3D seismic data. The structural character at the Schrader Bluff level in the vicinity of the Polaris Pool is dominated by three different fault trends: Northwest- Southeast, North-South, and East-West. Northwest-Southeast Fault Trend The northwest-southeast striking fault trend, with throws of up to 200 feet dominates the southern part of the Polaris Pool. Faults with this orientation occur as antithetic pairs or triplets, forming elongate grabens such as the one along the southwestern margin of the proposed Polaris PA. Northwest-southeast trending faults with throws of 25 to 75 feet 15/60 4"' Polaris Pool Rules and Area Injectit ,'der Application September 12, 2002 are found in the M and S Pad area. These faults occur in an antithetic pair, forming a crestal graben along the structural high running through S Pad to just south of M Pad. North-South Fault Trend~ Apparent Horst Blocks North-South striking faults, generally downthrown to the west are the second most dominant fault system in the Polaris Pool. These faults have throws of up to 250 feet. Some of the north-south trending faults can be demonstrated to have relatively late movement, with offsets as shallow as 800 feet TVDSS in the permafrost. A number of the north-south trending faults appear in pairs apparently forming elongate horst blocks. These apparent horst blocks are seen in the areas west and southwest of the V-200 well, northwest of S Pad, and a very long, narrow horst appears west and north of W Pad. The east-dipping fault in the pair is invariably truncated by the larger offset west-dipping fault. East-West Fault Trend East-West striking faults that dip both north and south are common in the downdip (eastern and northeastern) areas of the Polaris Pool. These faults have throws of up to 100 feet. Most of these faults are located where the Schrader Bluff Formation is in the regional aquifer, with limited exceptions: An east-west trending, south-dipping fault forms the southern boundary of the Schrader Bluff accumulation just west of N Pad. This fault has a throw of up to 80 feet. An east west trending, south-dipping'fault subdivides the reservoir in the area of the well K 22-11-12, east of W Pad. S Pad- M Pad Structure in the S Pad - M Pad area consists of a complexly-faulted structural high, which plunges towards the southeast, where it is truncated by a large east-west fault near N Pad. The structure is dominated by a northwest-southeast striking pair of antithetic faults which intersect a large Offset, north-south trending, and west-dipping fault system. The northwest-southeast antithetic fault pair subdivides the S Pad - M Pad structure into three major fault sub'blocks: 1) A crestal area and northeast-dipping flank, with S-200 and S-201 in this fault block; 16/60 Polaris Pool Rules and Area 1: ~n Order Application September 12, 2002 2) A crestal graben located between the two NW-SE faults, which runs from just south of the S Pad surface location, to just south of the M Pad surface location; 3) A fault-bounded structural high south of the graben, with development wells S-213 and S-216 situated in this fault block. Term Well C (TW-C) Area Term Well C (TW-C) is located in a saddle downdip from the structural high at W Pad to the south and downthrown by faulting from the southern S Pad/M Pad fault block. A long, north-south fault lies to the west. TW-C appears to be separated from the V-200 block by small offset faults, some of which may be inferred from fluid contact data. A fault system separates the TW-C block from the southern S Pad fault block. W Pad The structural trap at W Pad is formed by the intersection of a major northwest-southeast oriented fault with a large-offset north-south trending fault system, with dip closure to the east and northeast. The downdip extent of structural closure to the southeast is dependent upon the juxtaposition of sand intervals across, and clay/shale smearing along, a small offset east-west trending fault. The W Pad trap appears less intensely faulted than the S Pad/M Pad areas. Reservoir Compartments Elements of each of the major area fault systems were used to subdivide the Polaris Pool into reservoir compartments for development planning purposes. The location and areal extent of these reservoir compartments is marked by the polygon boundaries shown in Exhibit 1-7. Each compartment was defined along mapped fault trends and was assumed to be hydraulically isolated by sealing faults from adjacent compartments. The sealing character of the faults forming the compartment boundaries is inferred from both limited fluid contact and pressure data at Polaris and from analog studies which show a high probability of clay smear seals forming along faults in the Polaris low net to gross reservoirs. Polygon nomenclature and boundary character is summarized below. 17/60 Polaris Pool Rules and Area Injectiot .~er Application September 12, 2002 Table 1 Reservoir Polygon SfM Pad North S/M Pad Graben SfM Pad South W Pad/TWC Polygon K 22-11-12 Polygon Horst Block Polygon Boundary Character Fault bounded on south and west; bounded by Oil/Water contacts on the north and east. Fault bounded on north, south, and west; bounded by Oil/Water contacts on the east. Downthrown from S/M Pad North and S/M Pad South polygons. Fault bounded on north, south, and west; bounded by Oil/Water contacts on the east. Up-thrown to W Pad/TWC and S/M Pad South polygons. Fault bounded on north, south, and west; bounded by Oil/water contacts on the east. Downthrown to S/M Pad South and Horst Block polygons. Fault bounded on north, south, and west; bounded by Oil/water contacts on the east. DoWnthr0wn to W Pad/TWC polygon. Fault bounded on all sides. Up-thrown to W Pad/TWC polygon. Fluid Contacts Exhibits I-8 and I-9 show the depths of interpreted Oil/Water 'Contacts (OWCs) in the M, N, and O sands in the Polaris Pool in the S/M and W Pad areas. M sand OWCs are relatively well defined by existing well control. N and O sand OWCs are less well defined due to the lack of well control in downstructure areas. No Gas/Oil Contacts (GOCs) have been logged in any Polaris sand nor is the presence of free gas in Polaris Pool intervals predicted from oil PVT test results. Each sand in the Polaris N and O interval was assumed to be vertically isolated from overlying and underlying sands and was assumed to have a different associated OWC depth. 18/60 Polaris Pool Rules and Area I on Order Application September 12, 2002 N and O Sands Most Polaris N and O sand OWCs were interpreted 1. at the midpoint between the deepest Oil-Down-To (ODT) levels logged in upstructure wells and the downdip structural spill point for each sand (W Pad), or 2. at the midpoint between the updip ODT levels and downdip Water-Up-To (WUT) levels in the downdip N-13 well (S and M Pad). An open hole OWC of-5226' TVDSS was logged in the OBd sand in the W-201 well in the downstructure W Pad area. A W Pad crestal area OA sand Oil-Down-To (ODT)/OWC level of-4834' TVDSS is interpreted between a 10 vertical foot range of Oil-Down-To and Water-Up-To levels in offset wells W-40 and W-200 PB 1. A W Pad Nb sand OWC of-4756 feet TVDSS was logged in well W-203. Based on the described methodology, the N and O sand expected case oil column heights at S and M Pad range between 210 feet (OBf) and 290 feet (Nc). S and M Pad area N and O sand OWC depth uncertainties average 100 vertical feet per sand between the minimum possible and maximum possible OWC cases. W Pad expected case oil column heights range from 35 feet (OA sands) and 68 feet (Nb sands) to 290 feet (OBc). The W Pad area OB sands average oil column height is 270 feet. W Pad area N and O sand OWC depth uncertainties between the minimum possible and the maximum possible OWC cases average 150 vertical feet per sand. The presence of wet OA sands in the W Pad/TWC fault block structurally high to oil-filled OA sands in the S/M Pad North and South polygons indicates that the S/M Pad fault blocks are in fluid isolation from the W Pad/TWC area fault blocks. M Sands In contrast to the minimal number of Polaris N and O sand fluid contacts logged, Mb and Mc Sand OWCs have been logged in numerous wells in the S, M, and W Pad areas. Ma sand OWCs have not been logged in any Polaris well. The improved definition of Mb and Mc sand OWCs results from: 1. M sand OWCs are more concentrated in crestal, rather than downdip, fault block areas beneath existing well pads and have been penetrated and logged by more PBU wells than have the N or O sand OWCs, and 19/60 Polaris Pool Rules and Area Injectio{ der Application September 12, 2002 2. oil versus water contrast is more apparent in the relatively thick and clean M sand section than in the lower net-to-gross N and O sands. Similar to the Polaris N and O sand intervals, M sand OWC levels logged in different M sand intervals indicate that each M sand behaves as a separate reservoir unit. An Mc sand OWC was logged in well W-200 at -4635' TVDSS in the crestal W Pad area upstructure and fault separated from Mc oil in the Mobil exploration well K22-11-12 (Exhibit 1-9). This difference in Mc OWC levels between wells indicates structural and/or stratigraphic isolation between the W Pad and K22-11-12 fault blocks. Mc sand OWC depths in the S and M Pad areas were interpreted at the midpoints between Oil- Down-To and Water-Up-To depths logged in S and M Pad wells. Based on the available fluid data, S and M Pad area Mc OWCs were assumed to be different for each major fault block and may be stratigraPhically as well as structurally controlled. Mb20WCs logged' in the crestal S Pad area indicate reservoir compartmentalization between the well S-200 location (Mb20WC of-4730 feet TVDSS) and several adjacent wells (e.g. S-16 and S-31) which logged Mb20WCs at -4794 feet TVDSS. A W Pad area Mb20WC' of -4595 feet TVDSS was constrained by water-up-to and oil-down-to levels in crestal wells W-200PB 1 (ODT of -4583 feet TVDSS) and W-203 (WUT of- 4604 feet TVDSS). No Mb20WCs were logged at M Pad where the Mb2 sands lie below the regional OWC levels logged at S Pad. Logged and interpreted OWC depths at S and W Pads result in expected case oil column heights of 30 to 94 feet at S Pad, and 35 feet at W Pad. An Mb 1 sand OWC depth at -4770 feet TVDSS is well defined in the crestal S Pad area by multiple logged wells. An M Pad Mb l OWC of -4839 feet TVDSS was logged in well M-01. An Mbl OWC°f-4592 feet TVDSS logged in crestal W Pad well W-212 lies 178 and 247 feet, respectively, higher than the interpreted S and M Pad Mb20WCs. Projected Mb 1 oil column heights are 135 feet at S Pad, 79 feet at M Pad, and 112 feet at W Pad. 20/60 Polaris Pool Rules and Area I' vn Order Application September 12, 2002 Ma sand OWCs are interpreted at the midpoint between updip oil-down-to and downdip water-up-to levels at S and M Pad (-4810 feet TVDSS at S Pad, Exhibit I-4; and -4832 feet TVDSS at M Pad), and between updip oil-down-to and the downdip structural spill point at W Pad (-4700 feet TVDSS) (Exhibit I-9). Based on the interpreted OWC depth, the Ma sands contain oil column heights ranging between 130 feet and 280 feet at S/M Pad and W Pad, respectively. Net Pay and Pool Limits The limits of the Polaris Pool are defined by updip fault barriers and downdip at the zero foot limits of M, N, and O sand expected case net pay. Polaris is bounded on the west and south by north-south and northwest-southeast faults where the reservoir is juxtaposed against impermeable silts and mudstones of the upper Schrader Bluff Formation and overlying Ugnu Formation. To the east and north, the Polaris Pool limit is defined by the down-dip intersection of the top of the reservoir with the expected case O, N, and M sand oil-water contacts. Polaris Pool net pay thicknesses were derived using a petrophysical log model developed for the Polaris Pool. Reservoir porosities were based on log bulk density readings. Grain densities were tied to conventional core grain density measurements from the S-200PB 1 and W-200PB1 wells. Water saturations were calculated using the Archie water saturation equation. Porosity and permeability relationships were derived using core porosity versus core permeability crossplots. Log model cutoffs of 6 millidarcies permeability and .55 water saturation units were used to define Polaris net pay. Exhibits 1-10, I-11, and 1-12 show the location of the proposed Polaris Pool Rules area in relation to the Polaris Pool fault boundaries and expected case limits of O, N, and M sand net pay. Exhibit 1-10 is a Polaris Pool composite O sand net pay map showing the combined thickness and extent of the Polaris area OA through OBf sand net pays in relation to the proposed Pool Rules and Participating Area boundary. The map has a contour interval of 10 feet. Exhibit I-11 is a Polaris Pool composite N sand net pay map showing the combined Na through Nc sand net pay thickness, with a contour interval of 5 feet. Exhibit I-12 is a Polaris Pool composite M sand net pay map showing the combined 21/60 Polaris Pool Rules and Area Injection, cler Application September 12, 2002 Ma through Mc sand net pay thickness, with a contour interval of 10 feet. Exhibits I-13, I-14, and 1-15 show the limits of the Polaris Pool Rules area in relation to O, N, and M sand oil pore-foot thickness contours. Similar to the net pay maps in Exhibits 1-10 through 1-12, the O, N, and M oil pore-foot thickness maps represent the combined, oil pore-foot thickness for all of the O sands (Exhibit 1-13), all of the N sands (Exhibit 1-14), and all of the M sands (Exhibit 1-15). 22/60 Polaris Pool Rules and Area Ir )n Order Application September 12, 2002 II. Reservoir Description and Development Planning Reservoir management and development scenarios for Polaris have been evaluated using pattern and partial field reservoir simulation models. Analyses of well spacing and pattern configurations were performed with the simulation models to identify well locations. Evaluation of Polaris using the Polaris log model and reservoir simulation models has identified water flooding as a viable development option. Low recovery estimates for primary depletion are influenced by low gas oil ratio (GOR), low initial reservoir pressure and viscous oil. Polaris development will utilize the existing footprint of IPA Pads S, M, and W, with minor modifications. , Rock and Fluid Properties Porosity and Permeability Porosity and permeability values were measured by routine core analysis (air permeability with Klinkenberg correction) of core plugs from S-200PB 1 and W-200PB 1. A value of 0.1 was used for the ratio of vertical to horizontal permeability (kv/kh). Typical plug kv/kh values ranged from 0.001 to 1.0. Exhibit II-1 shows values for porosity and horizontal permeability by zone that were used in the reservoir simulation. Porosity and permeability are areally constant in the model. No porosity or permeability cut-offs were utilized. Thick shale intervals were not included in the models but were captured as transmissibility barriers to improve simulation efficiency, while small shales were included. Water Saturation Water saturations were derived using air/brine capillary pressure analyses from S-200PB1 and W-200PB1 core. Distribution of the data was characterized using a Leverett J-function to capture variations in water saturation with variations in porosity and permeability. The J-function data were then used to initialize the Polaris reservoir model under capillary pressure equilibrium. Each interval was assumed to have a separate oil/water contact; the contacts were varied in 'the model to represent various structural locations within the reservoir. 23/60 Polaris Pool Rules and Area lnjecti~ .der Application September 12, 2002 Relative Permeability Relative permeability curves for the Polaris accumulation are based on unsteady state relative permeability experiments on S-200PB 1 and W-200PB 1 core. The experiments resulted in a wide range of curves that were considered of questionable validity because of problems in implementation of the unsteady state technique. The range of results was narrowed to a single curve that is nearly identical to the curves used to model the Schrader Bluff Pool within the Milne Point Unit. Exhibit 11-2 shows the relative permeability curves used in the reservoir simulation. Initial Pressure and Temperature RFT and PBU data from S-200 and W-200 indicate that initial reservoir pressure is somewhat variable, and that the reservoir is compartmentalized. A datum of 5000' tvdss has been chosen as the pressure datum for the Polaris Pool. Average initial reservoir pressure is estimated at 2180 psi at 5000' tvdss in the S Pad area and 2240 psi at 5000' tvdss in the W Pad area. Reservoir temperature is approximately 98 degrees Fahrenheit at this datum. Fluid PVT Data Two types of fluid data have been gathered at Polaris - fluids extracted from whole or sidewall core plugs and down-hole production samples. Data obtained from core plug samples are considered to have a large range of uncertainty. Samples from the same well in the same sand can show API gravity variations of up to 8-10°API units. It is unclear whether the crude variations are real or an artifact of the sample acquisition and processing procedures. The plugs are somewhat flushed during the drilling process and the residual crude may be different than the native-state crude. In addition, the small volumes, extraction techniques, and measurement techniques may contribute to the wide range of data observed to date. Reservoir fluid PVT studies were conducted on down-hole samples from the OBd, OBa/OBb and OA sands in S-200 and from the OBd/OBe sand from W-200. Though the data are limited in quantity and are subject to some uncertainty as noted, the PVT samples show significant variations in fluid properties both horizontally and vertically. 24/60 Polaris Pool Rules and Area Ir ~n Order Application September 12, 2002 These variations likely reflect varying levels of bio-degradation of the Polaris crude. In the OBd sand, API gravity ranges from 22.2 to 24.5° and solution gas oil ratio (GOR) ranged from 287 scf/stb to 326 scf/stb. In the OA sand, the API gravity was measured at 20° with a solution GOR of 250 scf/stb. The formation volume factor ranges from 1.18 to 1.11 RVB/STB in the OBd sand. The formation volume factor was measured at 1.11 RVB/STB in the OA sand. The OBd sand live oil viscosity ranges from 5.1 centipoise (cp) in S-200 to 14.22 cp in W-200. OA sand viscosity was measured at 16.1 cp at reservoir pressure and temperature. Polaris crude shows a wide range of bubble points, varying from 1994 psi in the S-200 OBd sample to 1633 psi in the S-200 OA sample. Exhibit 11-3 shows a summary of the fluid properties for the Polaris accumulation. The PVT properties used in reservoir simulation were derived from measured values; the PVT tables used to represent the S Pad area are shown in Exhibit I1-4. A similar set of tables was created to represent the W Pad area'. Hydrocarbons in Place Estimates of hydrocarbons in place for Polaris are derived from net-oil-pore-feet maps and reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. The current estimate of oil and gas in place are as follows: Zone OOIP (mmstb) OGIP (bscf) Mc 25-120 4-30 N 25-80 5-25 O-Sands 300-550 75-195 Total 350-750 84-250 The ranges in OOIP are determined primarily by uncertainty in the oil-water contacts. The ranges in OGIP are determined by uncertainties in oil-water contacts and solution GOR. The Polaris Pool is under-saturated. Hydrocarbons in place estimates from reservoir simulation are not available because a full-field reservoir simulation model has not been developed. Fluid saturations observed in the pattern models have been compared to saturations calculated by the Polaris log model and are in good agreement. 25/60 Polaris Pool Rules and Area Injecti~. der Application September 12, 2002 Reservoir Performance Well Performance While a number of wells have penetrated the Schrader Bluff Formation in the Polaris area, only two wells, S-200 and W-200, have been tested long term. Both wells have been producing since late 1999 and have successfully sustained rates. Both wells have used gas lift as the artificial lift method, which has caused hydrate problems to occur. The hydrate problems have been somewhat resolved by frequent hot oil tubing washes or by methanol injection. Both wells are producing under primary recovery. In addition to these wells, stable production has been established in W-201 and in S-213 with the use of continuous methanol injection. Stable production has not been established in S-201 and S-216 due to hydrate formation. S-200 is a crestal well in the northern S Pad area. UpOn completion of drilling, the well received four fracture stimulation treatments targeting the N, OA, OBa, OBb, OBd, and OBe sands. Pressure buildup surveys to evaluate the effectiveness of the stimulation treatments showed skins had been reduced to -3. Some of the sands appear, at least in part, to be somewhat unconsolidated. The N sand showed strong tendencies to produce sand while preparing the well for production so a resin squeeze treatment was performed to consolidate the sand in the near-wellbore region. The treatment successfully mitigated sand' production but a skin of +3 Was observed from a post-treatment pressure build-up test. S-200 production was initiated in November 1999 and initially produced at 600 bopd, 450 GOR and 0-10% WC. While somewhat damaged, production logs show theN sand is still' contributing approximately 50 bopd. After 18 months, the well was producing 400-500 bopd, at 5-10% WC and 1000 GOR, and had produced approximately 200 mbo, but was incurring 30-50% down-time because of hydrates forming in the tubing. The well has been shut in since October 2001 after developing mechanical problems with the liner. W-200 is a crestal well in the southern W Pad area. Upon completion of drilling, the OBd and OBf sands were fracture stimulated and tested. A pressure build-up survey 26/60 Polaris Pool Rules and Area I, on Order Application September 12, 2002 indicated a-3.5 skin was achieved with the stimulation treatment. In preparing the well for production, the OBa and OBc sands were perforated and fracture stimulated. Production was initiated in December 1999 and initially tested at 1100 bopd, 450 GOR and 0-5% WC. After 27 months, the well is producing 600 bopd, at 2-5% WC and 2500 GOR, and has produced approximately 585 mbo. W-200 experiences minimal downtime and has not experienced significant hydrate forrnation but has had some paraffin buildup on the tubulars. S-213 penetrates the S/M Pad South fault block. Three fracture stimulation treatments were performed to initiate production from the N, OA, OBa, OBb, and OBd intervals. Production testing between stimulation treatments indicates that all zones are contributing to production. Stimulations were complete by mid-July 2001, and once fully stimulated, the well produced 620 bopd, 12% WC, 1100 GOR. Currently the well is producing using a jet pump as the artificial lift method. W-201 was drilled as a horizontal well in June 2001. The well was designed to find the oil-water contact (OWC) in the OBd interval, be plugged back to provide stand-off from the OWC, and then be completed as a horizontal producer in the OBd interval. The well was drilled and completed as designed, but significant formation damage was incurred in the producing interval. Production was established in July 2001 at 200-400 bopd from the horizontal interval. Attempts to remedy the damage included a formic acid treatment, perforating, and a clay acid treatment, 'but none were successful. The heel of the well was fracture stimulated in the OBa, OBc, and OBd sands in December 2001, significantly improving production. The well produces 600-700 bopd, 0-5% WC, 450 GOR after 7 months of production as a fracture stimulated well. Other Polaris production wells include S-201, S-216, W-203, and W-211. Exhibit IV-1 shows representative well test results for all Polaris wells. The combination of relatively low rates, low produced fluid temperatures, water, and lift gas has created hydrate problems in wells S-201 and S-216 that have not been remedied with hot oil tubing washes and methanol injection. Both wells have been converted to jet pumps as an alternative artificial lift method. Jet pumps have resolved the hydrate problems. Well W-211 was completed as a conventional fracture stimulated well in the O sands and is 27/60 Polaris Pool Rules and Area Injectiot, .~er Application September 12, 2002 currently producing on gas lift. Well W-203 was completed as a trilateral high-angle well with approximate 3500 foot long horizontal sections drilled in each of the OBa, OBc, and OBd sands and is also producing as a gas lifted well. Aquifer Influx The aquifer to the north and east of Polaris could provide pressure support during field development. Early production data from the flanks of the field will be evaluated to determine the extent of pressure support. Gas Coning / Under-Running There are no. indications of a free gas column in the Polaris Pool; coning or under-mn mechanisms are not anticipated. Development Planning Several reservoir models using data from the Polaris Pool were constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. Reservoir Model Construction Initially two separate fine scale three-dimensional reservoir simulation models were constructed using S-200 and W-200 PVT data and core porosity and permeability information. The models are black oil models with grids of approximately 200 feet by 200 feet, representing an area of approximately 800 acres. The models consist of approximately 90 one-foot thick layers representing the sand in the N, OA, OBa, OBb, OBc, and OBd intervals. Faults are not present in either model. The results of the two models were similar and were used for development planning efforts. Development Options Development options evaluated for the Polaris Pool include primary depletion and waterflood. Preliminary screening of miscible gas flooding is also in progress. Primary Recovery Primary recovery was evaluated for development of the Polaris Pool. The primary recovery mechanism was a combination of solution gas drive and reservoir compaction. 28/60 Polaris Pool Rules and Area It m Order Application September 12, 2002 Model results indicate that primary depletion would recover approximately 5-10% of the development area OOIP. Low primary recovery is a result of a combination of low GOR, low initial reservoir pressure and viscous oil. Waterflood Waterflood has been identified as a viable development option for Polaris. It is anticipated that overall field development will involve 15-25 injectors and 25-35 producers. Due to differences in rock quality and crude quality in the different intervals, recovery ranged from 15% to 30% of OOIP (inclusive of primary recovery) in the deVeloped area, at 1.5 hydrocarbon pore volumes injected (HCPVI). Production rates are estimated to peak at 12,000-15,000 bopd, with a maximum water injection rate of 20,000-25,000 bwpd. The Polaris waterflood oil and water production and water injection forecasts are shown in Exhibit II-5. Enhanced Oil Recovery (EOR) Preliminary evaluations indicate that EOR could yield a net recovery of up to 6% of OOIP where implemented. The recovery estimate accounts for vertical and areal sweep efficiencies in Polaris as well as the Prudhoe Bay reserve impact associated with miscible injectant (MI) usage at Polaris. It is requested that an EOR pilot be allowed on three Polaris wells to aid in designing and implementing a full EOR project. This pilot would provide injectivity and conformance information before MI injection, during MI injection, and after MI injection. The Polaris EOR pilot is requested for a period of two years, starting when water injection is initiated in the wells, to allow sufficient fillup and two full WAG cycles The pilot period will allow water injection to be established and fill-up to occur prior to MI injection and is sufficient time to allow two full WAG cycles. The three wells under consideration include one well in the S Pad area targeting the N, OA, OBa, OBb, and OBd sands and two wells in the W Pad area targeting the OBa, OBc, and OBd sands. The MI source will be Prudhoe Bay miscible injectant (MI). Polaris fluids show compositional similarity 'to Milne Point Schrader Bluff fluids for which an equation of state (EOS) characterization has been developed (MPU Schrader Bluff EOS). The MPU Schrader Bluff EOS was demonstrated to reliably predict Polaris 29/60 Polaris Pool Rules and Area Injecti , .der Application September 12, 2002 oil PVT properties as shown in Exhibit 11-6. The MPU EOS was then used in slim-tube simulation to predict miscibility between Prudhoe Bay MI and Polaris fluids ranging in live oil viscosity from 5-40 centipoise. The slim-tube modeling demonstrated the classical multi-contact condensing/vaporizing mechanism with a minimum miscibility enrichment (MME) of lean gas with 60-70% Prudhoe Bay MI. The EOR oil recovery and solvent requirement were estimated by first performing a fine- scale fully compositional reservoir simulation using Polaris type pattern models to capture' the vertical sweep efficiencies. The type pattern models were based on reservoir description from wells S-200 and W-200. MI injection in the S-200 model included zones N, OA, OBa, OBb, and OBd, and the W-200 model included zones OBa, OBc, and OBd. Scale-up of the type pattern was performed to account for areal sweep efficiencies expected with irregular patterns and complex faulting as well as the reserve impact in Prudhoe Bay due to reduced MI in the Prudhoe Bay Miscible Gas .Project. Laboratory phase behavior and slim-tube experiments are underway to fine-tune the EOS characterization. A detailed reservoir simulation study will scale up the S-200 and W-200 pattern model results for application to the entire field. Scale up results will be utilized for optimizing the development to maximize benefits, optimizing WAG parameters (WAG ratio, slug volume, optimum MI start-up time) and defining the volume of Prudhoe BaY MI required as well as the expected returned MI. Horizontal Wells While there have been favorable results with horizontal multi-lateral wells in other Pools within the Schrader Bluff Formation (Milne Point and W.est Sak), the initial development plan for Polaris consists primarily of Vertical wells. Horizontal wells may be utilized selectively. The W-201 well was drilled as a horizontal well to provide horizontal well productivity information. While production from W-201 as a horizontal well was substantially less than expected, the likely source of the problem has been identified. Simulation and development planning efforts show that horizontal wells have the potential to enhance rate and recovery in some areas while reducing development costs and minimizing facility expansion requirements. Horizontal well potential is currently 30/60 Poi,aris Pool Rules and Area h >n Order Application September 12, 2002 being evaluated in the W Pad area where the target has been narrowed to three sands - OBa, OBc, and OBd. A th-lateral well, W-203, that targeted approximately 3500 feet of horizontal section into each of these three sands has been drilled and is currently on production. Development Plan Reservoir simulation supports implementation of a waterflood in the Polaris Pool. Initial development will take place in a step-wise approach, working from the crests towards the outer limits of the Pool, incorporating data gathering necessary to refine development plans. Peak production rates are expected to be 12,000 to 15,000 bopd. Waterflood peak injection rates are estimated at 20,000 to 25,000 bwpd. The Operator will determine the optimal field off-take rate based upon sound reservoir management practices. Phase I Development Phase I development focuses on developing and establishing waterflood operations in select portions of three primary areas. Several water flood development options were studied using the Polaris pattern reservoir simulator; the results provided criteria for spacing of wells and identifying the number of injectors for adequate voidage replacement. Phase I development will be used to validate the development assumptions and refine Phase II and Phase III development plans. Phase I development in the S Pad area to date targets two fault blocks. S/M Pad North block development includes sidetracking S-200 to repair a split liner, then converting the well to injection to support wells S-201 and other potential wells. Performing a production test of the Mc sand in the S-200 well prior to conversion to injection is being evaluated. Other wells being planned include an additional crestal production well and a supporting offset injector, which could also support other potential wells. Aurora well S- 104i will provide support for the additional crestal producer through commingled injection in the Schrader Bluff and Kuparuk. The plans for commingled injection for well S-104 are discussed in the Operations section. Development of the S/M Pad South block consists of two existing producers, S-213 and S-216, and a planned supporting injector S-215i. 31/60 Polaris Pool Rules and Area Injection .der Application September 12, 2002 Phase I development in the W Pad area also is underway and consists of drilling one producer, W-211, and a supporting injector, W-212i, which will also support existing well W-200. A tri-lateral horizontal well, W-203, in the down-dip area of the W Pad polygon, has recently been drilled. It is anticipated that offset injectors will be planned once horizontal well performance has been evaluated and incorporated into the development plans. Phase II Development Polaris Phase II development is directed to completing development of the north, graben, and south S Pad polygons, the W Pad polygon, and the K22-11-12 polygon. Development of these polygons will require an additional 8-12 producers and 5-7 injectors in the S Pad area and 3-8 producers and 4-8 injectors in the W Pad and K22-11-12 areas. Potential locations have been identified but may be modified as production performance from Phase I development, espeCially horizontal well performance, is evaluated and simulation efforts are continued. The Phase II drilling program is designed to access down-dip areas with higher water saturation as well as higher-risk, structurally complex areas. Phase III Development Polaris Phase III development would involve developing areas that require improved understanding of fault transmissibility and presence, or refinements in drilling techniques to reach the targets. These areas include the Term Well C area, the Horst Block area, and extreme down-dip areas of the blocks developed in Phase I and Phase II. Phase I and Phase II results and performance data will be key in moving forward with developing ,, Phase III areas. Well Spacing Initial well spacing for development is nominally 120 acres under the vertical well development scenario. Due to faulting, the patterns are expected to be irregular and wells ' may be areally very close to adjacent wells but will be isolated due to reservoir compartmentalization. Infill drilling and peripheral drilling will be evaluated based on production performance and surveillance data. To allow for future flexibility in 32/60 Polaris Pool Rules and Area I on Order Application September 12, 2002 developing the Polaris Pool and tighter well spacing across fault blocks, a minimum well spacing of 20 acres is requested. Reservoir Management Strategy A key development strategy is to maintain reservoir pressure above the bubble point. Drilling injectors and establishing waterflood patterns as the producers are drilled will minimize offtake under primary depletion. The voidage replacement ratio (VRR) will be balanced to maintain average reservoir pressure above the bubble point pressure. The objective of the Polaris reservoir management strategy is to operate the Pool in a manner that will maximize recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached as a dynamic process. The initial strategy is derived from model studies and limited well test information. DeVelopment well results and reservoir surveillance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Polaris Pool will continue to be evaluated throughout the life of the field. Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Polaris Pool. Development will take place in up to three phases. The first phase includes establishing production and waterflood operations in key areas at both S Pad and W Pad. Additionally, Phase I accommodates a tri-lateral horizontal producer. Phase II would encompass developing the reinainder of the core areas of the field. Phase III would progress development in areas that currently require improved understanding including fault tra.nsmissibility and presence, or refinements in drilling techniques to reach the targets. Peak production rates are expected to be 12,000 - 15,000 bopd. After waterflooding commencement, peak injection rates will be 20,000 - 25,000 bwpd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. Polaris production performance to date can be divided into two aspects - reservoir delivery and well operability. Production results to date confirm initial evaluations of 33/60 Polaris Pool Rules and Area Injectioi' der Application September 12, 2002 reservoir delivery. Well operability, affected primarily by hydrate formation, has been more of a problem in recent wells than indicated from initial production. Keeping the wells on line with a combination of low rates, cool production temperatures, presence of water, and lift gas composition and temperature, have proven both challenging and costly. The use of alternative artificial lift methods, enhancing rate through better fracture stimulations and the use of horizontal wells are all expected to improve operability. 34/60 Polaris Pool Rules and Area 1~ )n Order Application September 12, 2002 III. Facilities General Overview Polaris wells will be drilled from existing IPA drill sites, M Pad, S Pad and W Pad, and will utilize existing IPA pad facilities and pipelines to produce Polaris fluids to Gathering Center 2 (GC-2) for processing and shipment to Pump Station No. 1 (PS 1). Polaris fluids will be commingled with IPA fluids on the surface at the respective Well Pads to maximize use of existing IPA infrastructure, minimize environmental impacts, reduce costs, and maximize recovery. The GC-2 production facilities to be used include separating and processing equipment, inlet manifold and related piping, flare system, and onsite water disposal. IPA field facilities that will be used include low-pressure large diameter flowlines, gas lift supply lines and water injection supply lines associated with the three IPA pads. Existing MI supply lines may be utilized for future EOR applications. The oil sales linc from GC-2 to PS 1 and the power distribution and generation facilities will be utilized. Exhibit III-1 shows details of the Polaris well tie-ins at S Pad and Exhibit 111-2 shows details of the proposed S Pad Polaris development. Drill Pads and Roads M Pad, S Pad and W Pad have been chosen as the surface locations of Polaris wells to reach the expected extent of the reservoir while minimizing new gravel placement, minimizing well step out, and allowing for the use of existing facilities. An expansion of existing S Pad to accommodate additional wells was completed in April 2000. Additional gravel requirements at M Pad and W Pad have not been determined. However, efforts will be made to stay within the existing permitted footprint of these Well Pads. A schematic of the S Pad drill site layout including contemplated Polaris facility additions is shown in Exhibit Ill-2. Schematics of the existing M and W Pads are included as Exhibit 111-3 and 111-4. 35/60 Polaris Pool Rules and Area lnjecti . .der Application September 12, 2002 No new pipelines are planned for development of the Polaris reservoir. Polaris production will be routed to GC-2 via the existing low-pressure large diameter flowlines. No new roads or roadwork is anticipated. Pad Facilities and Operations A trunk and lateral production manifold capable of accommodating up to 20 Polaris wells is planned as an extension to an existing S Pad manifold system. A schematic showing the surface well tie-ins is shown in Exhibit 111-2. The size and type of well tie-in manifold system required for M Pad and W Pad have not been determined. Water for waterflood operations will be obtained by extending an existing 6" water injection supply line at S Pad. Preliminary engineering calculations indicate the line is sufficient to deliver water to Polaris injection wells at a rate of 28,000 bpd and a pressure of approximately 2000 - 2100 psig. Should water injection pressures be insufficient, injection pressure will be boosted loCally. An upgrade of the existing S Pad power system should not be required for additional water injection booster pumps. Artificial lift will be performed either with artificial lift gas or with jet pumps using injection water as the power fluid. Artificial lift gas will be obtained from the existing 10" gas lift supply line at S Pad. Preliminary engineering estimates indicate that the line is sufficient to deliver gas to Polaris production wells at a rate of 30 mmscfd and a pressure of approximately 1800 psig. For jet pumping, injection water pressure may need to be boosted locally to optimize the power fluid to produced fluid ratio. It is anticipated that water for waterflood operations, artificial lift gas and MI (if needed) can be supplied to Polaris wells at M Pad and W Pad from the existing pipeline infrastructure. Should injection pressure be insufficient for Polaris requirements, it could be boosted locally. Well control will include automated divert valves. Well safety systems and the pad emergency shutdown system will be set up to be operated manually as well. Wells will be tested using existing well test facilities at S, M and W Pads. Wells will be 36/60 Polaris Pool Rules and Area IL on Order Application September 12, 2002 put into test using automated divert valves. Test frequency and protocols are addressed in Section V. Well pad data gathering will be performed both manually and automatically. The data gathering system will be expanded to accommodate the Polaris wells and drill site equipment. The data gathering system will continuously monitor the flow, pressures and temperature of the producing wells. These data will be under the well pad operator's supervision through his monitoring station. Gathering Center No modifications to the GC-2 production center will be required to process Polaris production. GC-2 was built to process a nominal oil rate of 400 mbopd, gas rate of 320 mmscfd (modifications have increased this to 1,200 mmscfd) and a nominal produced water rate of 280 mbwpd. Production, including that from the Polaris Pool, is not expected to exceed GC-2 capacity. 37/60 Polaris Pool Rules and Area Injectiot{ .~er Application September 12, 2002 IV. Well Operations Existing Wells A number of exploration, appraisal and development wells that targeted the deeper Kupamk and Ivishak production have been drilled and logged in the Schrader Bluff Formation. However, only the recently drilled S-200, S-201, S-213, S-215i, S-216 W- 200, W-201, W-203, W-211 and W-212i have been drilled and completed in the Polaris Pool. These well locations are shown in Exhibits I-2 and 1-3. The Polaris Pool is currently producing from four W Pad wells (W-200, W-201, W-203, and W-211) and four S Pad wells (S-200, S-201 S-213, S-216). Recent well test data for these wells are shown in Exhibit IV-1. S-200 was shut-in in October 2001 due to a liner problem. One W Pad injector, W-212i, and one S Pad injector, S-215i, will be available for water injection upon approval of the Area Injection Order. A second S Pad injector, S-200, will be available for water injection once the well is converted from a producer to an injector, scheduled by year end. Drilling and Well Design Polaris development wells will be directionally drilled utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in the Prudhoe Bay Unit and other North Slope fields. A 16" or 20" conductor casing will be set 80' to 120' below pad level and cemented to surface. Requirements of 20 AAC 25.035 concerning the use of a diverter system and Secondary well control equipment will be met. Surface hole will be drilled no shallower than 500 TVD feet below the base of permafrost level. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle/build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous PBU wells. Cementing and casing requirements similar to other North Slope fields have been adopted for Polaris. 38/60 Polaris Pool Rules and Area I~ on Order Application September 12, 2002 The casing head and blowout-preventer stack will be installed onto the surface casing and tested consistent with 20 AAC 25.035. The production hole will be drilled below surface casing to the target depth in the Schrader Bluff Formation, allowing sufficient rathole to facilitate logging. Production casing will be set from surface and cemented. Production liners will be used as needed to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells, such as high departure or horizontal wells. No significant H2S has been detected in the Schrader Bluff Formation while drilling other development wells or in any Polaris well drilled to date. However, with planned waterflood operations there is potential of generating H2S over the life of the field. Consequently, H2S gas drilling practices will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellpad. All personnel on the rig will be informed of the dangers of H2S, and all rig pad supervisors will be trained for operations in an H2S environment. Well Design and Completions Multi-lateral, horizontal and conventional wells may be drilled at Polaris. The horizontal and multi-lateral well completions could be perforated casing, slotted liner, barefoot section, or a combination. All conventional wells will have cemented and perforated completions. Fracture stimulation may be necessary, to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8" to 5-1/2" depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Polaris wells. 39/60 Polaris Pool Rules and Area Injectio$. der Application September 12, 2002 The following table indicates typical casing and tubing sizes for proposed Polaris wells: Surface Inter / Prod Casing Production Production Casing Liner Tubing Conventional 10-3/4" to 7" 7" to 3-1/2" Not Planned 4-1/2" to 2-3/8" Horizontal & 10-3/4" to 7" 7" to 4-1/2" 5-1/2" to 2-7/8" 4-1/2" to 2-3/8" Multi-lateral ................................ Plans are to run L-80 grade casing in the Polaris wells. Tubing strings will be completed with either 13-Chrome or L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/1Moly, which is compatible with both L-80 and 13-Cr. Use of 13-super chrome or equivalent is possible on certain completion jewelry. Polaris producers will' be completed 'in a single zone (Schrader Bluff Formation). Injectors may be single or multi-zone (Kuparuk, Schrader Bluff, Sag and/or Ivishak Formations) utilizing a single string and multiple packers as necessary. As shown in the typical well schematics (Exhibit IV-2 for conventional production wells, Exhibit IV-3 for conventional injector wells, and Exhibit IV-4 for multi-zone injector wells), the wells have gas lift mandrels to provide flexibility for artificial lift or commingled production and injection. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Additionally, jewelry will be installed so that jet pumps can be utilized providing further flexibility for artificial lift. Any completions that vary from regulatory specifications will be brought before the Commission on a case by case basis. The Polaris Owners may utilize surplus IPA wells for development provided they meet Polaris needs and contain adequate cement and mechanical integrity. The injectors will be designed to enable multi-formation injection where appropriate to the Kuparuk, Schrader Bluff, Sag and Ivishak Formations. Injectors may be pre- produced prior to converting to permanent injection. Production from these wells could improve their injectivity and be used to evaluate reservoir productivity, connectivity and 40/60 Polaris Pool Rules and Area I on Order Application September 12, 2002 pressure response, enabling refinement of reservoir models and depletion plans. Measurement while drilling (MWD) and logging while drilling (LWD) will typically begin after setting the 9-5/8" or 7-5/8'' surface casing. Production hole will be drilled to below the Schrader Bluff Formation and either a 5-½" by 3-½" or 7" long string will be cemented in place across the Schrader Bluff Formation. MWD will typically include drilling parameters such as weight on bit, rate of penetration, inclination angle, etc. LWD measurements will typically include gamma ray (GR), resistivity and density and neutron porosity throughout the reservoir section. Open hole electric logs may supplement or replace LWD logging, including GR, resistivity, density and neutron porosity and other logging tools when wellbore conditions allow their use. A nine (9) to eleven (11) pound per gallon (ppg) freshwater low-solids non-dispersed mud system or equivalent will typically be used to drill the production / injection hole down to the 7" casing point. If any horizontal section is drilled, the mud system parameters may be optimized for that hole section. The horizontal wells and multi-lateral wells will typically utilize 7" intermediate casing set in the Schrader Bluff Formation. The reservoir section will be drilled with a 6-1/8" horizontal production hole, completed with a 4-½" or 3-V2" slotted or solid liner, and cemented and perforated as necessary Surface Safety Valves Surface safety valves (SSV) are included in the wellhead equipment for all Polaris Pool wells (producers and injectors). These devices can be activated by high and low pressure sensing equipment on the flowline and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded. Testing of SSVs will be in accordance with Commission requirements. Subsurface Safety Valves The characteristics of the Polaris Pool should not require the installation or use of subsurface safety valves on production wells. Polaris producers are relatively low rate oil wells produced by artificial lift in a waterflood development. Subsurface safety 41/60 Polaris Pool Rules and Area Injectio~ .~er Application September 12, 2002 valves (SSSV) will be installed on gas or miscible injectant (MI) injectors when in service. All well completions will be equipped with nipple profile at a depth just below the base permafrost should the need arise to install a downhole flow control device or pressure operated safety valves during maintenance operations or for future MI service. Subsurface safety valves are not required in Polaris wells under the applicable regulation, 20 AAC 25.265. In light of developments in oil field technology, controls and experience in operating in the arctic environment, the Commission has eliminated SSSV requirements from pool rules for the Prudhoe Oil Pool and the Kuparuk River Oil Pool. See Conservation Orders 363 and 348, respectively. In addition, SSSVs have not been required for producing wells at Milne Point, and West Sak, also producing from the Schrader Bluff Formation. Drilling Fluids Freshwater low solids, non-dispersed fluids will be used to drill the Schrader Bluff Formation. Typically KC1 will be added to this mud system for weight and to reduce formation damage caused by reactive clays. Other muds may be used in the future to minimize skin damage from drilling and enhance performance. Stimulation Methods Fracture stimulation has been implemented for all vertical Polaris producers drilled to date and may be implemented in the future to mitigate formation damage, for sand control and to stimulate Polaris wells. It may also be necessary to stimulate horizontal wells, depending upon well performance. Acid or other forms of stimulation may be performed as needed in the future. Reservoir Surveillance Program Reservoir surveillance data will be collected to monitor reservoir performance and define reservoir properties. Reservoir Pressure Measurements An updated isobar map of reservoir pressures will be maintained and reported at the 42/60 Polaris iPool Rules and Area I on Order Application September 12, 2002 common datum elevation of 5,000' TVDSS. Pressure data could be stabilized static pressure measurements at bottom-hole or extrapolated from surface (assuming single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, repeat formation test, permanent gauges, or an open hole formation test. An initial static reservoir pressure will be measured on each production or injection service well. A minimum of one reservoir pressure will be taken each year in each of the six Polaris reservoir polygon areas identified in Exhibit 1-7, (i.e., S/M Pad North, S/M Pad Graben, S/.M Pad South, W Pad/TW-C, K221112, and Horst Block polygons), when at least one Polaris production well has been completed in the respective polygons. A minimum of two pressure surveys will be taken annually in the S/M Pad North and the W Pad/TW-C reservoir polygons, as identified in Exhibit I-7, when two or more production wells have been completed in each of these polygons. It is anticipated that the operator will collect more pressure measurements during initial field development to identify potential compartmentalization and fewer measurements as the development matures. Data and results from all relevant reservoir pressure surveys will be reported annually and will be available to 'the Commission upon request. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, may be periodically run to help determine reservoir performance (i.e., production profile and injection profile evaluations). Surveillance logs will be run on commingled injection wells annually to assist in the allocation of flow splits. Completions - Producing Wells Current development plans call for two types of producing wells, conventional hydraulically fractured wells, and high angle/horizontal wells. The conventional hydraulically fractured well will have surface casing set 500 feet or deeper below the base of permafrost, located at approximately 2000' TVDSS, and cemented to surface. A "longstring" production casing will be run from surface to TD which will typically be set 100 feet below the base of the production target to allow room for production logging. The longstring will be cemented from TD to above the highest significant hydrocarbon- 43/60 Polaris Pool Rules and Area Injecti~ rder Application September 12, 2002 bearing interval in the Ugnu section. Production tubing will be run inside the longstring and sealed in the long string at least above the Mc sand with a production packer or other sealing device to provide an isolated annulus to be used for gas lift. Gas lift mandrels will be placed in the tubing string as well as a sliding sleeve to accommodate jet pumps. There will be no subsurface safety valve, however a nipple will be installed at approximately 2200 feet TVDSS. There will also be nipples located above and below a production packer or other sealing device. High angle wells will be similar to the conventional completion described above. High angle wells will either have a cased and perforated completion, a slotted liner hung off in the longstring or some other variation High angle multilateral completions are being evaluated to enhance recovery and rate while reducing development costs, .facility requirements, and downtime associated with lower flow rates from conventional wells. Artificial Lift The primary artificial lift method will be gas lifting with lift gas supplied from the gas lift system, with jet pumping using injection water as the power fluid as a possible alternative. It is anticipated that all Polaris production wells will require artificial lift for the life of the well. Gas lift has proven to provide a bottom hole flowing pressure of approximately 1000 psi but has caused operational difficulties. The majority of the producing wells are within the hydrate window when they are first starting up with gas lift, making them operationally difficult to keep online until the wellhead temperature is above 50 deg. F. Controlling hydrates has been accomplished with hot oil treatments and methanol injection with mixed success. Jet pumps are currently being deployed and tested and are expected to mitigate the hydrate problems associated with gas lift. Polaris will likely experience a mix of gas lifted and jet pumped wells throughout field life. Completions - Injection Wells The injection wells will have surface casing set below the base of the SV3 sand located at approximately 2800' TVD and cemented to surface. Exhibit IV-3 shows a typical injection well completion diagram. A "longstring" casing will be run from surface to TD which will typically be set 100 feet below the base of the injection target to allow room 44/60 Polaris Pool Rules and Area I~ )n Order Application September 12, 2002 for future logging. The longstring will be cemented from TD to above the highest significant hydrocarbon-bearing interval in the Ugnu section. Injection tubing utilizing metal-to-metal seals will be mn inside the longstring and sealed approximately 200 feet above the Ma sand with an injection packer or other sealing device to provide an isolated annulus to be used for monitoring casing integrity. Tubing-casing annulus pressure and injection rate of each injection well will be checked at least weekly to confirm continued mechanical integrity. A schedule will be developed and coordinated with the Commission that ensures the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. There will be no SSSV during water injection service, but injectors will have a nipple capable of accepting an SSSV during MI injection. Commingled Injection Approval is requested to complete commingled injectors where deemed prudent, including approval for commingled water injection in well S-104i in the Aurora and Polaris pools. Well S-104i was completed with isolation packers and injection mandrels, which will allow multi-zone water injection. Installing a restrictive orifice in the injection mandrels will control injection rates. Water injection allocation will be accomplished by performing a spinner survey at least once per year. Additional opportunities may arise to take advantage of commingled injection wells. 45/60 Polaris Pool Rules and Area Injecti .ier Application ~, September 12, 2002 V. Production Allocation Polaris production allocation will be done according to the PBU Western Satellite Production Metering Plan, described in the letter dated April 23, 2002. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor will be applied to adjust total Polaris production. All new Polaris wells will be tested a minimum of two times per month during the first three months of production. A minimum of one well test per month will be used to tune the performance curves and to verify system performance. No NGLs will be allocated to Polaris wells. To support implementation of this procedure, several modifications to the WOA allocation system have been initiated. Conversion of all well test separators in the GC-2 area to two-phase operation with a coriolis meter on the liquid leg is expected to be complete in 2002. The test bank meters at GC-1 and GC-2 have been upgraded as part of the leak detection system and a methodology for generating and checking performance curves for each well has been developed. 46/60 Polaris Pool Rules and Area h .)n Order Application September 12, 2002 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection and a miscible gas injection pilot to enhance recovery from the Polaris Pool. The proposed area for Area Injection Operations is the Polaris Participating Area outline shown in Exhibit 1-2. This section addresses the specific requirements of 20 AAC 25.402(c). Plat of Project Area 20 AAC 25.402(c)(1) Exhibit I-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Polaris Pool, as of June 1, 2002. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or applicable successor regulation. Operators/Surface Owners 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) BP Exploration (Alaska) Inc. is the operator of the proposed Polaris Participating Area. Exhibit VI-1 is an affidavit showing that the Operators and Surface Owners within a one- quarter mile radius of the area and within the proposed Polaris Participating Area have been provided a copy of this application for injection. Description of Operation 20 AAC 25.402(c)(4) Development plans for the Polaris Pool are described in Section II of this application. Drill pad facilities and operations are described in Section III. Geologic Information 20 AAC 25.402(c)(6) The geology of the Polaris Pool is described in Section I of this application. 47/60 Polaris Pool Rules and Area Injecti~ .der Application September 12, 2002 Injection Well Casing Information 20 AAC 25.402(c)(8) Three wells, S-104i, S-215i, and W-212i, were permitted and drilled for injection service for the Polaris Pool. The casing programs for these wells were permitted and completed in accordance with 20 AAC 25.030. The completion diagram in Exhibit IV-3 is representative of a typical Polaris injection well. Exhibit IV-4 demonstrates a typical Polaris-Aurora commingled injector. A cement bond log has been run on S-104i and demonstrates isolation of injected fluids to the Kuparuk River and Schrader Bluff Formations. The S-104i well was completed in accordance with 20 AAC 25.412. Cement bond logs will be obtained on S-215i and W- 212i to demonstrate zonal isolation prior to water injection. The casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for newly drilled injection wells. All drilling and production operations will follow approved operating practices regarding the presence of H2S in accordance with 20 AAC 25.065. Conversion of wells from production service to injection service will be in accordance with 20 AAC 25.412. Injection Fluids 20 AAC 25.402(c)(9) Type of Fluid/Source Fluids requested for injection for the Polaris Oil Pool are: a.' Produced water from Polaris or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; b. Tracer survey fluid to monitor reservoir performance; c. Fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); d. Source water from the Seawater Treatment Plant; e. Prudhoe Bay miscible gas from the PBU MI distribution system in one S Pad 48/60 Polaris Pool Rules and Area Ir )n Order Application September 12, 2002 injector and two W Pad injectors for a period of two years for the purpose of testing MI injectivity and post-MI water injectivity (Polaris EOR Pilot). The pilot is requested for two years with the pilot time-period starting when water injection is initiated in the individual wells. The AOGCC will be notified of the pilot wells prior to commencing MI injection. The initial plan is to use produced water from GC-2 as the primary water source for Polaris injection. No compatibility issues between source water and injection zones of interest have been identified. Composition The injection water composition in the Polaris Pool, based on water analysis from the W- 200 well, GC-2 produced water, and sea water, are provided in Exhibit VI-2. The composition of Polaris produced water will be a mixture of connate water and injection water, and these will change over time depending on the rate and composition of injection water. The composition of Prudhoe Bay miscible gas is provided in Exhibit VI-3. Mechanical Integrity of Wells 20 ^^C 25.402¢)(15) Mechanical Integrity of Wells Within SA mile of Iniectors Three injection wells have been drilled S-104i, S-215i, and W-212i. Two injection wells W-207i and S-200i may be drilled in the near future. A map showing all penetrations through the Schrader Bluff Polaris Pool, and wells within 1¼ mile of the injection wells are shown as Exhibit VI-4. The wells within the 1¼ mile radius are, W-15, W-17, K241112, S-03, S-24A, S-31A and S-200PB 1. A report of the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well is included as Exhibit VI-5 to VI-11. 49/60 September 12, 2002 Maximum Injected Rate Maximum fluid injection requirements at the Polaris Pool are estimated at 20,000 to 25,000 BWPD. Injection Pressures 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 2300 psig. The estimated maximum surface injection pressure is 2800 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing, with a maximum expected bottom hole pressure of 5100 psig. 'Fracture Information 20 AAC 25.402(c)(11) The expected maximum injection pressure for Polaris Pool injection wells will not propagate fractures through the confining strata, which would allow fluids to enter any freshwater strata. Each Schrader Bluff O, N, and M sand is separated from the adjacent overlying and underlying sand by 10 to 75 foot thick non-reservoir silty mudstones which provide effective fluid isolation between adjacent sands as shown by regional fluid level data (e.g., Exhibit 1-4). In several production wells (e.g. S-200 and W-200) the O and N inter-sand mudstones have been stimulated with propped hydraulic fracture treatments designed to connect adjacent sands. The minimum stress during the propped fracture treatments has been measured in the O and N sands by performing data fracs, which were analyzed to determine closure pressure. The average frac gradient in the sands is 0.61 psi/ft with a range from 0.59 to 0.62 psi/ft. A stress test' was performed in Polaris well S-213 to determine the frac gradient of the basal mudstone in the OBa at 6020 feet MD (5067 feet TVDSS). This non-reservoir silty mudstone is typical of Polaris O, N, and M interval mudstones by virtue of the 95 API units on the GR log versus 35-45 API units for the clean sandstone. The results of the S-213 stress test indicated a frac gradient in the mudstone of 0.66 psi/ft. This would yield a stress contrast of 5100 feet TVDSS x (0.66 - 0.61 psi/ft ) =255 psi 50/60 Polaris Pool Rules and Area Il on Order Application September 12, 2002 between the sandstone and mudstone layers. The average net pressure during the fracture treatments is 189 psi. The treating pressure during these propped fracture treatments exceeds the available produced water injection pressure, therefore, it is unlikely that a net pressure will be reached through injection that will cause a fracture to grow above the mudstone barriers. The stress contrast estimate was confirmed by an analysis of the rock properties in well S-200 from data obtained by running a Dipole Sonic Log. The analysis shows a 300psi stress contrast between the sandstone and mudstone, which reasonably matches the contrast shown in the S-213 stress test..The observed mudstone properties appear to be similar through out the Polaris Pool area, both laterally and vertically, therefore, it is apparent that multiple barriers are present which will provide containment within the Pool. To ensure injection contbrmance, injection performance will be monitored for each injection well. Any significant change in injectivity, which would indicate injection out of zone will be followed up with surveillance. The surveillance could include spinner/temperature logs and if necessary, a tracer survey to determine the location of the injection anomaly. Freshwater Strata Aquifer Exemption Order #1., dated July 11, 1986, exempts all portions of the aquifers beneath the Western Operating area of the Prudhoe Bay Unit, including the area designated under the Polaris Area Injection Order. Hydrocarbon Recovery 20 AAC 25.402(c)(14) Polaris Pool original oil in place is discussed in Section II. Reservoir simulation studies, also discussed in Section II, indicate incremental recovery from waterflooding to be approximately 10-20% of the original oil in place, relative to primary depletion. 51/60 Polaris Pool Rules and Area Injectio~ .~er Application September 12, 2002 VII. Proposed Polaris Pool Rules BP Exploration (Alaska) Inc., in its capacity as Polaris Operator and Unit Operator, respectfully requests that the Commission adopt the following Pool Rules for the Polaris Oil Pool: Rule 1: Field and Pool Name The field is the Prudhoe Bay Field and the pool is the Polaris Pool. The Polaris Pool is classified as an Oil Pool. Rule 2: Pool Definition The Polaris Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 5393 feet MD and 6012 feet MD in the PBU S-200PB 1 well (-4651 and -5269 feet TVDSS, respectively), within the area described below. Affected Area (Umiat Meridian): Township Range Lease Sections T12N-R12E ADL28256 Sec ADL 47448 Sec ADL28257 Sec ADL28258 Sec T12N-R13E ADL28279 Sec TllN-R13E ADL28282 Sec TllN-R12E ADL28260 Sec ADL28261 Sec ADL 28263-1 Sec ADL 28263-2 Sec 22 S/2 S/2 and NE/4 SE/4 23 S/2 NW/4 and SW/4 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26, 35, 36 27, 33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 31 SW/4 NW/4 and SW/4 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4, 7 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4, 8 W/2 SW/4 1, 2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 15, 16E/2 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4 52/60 Polaris Pool Rules and Area In n Order Application September 12, 2002 ADL 47451 Sec ADL28264 Sec ADL 47452 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 26 N/2 N/2 27 NE/4 NE/4 Rule 3: Well Spacing To allow for close proximity of wells in separate fault blocks, spacing within the pool will be a minimum of 20 acres. The pool shall not be opened in any well closer to 500 feet to an external boundary where ownership changes. Rule 4: Casing and Cementing Practices (a) In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface. (b) In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' TVD below the base of the permafrost. Rule 5: Automatic Shut-in Equipment (a) All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and preventing an uncontrolled flow. (b) All wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a down hole flow control device. (c) Subsurface safety valves (SSSV) must be installed on gas or miscible (MI) injection wells when in service. (d) Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the SSV system, SSSV system, and associated equipment are in proper working condition. Rule 6: Common Production Facilities and Surface Commingling (a) Production from the Polaris Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. (b) The Pmdhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002. (c) All wells must be tested a minimum of once per month. All new Polaris wells must be tested a minimum of two times per month during the first three months of production. 53/60 Polaris Pool Rules and Area Injectioi aer Application September 12, 2002 (d) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. (e) Commission approval of the Prudhoe Bay Unit Western Operating Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined no later than July 31, 2003. Rule 7: Reservoir Pressure Monitoring (a) Prior to regular production or injection, an initial pressure survey must be taken in each well. (b) A minimum of one pressure survey will be taken annually in each of the six Polaris reservoir compartments where Polaris production wells exist. A minimum of two pressure surveys will be taken annually in the S/M Pad North and the W Pad/TW-C reservoir polygons when two or more production wells have been completed in each of these polygons. (c) The reservoir pressure datum will be 5000' feet true vertical depth subsea. (d) Pressure surveys may consist of stabilized static.pressure measurements (bottom-hole or extrapolated from surface), pressure fall-off tests, pressure build-up tests, multi- rate tests, drill stem tests, and open-hole formation tests. (e) Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. (f) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. Rule 8: Gas-Oil Ratio Exemption Wells producing from the Polaris Pool are exempt from the gas-oil ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240(b) are met. Rule 9: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 1633 psi at the datum depth of 5000' or by May 1, 2003, whichever occurs first. Rule 10: Multiple Completion of Water Injection Wells (a) Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as there is mechanical isolation between pools. (b) Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. 54/60 iPolaris Pool Rules and Ama Ir ~n Order Application September 12, 2002 (c) Results of logs or surveys used for determining the allocation of water injection must be supplied in the yearly reservoir surveillance report. Rule 11: Reservoir Surveillance Report An annual reservoir surveillance report for the prior calendar year must be filed by April lst: (a) Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques. (b) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval. (c) Summary and analysis of reservoir pressure surveys within the pool. (d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. (e) Review of pool production allocation factors and issues over the prior year. (f) Future development plans (g) Review of annual Plan of Operations and Development. Rule 12: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into fresh water. 55/60 Polaris Pool Rules and Area Injectiot. _ler Application September 12, 2002 VIII. Proposed Area Injection Order BP Exploration (Alaska) Inc., in its capacity as Polaris Operator and Unit Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Polaris Pool and consider the following rules to govern such activity: Affected Area: Township Range Lease Sections T12N-R12E ADL 28256 Sec ADL 47448 Sec ADL28257 Sec ADL28258 Sec 22 S/2 S/2 and NE/4 SE/4 23 S/2 NW/4 and SW/4 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26, 35, 36 27, 33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2 T12N-R13E ADL 28279 Sec 31 SW/4 NW/4 and SW/4 TllN-R13E ADL28282 Sec 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4, 7 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4, 8 W/2 SW/4 TllN-R12E ADL28260 Sec 1, 2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4 ADL28261 Sec 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 ADL 28263-1 Sec 15, 16 E/2 ADL 28263-2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4 ADL 47451 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 ADL 28264 Sec 26 N/2 N/2 ADL 47452 Sec 27 NE/4 NE/4 56/60 Polaris Pool Rules and Area h )n Order Application September 12, 2002 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to, and correlate with, the interval between the measured depths of 5393 and 6012 feet in the PBU S-200PB 1 well (-4651 and -5269 feet TVDSS, respectively). Rule 2: Authorized Injection Fluids Fluids authorized for injection within the affected area are: (a) (b) (c) (d) Produced water from Polaris or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; Tracer survey fluid to monitor reservoir performance; Source water from the Seawater Treatment Plant; Prudhoe Bay miscible gas from the PBU MI distribution system in one S Pad injector and two W Pad injectors for a period of two years for the purpose of testing MI injectivity and post-MI water injectivity (Polaris EOR Pilot). The pilot is requested for two years with the pilot time-period starting when water injection is initiated in the individual wells. The AOGCC will be notified of the pilot wells prior to commencing MI injection. Rule 3: Fluid Injection Wells The 'underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412. The application to drill or convert a well for injection must be accompanied by sufficient information to verify the mechanical condition of wells within one-quarter mile radius. The information must include cementing records, cement quality log or formation integrity test records. Rule 4: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity 57/60 Polaris Pool Rules and Area Injecti~. der Application September 12, 2002 A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. Rule 6: Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 7: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result an increased risk of fluid movement into a fresh water source. 58/60 Polaris Pool Rules and Area Ir ,n Order Application September 12, 2002 IX. List of Exhibits I- 1 Location of the Polaris Pool Alaska North Slope 1-2 Polaris Pool and Proposed Polaris Participating Area Outline Map 1-3 Polaris Pool Area Top Schrader Bluff OA Structure Map 1-4 Polaris Pool Area Structural Cross Section A - A' I-5 Polaris Pool Type Log S-200PB 1 I-6. Polaris Pool Area Lower Mb2 Mudstone Isopach Thickness Map I-7 Polaris Pool Area N and O Sand Reservoir Compartment Map I-8 Polaris Pool S and M Pad Area Interpreted Oil/Water Contacts Cross Section g mB~ 1-9 Polaris Pool W Pad Area Interpreted Oil/Water Contacts Cross Section 1-10 Polaris Pool Area Schrader Bluff O Sand Composite Net Pay Thickness Map I- 11 Polaris Pool Area Schrader Bluff N Sand Composite Net Pay Thickness Map 1-12 Polaris Pool Area Lower Ugnu M Sand Composite Net Pay Thickness Map I-13 Polaris Pool Area Schrader Bluff O Sands Composite Oil Pore Foot Thickness Map I-14 Polaris Pool Area Schrader Bluff N Sands Composite Oil Pore Foot Thickness Map 1-15 Polaris Pool Area Lower Ugnu M Sands Composite Oil Pore Foot Thickness Map II-1 Polaris Model Reservoir Description 59/60 Polaris Pool Rules and Area Injectiol, aer Application September 12, 2002 11-2 Polaris Relative Permeability Plot 11-3 Polaris Fluid Properties 11-4 Polaris Model PVT Properties 11-5 Polaris Waterflood Rate Forecast 11-6 Polaris PVT Match Using MPU Schrader Bluff EOS 111-1 Polaris Well Tie-ins-Northem S Pad 111-2 Polaris S Pad Development - Surface Facilities III-3 Polaris M Pad Development - Surface Facilities 111-4 Polaris W Pad Development- Surface Facilities IV,1 IV-2 Polaris Well Test Summary Typical Polaris Production Well Bore Schematic IV-3 Typical Polaris Injection Well Bore Schematic IV-4 Typical Polaris-Aurora Commingled Injector Well Bore Schematic VI-1 Affidavit VI-2 Polaris Injection Water Compositions VI-3 VI-4 Prudhoe Bay Miscible Gas Properties Polaris Pool/Injection Area VI-5 VI-6 VI-7 W-15 Well Integrity Report W-17 Well Integrity Report K241112 Well Integrity Report VI-8 S-03 Well Integrity Report VI-9 S-24A Well Integrity Report VI-10 S-31A Well Integrity Report VI-11 S-200 & S-200PB 1 Well Integrity Report 60/60 Location of the Polaris Alaska North Slope , . :::,,.,., North Star Unit Milne Poin't :' Unit :un~, Kuparuk River Unit Po~a¢~s Poo~ Prudhoe Bay Unit 0 3 6 Miles Exhibit 1-1. Po]aris Po]aris T12N=R12E PoP'injection Area a Participating Area Proposed Outline s Pool/Inject on Area and Proposed Polar s Participating Ares Gl"eer~ Cor~tours - Extenf of Polads O Sa~,d Pay Red Cor~tours - Extelqt of PoJaris N Sar'~d P~y Exhibit I-2. Blue Cor'~tours - Exter~t of Polaris M Sal-~d Pay Po~ris Pool/~njectio~Area Top Schrader B~uff OA Structure ~lap Schrader Bluff Schrader Bluff Schrader Bluff ¢~ HighAng~e Exhibit 1~3, Polaris Pool/Injection Area Type Lo9 We]] S-200PB1 Nc Oga OBe GAP[ Oil APl Gravity from Core 200 SWC) APl APl APl APl APl APl APl APl APl APl APl Exhibit Exhibit H-5 - Polaris Waterflood Rate Forecast Polaris Waterflood Rate Forecast 30000 ~ i~Polaris Oil Production Polaris Water Production = ~ ~ Polaris Water Injection 25000], ~20000 15000 10000 5000 1995 2000 2005 2010 2015 2020 2025 2030 2035 Exhibit I11-1 Polaris Well Tie-ins - Northern S-Pad To/]Fro m Modde 57 S-216 S-44 S-200 S412i S400 S407i S~201 S-114 8-104i S-!0/i S402 Sl10 S-108 Sl13 S-103 S406 S-105 0000 To/From Modde 93 PoNris Well Aurora Well Aurora injection Well IPA Welt Pote~tial Well Pipk~g Producti{m/l'¢s~ (;as tlft Water Exhibit 111-2: Polaris S-Pad Development Production (#) Test (#) Gas Lift (#) Water (#) M~ (#) Future Equipment (#) Aurora Well Existing Polaris Well IPA Well Potential IPA Well # - Surface Satellite Equipment Exhibit 111-3' Polaris M Pad Development 1133 .......... Enter Exit 10 ~=--,x []24 53 cs WELL PRODUCER WELL INJECTOR 86 B Enter/Exit .... _ ?4-_/ _ DATE : 09/18/2001 SCALE: 'V' = 250' MAP DATE: 1999 PBU - M PAD bs14495 dgn (Well surface locations shown are PBU IPA wells; future Polaris Pool well M Pad surface locations have not yet been determined) Exhibit !11-4' Polaris W Pad Development Polaris 2002 Scope Polaris Future Scope RELIEF SUMP NOTES: WELL, 4" PRODUCTION LINE AND 3" GLT LINE GAS OR WATER INJEC-RON WELL, SOURCE WA-FER WELL CELLAR, 4" PRODUCTION LINE AND 3" GLT LINE -- NO WELL HEAD CELLAR ONLY -- NO LINES OR WELL HEAD SUBSIDENCE WELL SUMP EXHIBIT IV-1. POLARIS REPRESENTATIVE WELL TEST SUMMARY Well Test Date s-200- 10/23/2001 Oil Flow Rate Watercut Gor Tubin_~ BPD Pct scf/bbl oil Gas Lift Rate Temp 409 0 584 1,330 39 Tubing Pressure 304 S-201 ** 8/22/2002 252 26 690 0 112 306 S-213** 8/23/2002 276 10 865 0 107 305 S-216** 7/4/2002 362 8 393 0 110 293 W-200 8/15~002 W-201 8/27/2002 W-203'** 8/27/2002 609 3 1,190 1,540 55 610 18 641 1,560 52 287 284 1548 7 1428 3460 69 298 W-211 8/19/2002 . * Shut-in ** On Jet Pump *** Multi-lateral Well 315 61 1323 2990 62 313 TREE = 4" 5000 psi 9-5/8" CSG, 40#, L-80-BTC, ID= 8.835" IVinirru'n ID = 2.813" 3-1/2" X NIPPLE 3-1/2" 'I'BG, 9.3~ L-80 .0087 bpf, ID= 2.992" Exhibit 1¥-2. I 4-1/2 " X 3-1/2" XO NP, ID = 2.992" i3-1/2" X NIP, ID =2.813" I iGAS LIFT MANDRELS I Sliding Sleeve I 3-1/2 " X NIP, ID=2.813" '1 7"X4-1/2" PKR, ID=3.875" I 3-1/2" HES X NIP, ID = 2.813" I I 3-1/2 " HES X NIP, ID = 2.813" I IWLEG I 7" CSG, 26#, L-80 MOD-BTC, ID = 6.276" I I 20 'SHORTJOINT& RA TAG I I 20 'SHORTJOINT& RA TAG I PRUDHOE BaY UNIT / FOLARIS FIELD Typical Production Well BP Exploration (Alas ka) TREE = 4" 5000 psi Exhibit IV-3. 9-5/8" CSG, 40#, L-80-BTC, ID = 8.835" IIVinirr[m ID 3.725" 4-1/Z' XN-Nipple 3-1/2" TBG, 9.3~ L-80 .0087 bpf, ID= 2.992" I4-1/2" X NIP, ID = 3.813" I I 4-1/2 " X NIP, ID = 3.813" I I 7 " X4-1/2" PKR, ID =3.938" I4-1/2" X NIP, ID = 3.813" I I 4-1/2 " XN NIP ,ID = 3.813" I IWLEG I 20'SHORTJOINT& RA TAG I I 20 'SHORTJOINT& RA TAG I 7" CSG, 26#, L-80 MOD-BTC, ID = 6.276" PRUDHOE BAY UNIT / POLARIS FIELD Typical Polaris Injection Well BP Exploration (Alas ka) Exhibit IV-4. TREE: 4-1/16 "- 5M CIW Carbon WELLHEAD: 11" - 5M FMC G5 9-5/8", 40 #/ft, L-80, BTC I1900-4000' TVDss I 4-1/2" 'X' Landing Nipple 3.813" ID 7" x 4-1/2" Baker "Premium" ~ Production Packer 3-1/2" MMGW Water Flood GLM with Injection Valve w/Prem threads Plug Back De 7", 26 #/ft, L-80, BTC-Mod 4-1/2" 'x' Landing Nipple with 3.813" seal bore. 4-1/2" 12.6# L-80, Premium Connection Tubing 3-1/2" NSCT 9.3 # L-80 Tubing between MMGW GLM's 3-1/2" 'X' Landing Nipple 2.813"1D 7"x 4-1/2" Baker "S-3" Packer 3-1/2" 'X' Landing Nipple 2.813" ID 3-1/2" 'X' Landing Nipple 2.813" ID 3-1/2" WireLine Entry Guide PRUDHOE BAY UNIT/POLARIS FIELD Typical Polaris-Aurora Commingled Injector APl NO: 50-029-xxxx BP Exploration (Alaska) Exhibit VI-1. AFFIDAVIT STATE OF ALASKA THIRD JUDICIAL DISTRICT .. · I, Gilbert G. Beuhlerl declare and affh'm as follows: . I am the Greater Prudhbe BaY Satellites Manager for BP Exploration (Alaska) Inc., the designated operator of the proposed Polaris Participating Area, and as such have responsibility for Polaris operations. .. On ~?~1-i/':~-°~:¢ I caused copies of the Polaris Pool Rules and Area 'Injection Order ApPlication t° be provided to the following surface owners and operators of all land within a quarter mile radius of the proposed injection area: : ',.. Operators: BP EXPLORATION(ALAsKA), INC. ATTENTION: NEIL MCCLEARY ' ANCHORAGE, 99519~6612 Surface Owners: :.... STATE OF ALASKA'i.:. '/~'. · .. DEPARTMENT OF' N~~ RESOURCES ATTENTION: DR. '~K,MYERS 550 WEST 7TM AVENUE}suITE 800 ANCHORAGE, AK' 99501-3510 Gilbert G. Beuhler ' ."' .. Declared and affirmed before me this day of ~ a.~2)4-cH ~.~ x~- · 2. 0o2- Notary Public. in',and for. Ala<ska My commissi°n' :~xph'es: My Ci3r~'"'/zfli:~.qi on Exhibit VI-2: Polaris Injection Water Compositions Barium:.'-:-_:~': :::;/:~i':.----iii' ~'" 16.9 2.17 i 0 aicarb°nate:'~ '.'~ ..... 4640 .................................... ~64~-~)' .................. i ................. ~-Z~'(~ ................... calciUm; "i-~-:'::':::''''~ 55 .............. 247 ........................ '! ...................... ~i~'~ ................ .Ch iOride,.'.-:_.;:' '.._....::' ::. - · ........................ r;i~,-~~ .......................... ! ...................... ;i"~56'~)-6 ..................... i' ................... i"~b ............... Sodium-~.: .:)-' ':': ':- 7221 8080 ~ 8400 - .'. -.J .-. - . ' _ . ~.~.~ ...... . ..... ; .................. . ................. -,.,..~.~.. ........... .,.~.:... ...... ~.. ............... . ................ Strontium '- ' 10.3 26.2 , 5 '-~ ~ .- -' . . - .. ' ....... . ............ . .......... . ....... . ........... -_- ....... ........ . ...................... . ............................ _ ........ + ...................... ~ ..... . .......... Sulfate 479 560 ~ 2670 ..... '.- ~ ~ TDS--'. '~ -"- 26322 ~ 23427 .~ 28687 - :1 ' ' ' ''1'' I' Exhibit VI-3: Prudhoe Bay Miscible Gas Properties :C02: "--~'.:~- i.:.!':..-:-:. 44.01 18.8- 19.3 .C3."-/':~ '; .... - -' 44.1 20.1 - 23.7 -nC~--._~':'''' ---:'.'.:/-:' ....... ~~ ............... ~.9- 5.-4 nc5-:'~/.. ~_-.~. ~_.'._~: .: ........... ~'~2'~-S .................................. 70'a-' :~2-0-~ C 10~13.:: ~:_ :. :.-_._ ':: ........ ~-~-35 2-~ .............................. O.-o- C14;:lgt :.::,' :: ;":::- ....... ~23'~'~ ................................. ~'~ C2o,35-: -.-_-._: aza.s2 o.o C36+~ '""- 722 0 M°i-Wt' .'-.'." 31.g- 32.1 . Polari~ ~o]/Injection Polaris injection Wei~ Location Map 7 --~ ${} 29 el/~njeot[en Area and P~*op©sed Pe~ris Ps~icips~ ng Aresj Exhibit Vt-4. : Inte Exhibit VI-5 W- 15 Wel~ Original Completion Date: Schrader Bluff Penetration Hole Diameter: 7/14/90 12-1/4" Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: 9-5/8" SI-CTD Sidetrack Cement Logs Across Schrader Bluff: None Comments: Cement returns to surface were noted during the 13-3/8" primary cement The 13-3/8" casing was tested to 3000 psi. The 9-5/8" primary cement job was designed to cover the Ugnu sands. The 9-5/8" casing was pressure tested at 2500 psi. At the time of this writing W-15 is being sidetracked with coiled robing in the 9-5/8" casing with a window cut at 11822'md. Additional Information: Exhibit VI-5a Well Diagram Exhibit VI-5b Directional Survey Exhibit VI-5c Significant Drilling Daily Reports & Cement Program Exhibit VI- 5a ~ TRIq= = 4-1/16" CiW ACTUATOR = OTIS " > 90° @ 12148'. *HORIZONTAL WELL* KB. BEV = 90.6~,' BF. ELEV = 54.24' KOp= 3193'~ t2o85, H4.1/Z, OTISHXOSSSV.P,~D:3.843,,I Max Angle = 90@12700 ~"~1 Datum MD = 11692' ~)aturn TV D = 8800' SS ' ~GAS LFT MANDRELS I' 1'~'~ --~ =~-"~~~'I~TCH PORT DATE I ,~-~...os~. ~#..-~o..o=,~.~.. H ~o" I~ i~ -r ~---~ ~..~~-~-~-¢~- ~ ~ o~,~.~'---~ 4 6279 5429 52 OTIS DMY RA 0 07/19/02 -~ 3 9304 71981 47 o~s D~ RA , 0 07149/02 ,, 2 10988 8375, 4910~S D~ RA I 0 07/~9/02 Minimum ID= 3.813" @2085' I 11215 8521L 51 o~s DMY RA ~0 07/49/02 4-112" OTIS SSSV NIPPLE I I { 11244' H4-1/2"PARKERSWSNIP, ID=3.813" I ~ ~~t 11251' H0-5/8"X4-1/2"OTIShr::MPKR, D=3.SS0"I I I t 1127s' ~4-1~2"PA~<EaSWSN~P,~D--3.8~"I t I-----i ~36' H~-~,,~,.x~.,¥,¥v.~,~,~,-,-,,:.,,o,~.v I?'X4-112"TIWS-6PKR, D=3.863" H 11844' ~,~-----~ 12351' Hq-1/2"OT~S XDSLIDI~IGSLV, ,D=3.813"I REF LOG: TIE Ixl [OG/$ONA/RWD ON 07107190 Note: Refer to Production DB for historical perf data SIZE SPF HTE~VA L Opn/Sqz DATE 2-7/8" 6 11810- 11840 O 0,~/03/98 2-7'8" 6 11868-11974 O 05/03/98 ~ ~ ~ 12732' HCT'cExT CSGPKR I 2-3/4" 6 12420- 12440 O 7/2/1993 2-3/4" 6 12680-12700 0 7/2/1993 13134 H4-1/2,, OTIS XD SLIDI',IG SLV, 1314,4' 3" BKR IBP- 08/29/90 I 4-112"LNR, 12.~, [-80, .0~52,,bpl, ID' 3.958" H 13105' I'~ · DATE REV BY COIVNIENTS DATE REV BY COMIVENTS PRUDHOEBAY UNIT 07/14/90 DFF ORIGINALCOiVPLETION 08/18/02 JLJ/KK SErWHIPSTOCK& CBP WELL: W-15 02/09/01 SIS-QAA CONVICTED TO CANVAS PERMITNo: 190-0530 ,,, 03/05/01 SIS-LG FINAL AFl No: 50-029-22042-00 04/05/02 RN/CH/TF CORRECTIONS SEC 21, Tll N, R12E. 836' FIlL & 1184' FEL 07/19/02 jB/tlh GLv UPDATE BP Exploration (Alaska) ,, SIZE SPF HTE~VA L ..Opn/Sqz DATE 2-7/8" 6 11810 - 11840 O 0~/03/98 2-7/8" 6 11868 - 11974 O 05/03/98 2-3/4" 6 12420- 12440 O 7/2/1993 2-3/4" 6 12540- 12560 O , 7/2/1993 2-3/4" 6 12680- 12700 O 7/2/1993 DATE REV BY COIVtvlENTS DATE REV BY COMIVENTS 07/14/90 DFF ORIGINAL COiVPLETION 08/18/02 JLJ/KK SEt WHIPSTOCK & CBP 02/09/01 SIS-QAA CONVI3~TED TO CANVAS ,,, 03/05/01 SIS-LG FINAL 04/05/02 RN/CH/TF CORRECTIONS 07/19/02 jB/tlh GLv UPDATE Wel*i W-15 Directional Survey( ................................................. Exhibit VI - ~ 500292204200 COMP Bp Exploration (Alaska) APZ/UWI: Survey Type: Company: Survey Date: Survey Top: Survey Btm: 0' MD 13,166' MD MD TVD SS INCLINE AZIMUTH DOGLEG ASP_X ASP_Y 0 0.00 90.64 0.00 0.00 0.0 612,048.6 5,959,421.2 40 40.00 50.64 0.22 116.07 0.0 612,048.8 5,959,421.2 41 41.00 49.64 0.22 120.31 1.6 612,048.8 5,959,421.2 48 48.00 42.64 0.15 126.42 1.0 612,048.8 5,959,421.2 60 59.80 30.84 0.10 127.60 0.4 612,048.8 5,959,421.2 72 71.60 19.04 0.12 122.85 0.2 612,048.8 5,959,421.2 83 83.40 7.24 0.13 117.54 0.1 612,048.8 5,959,421.2 95 95.10 -4.46 0.13 116.21 0.0 612,048.8 5,959,421.2 109 108.50 -17.86 0.12 118.42 0.1 612,048.9 5,959,421.2 122 122.45 -31.81 0.12 117.92 0.0 612,048.9 5,959,421.2 136 136.40 -45.76 0.10 116.60 0.1 612,048.9 5,959,421.2 150 150.35 -59.71 0.10 112.13 0.1 612,048.9 5,959,421.2 164 164.30 -73.66 0.10 101.66 0.1 612,048.9 5,959,421.2 178 178.30 -87.66 0.10 92.19 0.1 612,049.0 5,959,421.2 192 192.30 -101.66 0.08 81.35 0.2 612,049.0 5,959,421.2 206 206.35 -115.71 0.05 63.53 0.3 612,049.0 5,959,421.2 222 221.65 -131.01 0.02 335.38 0.4 612,049.0 5,959,421.2 238 237.85 -147.21 0.05 233.02 0.4 612,049.0 5,959,421.2 254 253.95 -163.31 0.12 201.61 0.5 612,049.0 5,959,421.2 270 270.15 -179.51 0.17 176.85 0.5 612,049.0 5,959,420.8 286 286.35 -195.71 0.20 150.38 0.6 612,049.0 5,959,420.8 303 302.55 -211.91 0.17 113.25 0.8 612,049.0 5,959,420.8 319 318.75 -228.11 0.15 65.66 0.8 612,049.0 5,959,420.8 335 334.95 -244.31 0.08 0.08 0.9 612,049.1 5,959,420.8 351 351.25 -260.61 0.07 251.33 0.8 612,049.1 5,959,420.8 368 367.50 -276.86 0.13 157.43 0.9 612,049.1 5,959,420.8 384 383.80 -293.16 0.17 107.08 0.8 612,049.1 5,959,420.8 400 400.05 -309.41 0.20 65.08 0.8 612,049.1 5,959,420.8 416 416.35 -325.71 0.18 24.30 0.8 612,049.3 5,959,420.8 433 432.60 -341.96 0.10 282.80 1.4 612,049.3 5,959,420.8 449 448.90 -358.26 0.10 155.66 1.1 612,049.1 5,959,420.8 465 465.10 -374.46 0.15 82.56 1.0 612,049.3 5,959,420.8 481 481.30 -390.66 0.23 65.33 0.6 612,049.3 5,959,420.8 498 497.65 -407.01 0.32 48.63 0.7 612,049.4 5,959,420.8 514 514.00 -423.36 0.25 348.60 1.8 612,049.4 5,959,421.2 530 530.35 -439.71 0.15 39.17 1.2 612,049.4 5,959,421.2 547 546.65 -456.01 0.23 92.75 1.1 612,049.4 5,959,421.2 563 563.00 -472.36 0.32 33.08 1.7 612,049.5 5,959,421.2 579 579.35 -488.71 0.17 294.96 2.3 612,049.5 5,959,421.2 596 595.70 -505.06 0.15 154.71 1.8 612,049.5 5,959,421.2 612 612.05 -521.41 0.30 53.66 2.2 612,049.5 5,959,421.2 628 628.40 -537.76 0.22 341.90 1.9 612,049.5 5,959,421.2 645 644.75 -554.11 0.15 18.04 0.8 612,049.5 5,959,421.2 661 661.05 -570.41 0.28 63.90 1.3 612,049.6 5,959,421.2 677 677.20 -586.56 0.30 1.24 1.9 612,049.6 5,959,421.5 693 693.30 -602.66 0.18 45.57 1.3 612,049.6 5,959,421.5 709 ' 709.45 -618.8'1' 0.23 85.05 0.9 '612,049.6 5,959,421.5 726 725.60 -634.96 0.30 19.40 1.8 612,049.7 5,959,421.5 742 741.80 -651.16 0.15 270.06 2.3 612,049.7 5,959,421.5 758 757.95 -667.31 0.18 141.49 1.8 612,049.7 5,959,421.5 774 '790 806 823 839 855 871 887 904 920 936 952 968 984 1,001 1,017 1,033 1,049 1,065 1,081 1,098 1,114 1,130 1,146 1,162 1,178 1,195 1,211 1,227 1,243 1,259 1,276 1,292 1.308 1.324 1.341 1.357 1.373 1,389 1.405 1,422 1,438 1,454 1,470 1,486 1,502 1,518 1,534 1,550 1,566 1,582 1,598 1,614 1.630 1.646 1.662 1.678 1.694 1.710 1,727 1,743 1,759 1,775 1,791 1,807 1,824 1,840' 1,856 1,872 1,888 774.10 790.30 806.45 822.60 838.80 855.00 871.15 887.35 903.55 919.65 935.85 952.05 968.25 984.35 1,000.55 1,016.70 1,032.85 1,048.95 1,065.10 1,081.29 1,097.49 1,113.69 1,129.89 1,146.09 1,162.29 1,178.44 1,194.64 1,210.84 1,226.99 1,243.24 1,259.44 1,275.64 1,291.84 1,308.04 1,324.29 1,340.54 1,356.74 1,372.94 1,389.19 1,405.44 1,421.59 1,437.59 1,453.59 1,469.59 1,485.59 1,501.59 1,517.69 1,533.69 1,549.79 1,565.84 1,581.89 1,597.94 1,613.94 1,629.94 1,646.03 1,662.13 1,678.23 1,694.33 1,710.43 1,726.63 1,742.73 1,758.93 1,775.03 1,791.23 1,807.38 1,823.58 1,839.78 1,855.88 1,872.08 1,888.28 -683. -699. -715.. -731.' -748.16 -764.36 -780.51 -796.71 -812.91 -829.01 -845.21 -861.41 -877.61 -893.71 -909.91 -926.06 -942.21 -958.31 -974.46 -990.65 -1,006.85 -1,023.05 -1,039.25 -1,055.45 -1,071.65 -1,087.80 -1,104.00 -1,120.20 -1,136.35 -1,152.60 -1,168.80 -1,185.00 -1,201.20 -1,217.40 -1,233.65 -1,249.90 -1,266.10 -1,282.30 -1,298.55 -1,314.80 ~1,330.95 -1,346.95 -1,362.95 -1,378.95 -1,394.95 -1,410.95 -1,427.05 -1,443.05 -1,459.15 -1,475.20 -1,491.25 -1,507.30 -1,523.30 -1,539.30 -1,555.39 -1,571.49 -1,587.59 -1,603.69 -1,619.79 -1,635.99 -1,652.09 -1,668.29 -1,684.39 -1,700.59 -1,716.74 -1,732.94 :1,749.14 -1,765.24 -1,781.44 -1,797.64 ,ibit VI- 5b 0.32 57.27 0.22 345.22 0.17 35.19 0.28 93.46 0.28 30.33 0.17 309.57 0.17 192.77 0.27 86.65 0.23 14.81 0.17 295.40 0.22 212.61 0.22 115.43 0.15 . 21.71 0.17 291.10 0.27 229.86 0.35 216.54 0.30 204.65 0.23 216.77 0.33 216.34 0.42 192.09 0.28 187.71 0.30 203.64 0.43 208.59 0.37 186.99 0.25 185.71 0.33 203.36 0.47 201.93 0.38 182.04 0.25 159.82 0.25 178.75 0.38 200.72 0.43 185.37 0.33 160.04 0.22 154.22 0.30 179.32 0.48 184.95 0.45 159.04 0.35 144.50 0.28 145.25 0.22 168.15 0.33 193.29 0.48 192.89 0.45 176.63 0.37 152.43 0.28 141.24 0.22 160.84 0.32 184.06 0.43 176.26 0.35 151.63 0.30 137.00 0.23 128.98 0.18 162.00 0.20 168.75 0.22 135.03 0.15 112.14 0.13 159.14 0.13 156.29 0.13 65.70 0.22 50.38 0.23 31.69 0.23 27.63 0.23 58.06 '0,28 ' ' 38.65 0.27 28.64 0.28 52.67 0.30 26.11 2.1 1.9 2.2 2.0 2.0 2.0 1.1 1.5 1.8 1.9 1.8 2.2 1.8 1.6 1.6 2.0 1.7 1.4 1.5 0.7 0.5 0.6 0.6 1.1 0.9 0.5 0.8 1.0 0.8 0.7 0.9 1.1 1.1 0.5 1.1 0.7 1.2 0.7 0.9 1.1 1.3 0.9 0.4 0.7 1.0 0.9 0.8 1.2 0.7 0.7 0.9 0.8 1.2 0.6 0.5 0.8 0.2 0.8 0.6 0.7 0.0 1.1 0.6 0.5 0.1 0.7 0.6 0.3 0.7 0.8 612,04~7 612,0~' ' 612,04~.i' 612,049.7 612,049.9 612,049.9 612,049.9 612,049.9 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,049.9 612,049.9 612,049.9 612,049.7 612,049.7 612,049.7 612,049.8 612,049.6 612,049.6 612,049.6 612,049.6 612,049.5 612,049.5 612,049.5 612,049.5 612,049.5 612,049.5 612,049.5 612,049.5 612,049.6 612,049.5 612,049.7 612,049.7 612,049.7 612,049.8 612,049.8 612,049.7 612,049.7 612,049.8 612,049.8 612,049.8 612,049.8 612,049.8 612,049.9 612,049.9 612,049.9 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.2 612,050.2 612,050.2 612,050.2 612,050.3 612,050.3 612,050.3 612,050.4 612,050.4 612,050.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.9 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.5 5,959,421.2 5,959,421.2 5,959,421.2 5,959,421.2 5,959,420.8 5,959,420.8 5,959,420.8 5,959,420.4 5,959,420.4 5,959,420.4 5,959,420.4 5,959,420.1 5,959,420.1 5,959,420.1 5,959,420.1 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.3 5,959,419.3 5,959,419.3 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.0 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.2 5,959,418.2 5,959,418.2 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,419.0 1,gOb 1',921 1,937 1,953 1,969 1,986 2 ~002 2.017 2.028 2.040 2.051 2,063 2,074 2,086 2,098 2,109 2,121 2,132 2,144 2,156 2,172 2,188 2,205 2.221 2.238 2.255 2.271 2.288 2,305 2,322 2,338 2,355 2,372 2,388 2,405 2,422 2,439 2,455 2,472 2,489 2,506 2,522 2,539 2,556 2,573 2,590 2,606 2,623 2,640 2,657 2,674 2,690 2,707 2 224 2,741 2,757 2,774 2,791 2,808 2,825 2,842 2,858 2,875 2,892 2,909 2,925 2,942" 2,959 2,975 2,992 ...% ,-.%/.%/~, 1,904.b3 1,920.73 1,936.93 1,953.13 1,969.33 1,985.53 2,001.83 2,016.53 2,028.03 2,039.63 2,051.23 2,062.83 2,074.38 2,085.93 2,097.53 2,109.08 2,120.68 2,132.28 2,143.68 2,156.28 2,171.63 2,188.18 2,204.78 2,221.38 2,238.08 2,254.78 2,271.43 2,288.08 2,304.78 2,321.48 2,338.18 2,354.83 2,371.53 2,388.33 2,405.03 2,421.73 2,438.53 2,455.33 2,472.08 2,488.83 2,505.63 2,522.43 2,539.18 2,555.98 2,572.78 2,589.58 2,606.38 2,623.18 2,639.93 2,656.78 2,673.58 2,690.38 2,707.13 2,723.92 2,740.67 2,757.42 2,774.32 2,791.12 2,807.91 2,824.71 2,841.60 2,858.39 2,875.27 2,892.05 2,908.63 2,925.20 2,941.76 2,958.31 2,974.86 2,991.39 -1,~13.~9 -1,830.09 -1,846.29 -1,862.49 -1,878.69 -1,894.89 -1,911.19 -1,925.89 -1,937.39 -1,948.99 -1,960.59 -1,972.19 -1,983.74 -1,995.29 -2,006.89 -2,018.44 -2,030.04 -2,041.64 -2,053.04 -2,065.64 -2,080.99 -2,097.54 -2,114.14 -2,130.74 -2,147.44 -2,164.14 -2,180.79 -2,197.44 -2,214.14 -2,230.84 -2,247.54 -2,264.19 -2,280.89 -2,297.69 -2,314.39 -2,331.09 -2,347.89 -2,364.69 -2,381.44 -2,398.19 -2,414.99 -2,431.79 -2,448.54 -2,465.34 -2,482.14 -2,498.94 -2,515.74 -2,532.54 -2,549.29 -2,566.14 -2,582.94 -2,599.74 -2,616.49 -2,633.28 -2,650.03 -2,666.78 -2,683.68 -2,700.48 -2,717.27 -2,734.07 -2,750.96 -2,767.75 -2,784.63 -2,801.41 -2,817.99 -2,834.56 -2,851.'12' -2,867.67 -2,884.22 -2,900.75 ,!~ <hibit VI-5b 0.17 6.96 0.27 70,89 0.33 22.25 0.35 340.82 0.33 330.55 0.27 307.75 0.17 265.06 0.13 177.86 0.20 86.21 0.28 30.65 0.28 325.33 0.23 266.19 0.17 179.93 0.22 82.04 0.30 31.25 0.27 336.35 0,22 331.46 0.28 341.05 0.23 269.67 0.18 146,14 0.28 25.08 0.32 323.87 0.22 238.40 0.20 107.96 0.25 7.69 0.23 308.93 0.22 246.16 0.20 159.76 0.20 174.12 0.23 237.01 0.25 190.64 0.18 70.46 0.17 282.83 0.27 185.12 0.20 107.63 0.18 119.58 0.33 155.21 0.17 179.04 0.17 191.19 0.33 130.02 0.23 143.75 0.27 147.83 0.22 84.13 0.17 106.48 0.30 152.99 0.40 149.24 0.47 140.59 0.52 117.33 0.63 111.12 0.72 121.10 0.75 120.85 0.80 113.32 0.90 107.78 1.02 106.43 1.23 108.23 1.67 112.11 1.98 111.24 2.25 110.91 2.55 111.02 2.97 110.24 3.42 109.29 3.70 109.04 4.08 108.94 4.45 108.78 4.82 108.98 5.48 109.66 ).9 2.1 0.8 1.5 1.6 1.6 0.6 1.1 1.6 1.8 2.1 2.0 2.6 2.2 2.4 2.6 2.1 2.1 0.4 0.4 1.8 2.2 2.4 1.8 2.3 2.3 2.1 1.4 1.4 1.7 0.3 1.3 1.1 2.2 2.0 2.0 1.8 0.3 1.3 1.1 0.2 1.7 0.7 0.3 1.6 0.5 1.3 0.6 0.6 1.2 0.8 0.9 0.2 0.7 0.8 0.7 1.3 2.7 1.8 1.6 1.8 2.5 2.7 1.7 2.3 2.2 2.2 4.0 blZ,UDU.D 612,050,.~ 612,05~ 612,050.7 612,050.7 612,050.7 612,050.8 612,050.8 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.6 612,050.5 612,050.5 612,050.5 612,050.5 612,050.5 612,050.5 612,050.5 612,050.5 612,050.4 612,050.4 612,050.4 612,050.4 612,050.4 612,050.4 612,050.4 612,050.4 612,050.4 612,050.4 612,050.5 612,050.5 612,050.5 612,050.5 612,050.6 612,050.7 612,050.8 612,050.8 612,050.8 612,050.9 612,050.9 612,051.0 612,051.2 612,051.4 612,051.5 612,051.8 612,052.0 612,052.3 612,052.6 612,053.0 612,053.5 612,054.1 612,054.7 612,055.5 612,056.4 612,057.4 612,058.'5 612,059.6 612,060.8 612,062.3 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.7 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.4 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.0 5,959,419.0 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.6 5,959,418.3 5,959,418.3 5,959,418.3 5,959,418.3 5,959,417.9 5,959,417.9 5,959,417.6 5,959,417.6 5,959,417.2 5,959,416.9 5,959,416.5 5,959,416.'2 5,959,415.8 5,959,415.5 5,959,414.8 ~,UUO 3,025 3,042 3,058 3,075 3,091 3,108 3,125 3,141 3,158 3,174 3,191 3,205 3,225 3,250 3,276 3,303 3,330 3,357 3,383 3,410 3,437 .3,464 3,491 3,518 3,545 3.572 3.599 3.625 3.656 3.682 3,717 3.753 3,788 3,823 3,859 3,895 3,930 3,966 4,001 4,037 4,072 4,108 4,144 4,179 4,215 4,251 4,286 4.322 4.357 4.392 4,427 4,462 4,496 4,531 4,566 4,601 4,636 4,671 4,706 4,741 4,777 4,812 4,847 4,882 4,917 · 4,952 4,988 5,023 5,057 .D,UU ! · '~ J,- 3,024.36 3,040.85 3,057.33 3,073.79 3,090.24 3,106.67 3,123.14 3,139.49 3,155.98 3,172.34 3,188.30 3,202.42 3,222.12 3,246.25 3,272.40 3,298.59 3,324.63 3,350.63 3,376.57 3,402.59 3,428.60 3,454.54 3,480.42 3,506.33 3,532.15 3,557.79 3,583.38 3,608.67 3,637.46 3,661.82 3,694.60 3,727.45 3,760.18 3,792.84 3,825.40 3,858.04 3,890.42 3,922.77 3,954.81 3,986.77 4,018.68 4,050.48 4,082.11 4,113.53 4,144.74 4,175.64 4,206.30 4,236.75 4,266.48 4,295.96 4,325.20 4,353.71 4,382.03 4,410.01 4,437.73 4,465.38 4,492.88 4,520.06 4,546.86 4,573.28 4,599.33 4,625.06 4,650.40 4,675.34 4,699.78 4,723.80 4,747.54 4,770.64 4,793.06 ~ ~1~ 1') -/,~J. I.~l -2,933.72 -2,950.21 i'-,,,hibit VI- 5b -2,966.69 -2,983.15 , ..-,~ -2,999.60 7.97 109.37 -3,016.03 8.35 109.68 -3,032.50 8.70 109.24 -3,048.85 9.02 108.47 -3,065.34 9.40 107.68 -3,081.70 9.82 106.96 -3,097.66 10.12 106.46 -3,111.78 10.45 105.88 -3,131.48 10.93 105.02 -3,155.61 11.43 104.30 -3,181.76 11.97 103.58 -3,207.95 12.50 102.97 -3,233.99 12.97 102.45 -3,259.99 13.45 101.83 -3,285.93 13.98 101.18 -3,311.95 14.52 100.63 -3,337.96 15.07 100.14 -3,363.90 15.60 100.03 -3,389.78 16.07 100.18 -3,415.69 16.63 100.35 -3,441.51 17.30 100.34 -3,467.15 17.90 100.11 -3,492.74 18.62 99.76 -3,518.03 19.45 99.46 -3,546.82 20.20 99.46 -3,571.18 20.73 99.74 -3,603.96 21.53 100.28 -3,636.81 22.30 100.57 -3,669.54 22.87 100.57 -3,702.20 23.28 100.53 -3,734.76 23.67 100.37 -3,767.40 24.13 99.94 -3,799.78 24.62 99.26 -3,832.13 25.08 98.62 -3,864.17 25.57 98.14 -3,896.13 26.05 97.86 -3,928.04 26.58 97.55 -3,959.84 27.13 97.31 -3,991.47 27.82 97.33 -4,022.89 28.60 97.42 -4,054.10 29.47 97.58 -4,085.00 30.35 97.73 -4,115.66 31.03 97.75 -4,146.11 31.63 97.73 -4,175.84 32.32 97.80 -4,205.32 33.17 98.07 -4,234.56 34.03 98.33 -4,263.07 34.77 98.46 -4,291.39 35.57 98.60 -4,319.37 36.47 98.72 -4,347.09 37.30 98.75 -4,374.74 38.10 98.68 -4,402.24 38.98 98.59 -4,429.42 39.92 98.58 -4,456.22 40.88 98.68 -4,482.64 41.83 98.81 -4,508.69 42.72 98.96 -4,534.42 43.53 99.06 -4,559.76 44.38 99.16 -4,584.70 45.37 99.37 -4,609.14 46.35 99.60 , -4,633.16. 47.28 . 99.77 -4,656.90 48.22 99.92 -4,680. O0 49.17 100.09 -4,702.42 50.05 100.20 .Z~ 7')4 ~ I~fl ~ Inn ~':: 1.8 2.3 2.3 2.3 2.9 2.3 2.1 2.1 2.4 2.6 1.9 2.4 2.5 2.1 2.1 2.0 1.8 1.9 2.1 2.1 2.1 2.0 1.8 2.1 2.5 2.2 2.7 3.1 2.5 2.1 2.3 2.2 1.6 1.2 1.1 1.4 1.6 1.5 1.5 1.4 1.5 1.6 1.9 2.2 2.5 2.5 1.9 1.7 2.0 2.5 2.5 2.2 2.3 2.6 2.4 2.3 2.5 2.7 2.7 2.7 2.5 2.3 2.4 2.8 2.8 2.7 2.7 2.7 2.6 612,065. ~ 612,06( 612,069.3 612,071.3 612,073.4 612,075.6 612,078.0 612,080.4 612,082.9 612,085.7 612,088.3 612,090.7 612,094.3 612,099.0 612,104.2 612,109.8 612,115.5 612,121.6 612,127.8 612,134.4 612,141.0 612,148.1 612,155.4 612,162.8 612,170.6 612,178.7 612,187.0 612,195.6 612,205.9 612,214.8 612,227.3 612,240.4 612,253.8 612,267.6 612,281.4 612,295.7 612,310.3 612,325.0 612,340.1 612,355.4 612,371.2 612,387.1 612,403.4 612,420.1 612,437.3 612,455.0 612,473.1 612,491.5 612,510.0 612,528.8 612,548.0 612,567.4 612,587.2 612,607.4 612,627.9 612,649.1 612,670.8 612,692.9 612,715.5 612,738;5 612,762.1 612,785.8 612,810.1 612,834.6 612,859.5 612,884.8 612,910.6 612,936.6 612,962.6 ~,1 ') Q~Q n 5,959,413.7 5,959,413.0 5,959,412.3 5,959,412.0 5,959,411.3 5,959,410.2 5,959,409.5 5,959,408.8 5,959,408.1 5,959,407.4 5,959,406.4 5,959,405.7 5,959,405.0 5,959,403.6 5,959,402.6 5,959,401.2 5,959,400.2 5,959,398.8 5,959,397.8 5,959,396.4 5,959,395.4 5,959,394.5 5,959,393.1 5,959,391.7 5,959,390.4 5,959,389.1 5,959,387.7 5,959,386.7 5,959,385.1 5,959,383.7 5,959,381.7 5,959,379.4 5,959,377.0 5,959,374.6 5,959,372.3 5,959,369.9 5,959,368.0 5,959,365.6 5,959,363.6 5,959,362.0 5,959,360.1 5,959,358.1 5,959,356.2 5,959,354.2 5,959,352.3 5,959,350.4 5,959,348.1 5,959,345.8 5,959,343.5 5,959,341.2 5,959,338.9 5,959,336.3 5,959,333.7 5,959,330.7 5,959,328.1 5,959,325.1 5,959,322.1 5,959,319.1 5,959,315.8 5,959,312.9 5,959,309.6 5,959,305.9 5,959,302.6 5,959,298.9 5,959,295.3 5,959, 29.1.. 3 5,959,286.9 5,959,282.9 5,959,278.5 5,127 5,161 5,196 5,230 5,265 5,299 5,334 5,368 5,403 5,437 5,472 5,506 5,541 5,576 5,610 5,645 5,680 5,714 5,748 5,781 5,815 5,848 5,882 5,916 5,950 5,984 6 ~018 6.052 6.086 6 ~121 6.155 6,189 6,223 6,257 6,291 6,325 6,359 6,393 6,426 6,460 6,493 6,527 6,560 6,593 6,626 6,660 6,693 6.727 6 360 6.794 6.827 6.860 6,894 6,927 6,960 6,993 7,026 7,058 7,090 7,122 7,154 7,186 7,219 7,251 7,284 7,317 7,349 7,382 7,415 7.447 4,836.79 4,858.07 4,878.97 4,899.43 4,919.64 4,939.62 4,959.56 4,979.76 5,000.00 5,020.18 5,040.42 5,060.69 5,080.96 5,101.19 5,121.42 5,141.62 5,161.80 5,182.05 5,201.95 5,221.54 5,241.19 5,260.87 5,280.72 5,300.85 5,321.04 5,341.34 5,361.68 5,382.05 5,402.51 5,423.10 5,443.70 5,464.41 5,485.04 5,505.82 5,526.73 5,547.65 5,568.56 5,589.19 5,609.57 5,629.82 5,649.91 5,669.79 5,689.51 5,709.02 5,728.30 5,747.49 5,766.54 5,785.38 5,804.04 5,822.53 5,840.88 5,859.16 5,877.26 5,895.27 5,913.05 5,930.69 5,948.17 5,964.90 5,981.64 5,998.31 6,015.04 6,032.04 6,049.04 6,066.04 6,083.05 6,099.99.. 6,116.99 6,133.96 6,150.89 6.167.78 -4,746.15 -4,767.43 -4,788.33 -4,808.79 -4,829.00 -4,848.98 -4,868.92 -4,889.12 -4,909.36 -4,929.54 -4,949.78 -4,970.05 -4,990.32 -5,010.55 -5,030.78 -5,050.98 -5,071.16 -5,091.41 -5,111.31 -5,130.90 -5,150.55 -5,170.23 -5,190.08 -5,210.21 -5,230.40 -5,250.70 -5,271.04 -5,291.41 -5,311.87 -5,332.46 -5,353.06 -5,373.77 -5,394.40 -5,415.18 -5,436.09 -5,457.01 -5,477.92 -5,498.55 -5,518.93 -5,539.18 -5,559.27 -5,579.15 -5,598.87 -5,618.38 -5,637.66 -5,656.85 -5,675.90 -5,694.74 -5,713.40 -5,731.89 -5,750.24 -5,768.52 -5,786.62 -5,804.63 -5,822.41 -5,840.05 -5,857.53 -5,874.26 -5,891.00 -5,907.67 -5,924.4O -5,941.40 -5,958.40 -5,975.40 -5,992.41 -6,009.35 -6,026.35 -6,043.32 -6,060.25 -6.077.14 { ~ibit VI-5b 54.00 54.53 54.57 54.22 53.98 54.18 54.33 54.22 54.15 54.27 54.27 54.30 54.38 54.12 54.00 54.10 54.08 54.13 53.90 53.68 53.72 53.55 53.37 53.25 53.27 53.10 52.77 52.63 52.58 52.43 52.35 52.18 52.12 52.35 52.45 52.58 52.90 53.28 53.67 53.98 54.28 54.70 55.17 55.50 55.83 56.25 56.53 56.70 56.95 57.20 57.43 57.70 57.97 58.18 58.32 58.38 58.42 58.43 58.47 58.47 58.55 58.67 58.68 58.70 58.75 58.88 58.95 100.30 100.32 100.26 100.18 100.22 100.36 100.43 100.45 100.52 100.58 100.59 100.59 100.64 100.58 100.53 100.58 100.57 100.53 100.55 100.60 100.65 100.63 100.60 100.62 100.67 100.69 100.70 100.76 100.82 100.81 100.84 100.91 100.93 100.89 100.82 100.75 100.76 100.78 100.80 100.81 100.78 100.76 100.77 100.73 100.65 100.63 100.64 100.64 100.71 100.80 100.91 101.01 101.11 101.20 101.25 101.30 101.38 101.43 101.47 101.50 101.51 101.59 101.67 101.73 101.83 101.92 102.03 2.3 2.3 2.3 2.2 1.5 0.2 1.0 0.7 0.7 0.5 0.3 0.3 0.4 0.0 0.1 0.3 0.8 0.4 0.3 0.1 0.2 0.7 0.7 0.2 0.5 0.5 0.4 0.1 0.5 1.0 0.4 0.2 0.4 0.3 0.5 0.2 0.7 0.3 0.4 1.0 1.1 1.2 0.9 0.9 1.3 1.4 1.0 1.0 1.3 0.8 0.5 0.8 0.8 0.7 0.9 0.9 0.7 0.5 0.2 0.3 0.1 0.2 0.1 0.3 0.4 0.2 0.2 0.3 0.5 0.4 613,015..6 613,069./ 613,097.2 613,124.8 613,152.5 613,180.0 613,207.5 613,235.1 613,262.7 613,290.5 613,318.2 613,345.9 613,373.7 613,401.4 613,429.1 613,456.8 613,484.2 613,511.4 613,538.0 613,564.7 613,591.5 613,618.2 613,645.2 613,672.2 613,699.2 613,726.1 613,752.9 613,779.9 613,806.8 613,833.4 613,860.1 613,886.6 613,913.2 613,939.8 613,966.3 613,992.8 614,019.2 614,045.4 614,071.7 614,098.0 614,124.5 614,151.0 614,177.6 614,204.2 614,231.1 614,258.2 614,285.4 614,312.7 614,340.2 614,367.5 614,395.2 614,422.7 614,450.3 614,477.9 614,505.5 614,533.1 614,559.6 614,586.4 614,613.0 614,639.8 614,667.0 614,694.3 614,721.5 614,748.9 614,776.3 614,803.6 614,831.1 614,858.5 614.886.0 5,959,269.8 5,959,265.5 5,959,260.7 5,959,256.4 5,959,251.7 5,959,247.0 5,959,242.6 5,959,237.9 5,959,233.6 5,959,228.9 5,959,224.2 5,959,219.5 5,959,214.8 5,959,210.1 5,959,205.3 5,959,200.3 5,959,195.6 5,959,190.9 5,959,186.5 5,959,181.8 5,959,177.1 5,959,172.7 5,959,168.0 5,959,163.3 5,959,158.9 5,959,154.2 5,959,149.5 5,959,144.8 5,959,140.1 5,959,135.3 5,959,131.0 5,959,126.3 5,959,121.5 5,959,116.8 5,959,112.1 5,959,107.4 5,959,102.6 5,959,098.3 5,959,093.6 5,959,088.8 5,959,084.5 5,959,079.8 5,959,075.0 5,959,070.3 5,959,065.6 5,959,061.2 5,959,056.2 5,959,051.5 5,959,046.7 5,959,042.0 5,959,037.3 5,959,032.6 5,959,027.9 5,959,022.8 5,959,018.1 5,959,013.1 5,959,008.0 5,959,003.3 5,958,998.2 5,958,993.5 5,958,988.4 5,958,983.3 5,958,978.2 5,958,973.2 5,958,967.7 .5,958,962.7 5,958,957.6 5,958,952.2 5,958,946.7 5.958.941.3 7,;480 7,513 7,545 7,578 7,611 7,643 7,676 7,709 7,741 7,773 7,805 7,837 7,869 7,902 7,934 7,966 7,998 8,030 8,062 8,094 8,126 .8,158 8,190 8,222 8,254 8,286 8,318 8,348 8,381 8,416 8,449 8,481 8,513 8,545 8,577 8,609 8,642 8,674 8,706 8,738 8,770 8,803 8,835 8,867 8,899 8,932 8,964 8,996 9,028 9,059 9,091 9,123 9,154 9,186 9,218 9,249 9,281 9,313 9,344 9,376 9,408 9,440 9,471 9,503 9,534 9,566 9,597 9,628 9,659 9,690 6;184.56 6,201.48 6,218.38 6,235.27 6,252.06 6,268.87 6,285.85 6,302.70 6,319.50 6,336.33 6,353.25 6,370.33 6,387.66 6,405.32 6,422.79 6,440.29 6,457.88 6,475.67 6,493.51 6,511.46 6,529.54 6,547.73 6,566.14 6,584.65 6,603.36 6,622.06 6,640.75 6,659.04 6,679.16 6,700.41 6,720.39 6,740,25 6,760.32 6,780.78 6,801.65 6,823.00 6,844.56 6,866.28 6,888.19 6,910.11 6,931.99 6,953.87 6,975.65 6,997.43 7,019.14 7,040.86 7,062.43 7,083.57 ~ 7,104.59 7,125.54 7,146.43 7,167.34 7,188.26 7,209.19 7,230.34 7,251.58 7,272.90 7,294.31 7,315.86 7,337.50 7,359.25 7,381.00 7,402.85 7,424.66 7,446.42 7,468.12 7,489.65 7,511.00 7,532.70 7,554.46 -61093.92 -6,110.84 -6,127.74 -6,144.63 -6,161.42 -6,178.23 -6,195.21 -6,212.06 -6,228.86 -6,245.69 -6,262.61 -6,279.69 -6,297.02 -6,314.68 -6,332.15 -6,349.65 -6,367.24 -6,385.03 -6,402.87 -6,420.82 -6,438.90 -6,457.09 -6,475.50 -6,494.01 -6,512.72 -6,531.42 -6,550.11 -6,568.40 -6,588.52 -6,609.77 -6,629.75 -6,649.61 -6,669.68 -6,690.14 -6,711.01 -6,732.36 -6,753.92 -6,775.64 -6,797.55 -6,819.47 -6,841.35 -6,863.23 -6,885.01 -6,906.79 -6,928.50 -6,950.22 -6,971.79 -6,992.93 -7,013.95 -7,034.90 -7,055.79 -7,076.70 -7,097.62 -7,118.55 -7,139.70 -7,160.94 -7,182.26 -7,203.67 -7,225.22 -7,246.86 -7,268.61 -7,290.36 -7,312.21 -7,334.02 -7,355.78 -7,377.48 -7,399.01 -7,420.36 -7,442.06 -7,463.82 Et oit 59.10 58.93 58.72 58.58 58.52 58.35 58.03 57.82 56.83 56.62 57.22 56.95 56.57 56.25 56.10 55.88 55.58 55.25 54.87 54.45 54.13 53.83 53.38 52.92 52.50 52.10 51.90 51.63 50.98 49.97 48.93 48.17 47.72 47.35 47.03 47.02 47.20 47.35 47.53 47.68 47.82 48.00 48.22 48.40 48.55 48.72 48.80 48.72 48.53 48.33 48.10 47.80 47.52 47.28 47.10 46.98 46.87 46.65 46.40 46.32 46.30 46.23 46.17 46.08 45.78 45.38 VI- 5b 102.54 102.59 102.63 102.66 102.71 102.79 102.89 102.99 103.14 103.21 103.19 103.20 103.24 103.42 103.62 103.72 103.76 103.84 103.94 104.03 104.14 104.27 104.36 104.46 104.66 104.94 105.00 104.45 103.20 101.68 100.21 98.86 97.71 96.58 95.74 95.60 95.82 96.04 96.20 96.37 96.63 96.89 97.18 97.47 97.72 97.96 98.11 98.19 98.21 98.14 98.10 98.09 98.14 98.22 98.32 98.43 98.55 98.69 98.82 98.90 98.93 99.09 99.36 99.67 100.06 100.58 0.4 0.3 0.5 0.6 0.1 0.5 0.7 0.4 0.2 0.6 1.0 0.7 3.1 0.7 1.9 0.8 1.2 1.1 0.7 0.7 0.9 1.1 1.2 1.3 1.0 1.0 1.5 1.5 1.4 1.3 0.6 1.6 3.7 4.8 4.8 3.9 3.0 2.8 2.2 0.3 0.8 0.7 0.7 0.6 0.7 0.8 1.0 0.9 0.8 0.8 0.4 0.3 0.6 0.7 0.7 0.9 0.9 0.8 0.6 0.5 0.4 0.8 0.8 0.3 0.1 0.4 0.7 0.8 1.3 1.8 6141913,4 614,94~¢' 614,96~.~ 614,995.8 615,023.3 615,050.7 615,078.2 615,105.2 615,132.1 615,158.9 615,185.6 615,212.3 615,238.7 615,264.9 615,291.1 615,317.6 615,343.8 615,369.9 615,395.9 615,421.8 615,447.7 615,473.4 615,499.1 615,524.5 615,549.9 615,574.9 615,599.6 615,623.3 615,648.9 615,675.6 615,700.4 615,724.9 615,749.4 615,773.6 615,797.5 615,821.4 615,845.2 615,868.7 615,892.3 615,915.8 615,939.2 615,962.8 615,986.5 616,010.2 616,034.0 616,058.0 616,081.8 616,105.3 616,129.0 616,152.6 616,176.2 616,199.9 616,223.4 616,246.9 616,270.3 616,293.7 616,317.0 616,340.0 616,363.0 616,386.2 616,409.2 616,432.1 616,454.8 616,477.5 616,500.2 616,522.6 616,544.7 616,566.8 616,588.8 616,610.7 5,958,930.4 5,958,925.0 5,958,919.2 5,958,913.7 5,958,907.9 5,958,902.1 5,958,896.7 5,958,890.9 5,958,885.4 5,958,879.6 5,958,873.8 5,958,868.3 5,958,862.5 5,958,856.7 5,958,850.9 5,958,845.1 5,958,839.2 5,958,833.4 5,958,827.6 5,958,821.8 5,958,815.9 5,958,809.7 5,958,803.9 5,958,798.1 5,958,791.9 5,958,786.0 5,958,780.5 5,958,774.0 5,958,767.4 5,958,761.2 5,958,755.4 5,958,749.5 5,958,744.8 5,958,740.4 5,958,736.7 5,958,733.8 5,958,730.9 5,958,728.7 5,958,726.8 5,958,725.0 5,958,722.8 5,958,720.6 5,958,718.4 5,958,715.9 5,958,713.7 5,958,710.7 5,958,708.2 5,958,705.6 5,958,702.7 5,958,699.7 5,958,696.5 5,958,693.5 5,958,690.6 5,958,687.7 5,958,684.7 5,958,681.4 5,958,678.5 5,958,675.5 5,958,672.6 5,958,669.7 5,958,666.4 5,958,663.1 5,958,660.1 5,958,656.8 5,958,653.5 5,958,650.2 5,958,646.9 5,958,643.5 5,958,639.9 9,721 cj,753 9,784 9,815 9,846 9,878 9,909 9,940 9,971 10,003 10,034 10,065 10,097 10,128 10,160 10,191 10,222 10,253 10,283 10,314 10,345 10,376 10,407 10,437 10,468 10,499 10,530 10,561 10.592 10.623 10.653 10.684 10.715 10.745 10.776 10,806 10,836 10,866 10,896 10,932 10,955 10,977 11,000 11,024 11,048 11,072 11,096 11,121 11,145 11.169 11.189 11.206 11.222 11.238 11.254 11.271 11.287 11.303 11,320 11,336 11,352 11,374 11,399 11,424 11,449 11,473 11,498 11,523 11,548 11,573 7,576.44 7,598.56 7,620.70 7,642.92 7,665.06 7,687.25 7,709.41 7,731.54 7,753.66 7,775.78 7,797.87 7,820.14 7,842.43 7,864.69 7,886.92 7,909.16 7,930.91 7,952.60 7,974.29 7,995.99 8,017.75 8,039.60 8,061.40 8,083.27 8,105.23 8,127.36 8,149.47 8,171.61 8,193.64 8,215.74 8,237.83 8,259.64 8,281.18 8,302.52 8,323.54 8,344.26 8,364.68 8,385.02 8,405.36 8,429.30 8,444.19 8,458.71 8,473.79 8,489.55 8,505.31 8,520.97 8,536.61 8,552.11 8,567.58 8,583.04 8,596.03 8,606.19 8,616.31 8,626.44 8,636.58 8,646.72 8,656.87 8,666.95 8,676.95 8,686.85 8,696.71 8,709.92 8,724.82 8,739.72 8,754.58 8,769.40 8,784.11 8,798.57 8,812.86 8,826.84 -7,485.80 -7,507.92 -7,530.06 -7,552.28 -7,574.42 -7,596.61 -7,618.77 -7,640.90 -7,663.02 -7,685.14 -7,707.23 -7,7.29.50 -7,751.79 -7,774.05 -7,796.28 -7,818.52 -7,840.27 -7,861.96 -7,883.65 -7,905.35 -7,927.11 -7,948.96 -7,970.76 -7,992.63 -8,014.59 -8,036.72 -8,058.83 -8,080.97 -8,103.00 -8,125.10 -8,147.19 -8,169.00 -8,190.54 -8,211.88 -8,232.90 -8,253.62 -8,274.04 -8,294.38 -8,314.72 -8,338.66 -8,353.55 -8,368.07 -8,383.15 -8,398.91 -8,414.67 -8,430.33 -8,445.97 -8,461.47 -8,476.94 -8,492.40 -8,505.39 -8,515.55 -8,525.67 -8,535.80 -8,545.94 -8,556.08 -8,566.23 -8,576.31 -8,586.31 -8,596.21 -8,606.07 -8,619.28 -8,634.18 -8,649.08 -8,663.94 -8,678.76 -8,693.47 -8,707.93 -8,722.22 -8,736.20 $ 1.5 0 0.9 .hibit VI - 5b .4 o.4 ...... 4 0.1 44.82 101.33 0.3 44.88 101.29 0.2 44.97 101.27 0.3 45.05 101.30 0.3 45.05 101.32 0.1 44.98 101.33 0.2 44.87 101.46 0.5 44.75 101.64 0.6 44.83 101.79 0.4 ~4.92 101.87 0.3 4~ 93 101.88 0.0 45.u7 101.85 0.5 45.23 101.78 0.5 45.28 101.72 0.2 45.18 101.63 0.4 45.05 101.55 0.5 45.02 101.52 0.1 44.98 101.52 0.1 44.88 101.61 0.4 44.68 101.87 0.9 44.35 102.25 1.4 44.12 102.62 1.1 44.17 102.96 0.8 44.32 103.29 0.9 44.33 103.70 0.9 44.35 104.22 1.2 44.53 104.68 1.2 44.97 105.00 1.6 45.52 105.14 1.8 46.07 105.21 1.8 46.58 105.29 1.7 46.95 105.33 1.2 47.30 105.37 1.2 47.68 105.55 1.3 47.97 105.71 1.0 48.38 105.80 1.2 48.72 105.78 1.5 49.00 105.82 1.3 49.03 106.07 0.8 49.05 106.38 1.0 49.32 106.58 1.3 49.58 106.71 1.2 49.93 106.94 1.6 50.18 107.23 1.4 50.33 107.47 1.0 50.50 107.82 1.3 50.82 108.20 2.1 51.27 108.53 3.2 51.45 108.81 1.8 51.42 108.93 0.6 51.53 109.28 1.8 51.58 109.68 2.0 51.68 109.89 1.2 51.97 110.10 2.0 52.30 110.35 2.4 52.57 110.65 2.2 52.77 111.12 2.6 53.00 111.66 2.2 53.20 111.94 1.2 53.23 112.02 0.3 53.15 112.17 0.6 53.47 112.68 2.1 54.12 113.27 3.2 54.53 113.60 2.0 55.15 113.25 2.8 56.20 112.27 5.4 616,632.5 616,6~' ' 616,67L.~ 616,697.5 616,719.2 616,740.9 616,762.6 616,784.4 616,806.2 616,828.0 616,849.7 616,871.3 616,893.0 616,914.8 616,936.6 616,958.4 616,979.9 617,001.4 617,022.9 617,044.3 617,065.7 617,087.2 617,108.6 617,129.8 617,151.0 617,172.1 617,193.1 617,214.2 617,235.2 617,256.2 617,277.3 617,298.2 617,319.3 617,340.5 617,361.8 617,383.3 617,404.5 617,426.0 617,447.7 617,473.6 617,489.8 617,506.0 617,522.7 617,540.2 617,557.8 617,575.3 617,593.2 617,610.9 617,628.8 617,646.7 617,661.8 617,673.7 617,685.8 617,697.9 617,710.0 617,722.1 617,734.2 617,746.4 617,758.4 617,770.6 617,782.8 617,799.0 617,817.7 617,836.2 617,854.7 617,873.2 617,891.9 617,910.4 617,929.2 617,948.2 5,958,636.2 5,958,632.1 5,958,628.1 5,958,624.0 5,958,619.9 5,958,615.9 5,958,611.8 5,958,608.1 5,958,604.1 5,958,600.0 5,958,596.0 5,958,591.9 5,958,587.5 5,958,583.4 5,958,579.0 5,958,575.0 5,958,570.6 5,958,566.5 5,958,562.4 5,958,558.4 5,958,554.3 5,958,550.3 5,958,546.2 5,958,542.1 5,958,538.1 5,958,533.6 5,958,529.2 5,958,524.8 5,958,520.0 5,958,515.2 5,958,510.0 5,958,504.9 5,958,499.3 5,958,493.8 5,958,488.7 5,958,483.1 5,958,477.6 5,958,471.7 5,958,466.2 5,958,459.3 5,958,454.8 5,958,450.6 5,958,446.1 5,958,441.3 5,958,436.4 5,958,431.6 5,958,426.4 5,958,421.2 5,958,416.0 5,958,410.4 5,958,405.9 5,958,402.0 5,958,398.2 5,958,394.3 5,958,390.1 5,958,386.3 5,958,382.1 5,958,377.9 5,958,373.7 5,958,369.1 5,958,364.9 5,958,358.6 5,958,351.6 5,958,344.5 5,958,337.1 5,958,329.7 5,958,322.3 5,958,314.6 5,958,306.8 5,958,299.1 11,598 11;623 11.648 11.673 11 ~698 11.723 11,754 11,817 11,848 11,877 11,943 11,972 11,984 12,060 12,110 12,148 12,237 12,332 12,485 12,639 12,859 12,957 ~ 13,052 13,113 13,165 13,166 8,840.57 8,854.03 8,867.29 8,880.32 8,893.10 8,905.72 8,920.72 8,946.54 8,957.37 8,966.21 8,981.16 8,985.45 8,986.82 8,992.05 8,993.01 8,993.04 8,993.51 8,995.42 9,000.36 9,004.66 9,008.69 9,011.68 9,016.90 9,021.63 9,026.26 9,026.35 -8,749.93 -8,763.39 -8,776.65 -8,789.68 -8,802.46 -8,815.08 -8,830.08 -8,855.90 -8,866.73 -8,875.57 -8,890.52 -8,894.81 -8,896.18 -8,901.41 -8,902.37 -8,902.40 -8,902.87 -8,904.78 -8,909.72 -8,914.02 -8,918.05 -8,921.04 -8,926.26 -8,930.99 -8,935.62 -8,935.71 ,26 5.1 ,56 3.3 ,bit VI- 5b ,72 3.4 ......... 92 6.9 59.55 105.74 7.8 59,68 104.70 3.6 63.30 98.60 20.6 68.30 98.20 8.0 70.80 100.00 9.7 73.70 98.90 10.6 80.10 100.70 10.1 82.90 101.00 9.7 84.00 101.00 9.2 88.10 104.20 6.8 89.70 104.20 3.2 90.20 105.20 2.9 89.20 104.90 1.2 88.50 105.60 1.0 87.80 106.60 0.8 89.00 106.30 0.8 88.90 107.00 0.3 87.60 106.30 1.5 86.10 107.70 2.2 85.00 107.30 1.9 84.80 107.70 0.9 84.80 107.70 0.0 617,967.7 617,9~~ '~ 618,00..3 618,027.8 618,048.4 618,069.2 618,096.4 618,153.3 618,182.0 618,209.4 618,272.8 618,301.0 618,312.8 618,387.1 618,435.7 618,472.5 618,558.8 618,650.8 618,798.3 618,946.6 619,158.3 619,252.5 619,343.7 619,401.9 619,451.6 619,452.4 5,958,291.7 5,958,284.7 5,958,277.3 5,958,271.0 5,958,265.1 5,958,259.6 5,958,254.5 5,958,247.0 5,958,242.7 5,958,238.7 5,958,228.8 5,958,223.7 5,958,221.7 5,958,206.0 5,958,194.7 5,958,185.4 5,958,163.7 5,958,140.3 5,958,099.8 5,958,058.6 5,957,998.6 5,957,971.9 5,957,945.5 5,957,928.1 5,957,913.2 5,957,912.8 Exhibll," ,- 5c ALASKA PRODUCTION ~ WE TIME MgD MUD CODE INJ ~ TO1N. F;~- ..... ~,~,.,,,~L i CONTRA C I OR [ CATERING ~,VICE CO. ~ ~ER ~ lEDS , ,, Exh{" VI- 5c ALASKA PRODUCTION a, ,--/ C),/~¢11 ~r J~'.O Zl-/O I '$4 'mu ALAS~ PRODUCTION : k/1)5 Exhibi( '- 5c I~ Mi CI Exhibit V~' 5c ALASKA PRODUCTION z-~,2 YP MUD ,.,.-,. · COND lid ,, :x CATERING CO~E OTHER WATER USED Exhibit VI- 5t ~.BU/EWE DRILLING PROGRAM PROPOSED WELL DIAGRAM WELL W'-II5 (42-22-11-12~ HIGH ANGLEWELL AUDI RIG 3 CEMENTATION: 13 3/8" CEMENT SLURRY: Lead Slurry: 1920 cuft (1000 sacks) COLD SET III Tail Slurry: 1920 cuft (2000 sacks) COLD SET II Conductor ~ 13 3/1~" 68# L-80 Butt. Base Permafrost 1862' 4-1/2" Ball Valve with Flow Couplings 2100' 13 3/8" Shoe 2680' 17 1/2" Open Hole 2700' 9 5/8" CEMENT SI~URRY: Lead Slurry: .. 2153 cuft (1087 sacks). Class G+8% (see program for details) Tail Slurry: 576 cuft (500 sacks) Class G (see program for details) , 'i ,. 9 5/8" 47# L80 NSCC 4 1/2" 12.6g L-80 TDS with GLM's 7" LINER SLURRY: Slurry: ~" 247 cuft (160 sacks) Class G+35%Si Flour (see program for details)~.:: TIW 9 5/8" Packer 11234' TIW Liner Hanger 11284' 9 5/8" Casing Shoe 11534' 12 1/4" Open Hole 11544' 7" 26g L-80 IJ4S "Off Bottom" Cemented Liner 4 1/2" COMPLETION: WELLHEAD: FMC 4-1/16" TREE KOP: 2800' MAX. ANGLE: 87.8° TAILPIPE SIZE: 4 1/2" RECOMENDED: APPROVED: TIW Liner Hanger and Packer 11942' 7" Shoe 12042' 4-1/2" 12.6# L-80 TDS Solid Liner c/w 2 External Casing Packers and Sliding Sleeves 4 1/2" Liner Shoe 13042' -~"--~-7' 8 1/2" Hol~ TD, /~ 13042' Drilling .Engine.~r ' /~ /'3 . D~lling En~i'~hng Supervisor ~S 5110190 ; :,.~: , . i:' ': Exhibit VI 13-3/$" CASING AND CEMENTING PROGRAM WELL W-15 (PBU/EWE) PROGRAM: , , Install mud-line suspension landing ring on 20" conductor ensuring it is level. Ensure mandrel hanger O.D. will pass through riser. Nipple up riser. !' Drill 17-1/2" hole vertically to 2700 ft. MD BKB. Circulate until hole is clean. POH to run 13-3/8" casing. NOTES: a) Maintain mud'temperature as low as possible (40-45 deg. F). b) Clean, visually inspect, and drift casing. c) d) e) Have B.J. TITAN perform thickening time tests on cement delivered to location using mix water which will be used for the job. TT = 4-1/2 hours @ 50 deg. F for tail slurry. : Ensure 13-3/8'! Buttress double pin pup joint is of correct length so that ,:the casing head flange will be 18" above the top of the ceila~. Notify Alaska Oil & Gas Commission (279-1433)48 hours in advance to witness 13-3/8" BOPE test. 3. Run 13-3/8" 68# L-80Buttress casing as follows: - Float shoe (landed @ approximately 2680 ft.) - 1 joint 13-3/8":. 68#, L-80, Buttress casing - Float collar - 13-3/8",68#, L-80, BUTT casing (approx. 67 jts. total) - Mud-line suspension hanger assembly 13-3/8 .... Spe[i'ally Cut" Buttress double pin pup joint - Landing joinf:::' CASING RUNNING AND CEMENTING NOTES: a) Place 13-3/8" centralizers 5 ft. and 20 ft. above the shoe and every joint for the next 9 joints (11 total). ,: b) Bakedok first three (3) connections. c) Fill casing as necessary. d) Have a 13-3/8'" buttress swage with a 2" valve and cementer connection available on the floor while running casing. e) Place two (2) 13~-3/8" metal petal baskets inside conductor: One at 90 ft. BKB using stop rings above and below basket; and one on the first full joint below mud-line hanger to bottom out on casing collar (at approx. 65 ft. BKB) using a stop ring above basket. '. W-15 Drilling Program Page 2 5/16/90 i' Exhibit VI- 5c{, 4. Land 13-3/8" casing shoe at approximately 2680 ft. MD BKB as follows: a) Install mud-lin? suspension hanger on last joint. b) Pick up 13-3/8:' landing joint and wash down last joint if required. Tag 20" landing ring. Slack off weight while monitoring conductor for settlement. If settlement occurs, set slips and slack off remaining weight. If conductor does not settle, slack off all remaining weight on the landing ring and set slips for safety. o RU B.J. TITAN cementers. Make up plug holding head (with top plug installed) onto landing joint. Install bottom plug, make up landing joint and test lines to 30001psi. Break circulation. Pump 20 bbls. of water ahead of cement. MCr and pump cement as follows: Lead Slurry: Slurry: 1920 cuft :~ (1000 sacks) 'COLD SET III Weight: 12.2 ppg. Yield: 1.92 cu ft/sack Water: 10.53 gal/sack TT: '4.5 hours* Tail Slurry: Slurry: ~: 1920 cuft (2000 sacks) 'COLD SET II Weight:, 14.95 ppg. Yield:i. 'i 0,96 cu ft/sack Water: i,3.80 gal/sack TT: 4.5 hours* *Have B.J. TITAN perform thickening time tests on cement delivered to location using mix water which will be used for the job. . Release top plug. DiSplace cement to float collar at a rate of 8-10 bpm. Bump plug with 2000 psi. DO NOT OVER-DISPLACE plug by more than 1/2 the shoe volume (3 barrels). Provide details of cement returns on morning report and '.!ADC report. . WOC 4 hours to allow cement to develop sufficient strength to support the 13-3/8"casing. Rem%e. the slips and slack off weight slowly and observe casing for settlement, ) '. If settlement occurs, pick up all weight and WOC an additional two (2) heurs and repeat slack off procedure. 8. Nipple down riser and perform top job if necessary. 9. Bakedok and make up ~!3-3/8", 5000 psi split speed head so that tubing head annulus valves are oriented 90 deg. to the right of the direction facing the reserve pit. Approximate torque = 14,500 ft-lbs. However, under no circumstances should the head be "backed-out" counter-clockwise to meet this orientation requirement. 10, Install and test BOP stack as per BOP manual. W-15 Drilling Program Page 3 5/16/90 11. 12. 13. ~, ,. Exhibit Vi - 5~" Install long bowl protector. Test 13-3/8" casing to 3000 psi. before drilling out float equipment. Drill out shoe plus a minimum of 10 ft. new hole and perform formation integrity test. Drill 1~-1/4" hole per directional map. Measure KB to ground level and KB to BF. Record measurements on tour sheet and telex. W-15 Drilling Program Page 4 5/16/90 QTY 13.:~/8" MATERIALS LIST WEi,L.W-15 AFE # 125183 .i ITEM Exhibit VI- 5c~' vO(~AB N°. 1 1 70 11 13-3/8" But'tress float shoe 13-3/8" But/tess float collar 13-3/8" 68#' L-80,BUTr, R-3 (including ~ree extra joints) 13-3/8" LO .bow-type centralizers 13-3/8" Meta3. petal basket 13-3/8" Stop rings 13-3/8" 68#iL-80 Buttress double pin pup join~.i FMC split sPeedhead system, 13-3/8" But!tess w/AB seal ring x 13-5/8" API~*5000 psi. flange and 13-5/8" x 13-5/8" tubing spool FMC mud-lilac suspension · system 2 pails 1 box Thread dop6 -API modified Bakeflok .,. (10 x 1# cans),I' , , W-15 Drilling Program Page 5 Howco Howco 86050071 86127408 Howco 86129493 N/S built 86623800 FMC 86623906 86139010 86139001 5/16/90 Exhibit VI - 9-5/8" CASING AND CEMENTING PROGRAM SUMMARY; A. ~'ELL W-15 (PBU/EWE} . ; · . :, . Run 9-5/8" 4745 NT80;,S, NSCC casing to surface. Land shoe within 5 ft. of bottom with mandrel hanger. B. Cement casing with Class G cement. Inject down annulus after cement is in place to clear cement from annulus. Have cement company run thickening time tests on each load of cement delivered to location using mix water which will be used for the job. C. Install and test pack-offs. D. Test casing to 3000 p,Si. before drilling out shoe. PROGRAM; 1. Drill 12-1/4" hole dc~wn through the entire Sag River Sandstone formation (Top Sag, 8784' TVD BKB) and penetrate 10' into the top of the Shu~lik formation (Top Shublik 8865' TVD BKB) and maintain control ~? per target map. The North Slope geologist will predict the top of the IShublik formation from rig site data. While drilling from 7006' TVD to li2-1/4" T.D., the mud weight should be a minimum of 9,7 ppg. Open hole logs will be run as per saddleblanket. 2. Condition hole for casing. Pull wear bushing and install 9-5/8" rams. · ~. , 3. Run 9-5/8" 4745 NTS0.-S casing (set shoe within 5 ft. of 12-1/4" T.D.) as follows: - Float shoe (Buttress) with side ports - 3 joints of 4745 L-80 NSCC casing (first joint with pin nose seal removed) - Float collar (Buttress) - 9-5/8" 4745 N,:SCC casing to surface ( approx. 304 its. total) (first joint wi!:,h, pin nose seal removed) - Mandrel hange:r - Landing Joini: ', CASING RUNNING NOTES: ,.~ a) Bakedok bottom 3 joints. b). c) d) W-15 Drilling Program Page 6 Centralize bottom 10 joints with stand-off bands. Run turboclamps on every third joint from surface to 2680 ft. Have circulatb:g swage with valve and cementer hook-up available on floor while running casing. Fill casing as n~cessary 5/16/90 Exhibit VI- 5c{ e) Cut off nose seal of the two NSCC pins which will be made up with buttress float equipment. 4. Circulate last joint to bottom and land mandrel hanger in the wellhead. If mandrel hanger cannot be run, use emergency slips and pack-off. o . RU B.J. TITAN cememers. Rig up injection line to 13-3/8" x 9-5/8 annulus. Install, bottom plug in casing and top plug in head. Test all lines to 3000 psi. Pump 20 bbls of fresh water preflush ahead of the cement. , ' ,, Mix and pump cemenL Cement volume based on the 100% annular volume between 9-5/8" casing and 12-1/4" hole to bring the top of the cement to 50.0'MD above the top of the Ugnu sands + 50 cu.ft. (Top Ugnu sands 3473' TVD, 3480' MD, top of cement 2980' MD). Le~d Slurry_: 2153 cu.ft. (1087 sacks) Class G cement with 8% BENTONITE + 0.2% CD-31 + 0.6% R-1 + 1 gal/100 sacks FP-6L. Weight: 13.0 ppg. Yield: 1.98 cu.ft./sack Water: 10.78 gal./sack TT: 5:40 hours* Tail Slurry; 576 cu.ft. (500 sack ) Class G cement + 0.65 % FL-20 + 0.1% CD-31 + 0.06% R-1 + 1 Ga./100 sacks FP-6L. Weight: 15.8 ppg. Yield: 1.152i cu.ft./sack Water: 4.96 gal./sack TT: 4 hours* *Have B.J. TITAN mn thickening time tests on each load of cement delivered to the rig Using water which will be used for the job. 7. Drop the top plug. Displace the cement with mud at 8 to 10 bbl./min. Do not over-displace by more than half of the volume from the float collar to the shoe (4.4 bbls.). Bump plug and pressure to 3000 psi. After bumping the plug, close annular preventer and inject 50 bbl mud into the 13-3/8" :x 9-5/8" annulus at no more than 4 bbl/min to clear th~ "annulus. 8. Drain the BOP stack a!~d remove the landing joint. Flush pack-off area, install pack-off and energize as per wellhead manufacturers 9-5/8" mandrel hanger procedures. ~ t . 9. Test pack-off to 5000 psi. with annulus open. Install 5" rams. Test BOPE. Install short bowl protector. 10. RIH with 8-1/2" bit and drill cement to float collar. Test casing to 3000 psi. Clean out float .collar. Displace well to oil based mud prior to W-15 Drilling Program ' ~' Page 7 5/16/90 Exhibit VI- 5c { drilling out the re~naining cement, and 9-5/8" float shoe. Condition mud at shoel and drill 8-1/2" hole maintaining directional control as per target map. 'l'he Baroid RLL tool (EWR/CNPhi/SFD/GR) 1 will be run while drilling the 8-1/2" hole section, together with a MAD nm on the wiper trip after ~aching TD (at ROP of 150'/hr or less). Recommended Oil Based Mud Displacement Procedure: a) b) c) d) Drill cement to 9-5/8" sh'oe and condition water based mud for displacement. , ;' Transport all water based fluids in the surface system to the injection plant for injection. , Clean and flush the mud pits and surface equipment. ,. Pump 100 bbl of water/dirt magnet spacer. e) Pump 75 bbl of EZ SPot spacer and follow with the Oil Based Mud. f) g) After break through (.. the mud at the shoe [ It is recommended to avoid possible contarn ~/- 200 Electrical Stability), circulate and condition 'ior to drilling out. cl~sconnect all sources of water in the pit system to ination of the OBM. Oil Based Mud Recommended Properties: Weight: . 9.0 ppg PV: ' 12-14 cP ~,, YP: ,~:' 8-10 lb/100 squft Fluid Loss: t < 8 cc HPHT at 250°F Solids: <8% Oil/Water Ratio: ' 85/15 - 80/20 Electrical Stability: >1000 V Oil Based Mud Notes: 'ii;!:,;,, The mud weight whii~ drilling the 8-1~2" hole should be maintained at 9.0 ppg if hole conditions permit. This mud weight will provide 264 psi overbalance at the top of the Sadlerochit, and 272 psi overbalance at TD. The mud weight should'be kept to 9.0 ppg if possible, as the CTC packers are designed to inflate with 750 psi over the mud hydostatic. If the mud hydrostatic gets too high', there is a danger that with the addition of the inflation pressure, thePaoker pressure may be high enough to fracture the formation (frae. pressure could be as low as 0.58 psi/ft, which is equal to 5,220 psi at 9000' TVD BKB). Research and field results have shown that the most effective method of hole cleaning for high,angle wells is by drilling with a "thin" or "low vis" mud in turbulent flow., and pumping "high vis" sweeps as required. W-15 Drilling Program Page 8 5/16/90 i, Exhibit VI-6: W-17 Well Imegrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 7/5/1988 12-1/4" 9-5/8" Shut-in/Freeze Protected/Trouble Well None Comments: This well had a workover performed in Oct. of 1990 to replace the top 2,127 ft. of the 9-5/8' casing and mill out a cement sheath in the 7" liner. On 10/16/90 the 9-5/8' annulus was pressure tested ~ 2500 psi for 30 min. and held. Tubing to IA communication first noted in 12/1998. A flowing gas lift survey indicated holes in the tubing at 2250', 2274'and 2672'md. There is cement in the 9-5/8" by 13-3/8" annulus. This is based on the outer annulus pressure test and reports of cement during the work over. Additional Information: Exhibit VI-6a Well Diagram Exhibit VI-6b Directional Survey Exhibit VI-6c Significant Workover & Drilling Daily Reports Exhibit VI - 6a W17 ACTUATOR = OTIS K~. ELEV = 81.62' BF. B. EV = 53.71' ~;OP= 1484' Datum~XAn[~le=~= 52@118~'11402, , ~ ~ 2008' H3-112"OTSSSSVLAND. NP, ID=2.7S~ DatumTVD = 8800' SSI ST IVD TVD DEV TYPE VLV LATCH PORT DATE ~ 6 3271 2920 40 OTIS RA L ~ 5 i 7034 .5638 47 OTIS RA , 4 8772 6922 40 OTIS RA 3 9782 7673 45 OTIS RA 2 10476 8141 48 OTIS RA ' I 11076 8533 51 OTIS RA Minimum ID = 2.750" @ 2096' 3-1/2" OTIS SSSV NIPPLE I I :~ '~ll07' u ~ ~3-1/2"PAF~a~SWSN~P,~D=2.?50" ~ I I I t , I ~ss'H ELUDrrLO~GED021071~ I PERFORATION SUMMARYII ' REFLOG: BHC- GR ON 07105188 II II ANGLEATIOPPfiRF: 50 @ 11627' Note: Refer to Production DB for historical poff data I1 SIZE SPFI INTERVAL Opn/Sqz DATE II 5" 5 11627-11647 S 05/03/89 2-1/2" 4 11684-11709 S 09/10/90 I I 2-1/2" 4 i 11653-11673 S 09/10/90 2-1/8" 4 11709-11720 S 09/10/90 3- 3/8" 6 11684-11710 O 10/14/90 rl 2-1/8. 6 11627.11657 0 02/08/94 i I ?' [NR, 26#, L-80. U4S. 0.03~3 t~,, ~D = 6.2?6" I--I I DATE REV BY COMIVENTS DATE ; REV BY . COIVlVlB',ITS PRUDHOE BAY UNFr 9/88 ORIGINAL COlVPLETION ! WELL: W-17 10/16/90 JQ ORIGINAL COIVPLErlON : : PERMIT No: 88-0950 02/09/01 SIS-OAA CONVERTED TO CANVAS APl No: 50-029-21856-00 03/05/01 SIS-LC FINAL ~ Sec. 21,T11N, R12E 09/05/01 RN/TP CORRECrlONS i ~ BP Exploration (Alaska) SIZE SPF INTERVAL Opn/Sqz DATE 5" 5 11627-11647 S 05/03/89 2-1/2" 4 11684-11709 S 09/10/90 2-1/2" 4 11653-11673 S 09/10/90 2-1/8" 4 11709-11720 S 09/10/90 3- 3/8" 6 11684-11710 O 10/14/90 2-1/8" 6 11627-11657 O 02/08/94 DATE REV BY COMIVENTS DATE REV BY COk,t'vlB',lTS 9/88 ORIGINAL COlVPL ErlON 10/16/90 JQ ORIGINAL COIVPL El'ION 02/09/01 SIS-QAA CONVERTED TO CANVAS 03/05/01 SIS-LG FINAL 09/05/01 RN/TP CORRECTIONS .Well'W-17 Directional Survey' Exhibit VI - 6b 500292185600 GYRO Schlumberger API/UWI: Survey Type: Company: Survey Date: Survey Top: Survey Btm: 0' MD 12,048' MD MD TVD 0 0.00 20 20.00 24 23.90 39 38.50 53 53.10 68 67.80 82 82.40 97 97.10 112 111.70 126 126.30 141 140.90 156 155.50 170 170.20 185 184.80 199 199.40 214 214.00 229 228.60 243 243.30 258 257.60 272 272.00 286 286.40 301 300.80 315 315.10 330 329.50 344 343.90 358 358.20 373 372.60 387 387.00 401 401.40 416 415.80 430 430.20 445 444.50 459 459.00 473 473.30 488 487.70 502 502.10 517 516.50 531 531.00 545 545.40 560 559.80 574 574.20 589 588.60 603 602.90 617 617.40 632 631.70 646 646.10 661 " 660160 675 675.00 689 689.30 704 703.80 SS 81.60 61.60 57.70 43.10 28.50 13.80 -0.80 -15.50 -30.10 -44.70 -59.30 -73.90 -88.60 -103.20 -117.80 -132.40 -147.00 -161.70 -176.00 -190.40 -204.80 -219.20 -233.50 -247.90 -262.30 -276.60 -291.00 -305.40 -319.80 -334.20 -348.60 -362.90 -377.40 -391.70 -406.10 -420.50 -434.90 -449.40 -463.80 -478.20 -492.60 -507.00 -521.30 -535.80 -550.10 -564.50 -579.00 -593.40 -607.70 -622.20 INCLINE 0.00 0.00 0.13 0.10 0.17 0.28 0.30 0.28 0.27 0.22 0.18 0.15 0.15 0.17 0.18 0.20 0.17 0.12 0.10 0.10 0.12 0.12 0.10 0.10 0.17 0.17 0.13 0.13 0.15 0.17 0.17 0.15 0.17 0.17 0.20 0.22 0.20 0.20 0 22 0 22 0 20 0 18 0 15 0 17 0.18 0.20 0.20 0.15 0.18 0.18 AZIMUTH DOGLEG ASP_X ASP._Y 0.00 0.0 612,049.3 5,959,490.0 0.00 0.0 612,049.3 5,959,490.0 71.16 3.3 612,049.3 5,959,490.0 116.62 0.6 612,049.3 5,959,490.0 152.80 0.7 612,049.3 5,959,490.0 141.48 0.8 612,049.5 5,959,490.0 138.60 0.2 612,049.5 5,959,490.0 136.56 0.2 612,049.6 5,959,490.0 138.71 0.1 612,049.6 5,959,489.6 147.15 0.4 612,049.6 5,959,489.6 160.08 0.4 612,049.6 5,959,489.6 172.97 0.3 612,049.6 5,959,489.6 177.65 0.1 612,049.7 5,959,489.6 171.21 0.2 612,049.7 5,959,489.6 160.77 0.2 612,049.7 5,959,489.6 152.04 0.2 612,049.7 5,959,489.6 148.45 0.2 612,049.7 5,959,489.3 160.36 0.4 612,049.7 5,959,489.3 183.33 0.3 612,049.7 5,959,489.3 190.61 0.1 612,049.7 5,959,489.3 171.68 0.3 612,049.7 5,959,489.3 150.30 0.3 612,049.7 5,959,489.3 160.04 0.2 612,049.7 5,959,489.3 182.07 0.3 612,049.7 5,959,489.3 184.42 0.5 612,049.7 5,959,489.3 179.44 0.1 612,049.7 5,959,489.3 165.90 0.4 612,049.7 5,959,489.3 151.79 0.2 612,049.7 5,959,489.3 152.55 0.1 612,049.9 5,959,488.9 163.49 0.3 612,049.9 5,959,488.9 178.96 0.3 612,049.9 5,959,488.9 185.16 0.2 612,049.9 5,959,488.9 177.78 0.2 612,049.9 5,959,488.9 161.27 0.3 612,049.9 5,959,488.9 150.42 0.3 612,049.9 5,959,488.9 152.88 0.2 612,049.9 5,959,488.9 167.23 0.4 612,049.9 5,959,488.5 181.01 0.3 612,049.9 5,959,488.5 179.09 0.2 612,049.9 5,959,488.5 167.86 0.3 612,049.9 5,959,488.5 154.77 0.4 612,050.0 5,959,488.5 149.32 0.2 612,050.0 5,959,488.5 157.50 0.3 612,050.0 5,959,488.5 172.49 0.3 612,050.0 5,959,488.5 172.40 0.1 612,050.0 5,959,488.2 160.09 0.3 612,050.0 5,959,488.2 147.49 0.3 612,050.0 5,959,488.2 145.10 0.4 612,050.0 5,959,488.2 154.49 0.3 612,050.1 5,959,488.2 169.07 0.3 612,050.1 5,959,488.2 7,18 733 747 761 776 790 805 819 834 848 862 877 891 906 920 935 949 963 977 992 1,006 1,020 1,034 1,048 1,062 1,077 t,091 1,105 1,119 1.133 1.147 1.162 1.176 1.190 1.204 1,218 1,233 1,247 1,261 1,275 1,289 1,303 1,318 1,332 1,346 1,360 1,374 1,388 1,403 1,417 1,431 1,445 1,460 1,474 1,488 1,502 1,516 1,531 1,545 1,570 1,600 1,633 1,670 1,707 1,745 1,782 1,820 1,858 1,897 1,935 718.20 732.60 747.00 761.40 775.90 790.30 804.70 819.20 833.60 848.00 862.40 876.90 891.30 905.70 920.10 934.50 948.90 963.10 977.30 991.50 1,005.60 1,019.80 1,034.00 1,048.10 1,06'2.30 1,076.50 1,090.70 1,104.80 1,119.00 1,133.20 1,147.40 1,161.49 1,175.79 1,189.89 1,204.08 1,218.27 1,232.46 1,246.64 1,260.82 1,274.89 1,289.06 1,303.22 1,317.27 1,331.41 1,345.54 1,359.66 1,373.76 1,387.75 1,401.82 1,415.87 1,429.90 1,444.01 1,458.00 1,471.97 1,486.01 1,499.94 1,513.84 1,527.81 1,541.75 1,566.23 1.595.16 1.626.48 1.661.88 1.697.68 1 333.41 1.769.24 ' 1.805.16 1.840.96 1.876.68 1,912.34 -636.60 -651.00 -665.40 -679.80 -694.30 -708.70 -723.10 -737.60 -752.00 -766.40 -780.80 -795.30 -809.70 -824.10 -838.50 -852.90 -867.30 -881.50 -895.70 -909.90 -924.00 -938.20 -952.40 -966.50 ·-980.70 -994.90 -1,009.10 -1,023.20 -1,037.40 -1,051.60 -1,065.80 -1,079.89 -1,094.19 -1,108.29 -1,122.48 -1,136.67 -1,150.86 -1,165.04 -1,179.22 -1,193.29 -1,207.46 -1,221.62 -1,235.67 -1,249.81 -1,263.94 -1,278.06 -1,292.16 -1,306.15 -1,320.22 -1,334.27 -1,348.30 -1,362.41 -1,376.40 -1,390.37 -1,404.41 -1,418.34 -1,432.24 -1,446.21 -1,460.15 -1,484.63 -1,513.56 -1,544.88 -1,580.28 -1,616.08 -1,651.81 -1,687.64 -1,723.56 -1,759.36 -1,795.08 -1,830.74 ...... 0.15 u.12 0.13 0.17 0.12 0.12 0.13 0.10 0.05 0.03 0.03 0.05 0.05 0.05 0.05 0.05 0.05 0.08 0.10 0.08 0.07 0.08 0.10 0.10 0.12 0.13 0.17 0.23 0.38 0.65 0.98 1.38 1.73 2.00 2.30 2.58 2.90 3.27 3.68 4.12 4.53 4.97 5.43 5.90 6.43 6.93 7.43 8.02 8.63 9.17 9.60 10.10 10.63 11.10 11.53 12.05 12.63 13.25 14.20 15.05 15.87 16.88 17.82 18.40 18.78 19.28 19.97 20.72 21.28 .... 186.13 0.4 Exhibit VI - 6b 199.81 0.2 191.51 0.1 191.19 0.2 184.37 0.4 181.27 0.1 187.54 0.0 205.57 0.2 209.99 0.0 192.34 0.1 178.24 0.1 173.85 0.0 191.64 0.1 203.56 0.2 197.71 0.2 188.17 0.2 181.09 0.1 189~82 0.1 205.25 0.2 203.60 0.0 182.40 0.3 154.98 0.4 142.33 0.4 136.13 0.4 122.21 1.2 110.47 2.0 102.12 2.5 97.21 2.9 93.77 2.6 91.88 2.0 91.12 2.1 90.53 2.0 90.43 2.3 90.33 2.6 89.86 2.9 89.03 3.1 88.06 2.9 87.54 3.1 87.35 3.2 86.98 3.3 86.68 3.7 86.21 3.5 85.49 3.6 84.59 4.2 83.57 4.4 82.82 3.9 82.21 3.1 81.50 3.6 80.89 3.8 80.52 3.3 80.19 3.1 80.05 3.7 80.13 4.1 80.19 4.3 80.10 3.8 80.00 2.8 79.91 2.5 79.94 2.7 80.49 2.6 81.39 1.7 82.51 1.4 83.90 1.8 85.19 2.1 86.10 2.1 86.63 1.6 612,050.1 ...I. .1 .1 ,, ~,_,,,.,d. 1 612,050.1 612,050.1 612,050.1 612,050.1 612,050.1 612,050.1 612,050.1 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.0 612,050.1 612,050.1 612,050.2 612,050.4 612,050.7 612,051.1 612,051.6 612,052.1 612,052.7 612,053.3 612,054.2 612,054.9 612,055.9 612,057.0 612,058.2 612,059.5 612,060.9 612,062.5 612,064.1 612,065.8 612,067.8 612,069.7 612,072.0 612,074.2 612,076.6 612,079.1 612,081.8 612,084.5 612,087.4 612,090.4 612,093.5 612,099.4 612,106.8 612,115.3 612,125.5 612,136.5 612,148.1 612,159.9 612,172.2 612,184.9 612,198.1 612,211.8 5,959,488.2 5,959,488.2 5,959,488.2 5,959,488.2 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.8 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.4 5,959,487.1 5,959,487.1 5,959,487.1 5,959,487.1 5,959,487.1 5,959,487.1 5,959,487.2 5,959,487.2 5,959,487.6 5,959,487.6 5,959,487.6 5,959,487.6 5,959,487.6 5,959,488.0 5,959,488.1 5,959,488.5 5,959,488.5 5,959,488.9 5,959,489.3 5,959,489.7 5,959,490.5 5,959,490.9 5,959,491.3 5,959,492.1 5,959,492.5 5,959,493.7 5,959,494.9 5,959,496.8 5,959,498.8 5,959,500.8 5,959,502.8 5,959,504.4 5,959,506.1 5,959,507.7 5,959,508.7 5,959,510.0 1,973 2,011 2,050 2,088 2,126 2,165 2,203 2,241 2,280 2,318 2,356 2,394 2,432 2,470 2,507 2,545 2,583 2,620 2,658 2,696 2,733 2,771 ' 2,809 2,846 2,884 2,921 2,959 2,996 3,034 3,071 3.108 3 3.182 3.219 3.256 3,293 3,330 3,367 3,404 3,441 3,478 3,515 3,552 3,589 3,626 3,663 3,700 3,737 3,773 3,810 3,846 3,882 3,918 3,955 3,991 4,027 4,064 4,100 4,136 4,173 4,209 4,245 4,281 4,318 4,354 4,390 4,426 4,462 4,497 4,533 1,947.8(~ 1,983.29 2,018.49 2,053.54 2,088.27 2,122.93 2,157.10 2,191.03 2,224.59 2,257.69 2,290.40 2,322.43 2,353.90 2,385.17 2,416.11 2,446.68 2,476.85 2,506.61 2,536.20 2,565.48 2,594.59 2,623.35 2,651.89 2,680.35 2,708.46 2,736.56 2,764.67 2,793.00 2,821.35 2,849.61 2,877.62 2,905.61 2,933.68 2,961.72 2,989.87 3,018.03 3,046.23 3,074.47 3,102.65 3,130.97 3,159.45 3,187.80 3,216.23 3,244.72 3,273.34 3,301.96 3,330.50 3,359.24 3,387.52 3,415.72 3,443.82 3,'471.90 3,500.03 3,528.16 3,556.26 3,584.38 3,612.47 3,640.38 3,668.43 3,696.43 3,724.44 3,752.43 3,780.32 3,808.23 3,836.13 3,863.96 3,891.65 3,919.02 3,946.31 3,973.68 -1,901.69 -1,936.89 -1,971.94 -2,006.67 -2,041.33 -2,075.50 -2,109.43 -2,142.99 -2,176.09 -2,208.80 -2,240.83 -2,272.30 -2,303.57 -2,334.51 -2,365.08 -2,395.25 -2,425.01 -2,454.60 -2,483.88 -2,512.99 -2,541.75 -2,570.29 -2,598.75 -2,626.86 -2,654.96 -2,683.07 -2,711.40 -2,739.75 -2,768.01 -2,796.02 -2,824.01 -2,852.08 -2,880.12 -2,908.27 -2,936.43 -2,964.63 -2,992.87 -3,021.05 -3,049.37 -3,077.85 -3,106.20 -3,134.63 -3,163.12 -3,191.74 -3,220.36 -3,248.90 -3,277.64 -3,305.92 -3,334.12 -3,362.22 -3,390.30 -3,418.43 -3,446.56 -3,474.66 -3,502.78 -3,530.87 -3,558.78 -3,586.83 -3,614.83 -3,642.84 -3,670.83 -3,698.72 -3,726.63 -3,754.53 -3,782.36 -3,810.05 -3,837.42 -3,864.71 -3,892.08 21.90 ..... 75 ~.68 24.52 25.35 26.30 27.37 28.48 29.65 30.80 31.85 32.78 33.58 34.37 35.28 36.37 37.33 38.02 38.57 39.13 39.78 40.40 40.85 41.13 41.40 41.52 41.40 41.15 40.98 40.88 40.70 40.65 40.62 40.48 40.47 40.40 40.27 40.25 40.:1.7 39.93 39.80 39.80 39.75 39.58 39.43 39.25 39.03 39.02 39.02 39.05 39.10 39.18 39.22 39.20 39.35 39.47 39.53 39.58 39.58 39.48 39.52 39.57 39.67 39.80 39.78 39.72 39.72' 39.77 39.78 39.70 ~6.86 1.b b12,22b.8 Exhibit VI - 6b 87.19 87.07 87.08 87.20 87.39 87.60 87.88 88.20 88.39 88.51 88.63 88.82 88.96 88.86 88.23 86.89 85.30 84.05 83.53 83.49 83.48 83.49 83.50 83.49 83.47 83.45 83.44 83.42 83.41 83.47 83.53 83.57 83.66 83.74 83.79 83.82 83.81 83.80 83.80 83.82 83.84 83.90 84.01 84.13 84.23 84.36 84.48 84.50 84.46 84.38 84.26 84.26 84.34 84.40 84.47 84.50 84.53 84.61 84.75 84.87 84.92 85.06 85.24 85.37 i"~ r- ,al-- 2.8 2.9 3.1 3.0 2.8 2.5 2.2 2.2 2.4 2.9 2.6 1.9 1.5 1.5 2.0 2.8 3.0 2.3 1.2 0.3 0.3 0.7 0.5 0.3 0.5 0.1 0.1 0.4 0.0 0.2 0.4 0.1 0.3 0.7 0.4 0.1 0.1 0.5 0.4 0.5 0.6 0.1 0.2 0.2 0.2 0.3 0.2 0.1 0.4 0.4 0.3 0.1 0.1 0.3 0.2 0.2 0.3 0.4 0.3 0.3 0.1 0.3 0.3 0.3 /-% ..% 612,321.1 612,339.0 612,357.7 612,376.9 612,396.8 612,417.0 612,437.6 612,458.6 612,480.2 612,502.2 612,524.7 612,547.7 612,571.0 612,594.6 612,618.6 612,642.7 612,667.2 612,691.7 612,716.2 612,740.9 ' 612,765.4 612,790.2 612,814.6 612,838.9 612,862.9 612,886.7 612,910.6 612,934.4 612,958.2 612,982.1 613,005.8 613,029.6 613,053.1 613,076.8 613,100.3 613,123.9 613,147.3 613,170.7 613,194.1 613,217.4 613,240.5 613,263.6 613,286.3 613,309.1 613,331.7 613,354.5 613,377.2 613,400.0 613,422.9 613,445.9 613,468.9 613,491.7 613,514.8 613,537.7 613,560.6 613,583.7 613,606.6 613,629.7 613,652.7 613,675.8 613,698.7 613,721.3 613,743.9 613,766.6 b,gbg, blO.9 5,959,511.9 5,959,512.8 5,959,513.8 5,959,514.8 5,959,515.7 5,959,516.7 5,959,518.1 5,959,519.1 5,959,520.5 5,959,521.9 5,959,522.9 5,959,524.0 5,959,525.0 5,959,526.1 5,959,527.1 5,959,527.8 5,959,528.5 5,959,529.6 5,959,530.3 5,959,531.4 5,959,532.5 5,959,534.7 5,959,537.3 5,959,540.2 5,959,543.5 5,959,546.8 5,959,550.1 5,959,553.0 5,959,556.3 5,959,559.3 5,959,562.5 5,959,565.5 5,959,568.8 5,959,571.7 5,959,575.0 5,959,577.9 5,959,580.8 5,959,584.1 5,959,587.0 5,959,589.9 5,959,592.8 5,959,595.8 5,959,598.7 5,959,601.6 5,959,604.1 5,959,607.0 5,959,610.0 5,959,612.9 5,959,615.4 5,959,618.3 5,959,620.8 5,959,623.4 5,959,625.9 5,959,628.5 5,959,631.0 5,959,633.5 5,959,636.5 5,959,639.0 5,959,641.5 5,959,644.1 5,959,646.6 5,959,649.2 5,959,651.7 5,959,654.3 5,959,656.8 5,959,659.0 5,959,661.5 5,959,663.7 5,959,665.9 ~1',..,~0~ 4,604 4,640 4,675 4,711 4,746 4,782 4,817 4,853 4,889 4,924 4,959 4,995 5,030 5,066 5,100 5,135 5,170 5,204 5,239 5,274 5,308 5,343 5,378 5,412 5,447 5,482 5,516 5,551 5,585 5.620 5.654 5 ~689 5.723 5 ~757 5.791 5.825 5.859 5.893 5.927 5.961 5.995 6.029 6.063 6.097 6.131 6.165 6.199 6.233 6.267 6.301 6.335 6.368 6,402 6,435 6,468 6,502 6,535 6,568 6,602 6,635 6,668 6,701 6,735 6,768 6,801 6,834 6,,968 6,901 6,934 ~, UU J., UO 4,028.52 4,055.89 4,083.29 4,110.62 4,137.87 4,164.87 4,191.90 4,218.74 4,245.55 4,272.20 4,298.68 4,325.06 4,351.35 4,377.49 4,403.08 4,428.56 4,453.88 4,479.21 4,504.23 4,529.19 4,554.01 4,578.69 4,603.20 4,627.65 4,651.86 4,675.91 4,699.83 4,723.62 4,747.21 4,770.82 4,794.33 4,817.80 4,841.11 4,864.05 4,886.95 4,909.92 4,932.99 4,955.98 4,978.76 5,001.50 5,024.18 5,046.85 5,069.50 5,092.12 5,114.80 5,137.39 5,159.94 5,182.50 5,204.92 5,227.30 5,249.69 5,271.80 5,293.80 .5,315.88 5,337.93 5,360.07 5.382.23 5.404.35 5.426.62 5.448.94 5.471.23 5.493.62 5.515.99 5 538.46 5.560.98 5 583.57 5 606:20 5 628.83 5,651.43 -3,946.92 -3,974.29 -4,001.69 -4,029.02 -4,056.27 -4,083.27 -4,110.30 -4,137.14 -4.163.95 -4.190.60 -4.217.08 -4.243.46 -4.269.75 -4.295.89 -4.321.48 -4.346.96 -4.372.28 -4.397.61 -4.422.63 -4.447.59 -4.472.41 -4.497.09 -4.521.60 -4.546.05 -4.570.26 -4.594.31 -4.618.23 -4.642.02 -4.665.61 -4.689.22 -4.712.73 -4 ~736.20 -4.759.51 -4 782.45 -4,805.35 -4,828.32 -4,851.39 -4,874.38 -4,897.16 -4,919.90 -4,942.58 -4,965.25 -4,987.90 -5,010.52 -5,033.20 -5,055.79 -5,078.34 -5,100.90 -5,123.32 -5,145.70 -5,168.09 -5,190.20 -5,212.20 -5,234.28 -5,256.33 -5,278.47 -5,300.63 -5,322.75 -5,345.02 -5,367.34 -5,389.63 -5,412.02 -5,434.39 -5,456.86 -5,479.38 -5,501.97 -5,524.60 -5,547.23 -5,569.83 .."" 55 { .57 39.78 39.93 40.15 40.47 40.73 41.02 41.25 41.47 41.70 41.93 42.13 42.35 42.62 42.85 43.10 43.50 43.85 44.17 44.50 44.8'0 45.02 45.37 45.82 46.12 46.40 46.75 46.95 47.00 47.08 47.20 47.18 47.30 47.43 47.27 47.27 47.63 47.93 48.12 48.20 48.17 48.28 48.30 48.30 48.43 48.50 48.65 48.83 48.87 48.73 48.67 48.65 48.57 48.48 48.50 48.35 48.10 47.98 47.85 47.78 47.70 47.60 47.52 47.37 47.20 47.1~3 47.1S 47.03 ,4~ 7~ 85.50 85.84 85.97 86.08 86.27 86.45 86.51 86.56 86.68 86.79 86.82 86.82 86.93 87.10 87.23 87.34 87.45 87.59 87.77 87.91 88.00 88.08 88.13 88.21 88.28 88.30 88.35 88.45 88.52 88.58 88.68 88.79 88.92 89.10 89.34 89.55 89.66 89.78 89.92 90.07 90.20 90.26 90.39 90.50 90.45 90.36 90.36 90.38 90.36 90.32 90.31 90.35 90.40 90.44 90.42 90.32 90.16 90.03 89.96 89.88 89.75 89.61 89.47 89.40 g.-,' 0.2 613,8~' q Exhibit VI - 6b 0.8 0.9 0.7 0.7 0.7 0.7 0.6 0.7 0.8 0.7 0.7 1.2 1.1 1.0 1.0 0.9 0.7 1.1 1.3 0.9 0.8 1,0 0.6 0.2 0.2 0.4 0.2 0.4 0.4 0.5 0.2 1.1 1.0 0.8 0.5 0,3 0,4 0.3 0.3 0.5 0.2 0.5 0,6 0.2 0.5 0.2 0.1 0.2 0.3 0.1 0.5 0.8 0.4 0.4 0.3 0.4 0.4 0.3 0.5 0.6 0.3 0.3 0.5 613,948.3 613,971.4 613,994.8 614,018.1 614,041.6 614,065.1 614,088.7 614,112.4 614,135.8 614,159.3 614,182.8 614,206.6 614,230.4 614,254.5 614,278.7 614,303.1 614,327.4 614,352.0 614,376.7 614,401.6 614,426.5 614,451.7 614,476.7 614,502.0 614,527.2 614,552.5 614,577.7 614,602.5 614,627.3 614,652.2 614,677.2 614,702.2 614,727.3 614,752.6 614,777.9 614,803.2 614,828.5 614,853.9 614,879.4 614,904.8 614,930.3 614,955.8 614,981.4 615,006.9 615,032.6 615,057.7 615,082.8 615,107.8 615,132.8 615,157.7 615,182.8 615,207.5 615,232.3 615,257.0 615,281.6 615,306.3 615,330.7 615,355.3 615,379.8 6 ! !~, ~-04.3 6] ',i,428.7 6 ] '.:,453.2 615,477.5 ~1 c Ch1 7 5,959,670.2 5,959,672.4 5,959,674.6 5,959,676.4 5,959,678.5 5,959,680.7 5,959,682.9 5,959,685.1 5,959,686.9 5,959,688.7 5,959,690.5 5,959,692.4 5,959,694.2 5,959,696.0 5,959,697.8 5,959,699.3 5,959,701.1 5,959,702.6 5,959,704.0 5,959,705.8 5,959,707.3 5,959,708.8 5,959,710.3 5,959,711.4 5,959,712.8 5,959,713.9 5,959,715.4 5,959,716.5 5,959,717.7 5,959,718.8 5,959,719.9 5,959,721.0 5,959,722.1 5,959,723.2 5,959,724.3 5,959,725.1 5,959,726.2 5,959,726.9 5,959,727.7 5,959,728.4 5,959,729.2 5,959,729.6 5,959,730.0 5,959,730.7 5,959,731.1 5,959,731.1 5,959,731.5 5,959,731.9 5,959,731.9 5,959,732.3 5,959,732.4 5,959,732.7 5,959,732.8 5,959,733.1 5,959,733.2 5,959,733.5 5,959,733.6 5,959,733.9 5,959,734.0 5,959,734.3 5,959,734.3 5,959,734.7 5,959,735.1 5,959,735.5 5,959,735.9 5,959,736.2 5,959,737.0 5,959,737.3 5,959,738.1 7 doo 7 ~033 7.065 7.098 7.131 7,163 7,196 7,228 7,261 7,294 7,326 7,359 7,392 7,424 7,457 7,490 7,522 7,555 7,587 7,619 7,652 7,684 7.716 7.748 7.780 7.812 7.844 7.876 7.9O8 7.940 7.972 8 .O04 8,036 8.068 8,100 8,132 8,164 8,195 8,227 8,258 8,289 8,321 8,352 8,383 8,415 8,446 8,477 8,509 8,540 8,572 8,603 8,634 8,666 8,697 8,729 8,760 8,791 8,821 8,852 8,883 8,914 8,944 8,975 9,006 9,037 9,067 9,098 9,129 9,159 9.190 5,696.48 5,718.88 5,741.32 5,763.84 5,786.50 5,809.13 5,831.78 5,854.46 5,877.25 5,900.03 5,922.91 5,945.90 5,968.85 5,991.75 6,014.75 6,037.77 6,060.75 6,083.86 6,106.67 6,129.45 6,152.26 6,175.06 6,198.03 6,220.98 6,244.05 6,267.21 6,290.51 6,313.92 6,337.47 6,361.23 6,385.07 6,409.07 6,433.28 6,457.59 6,481.98 6,506.53 6,531.09 6,555.19 6,579.28 6,603.45 6,627.69 6,652.00 6,676.39 6,700.84 6,725.30 6,749.80 6,774.23 6,798.63 6,823.10 6,847.45 6,871.97 6,896.41 6,920.84 6,945.25 6,969.68 6,993.76 7,017.55 7,041.28 7,064.88 7,088.41 7,112.00 7,135.48 7,159.04'" 7,182.52 7,206.08 7,229.53 7,252.97 7,276.38 7,299.78 7.323.16 -5,614.88 -5,637.28 -5,659.72 -5,682.24 -5,704.90 -5,727.53 -5,750.18 -5,772.86 -5,795.65 -5,818.43 -5,841.31 -5,864.30 -5,887.25 -5,910.15 -5,933.15 -5,956.17 -5,979.15 -6,002.26 -6,025.07 -6,047.85 -6,070.66 -6,093.46 -6,116.43 -6,139.38 -6,162.45 -6,185.61 -6,208.91 -6,232.32 -6,255.87 -6,279.63 -6,303.47 -6,327.47 -6,351.68 -6,375.99 -6,400.38 -6,424.93 -6,449.49 -6,473.59 -6,497.68 -6,521.85 -6,546.09 -6,570.40 -6,594.79 -6,619.24 -6,643.70 -6,668.20 -6,692.63 -6,717.03 -6,741.50 -6,765.85 -6,790.37 -6,814.81 -6,839.24 -6,863.65 -6,888.08 -6,912.16 -6,935.95 -6,959.68 -6,983.28 -7,006.81 -7,030.40 -7,053.88 -7,077.44 -7,100.92 -7,124.48 -7,147.93 -7,171.37 -7,194.78 -7,218.18 -7.241.56 '~.63 { .57 46.42 46.23 46.03 46.02 45.98 45.87 45.73 45.65 45.55 45.43 45.40 45.35 45.28 45.22 45.12 44.95 44.83 44.78 44.67 44.42 44.22 44.13 43.98 43.68 43.20 42.80 42.43 42.05 41.63 41.22 40.82 40.33 39.93 39.85 39.92 39.80 39.55 39.35 39.15 38.95 38.68 38.55 38.65 38.82 38.97 39.07 39.00 38.87 38.88 38.88 38.93 39.08 39.20 39.33 39.53 39.68 39.85 40.00 40.08 40.12 40.08 40.10 40.13 40. 2 .? 40.30 40.30 40.35 40.50 89.25 ~9.12 89.09 89.08 89.11 89.16 89.18 89.08 89.01 89.03 88.98 88.91 88.89 88.81 88.66 88.61 88.60 88.51 88.43 88.46 88.60 88.78 88.94 89.08 89.36 89.69 89.98 90.29 90.58 90.89 91.27 91.49 91.46 91.44 91.51 91.50 91.52 91.60 91.50 91.29 .91.16 91.14 91.18 91.35 91.37 91.17 91.14 91.35 91.61 91.74 91.67 91.69 91.90 92.06 92.17 92.34 92.53 92.63 92.63 92.71 92.96 93.08 93.25 93.69 93.97 94.15 0.4 615.5~.~- 4 Exhibit VI - 6b 0.1 0.1 0.3 0.4 0.3 0.3 0.4 0.2 0.2 0.2 0.2 0.3 0.6 0.5 0.2 0.3 0.8 07 03 06 10' 15 13 13 1.4 1.4 1.4 1.4 1.7 1.5 0.5 0.2 0.4 0.8 0.6 0.6 0.7 0.9 0.6 0.4 0.5 0.5 0.5 0.2 0.6 0.1 0.4 0.5 0.5 0.4 0.4 0.8 0.6 0.6 0.6 0.5 0.3 0.1 O2 O5 04 ©4 O9 06 0.6 615,543.3 615,666.7 615,690.2 615,713.6 615,736.9 615,760.3 615,783.6 615,807.0 615,830.2 615,853.4 615,876.6 615,899.7 615,922.7 615,945.5 615,968.0 615,990.6 616,013.1 616,035.6 616,057.8 616,080.1 616,102.3 616,124.3 616,146.1 616,167.9 616,189.4 616,210.7 616,232.0 616,252.9 616,273.8 616,294.3 616,314.9 616,335.4 616,355.6 616,375.5 616,395.4 616,415.2 616,434.9 616,454.5 616,474.0 616,493.5 616,513.2 616,532.9 616,552.7 616,572.6 616,592.2 616,612.0 616,631.8 616,651.4 616,671.2 616,691.0 616,710.7 616,730.3 616,750.0 616,769.6 616,789.3 616,809.0 616,828.8 616,848.7 615,868.S 616,888.2 F.~ ~,.008.0 6, ]. ":1., ':227.9 616,947.7 616,967.6 616.987.5 5,959,739.2 5,959,739.9 5,959,740.7 5,959,741.4 5,959,742.1 5,959,742.8 5,959,743.6 5,959,744.3 5,959,745.0 5,959,745.7 5,959,746.1 5,959,746.8 5,959,747.6 5,959,748.6 5,959,749.4 5,959,750.1 5,959,750.8 5,959,751.5 5,959,752.6 5,959,753.3 5,959,754.0 5,959,755.1 5,959,756.2 5,959,756.9 5,959,758.0 5,959,758.7 5,959,759.4 5,959,760.1 5,959,760.8 5,959,761.1 5,959,761.8 5,959,761.8 5,959,762.1 5,959,762.1 5,959,762.0 5,959,762.0 5,959,761.6. 5,959,761.5 5,959,761.1 5,959,761.0 5,959,760.6 5,959,760.6 5,959,760.5 5,959,760.1 5,959,760.0 5,959,759.9 5,959,759.9 5,959,759.8 5,959,759.4 5,959,759.3 5,959,759.3 5,959,759.2 5,959,758.8 5,959,758.7 5,959,758.3 5,959,757.9 5,959,757.8 5,959,757.4 5,959,757.0 5,959,756.5 5,959,755.7 5,959,755.3 5 959,754.5 5 959,754.1 5 959,753.3 5 959,752.5 5 959,751.7 5 959,750.9 5 959,749.8 S.9S9.748.6 91221 9,252 9,282 9,313 9,343 9,373 9,403 9,433 9,463 9,493 9,524 9,554 9,584 9,614 9,644 9,674 9,704 9,734 9,765 9,795 9,825 9,855 9,885 9,914 9,944 9,973 10,003 10,032 10,061 10,091 10,120 10,150 10,179 10,209 10,238 10,268 10,297 10,327 10,356 10,385 10,415 10,444 10,473 10,502 10,530 10,559 10,588 10,617 10,646 10,674 10,703 10,732 10,761 10,790 10,818 10,847 10,876 10,905 10,934 10,962 10,991 11,018 11,046 11,066 11,055 11,142 11,161 11,181 71346.46 7,369.70 7,392.85 7,415.91 7,438.49 7,460.84 7,482.94 7,504.96 7,526.89 7,548.72 7,570.49 7,592.18 7,613.78 7,635.24 7,656.76 7,678.12 7,699.39 7,720.61 7,741.86 7,762.98 7,784.07 7,805.12 7,826.07 7,846.54 7,866.97 7,887.22 7,907.40 7,927.35 7,947.15 7,966.96 7,986.74 8,006.51 8,026.18 8.045.83 8.065.33 8.084.83 8.104.32 8.123.82 8.143.24 8.162.68 8.182.18 8.201.54 8.220.77 8,240.07 8,259.44 8,278.88 8,298.34 8,317.77 8,337.13 8,356.42 8,375.61 8,394.64 8,413.53 8,432.33 8,450.93 8,469.43 8,487.86 8,506.29 8,524.53 8,542.78 8,560.57 8,578.14 8,595.62 8,608.36 8,620.45 8,632.53 8, C .:: ':'.. ~ 7 8,656.69 8,668.82 8,680.94 -71264.86 -7,288.10 -7,311.25 -7,334.31 -7,356.89 -7,379.24 -7,401.34 -7,423.36 -7,445.29 -7,467.12 -7,488.89 -7,510.58 -7,532.18 -7,553.64 -7,575.16 -7,596.52 -7,617.79 -7,639.01 -7,660.26 -7.681.38 -7.702.47 -7.723.52 -7.744.47 -7.764.94 -7.785.37 -7.805.62 -7.825.80 -7.845.75 -7.865.55 -7.885.36 -7.905.14 -7.924.91 -7.944.58 -7.964.23 -7.983.73 -8.003.23 -8.022.72 -8.042.22 -8.061.64 -8,081.08 -8,100.58 -8,119.94 -8,139.17 -8,158.47 -8,177.84 -8,197.28 -8,216.74 -8,236.17 -8.255.53 -8.274.82 -8.294.01 -8.313.04 -8.331.93 -8,350.73 -8,369.33 -8,387.83 -8,406.26 -8,424.69 -8,442.93 -8,461.18 -8,478.97 -8,496.54 -8,514.02 -8,525.76 -8,538.85 -8,550.93 -8,562.97 -8,575.09 -8,587.22 -8,599.34 ,~OiTO 93 41.17 41.43 41.82 42.30 42.80 43.13 43.37 43.60 43.78 44.00 44.25 44.45 44.68 44.92 45.12 45.22 45.38 45.50 45.55 45.63 45.78 46.03 46.30 46.60 47.08 47.50 47.75 47.90 47.90 47.93 48.10 48.35 48.57 48.67 48.63 48.65 48.63 48.55 48.38 48.20 48.02 47.83 47.65 47.47 47.47 47.67 47.83 48.07 48.42 48.82 49.22 49.62 49.92 50.13 50.30 50.48 50.62 50.70 50.78 50.77 50.65 50.70 50.77 ?Q.TO 50.58 50.58 50.68 94.46 94.73 9b,lb 96.52 96.96 97.29 97.39 97.41 97.44 97.52 97.61 97.68 97.62 97.51 97.56 97.76 97.97 98.19 98.39 98.58 98.77 98.91 99.02 99.18 99.38 99.56 99.71 99.82 99.84 99.80 99.76 99.68 99.66 99.76 99.93 100.08 100.23 100.39 100.64 100.90 101.08 101.34 101.67 101.87 102.08 102.36 102.61 102.91 103.14 103.26 103.29 103.32 103.36 103.27 103.18 103.16 103 20 103 28 103 46 103 60 103 76 103 97 10~ 17 104 38 104 55 104 69 Exhibit 0.9 6171007 4 0.9 617,0~ VI - 6b 1.4 1.3 1.1 0.6 0.7 0.8 0.7 0.8 0.8 0.7 0.4 0.5 0.6 0.5 0.6 0.7 1.0 1.0 1.1 1.7 1.5 1.0 0.7 0.4 0.3 0.6 0.9 0.8 0.4 0.2 0.3 0.4 0.5 0.7 0.7 0.9 0.9 0.8 0.9 0.8 0.9 0.8 1.1 1.4 1.6 1.5 1.4 1.1 0.7 0.6 0.7 0.5 0.3 0.3 0.2 0.7 0.6 0.7 0.9 0.9 0.7 0.8 617,148.5 617,169.0 617,189.5 617,210.2 617,230.9 617,251.8 617,272.5 617,293.6 617,314.6 617,335.8 617,357.1 617,378.3 617,399.6 617,420.9 617,442.3 617,463.6 617,484.5 617,505.5 617,526.7 617,548.0 617,569.4 617,590.8 617,612.5 617,634.0 617,655.7 617.677.2 617.699.0 617.720.8 617.742.6 617.764.5 617.786.4 617.808.2 617.830.0 617,851.7 617,873.1 617,894.3 617,915.3 617,936.3 617,957.2 617,978.0 617,998.9 618,019.9 618,040.8 618,061.9 618,082.9 618,104.3 618,125.7 618,147.1 618,168.7 618,190.3 618,212.1 618,233.8 618,255.5 618,276.8 618,297.7 618,318.7 618,333.8 . ~,.~,.,8.3 12 .., _> '3 ._ , 7 ":",376.9 6 ~. c, -, .:! i.. 3 618,405.7 618,419.9 5,959,746.3 5,959,744.8 5,959,743.3 5,959,741.8 5,959,739.9 5,959,738.0 5,959,736.1 5,959,733.9 5,959,731.7 5,959,729.4 5,959,727.2 5,959,724.6 5,959,722.3 5,959,719.7 5,959,717.1 5,959,714.9 5,959,712.3 5,959,709.7 5,959,707.1 5,959,704.5 5,959,701.9 5,959,699.0 5,959,696.4 5,959,693.4 5,959,690.4 5,959,687.5 5,959,684.1 5,959,681.2 5,959,677.9 5,959,674.5 5,959,671.2 5,959,667.5 5,959,664.2 5,959,660.9 5,959,657.6 5,959,653.9 5,959,650.6 5,959,647.2 5,959,643.6 5,959,640.2 5,95,9,636.6 5,959,632.9 5,959,629.2 5,959,625.5 5,959,621.8 5,959,617.7 5,959,613.6 5,959,609.6 5,959,605.5 5,959,601.1 5,959,596.7 5,959,592.2 5,959,587.4 5,959,582.7 5,959,577.9 5,959,573.1 5,959,568.3 5,959,563.5 5,959,558.7 5,959,554 3 5,959,549 5 5,959,544 7 5 959,541 3 5 959,538 2 5 959,53,1 8 5 959,531. '4 C 0 C.' ", .... '~ _,. :~:~',-,~.7 9 5 ~59,524.5 5,959,521.1 11,300 .li,220 11,244 11,268 11,292 11,317 11,341 11,366 11,390 11,415 11,440 11,465 11,489 11,514 11,538 11,562 11,586 11,610 11,634 11,659 11,683 !1,707 11,731 11,755 11,779 11,803 11,822 11,837 11,848 11,948 12,048 8,693.06 8,705.91 8,721.15 8,736.61 8,752.10 8,767.72 8,783.46 8,799.32 8,815.40 8,831.55 8,847.66 8,863.74 8,879.79 8,895.47 8,911.05 8,926.66 8,942.28 8,957.92 8,973.48 8,989.04 9,004.53 9,019.94 9,035.20 9,050.41 9,065.52 9,080.22 9,091.77 9,101.32 9,107.84 9,169.31 9,230.78 -8,611.46 -8,624.31 -8,639.55 -8,655.01 -8,670.50 -8,686.12 -8,701.86 -8,717.72 -8,733.80 -8,749.95 -8,766.06 -8,782.14 -8,798.19 -8,813.87 -8,829.45 -8,845.06 -8,860.68 -8,876.32 -8,891.88 -8,907.44 -8,922.93 -8,938.34 -8,953.60 -8,968.81 -8,983.92 -8,998.62 -9,010.17 -9,019.72 -9,026.24 -9,087.71 -9,149.18 5n.57 ,~' ~,0 5u.35 50.23 50.22 50.15 49.95 49.73 49.42 49.27 49.33 49.43 49.55 49.68 49.78 49.83 49.77 49.72 49.87 50.10 50.30 50.60 50.88 51.20 51.52 51.77 51.93 52.03 52.07 52.07 52.07 104.83 106.23 106.60 107.01 107.30 107.55 107.66 107.61 107.61 107.70 107.76 107.71 107.54 107.41 107.40 107.41 107.34 107.24 107.13 107.07 107.04 107.03 107.05 106.99 106.99 106.99 0.8 618,434.3 Exhibit VI - 6b 1.1 1.5 1.8 1.1 0.8 0.5 0.5 0.5 0.5 0.3 0.3 0.6 0.8 1.0 0.8 1.3 1.2 1.4 1.3 1.1 0.9 0.7 0.6 0.0 0.0 618,539.5 618,557.6 618,575.8 618,593.8 618,611.8 618,629.7 618,647.7 618,665.4 618,682.9 618,700.7 618,718.3 618,736.0 618,753.7 618,771.4 618,789.3 618,807.1 618,825.0 618,843.1 618,861.2 618,879.1 618,893.2 618,904.9 618,913.0 618,988.8 619,064.5 5,959,517.6 5,959,513.8 5,959,509.4 5,959,504.5 5,959,499.7 5,959,494.8 5,959,490.0 5,959,485.2 5,959,480.0 5,959,474.4 5,959,469.2 5,959,463.6 5,959,458.4 5,959,453.2 5,959,447.6 5,959,442.4 5,959,437.2 5,959,431.6 5,959,426.4 5,959,421.2 5,959,416.0 5,959,410.4 5,959,405.2 5,959,400.0 5,959,394.8 5,959,389.6 5,959,385.4 5,959,381.9 5,959,379.5 5,959,357.6 5,959,335.8 Exhibit VI - 6c t ~I.IMP$ el MAKE/MODEL lINER ALASKA PRODUCTION -z~¥ "" '/ I'~'G 1 .,G ..ONE '~..LL NAME - NO. RF~r. ~TIME I DAT~/E DE TVO I. ,x o., :oo ,/,,-, z_ J mRESENT. DAILY J CUM. .O. UA,,O,,. I l' J s,~.,, ..s...y/ ~ --,x- ,~uo I c. Ec. ~ .o.. 5/ ?¢PE ~e._ IDEPTH (-~::~/~.~ VOL ~)Z b~tJ PIT .~ J DALLY CUM' VOL ~,¢:' ~. . ~.~, J yuo ~ '~'" 7~--~ ~:, ~;' ..,' /~" o~1 /..~ ,.~ /? /5- ~E~.I ~o,o~l ~" ,o.,,q / '"t "-- =/;~ o., ~ :,,A,~, ,...', I I : 2 3 PRESS x fiX:K) DN ~1000 TORO J ~:'~ SLACK J~ SERIAL qO BHA NO ~'~ 75"~ ~ : SUI:WE¥ .rJHA CHANGE (YIN) ~JHA~ · HR. SINCr . DRILL I , S'I'RING · , , }U~EY ANGLE ~ SE~ ,,~ NI-S ANGLE ~ SE~ ' NI.S ~-W I CONN. B~D J ~RE SHALE G~ G~ J PRESS ; TRIP . LENGTH / DELT~ TRIP CL JAVAIL 8ED.e. Exhibit VI ..... 6c ,;',i STANDARD ALASKA PRODUCTION WELL NAME - NO. PRESENT OPERATION TIME HRS. DRLG. MUD ~ I CHECK FC -- IFC Pm I ~ [ Mt ~PE J~ GELS RIG i , ~3MAKE/MOD--'L DAILY co~ 232 g ?g CSG FIT DAILY MUDS ~ 2 3 FL CUM. 1o. ~ SAND SOUDS II AVDP AVDC IWOB JAR PRESS UP xlO00 DN ROT PIU SLACK WT xlO00 SERIAL NO. 7_s"'~, A'z7 xlooo BHA CHANGE pt/N) LENGTH SURVEY MD # SURVEY MD SURVEY MD # SURVEY MD # TRIP CONN. BKGD GAS GAS GAS ANGLE ANGLE AZ ANGLE AZ ANGLE AZ SECT E/-W DLS NI-S E/-W DIS TVD SECT DLS OPERATING SUMMARY : NI-S E/-W DIS IPORE IDX I SHALE DELTA PRESS ~,' DEN TRBLE TRBLE CODE BAROMETER TOTALPERSONNEL3~ SAPC B.~.?. ~ J J TRBLE TRBLE ,' CODE COST , ,TEMP *FI i CATERiNG "i,' I SER ICE CO // j CONTRACTOR Z~ ,-~ I''~ :' ' I I I ITRBLE CODE jFLUID INJ OTHER JTRBLE COST WATER bbl USED IAVAIL. BEDS I bbl (' Exhibit VI - 6c {' JE'rS COND TYPE OD ID CHANGE LENGTH SURVEY MD # ~URVEY I MD ANGLE URVEY MO ANGLE URVEY MD ANGLE . TRIP CONN. IT VD 'rVD 1"VD TVD SEC~ NI-S DLS SECT FJ.W DLS SECT SEC% DL$ BKGD IPORE 1Dx I SHALE DELTA ~ PRESS I ,~ DEN TRIP CL TRBLE TRBLE COOE COST WINO I BAROMETER ~3tr I knt~ 1OTAL PERSONNEL /.l~_~/ I SAPC -~PC ~) t6/88) I TRBLE CODE ' TEk!P /1 I TRBLE,' , ] TR~L ~; TRBLE , I cLU,D iWATE~' - .,, ExhibitVl-6c ( ~ ,~RIG 1 RIG PHONE ALASKA PRODUCTION ~_z._:ool ¥/¢'/,r.r '"""-"-~ PRESENT i ;O~*.~^'hOn I [ SUPV HRS L.~T ,'- I ' :~ ' · ' DRLO C~'5 n 'tS ~ OmC PUMP r'' ');, J ",s ':J~ ~,.w I ~I~C }7--~ / ~.w i i s'~ :;~f ~l.,~ ~ ~ ~.w J PRESS [~J ]DEN DLS DL$ OL.q. # , '~TtIP CONN G~ DELTa, TRqP C '. ~VI'TY LOG : I Exhibit VI- 6c li]~t]]~' ~ STANDARD ALASKA PRODUCTION~2/~V~'~ I'RI~ - RIG PHONE su . ~s. ///~ MUD ~ CHECK ~ HOLE I PIT DAILY CUM. Pm PI Mt C~ I ~ND ~LIDS o I ~MP *F s~ ~ 2 ~ ~ ~ ~ ~ 3 PRESS ~ I ~M , M~ ..... xl~ ~ xl~ ~ xl~ I OFF ~ xl~ , BIT~ SIZE MAKE ~PE J~ TFA DE~H OUT F~AGE HOURS COND SERIAL NO. BHA NO. BHA CHANGE ',YIN)'/ITEM OD ID LEN~ ITEM OD ID LEN~H ITEM OD ID LEN~- : . BHA~ ,, 1 HR. SINCE ff61 ff INSPEC. 4 ~ ~ ff 5 DRILL AIR ~, I0 I ffl 11 .. SU~EY MD ANGLE ~ J ~D SE~ N/-S ~.W D~ SU~EY MD ANGLE ~ ~,~D SE~ I NI~ ~-W SU~EY MD I ANGLE ~ ~D SE~ ~ ~-W D~ SU~EY MD ANGLE ~ ~D SE~ NI~ ~-W TRIP I CONN'. Brad ~RE I DX I SHALE DELTA ~ I G~ O~ I PRESS OPE~TING SUMMA~ ...~. . . ~ ..~~...~ ~,v..~o. I <c,~.~,., I / 1115 1.7~ /6 o ~ D/~/~ ~ P/~ EAcT W~2~ ~ ~ ~l/~d ~ ~ ~/~' .... i?~ ~ I~ o o OTis P.z.~ ~,';i,~Y~h~ /qeO I,~~ o !o~~~ ~xa~L,~X~ ~y~-~ ~ ~'~ ~~'~~ ~11~ ...... .~, WlkD '~ FLUID bbll WATER In * USED bbl ~ CaTE,,.~ CO. ~AL PERSONNEL I~PC , CONTR~R.:~ I ISERvIcE AVAIL. I I i I I I I ~ ,, i SAPC 30 161881 Exhibit VI - 6c STANDARD ALASKA PRO~DUCTION ' . I""~"~'~ o .._~_ ' ~ ' ~-,~~'~~ .I ,,~ I ,~ ~,~ '=~.' .. ~' ~- , ~. ., . i~, r:z~. ~ ~~ ~ .- , ,, ~1""''~'~°', ~1°'"'" I'"""' ( Exhibit VI - 6c (" CEMI~NTATION: 13 3/8" CASING: 4128 cuff [4438 sacks) PERMAFROST PBU/EWE DRILLING PROGRAM PROPOSED WELL DIAGRAM WELL W-17 (11-23-11-12~ N_ABORS 22E Conductor 13 3/8" 68# L-80 Butt. Base Pexmafrost 1942' 9 5/8" CASING: 1st. Stage: Slurry: Tail Slurry: 2nd. Stage 1890 cuft (1000 sks) Class G (see program for details) 575 cuff (500 sks) Class G (see program for details) 280 cuft PERMAFROST cement followed by dry crude downsquccze 3-1/2" Ball Valve 1992' w/Flow Couplings i3 3/8" Shoe 2809' 17 1/2" Open Hole 2829' 9 5/8" 47# L-80 NSCC ,~._.XO: 9 5/8" 47# L-80 5352' NSCC Box X Butt. Pin 1/2" 9.3# L-80 A/B Mod. EUE with GLM's 9 5/8" 47# L-80 Butt. 7" LINER: Slurry: 251 cuff (213 sks) Class G (see program) I~ATCH MIX Sliding Sleeve 11016' TIW 9 5/8" Packer 11056' 3 1/2" COMPLETION: 3 1/8" CIW Tree KOP: 1200' WELLI-~AD: McEvoy TAILPIPE SIZE: 3 1/2" ISrinix~g'E'~g~neer z) / ,/£~'~ COMPLETIONS ENG Lindsey Liner Hanger 11106' 9 5/8" Casing Shoe 11356' 12 1/4" Open Hole 11361' 7" 26g L-80 IJ4S Liner 7" Marker Joint 11480' 7" Liner Shoe 11892' 8 1/2" Hole TD 11892' APPROVED: ~pervisor APPROVED: .4~.,,f~ J D~li~g Superintendent Exhibit VI - 6c 13-3/8" CASING AND CEMENTING PROGRAM PROGRAM; W-17 (PBU/EWE~ 1. Install mud-line suspensiofi landing ting on 20" conductor ensuring it is level. Ensure mandrel ha~ger O.D. will pass through riser. Nipple up riser. , Drill 1%1/2" hole to 1"¢.00' TVD BKB. Kickoff and directonally drill 17-1/2" hole to 2700 ft. TVD BKB (approximately 2809' MD BKB) per directional map. 3. Circulate until hole is clean. POH to mn 13-3/8" casing. NOTES: a) Maintain mud temperature as low as possible (40-45 deg. F). b) Clean, visually inspect, and drift casing. c) Have HALLIBURTON perform thickening time tests on cement delivered to locatior~I using mix water which will be used for the job. TT = 4 hours @ 50 deg. F for tail slurry. d) Ensure 13-3/8" BUttress double pin pup joint is of correct length so that the casing head flange will be 18" above the top of the cellar. e) Notify Alaska Oil & Gas Commission (279-1433) 48 hours in advance to witness 13-3/8" BOPE test. 4. Run 13-3/8" 68# L-80 Butiress casing as follows: - Float shoe (landed,@ approximately 2680 ft.) - 1 joint 13-3/8" 68# L-80 Buttress casing - Float collar - 2739 ft. 13-3/8" 68# L-80 Buttress casing (approx. 72 jts.) - Mud-line suspension hanger assembly - 13-3/8" "Specially Cut" Buttress double pin pup joint - Landing joint CASING RUNNING AND CEMENTING NOTES: a) Place 13-3/8" centralizers 5 ft. and 20 ft. above the shoe and every joint for the next 9 ,Its. (11 total). b) Bakedok first three,.(3) connections. c) Fill casing as necessary. d) Have a 13-3/8" butlke, ss swage with a 2" valve and cementer connection available on the floor while running casing. e) Place two (2) 13-3/8" metal petal baskets inside conductor: one at 90 ft. BKB using stop rings above and below basket; and one on the first full joint below mud-line hanger to bottom out on casing collar (at approx. 65 ft. BKB) using a stop ting above basket. Exhibit VI - 6c 5. Land 13-3/8" casing shoe at approximately 2680 ft. MD BKB as follows: a) Install mud-line suspension hanger on last joint. b) Pick up 13-3/8" landing joint and wash down last joint if required. Tag 20" landing ring.i Slack off weight while monitoring conductor for settlement. If settlement occurs, set slips and slack off remaining weight. If conductor does not settle, slack off all remaining weight on the landing ring and set slips for safety. o , o , RU Halliburton cementers. Make up plug holding head (with top plug installed) onto landing joint. Install bottom plug, make up landing joint and test lines to 3000 psi. Break circulation. Pump 20 bbls. of water ahead of cement. Mix and pump cement as follows: 4128 cu.ft., (4438 sacks) PERMAFROST Weight: 15.0 ppg. Yield: 0.93 cu. ft/sack Water:! 3.5 gal./sack TI': 4.0 hours *Have Halliburton perform thickening time tests on cement delivered to location using mix water which will be used for the job. Release top plug. Displace cement to float collar at a rate of 8 to 10 bpm. Bump plug with 2000 psi. iD© NOT QVERDISPLA(~E plug by more than 1/2 the shoe volume (3 barrels). Provide details of cement returns on morning report and IADC report. WOC 4 hours to allow cement to develop sufficient strength to support the 13-3/8" casing. Remove the slips and slack off weight slowly and observe casing for settlement. If settlement occurs, pick up all weight and WOC an additional two (2) hours mad repeat slack off procedure. Nipple down riser and perform top job if necessary. Bakeflok and make up 13-3/8" 5000 psi split speed head so that tubing head annulus valves are oriented. 90 deg. to the right of the direction facing the reserve pit. Approximate torque = 14,500 ft-lbs. However, under no circumstances should the head be "backed-out" counter-clockwise to meet this orientation requirement. 11. Install and test BOP stack as per BOP manual. 12. Install long bowl protector, i Test 13-3/8" casing to 3000 psi. before drilling out float equipment. 13. Drill out shoe plus a minimum of 10 ft. new hole and perform formation integrity test. Drill 12,1/,'.:.'' hole per directional map. 14. Measure KB to ground level and KB to BF. Record measurements on tour sheet and telex. ' ' ,r Exhibit VI - 6c 13-3/8,' MATERIALS LIST AFE # 120749 QTY 1 1 75 11 2 5 1 2 pails 1 box 13-3/8" Buttress float shoe 13-3/8" Buttress float collar 13-3/8" 68# L-80 Buttress, R-3 (3 joints extra) 13-3/8" LO bow-type centralizers 13-3/8" Metal petal basket 13-3/8" Stop tings 13-3/8" 68# L-80 Buttress double pin pup joint McEVOY split speedhead system, 13-3/8" Buttress w/AB seal ring x 13-5/8" API 5000 psi. flange and 13-5/8" x 13-5/8I' tubing spool Howco Howco 86050070 86127408 Howco 86129493 N/Sbu~t McEvoy 86627900 McEVOY or FMC mud-line suspension McEvoy system 86627905 Bowl protector (long, made for McEvoy McEVOY split speedhead. Re-use 86627913 from previous well.) Thread dope -API modified 86139010 Bakedok 86139001 (10 x 1# cans) Exhibit VI - 6c 9-5/8" CASING .~.ND CEMENTING PROGRAM ,WELL W-17 (PBU/EWE) SUMMARY: A. Run 9-$/8" 47# L-80 Buttress casing from T.D. of 12-1/4" hole to approximately 4500 ft. TVD (4500 ft. MD). Make up 9-5/8" NSCC Box X Buttress pin XO and mn 9-5/8" 47# L-80 NSCC casing to surface. Land shoe within 5 ft. of bottom witE mandrel hanger. Bo Cement casing with Class G cement. Note: Have Halliburton nm thickening time tests on each load of cement delivered to the rig using water which will be used for the job. C. Install and test pack-offs. D. Test casing to 3000 psi. before drilling out shoe. PROGRAM: Drill 12-1/4" hole to the top. of the Sag River Sandstone formation and maintain control as per target map. The North Slope geologist will predict the top of the Sag River formation from rig site data. While drilling from 7000' to 12-1/4" T.D., the mud weight should be 10.0 ppg. Open hole logs will be mn as per saddleblanket. 2. Condition hole for casing. Pull wear bushing and install 9-5/8" rams. 3. Run 9-5/8" 47# L-80 casing (set shoe within 5 ft. of 12-1/4" T.D.) as follows: - Float shoe (side ports) Buttress - 3 joints of 47# L-80 Buttress casing - Float collar (Buttress) - 9-5/8" 47# L-80 Buttress casing from FC to 4500 ft. TVD BKB (5352 ft. MD BKB) ( approx. 155 its.) - XO - 9-5/8" 47# L.80 NSCC Box X Buttress Pin - 9-5/8" 47# NSCC casing from 5352 ft. MD BKB to surface ( approx. 140 its.) - Mandrel hanger - Landing Joint CASING RUNNING a) Bakerlok bottom 3 ~io~nts. b) Centralize bottom 10 joints with stand-off bands. Run turboclamps on every third joint fr~,m surface to 2700 ft. c) r Have circulating swage with valve and cementers hook-up available on floor while running casing. . d) Fill casing as neces:,:ary Circulate last joint to bottom a~.d land mandrel hanger in McEVOY wellhead. If mandrel hanger:ca.,..anot be mn, use emergency slips and pack- off. Exhibit VI - 6c o o . 10. RU Halliburton cementers. Install bottom plug in casing and top plug in head. Test all lines to 3000 psi. Pump 20 bbls of fresh water preflush ahead of the cement. ~ Mix and pump cement. Cement volume based on 90% annular volume to the 13-3/8" shoe + 50 cu.ft. Lead Slurry: 1890 cu.ft. ( 1000 sacks) Class G cement with 0.2% CFR-3 + 8% Bentonite + HR-7 as needed for 4.5 hour thickening time. Weight: 13.5 ppg. Yield: 1.89 cu.ft./sack Water: 10.2 gal./sack. TI': 4.5 hours* Tail Slurry: 575 cu.ft. (500 sacks) Class G cement with 0.2% CFR-3+ 1.% Bentonite + HR-7 as needed for 4 hour thickening time.. Weight: 15.8 ppg.' Yield: 1.15 cu.ft./sack Water: 5.0 gal./sack TT: 4 hours* *Have Halliburton, ran thickening time tests on each load of cement delivered to the rig Using water which will be used for the job. Drop the top plug. Displace the cement with mud at 8 to 10 bbl./min. Do not over-displace by more than half of the volume from the float collar to the shoe (4.4 bbls.). Bump plug and pressure to 3000 psi. Drain the BOP stack and remove the landing joint. Flush pack-off area, install pack-off and energize as per wellhead manufacturers 9-5/8" mandrel hanger procedures. Test pack-off to 5000 psi. with annulus open. Install 5" rams. Test BOPE. Install short bowl protector. RIH with 8-1/2" bit and drill'cement to float collar. Test casing to 3000 psi. Clean out float collar, rem;lining cement, and float shoe. Condition mud at shoe and drill 8-1/2" hole maintaining directional control as per target map. Exhibit VI -- 6c 9-5/8" CASING & C. EMENTIN{~ MATERIALS LIS,T. :AFE# 120749 OTY 1 1 10 2 24 1 1 4 pails 143 158 9-5/8" Buttress float shoe 9-5/8" Buttress float collar 9-5/8" GEMOCO stand-off bands 9-5/8" WEATHERFORD stop rings 9-5/8" WEATHERFORD turboclamps 9-5/8" Top plug 9-5/8" Bottom plug, Thread dope -API modified 9-5/8" 47# L-80 NSCC casing R-3 (3 joints extra) 9-5/8" 47# L-80 Battress casing R-3 (3 joints extra) 9-5/8" NSCC Box X 9-5/8" Buttress pin XO joint 9-5/8" 47# Buttress pup joint (20 ft.) 9-5/8" 47# Buttress pup joint (10 ft.) 9-5/8" X 12" McEVOY mandrel hanger with pack-off for NSCC casing McEVOY short bowl protector (reuse) ~ Howco Howco 86127415 86129494 86126831 Howco Howco 86139010 86050240 86050233 86050242 86050236 86050238 McEvoy 86627928 McEvoy 86627914 Exhibit VI - 6c 7" ROTATING LINER AND CEMENTING PROGRAM WELL W-17 (PBU/EWE) SUMMARY: mo A 7" 26g L-80 liner is to be nm from the T.D. of the 8-1/2" hole to 250 ft. above the 9-5/8" casing shoe. Condition mud to a YP of 8 to 10 lbs./100 ft.2 prior to cementing liner. Bo The 7" liner will be cemented prior to being hung from a Lindsey Completion Systems hydnmlic set hanger. Note: Have Halliburton perform thickening time tests on the cement delivered to the rig using water which will be used for the job. C. If there are any doubts about the integrity of the 7" liner cement job, consult Anchorage office. PROGRAM: 1. Drill 8-1/2" hole to 11,892 ft. MD as per target map. 2. Run open hole logs on wi~eline from T.D. to 9-5/8" shoe as indicated on saddleblanket. Install 7" rmns and function test. 3. Rig up and mn 7" 26/I L-80 IJ4S liner on 5" drill pipe as follows: - 7" Buttress float shoe - 1 jt. 7" 29# L-80 Buttress liner - 7" Buttress float collar - 1 jt. 7" 29# L-80 Eurtress liner - XO jt. - 7" 26g L-80 IJ4S box X Buttress pin - 7" IJ4S landing collar (Lindsey) - 7" 26# L-80 IJ4S liner with marker joint at 11,480 ft. MD - Lindsey (IJ4S) liner hanger c/w tie back sleeve (pinned for 2300 psi setting pressure and 50,000 lb slack off to shear nmning tool) - 5" drill pipe (See drawing at end of program;) '. CASING RUNNING NO~,S: a) Ensure that 7" liner is cleaned and inspected prior to delivery to rig. b) Bakerlok bottom 5 joints. c) Centralize shoe and every fourth (4th) joint with 7" X 8-3/8" WEATHERFORD Metal Stand-off Bands. Centralize remaining joints with 7" X 8" GEMOCO Metal Stand-off Bands. Install a bumper ring above each cemralizer on IJ4S pipe. d) Have liner and drill p'.:'.pe swages on floor. Fill liner as necessary. e) Do not run liner on HWDP. Exhibit VI - 6c . 13. 14. 15. Drop DP wiper plug and s:axt displacing immediately after pumping cement. Continue to rotate and rec.,;procate liner while pumping and displacing cement. Displace cement with mud at a rate of 8 - 10 bpm. (turbulent flow) providing pressure does not exceed 1500 psi. Reduce displacement rate to 4 bpm. while picking up liner wiper plug. Resume 8 - 10 bpm. displacement rate. Watch torque closely. A torque increase may be noted when cement rounds the comer at the lit:er shoe. A 200 - 300 psi. pressure indication may be noted as drill pipe plug picks up liner wiper plug from mnning tool. Once the cement rounds the liner shoe and has been displaced half-way up to the 9-5/8" shoe, stop reciprocating but continue rotating. In the event that reciprocation is necessary for rotation, reciprocate with 10-15 ft. stroke as needed. Continue to rotate until 5 barrels before plug bumps. Slow pump rate to 4 BPM. Position liner. Bump plug and set hanger with 3000 psi. minimum. Check to see if floats are holding. 16. Slack off weight. Rotate to the right to release from hanger. POH. CEMENTING NOTES: If shear-out of the liner hanger is observed while nmning in the hole or while reciprocating, the releasing nut will be engaged. Stop rotating and continue reciprocating. b) If shear-out of the liner wiper plug is observed, measure displacement of liner at that point. c) Do not oVer-displace: by more than 1/2 shoe volume (2 bbls.). c) Measure displacement using pump stroke counter. 17. 18. 19. 20. 21. 22. After eight (8) hours mini~mtm WOC, pick up 8-1/2" bit w/o jets and 9-5/8" casing scraper positioned immediately above it and clean out to top of liner. Test to 3000 psi. after 12 hoars WOC. Install 3-1/2" rams. RIH with 6" bit w/o jets and 7" scraper and clean out to float collar. CBU 1-1/2 times at maximum rate with two pumps while reciprocating drill pipe. Pump 100 bbls. fresh water spacer followed by 1000 bbls. of 9.2 ppg. NaC1 brine. The NaC1 brine mus! be filtered through a 2 micron filter unit and contain less than 100 mg/li, tertotal solids. Displace well at maximum rate with two pumps. Reciproca'~:e drill pipe continually during displacement. Circulate until clean NaC1 appears at surface. Reverse circulate for one complete circulation for additional cleanup. Retest liner to 3000 psi. POH. Rig up and run CET/CBT/GR in 7" liner. Perforate and complete well according to perforating and completion programs to follow. OTY 1 1 1 1 2 21 23 6 20 i cont. 1 1 26 '(" Exhibit VI -- 6c 7" LINER M,~.'FERIAL REOUIREMENTS d~FE# 120749 7" Float shoe 7" Float collar 7" Landing collar 7" 26//U4S box X Buttress pin · XO joint for landing collar 7" 29//L-80 But~.ress casing, R-3 7" 26//L-80 IJ4S liner (Cond. "D") (3 joints extra) 7" Lindsey hydraulic hanger c/w tieback sleeve 7" Bumper rings (2 extra) 7" WEATHERFORD metal stand-off bands 7" X 8-3/8't (2 extra) 7" GEMOCO metal stand-off bands 7" X 8"(2 extra) (25#) API 5A2 modified thread dope 7" 26# L-80 TC4S marker joint (20 ft.) 6" Bit, API 2-1-1~ Seal rings VO~AB Howco Howco Lindsey 86050400 86050375 86121055/50 Lindsey 86129495 86127417 86127416 86139010 86121418 Vendor 86121838 i" E,,h!b~t V! 8c DRY CRUDE DDWNSOUEEZE PROCEDURE After injecting waste fluids in 1~-3/8" x 9-5/8" annulus, proceed with cement/dry crude downsqueeze procedure as follows. 1. Notify GC-1 at least four (41~ hours before vacuum truck arrives to pick up crude. At the same time, notify GC-3 that excess fluid will be sent at the end of the job. GC-1 will pro'~:ide the vacuum truck driver with a report of dry crude water content. 2. When vacuum truck an'ives at site, purge track from lower most valve into an available mud pit. Rig foreman must witness this step. Pick up water content report from driver. Dry crude must contain less than 5% water. 3. Hook cement line to side of wellhead on 9-5/8" X 13-3/8" annulus. Test lines to 3000 psi. 4. Mix and pump 300 sacks of either Permafrost C or Arctic Set I cement at a minimum of 8 bpm. TI' to exceed 2-1/2 hours. Do not exceed 3000 psi. Cement slurry properties are given below. 5. Pump 125 bbls. of 6.4 ppg.~ dry crude at 4 bpm. Do not exceed 3000 psi. Strap dry crude tank before and after pumping crude to insure all is pumped. 6. Shut in 9-5/8" X 13-3/8" annulus. 7. Pick uP purge water from step 2 with vacuum truck and return to GC-3 with Environmental Report from Tool Service. NOTES: a) Do not exceed 3000'l~si. surface pressure at any time during this procedure. b) Do not allow annulus to flow back at any time during this procedure. c) Record dry crude tank volume before and after job. Note on Morning Drilling Report. Note water content of dry crude on Morning Drilling Report. d) e) Cement slurry properties are: Halliburton Dowell B.J. Titan Permafrost.C.. Arctic Set COLD SETI Weight: 15.6 ppg.. 15.7 ppg. 15.3 ppg Yield: 0.95 cu.ft./sack 0.93 cu.ft./sack .94 cu ft./sack Water: 3.75 gal./sack 3.59 gal./sack 3.89 gal./sack TI': (@50 deg F) 3 hours 3 hours 3 hours Exhibit VI - 6c o 6. 7. 8. 10. 11. 12. Stop running liner when bottom is 250 ft. above 9-5/8" shoe. Reciprocate and rotate liner inside the casing. Measure the torque while rotating, both running in (downstroke) and pulling out (upstroke). Add liner connection make-up torque (8000 ft-lbs) to these values to establish separate maximum torques for upstroke and downstroke. Set torque limiter to maximum upstroke cementing torque. Make up cementing manifold and plug dropping head on single. Run liner into open hole until shoe is 15 - 20 ft. off bottom. RU Halliburton cementers. Break circulation while coming down on last single. Circulate and reciprocate string with 30 ft, stroke. Note pick-up weight and ming-in weight. Take care not to slack off more than 30,000 lb. while reciprocating in to avoid shearing pin in liner hanger. While reciprocating, slowl~ begin rotating liner. Bring speed up to 10 rpm. Watch torque closely while running in. If the downstroke torque exceeds the . maximum values determined in step 4, stop rotating but continue reciprocating. Continue to rotate and reciprocate. Circulate and condition mud for a minimum of two (2) hours at 8 to 10 bpm (pressure not to exceed 1500 psi).The YP of the mud should not exceed 8 to 10 lbs./100 ft.2. Test cementing lines to 3500 psi. Continue to rotate and reciprocate. Pump preflush consisting of 48 bbls MUDFLUSH + 35 bbls DUAL SPACER @ 10.5 ppg.. Continue to rotate and reciprocate. Batch mix and pump cement. Ensure that the mix water is at least 70-80 deg. F. Calculate slurry volume based on 50% excess over the annular open hole volume plus 150 cu.ft, for the liner lap and shoe volumes. Slurry: 251 cu.ft. (213 sacks) Class G cement with 0.5% HALAD 344 + 0.2% CFR-3 + LWL as needed for thickening time. Weight: 15.6 ppg. Yield: 1.18 cu.ft./sack Water: 5.2 gaL/sack TT: 4.5 hoars* *Perform thickening time tests simulating one (1) hour surface mixing and 3-1/2 hours pump time. Exhibit VI - 6c 7" 26~ I.I4S LINER SHOE - RUNNING ORDER IJ4S LINER LANDING COLLAR (IJ4S box x IJ4S pin) JOINT #3 7" 29# L-80 (IJ4S Box x Butt. pin) \ / = - - JOINT #2 29# L-80 (Butt. box x Butt. pin) FLOAT COLLAR 290 L-80 (Butt. box x Butt. pin) JOINT #1 29# L-80 (Butt. box x Butt. pin) FLOAT SHOE (Butt. box) NOTE: Joint #1 will be drifted and made up to float shoe and collar prior to defivery to site. Joint #3 will be s.[milarly supplied made up to landing collar. Exhibit VI-7:K241112 Well Integrity Report Original Completion Date:- Schrader Bluff Penetration Hole Diameter: Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 7/2/1970 12-1/4" 9-5/8" Plugged and Abandoned on 6/9/76 None Comments: The initial 9-5/8" primary cement job consisted of 500 sacks of cement which was to seal of the Sag/Ivishak formations. During the abandonment of this well 37 sacks of cement was squeezed at 9600' md and 50 sacks was squeezed at 9300' md. The 9-5/8" by 16" annulus has cement from 2100ft md to surface. It is unknown if there is cement in the 16" by 20" annulus. Additional Information: Exhibit VI-7a Well Diagram Exhibit VI-7b Directional Survey Exhibit VI-7c Significant Workover & Drilling Daily Reports Exhibit VI-7a: K241112 Circ. 104 sacks cmt. Squeezed 50 sacks Squeezed 37 sacks 500' Cement plugs to Surface I 2100' I 2503' [] 2750' 9300' 11,473' 13749' 9 5/8" by 16" annulus cemented to surface with' 1200 sacks cmt.circulated through perfs at 2100' 20" Csg 760' -Cement Retainer 2058' ,Cement Retainer 2400' i 13 3/8"x 16" Csg. 2454' ~Cement Retainer 2700' Cement Retainer 9243' Cement Retainer 9414' Bridge Plug 11,412' 9 5/8" 43.5# RS-95- 12 aA" Hole 11,713' Bridge Plug 13,400' Bridge Plug 13,539' 7" 29# N-80 - 8.25" Hole -'-'~'~ OiL CORPOR^I'iON KUPARU'" f~ ALASKA SPERRY-'-SUN WELL SURVEYING COMPANY SU~-3-16608 N 9 TRUE 23 JUNE 1970 RADIUS OF MEA$~ DEPTH 100 '200 300 400 500 600 700 800 900 t000 1!00 1.2.00 1300 1400 t500 1600 !700 ~800 !900 2000 '2100 2200 2300 2400 2.4.85 25O0 2'/O0 CURVATURP TRUE VERT SUB SEA ' ' DRIF~ DEPTH DEPTH ANGLE 100~00 200,,00 300~00 399~99 499:.99 599~99 699099 799 ~., 99 899.99 999.99 1099~99 !199~99 1299.99 1399~99 1499~9g !599~98 1799~98 %899~97 %999~97 2~99~97 2299~,97 2399~97 2699 ~ 97 Z., ~ 9 96 2699~96 0 15~ 0 15~ O. 30~ 0 20~ 0 30~ 0 10~ 0 10~ 0 10~ 0 !0~ 0 0 5~ · 0 15~ 0 15~ 0 25~ 0 25~ 0 25~ 0 25~ 0 . 15:~ 0 15~ 0 5~ 0 5~ 0 5~ 0 15' 0 15~ 0 25' 0 45 ~ 0 '4.5~ 0 'DRIFT DIREC 68 E 0 E 35 E 4.7 E .56 E 85 E 84 ~:~ 48 ~' 47 E 1 ! ' W 5 W 2.5 E 72 W 7..5 ;,! 1 E 5 W '~4 W 27 E 3O E 47 W 66 W 5 t W ~ 4 W 87 W 79 W 45 W 56 "; 6 E 06 O~ 2~. 2~ 2~ 2~ 2~ 2~ 2~ 2~ 3~ COORDINATES 08. S 0,~20 'E 42 S 0~4.3 E 0¢ S 0~63 E · 58 S l~lO E 04-i $ !,:,67 [.". .,, S 2,:.21 '" · .- :: 26 S 2 .~. '..;, 0 1.7 S 2 o '/'/ /'% (% 97 S 2~- :.",? ,-- 91. S 3~02 [". 91 S 2¢97 E 62 F, '' 3eh2 26 S 3 ,~, '::' 6 24 $ '5~,2e' 78 S 2~F..:8 E 5!:S 2 ~,..g~ . 19: $ 2~(.,1 E '14 S ' 2~,58 E :1.2,S 2,:, 79 ~9: ,Sc 2.~75 E , 4? $ .... 2~t':.,3E 55 S 2~50 E 6° S ......-~ ~, SOF. 75' "' ~ 37: F · 2) o:. ¢.; .. 7% $ Ir. 17 E ~9 S ' 0o03 ,.v $ 0c. 5-':--, W := CO?,iPUT£D ~3Y '"'"' .... " ,._ ,,.:~,~',,r T r-: C H DOG LEG SE~'FtO,.":,. SEVERITY O i .S T/"~'"' '"c 0 0 2 C'.,., 0o2e, Gl r. ~.,. 0 ,': 17 0 e 2; 3 0 ',. 0:3 0:, !/:- 0 ~-- '-"3 (? 0 ...'-'..::7 0o!6 O~ ~",~ 0,<~ 5'3 .. 0 ~, ,?. ! "0.26 0~0! O~J. 7 0~02 0~02 0 ~ 2Y 0~01 0 ,:, 2 ! 6 c, O 4, 1 :. '.".~ ITl ~.., 2~I 2o57 2078 2 ~,7/+ 2~23 lo80 I ,:, ! 7 .'!DiUS OF CURVATURE TRUE VERT SUB 5~'A,,. DR!'FT 2800 2'799 ~,9! 2900 2899~72 3000 2999~3:4 3].00 3098~69 _3200 3197~48 3300 3295~09 3400 3391~33 3500 3486~56 3600 3581~!1 3700 36'74~62 .3800 3766 ~67~ 3900 3857~29 4.000 41 O0 4033 4200 4!~8~2.! 4300 420i 4400 4282 4500 4361 4700 45 4900 4651 5000 4714~3g 5100 4'/76 ~ 30 5200 4838,90 5300 ~899~2 5400 4956~41 5500 5014~83 5600 5074.31 5700 5!29~86 5800 5182~%'0 5900 5230~96 6000 5276~75 6100 5921~95 6200 5967~35 6~00' 541t~97 6400 54 54 6500 5494~90 2 45''¢ 4 15~ 5 4.5.~ - 7 15~ - 10 30~ "14 30 ~ 17 0~ · !8 30~ 19. 30~ 22 0~ 24, 0~ 26 0~ 28 0~ 31 0~ 33 0~ 34 30 ~ 36 45~ 38 45~ 43 15 (- 46 !5 ~ 49 15~ ~2 !5~ 51 1~~ D4 15~ 56 15~ ~2 15~ 54 45~ 57 45' '59 15~ 62 15~ 63 15~ 63 0~ 63 0~ 64 0~ 65 45~ 66 30~ ~-., ~ F ~1" DiREC t, EC TAN'eULAF.,' COORD!NATFS 4o38 $ 1 e 4,.,- 2,~55 $ 7,:23 2~,12 }'4 14057 8~69 N 23o79 16o52 l') 37o07 .28 ~, 60 N 54.~ 98 z:.5 ~ 58 67~37 N 97~60 89~57 N 121~61 1t3~30 N 147o72 139~69 't~ 176~53 168~24 N 207~59 . , ~32~,'/8 N 2 76 ~ -~.u 269~26 N 315~33 ~/,6o_12 N .,~99~.25- . 38b~68 ... ~ ~-, z,.o~ 39 519o17 568~21 N 652~00 6!9~2 N 709~99 667~83 f~4 7'/1 e 83 ?i0~30 75i~89 t'l 905009 79i~08 852~88 N 1126~42 879o26 N 1205o25 902~76 N 1287¢21 .926¢07 N 137I~27 949~83 '¢'~ 145~94'- 972~91' N 154~!0 9e5,~¢,v ¢,~ *~29~6 ~ 043~32 ~'' 84 ,~ IP02o . 1065o44 '6 ~. 06 1 o 4 .;'3 2o27 7~2.3 ~ o 96 14 ~ 57 1~'65 23,~ 78 3 ¢ 42 3'/~ 07 5,~ 3;3 54. o 2~,67 75¢30 le 50 9'7 1.~05 12l 2 ,~ 5.3 1 t:. 7 2 ,:: 04 ! 76 2 o 05 207 2 ,:, O0 24 0 25 e 00 2 '? 6 -- 2 ~, 0 '? 3 ! :% I ). ~ 89 355 cr o ~, i fl 4. 4:. 5 2 ~. f;'."~ 493 2 ~, D 0 54 3 3 *:. 09 59'5 o 56 3~ 09 652~,00 2';010 709 e. ¢"?,, 6 o 27 771~, 82 io56 8 3 7 o ,.'..~. z:.~ 65 977~2 , 5o05 !05I~3:3 3~00 1 !26~43- 3~95 !205 ¢25 2~29 1287~20 3¢13' t371~27 1 o 34 1456~93 · 0o2".5 154,3~,09 :). t, .~,-,,. 1 715 c, :~9 2~rl3 }, '"0" 0~7'5 !891o57 R/~DIUS OF CURVATURE biEAS~. TRUE VERT SUB SEA ~:.~ TH DEPTH DEPTH 6600 6700 6800 6900 7000 7100 '?2 O0 7300 7400 7500 7600 7700 7800 7900 8000 8100 8;:00 8300 8400 8500 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 9500 · %, ,! 9800 9900 0000 k.-' ]. '.','-., 02 O0 !.0q00 5:~o4~58 5466~78 5574~65 5506*85 5614~93 5654~60 5586680 5694~ 68 5626o 88 5734~95 5667~ !5 ' 5774~82 . 5707~02 5814~ 10 5746~ 30 5854 ~,77 5786~ 97 5[¢97o23 5829~43 5939~49 5871e69 5982~74 F914~94 6077 ~ 55 5o5° .... · ~ 75 6073 ¢ 9*¢. 6006~ ~.. 2 612!o6~ 605~,83 61r. o . 621$~2! 6!50~,41 6265~74 ~ 63.97~,94 6312 6557 ~ 89 640~ ~92 6446~B~ 6492~33 6q~8~89 6584~87 663,0~85 6677~03 6~22~62 6?66¢85 6809~?0 6851~96 6894~62 69D8~¢6 6~ 4?' ?028c87 70 75 ~ OA 7~22~18 7~70~:66 6244 ~ 69 6290t. 09 6334o12 6378~55 6424~53 64-7!~09 6517~07 6563~05 6609~23 6654~82 6699~. 0'5 6741 · 90 6784~16 6826~82 6870~66 6~ 5 67 . g~. 696! ~07 7007'~24 7054 ~ 3 r~ 7102~86 DRIFT AM~_i ~ DRIFT DIREC N 76 E N 77 E N 77 E N · 78 E N 79 E R 79 E N 79 E N 79 E N 83 N 84 E N t% N .05 E · t;o N 88 E N 90 F:: $ 89 E $ o 0 E ,,- S 90 E S 89 E S 9O E · S 89 S 89 S 8,9 'E S 87 S 86 E S 85 S 85 S 84 E S 6,'.', E S ,~,:~ E S Oz.,. E S 84 E COORDINAT~g~.... · r: - c: 7 [; I2vo~-..,. N -~r, r,~ _ -./'"~- o E 1295~.z:--~ N >u/:,~0., 1294~.6~ N 37(.,2087 ~294o63 N 3852~46 E 1293~08 N 4029~79 E .~292~3~ N A~.~!8o5t,.. 1290.76 N 420'i~34 E !288~t;.,.5 N 4296~01 E 128a~55 N h. 3~'' ~" ... o'.-~'72 E 1279~0~ .N 4474~44 E 127!~, N 4564o51 E - 1264.~09 N 46P4~80 [:, !254 6h- N t~.7Az~Tz+ 3 2440 .... o ~ ,- z2~0!3 N 4o22e8~. E 1225004' N 5011038 E 12~r,~an N ~0,S;.9~.50 1205~02 N 5187o~3 E 1195¢I~ ~ 5270~0,, .- DOG SEVER 0 o · Oo '20 Oc- 0 e ie Oo 25 1980063 !8 2069c SrO 2 .t. 58 c. 9C', 95 2245,-.' e 5" ~ F; 2338~°.c, 50 2''~ '" 00 75 2008 ~' 07 26( 90 2 8 ', m x 2 ¢, 29( *'2 o 7 32 ~ I 25 3 '32 'f9 3" ~.? i_ 9 ;3 3 'i 6 _.. 52 394 ! ~ 25 02 z;. 029 92 4 ! ). f', .... 2 5 4 2 0 7 c 3 3 f; J 4296 ~ 00 3 4 L../,, 7 t::, r, ,., - ! 7 45 f/4 c. 50 O0 465,4079 . ~, '~ 1. 0 ~ l, ,'~ :~ ',:' c, .,' .. C, 0 i; 5 rj [;- 922 ~ L't/:. 89 90 ! 1 s 37 73 5274 ¢ 02 M~AS ~ DE'PI'H !0400 10500 10600 1070O 10800 10900 !tO00 1!~00 1].200 11300 11400 · 11500 11600 1!?00 11900 !20OO 12100 122O0 123n~ !°400 12500 12600 12700 12800 12900 13100 1.3200 't~300 !3400 13~33. 13474 13500 ~ O0 ~ ,. 13655 CURVATURE TRUE VERT 'D E P T 1.4. 7221~60 7274~03 7326~28 7378¢35 7431.34. 74-.q5~80 7r ~, 7599~61 7657~!5 7713~25 7768~26 7822036 7875~72 7929~63 7982~8t 8054 ~ 87 808~o78 8 ! 44 ~ 34 8201,~1& 8259¢93 831~06 8379,42 8440~12 8499~60 8557~14 86!3~60 8669~70 - 872~34 878B~34 '8~97~34 8916~!5 8939e29 8953~8~ ' 9017~22 -, r, 01 . . SUB S [:A DEPTH 7153~80 7206~23 7258~48 7310~55 7369~54 7418~00 7474~t0 7531~81 7589~35 764.5~45 7700o46 7754~56 7807~92 786].~83 7915~01 7967~07 8020.98 80'~' 5~ 8~9!¢78. 825I~26 83!!~62 8272o32 $4B1~80 8489.~4 8545~80 860~90 8658~54 87~5~54 8829,54 884~5 887%~49 8886¢0B ~ - 894~¢2B 8949~42 897.!~2~ DRIF~ ANGLE 58 58 58 .57 .54 55 57 57 58 59 58 54 53 53 52 52 54 55 55 5~ 55 55 55 55 55 55 5n -57 57 30~ 15' 45! 30~ 30~ 30~ t 5 .~ - 30~ 15~ 0~ 30~ 0~ 45" 0~ 30¢ O~ 45 '~ ~5~ . 15~ 30" 45~ 45~ 0" 0~ 0~ 45I 0~ 0~ S S S S S S S S $ S S S S S S $ S S .$ .S S S S S S S' S S S S $ S 5 S S $ S O-. DR ! FT . RnC 82 83 81 '82 82 82 8,2 81 80 79 80 ?9 80 ?9 8O 80 78 7'7 76 ?0 66 62 58 52 .'..;2 E E E E E F... E E E E Lo E E E E E E ,,.. E 1!86~ 1175~ !i64~ 1!52~ 11400 1!28~ !!!7.~ 1105~ 1093~ !064~ 1049~ 100~ 955~ 94!~ 929~ 905~ 889e 868~ 843 ~ 816~ 787~ 757~ 72~ 689~ 647~ · 587~ 567~ 497~ 4.77~ 79 N 6656on0. 6z.- N '767 75 - 87:~N 6928~45 4~ N 7006~ 86 N 70~',' 45 62 N ?!6!~02 78 N 7237~47 48i'N 7~14-~ 58' N 7391 24.~ N 04~ N 7544~75 89 N 7689083 07 N 7780~45 AA~ 2~N ?825082 70 N 7892=0F 95 N 7902075 3! ~,~ 7'92q~ . .. .... :- E £ E E E E 1 ¢ '/5 0,:, 99 1¢,72 J. ~, 50 2 ~ 4.0 0 ,: ,.S (.. Oo r.':' 2 ~z:.6 !o5! 2053 1 ~, f..5 .... --:- o (',~ [,/:./'" c. ]. ~ 5 ,.':, 2. '_4 ~, 2.8 r"O° 57 r"'0-.; ~ r, F., ;..~:, 9 - "' .5 9 ~' ' '"' £, 2. 05 o-. ,: f, ,:;; m ;.. ~,-, 65 ~,.:;,'. d..C, I '.',3 ' '( 0 70 ? ,1. ,,.., .; ~; ~... ~. ? ?; 91, 74 O g ;~ ,2: C: 7-5" ~'. 7 ,":, ! k::., C'.' 7758 ~ 23 778004-4 '' t', f' .", '~ ' [ (.; '-.} c:, 0 ;. b 7 8 .?. 9 ¢ f.:'. :? '7 o .,.'~ .p ,q ,~., 7 ,.. 0 4 ~ 7" ' { SUBMIT IN D1JPI.I~i ~ .~ibit VI- 7c I . (Se6 ,er ,~ 8tructto.n~ Or~ ~ OIL AND GAS CONSERVATION CO!.A;'i~ITT£E ~e,.~ i ' WELL COMPLETION OR R[COM~L[TION R[PORT AND LOG * la. TY~ O~ W~LL: On. ~ uas ~ . . . ~b. TYP~ OF COMPLE~ON: , BACK ~f. SVR. Other 2. N&Mg OF OprR&TOP- , : '.MOBIL OIL OORPOKATION 3. ADDRES3 OP OPERATOR ~ !P.O.POUCH 7-003, ANCHOPAgE, AK 99501 ~ " '- LOCATION OF W£LL (Report location clearly and in accordance with any State requirements)* xt~u~a~ 1700' FSL and 600~ F~Sec.23,TllN~R12E,U.~. . · t to~ ~,oa. ~t,.~ ,~vo~t~ bao~ 2282' FSL and 3 07' F~, : At tdtal dep~ Sec. 24, TllN,R12E. ~ At 13,655'M.D. 2177' FSL and 3249' F~, Sec. 24,.TllN, R12E 5. APl NL~~','J:.!~C--kI, CODE 50-029 6. L.F.-k.$.E D'.>_._~I,f;:~.\'i'U~N ADL 47451 ~[ IF I.N'D,t.4~N', 2d_J.,O-l~rEE 8. UNIT,F>-~.k,[ OR L~AS'~' NAk.iE 'Kuparuk State g. W~_.LL NO. Kuparuk 24-11-12 ~0. rm~ .,,~a) ~oo,., o.~. :V~UDC>.T ?rudhoe Bay Sadleroch 11. SEC., r., R., Ot~ECTIVE) Sec. 24,TllN, R12E .. 12. P~C.ilT ~O. 70-22 ~2. LI-~T OF /TTACII.M£NT8 JOIL GRAViTY-APl (CO~ 'Well History) = - 33.1 hereby certify t~mt the foregoing and attached information Is comple-t~ and correct' a~N/.~ermined 'f~°tn all-'~'~l~ble"record~ /2 >/ 2;--U , '"' SIGNED/: ' Z -'~ ~<:',L,-C. TITL~ Division Oper. Engineer DATB -- -- ......,, t ::- - --~ ~--~ ~_ .. ~ r:_ ~. - ~ - -~ -~-~:: ~._ ~ : *(See Instructions and Spaces [or Additional Data on R~verse Side) , 31. DlSPOSZTION Or (n~s (3old, ~,ed for.fuel, ~¢~tted, etc.) · ~ ~DATEF~$TPR~DU~T~P~DUCT~NME.~D(F~wh~ga$~p~mp~-~z~andtyp~p~In~ ] VqELL STATUS (ProduciM or 'Short Term Drill Stem Tests ' . . =~'~ended '13,544'-'13,590' (4 holes/fl)"' , . . i'13,510'-13,530' (2 holes/ft)'- '" i13,444'-13,466' (2 holes/fl).. ..." '13,638'-13,641' (4 holes/ft)'. ' "': C'.'" .' ""' ' , D~.i II~TEP. VAL (biD) J ASiO%.'N'r ;u\~D I-lIND O,F NtATZ2JAL USED 13,670' ] 75sx Class G 13,61.0..' ..... t 75sx Class G , i ............. j .I .. ': 13, 7~9'. (9095') ~z~ 13,705(906~)/ ~ow ~m~- Surface~°~ ,oo~Sto T.D. c~, ,oo~s .'. ' ,. SURVEY' ~IADE ' ~Top Permo-Triassic 13,433 M.D. (8928 T.V.D.) :' ~' YES , . 24. ~E E~CT~C ~ND OTH~ ~OGS RUN 'D~, S0N~C, ~PC, S~~ C~n~E~ -- C~U A~ SA~ K~Y. ~~0N ' ' CASP~G RECO~ (Re~rt all ~rlngs sat in walD - .30" ' I'~:~>' t~.e. :8'- - i 3a', 1~0~ ~o~a~ ......... .j .... - 'l .... I I-:'o,' - - -_ j ..... 16"k132~/8'' .... ' J'109~6~!~ 'J K-55 "~24-9~' ' ~"50~X' Pond~cFlyash J ...... '28. PE~O~TIONS OPE. N TO PKODU~20~ (in:e~al, size and number) 20. ACID, S?!OT, F~k~'L~E, CE?,IE~'T SQUEEZE, ~C, Date' 1970 3/1-4/1 4/1-4/5 4/5-4/8 4/12-4/14 4!14 5/21 Exhibit VI- 7c MOBIL OIL CORPOP~iTION HISTORY OF OIL OR GAS ~LL OPERATOR: MOBIL OIL CORPOP&TI6N ~LL NO.: 'KUPARUK STkTE #24-11 12 FIELD' NORTH SLOPE SEC, 24 TllN R12E U,M, .. Well History of Kupa.ruk g~24-11-12. " This well was drilled using Parker Rig f~96, positioned 1700' FSL and 600' FWL, Sec. 23, TllN, R12E, U..M.~ under Permit No. 70-22. All depths refer to K.Bo 21.1 above gravel pad. (67.80' above sea level) · . . · .. _Rigging Up and Setting 30" Conductor PiPe. Moved rig and rigged up. S~t 58' mf 30" comd,Jctor pipe in 36" hole and cemented with 190 sacks Fondu'e cement~ ' · . ~Spud; drilling 17-'1/2" to 760' and Reaming to 24". Spudded 17-1/2" hole a.t'll:45pm 4-1-70 Drilled hole to 7'60' Opened 17-1/2" hole to 24" to 760'. Mud: 9.3#/gal., risc. 245 sec. · Running 20" O.D. Casing to 759' .Ran 18its.. 20" O.D. 94# H-40 csg.. w/guide shoq duplex float collar, and sub sea. hanger. Could not break circulation with 700 psi. 20" csg. pumped out of hole, elevators opened and casing fell fown hole. Recovered 17 jt's 20" csg. Recovered bottom jt of 20"' csg. by screwing into Duplex collar with drill pipe. Conditioned hole and ~e-ran 20" csg. Ran 18 its. 94~/ft., I{-40, 20" O.D. csg. to 750'. Cemented through Duplex Float. Colla~ with 600 sacks 50:50 ~iment Fondue-Flyash w/3% ·salt. Cement in place at ll:30pm 4-7-70. DrilIing 17-1/2" Hole to 2530'. Installed 20" Hydril and tested to"1000 psi--OK.· Drilled out firm cement between Float Collar and Shoe. Drilled 17-1/2" h61e from 750' to 2530'. Mud: 9.4#/gal.--200 sec.--14cc. Surveyed well every 200-300'. Mud: 9.4#/gal.--165 sec.~-13.6cc, AtteMp_~in__g to. Lo~ .and Running 16" x 1'3-3/8" O..D. Ca.s.in~. Schlumberger's attempt to log was unsuccessful. Log stopped at 1840'. }~d: 9.3#/gal.--150 sec.--13cc.' Ran 45 its. of 13-3/8" O.D. 61#/ K-55 Buttress(1742.16) and 18 jts. 16" O.D. 109# K-55 Buttress (746.73). Hanger-496'; Shoe a~ 2496' Float Collar-2454. Cemented with 1350 sx 50:50 Ciment Fondu-Flyash ~/3% saIt. Displaced 16" x 20" annulus W/45 bbls. diesel oil. · Drilling 12-1/4" Hole to ll,Y00'. · Waited on BOP Flange. Installed BOP and tested to 2000 psi. · Drilled Float Collar and Float Shoe and Drilled 12-1/4" h61e to 2600'. Ran Sperry Sun gyroscopic survey. Ran Dynadrill 2600'/2985'. Reaming to 2977 when drilling string reveYsed. Backed off drill pipe at 2655', Recovered all of fish. .. History of Oil or Gas Well Page 2 .. Exhibit V~- 7¢ ~o~aruk State fJ24-11-12 . .. 4/14-5/21 Drilled 12-~/4" hole to 3161', Ran Dynadri%l 3161'/3272'. Drilled··to .Cont. 5013' with stiff hook-up. Ran Dynadrill 5013'/5115' '-' Drilled 5115'/5377' with stiff hook-up. .Ran Dynadri{1 5377'/5423'. .. Dri]led with Dynadrill 5423'/5483' Drilled 5483'/5661" with drilling · , . assembly, Ran Dynadrill 5661' ./5763'. Drilled to 7306'. Ran Dynadrill 7306'/ 7449'. Drilled to 8866'. Ran Sperry Sun gyrosc'opic survey through drill · pipe· Stopped at 6300', Dri'll&d 12-1/4" hole to 11,700'. . ':." . 5/.21-5/28 Running 9-5/8" O.D. C~s~n'g to 11,?00'. Ran 180 /ts· 9-5/8" 43o5-¢~ RS-95 LT&C casing, (To~al ·length of 7497.88), Ran 47 /ts' 925/8'' 47f~ RS-95 LT&C (Totals1889.20). Ran csg. to 9387'. Picked up TIW liner hanger, Could not engage, threads. Layed hanger down .. · and continued to run 56 /ts. 9-5/8" 43.5~r~ RS~95 LT&c Total 2323.22 on top" ". .st'r~n~. ' Landed casing with shoe a.t. 11,695' float a.t 11,609' Total csg ran was 236 /ts.. 43.5~"and 47 ftSo 47~ (11,713.60'). Could not break .----. . ..ci.rc-u.!at~:.~. with 30d.o psi-.. "AttcmPt~-te- ~ircu!?c~ta"with Dowa'll a.t 4~0'0 p's'i:; lqipp'led up BOP's, tested to 2000 psi and drilled out float coil'ar with · . "'8'-1/2" bit, Could not circulate· Drilled out shoe at 11,695, cleaned out, and established circulation. Ran retainer and set at 11,600', Cemented 9-5/8" casing with 500'sx Class "G" with 2% D.-8 and 18% salt· Ran Sperry Sun. .. . Stopped at 11,120'. .. ' ; -' · . 5'/29-6/12 .Driilin~ 8-1/2" Hole 13~749' TD. ' '. Iqippled up BOP and tested at 2000 psi, Drilled retainer at 11,600' · and firm'cement to 11,695', Drilled 8-1/2" hole 11,695'/12,385'. Drilling · string stuck in 8-1/2" hole, Established circulation, spotted pipe lax and jarred string free, Cleaned out and conditioned hole, Drilling string " .st6ck while conditioning hole. Worked and jarred pipe ,free. Increa. sed .·. mud wt. and viscosity. Drilled ahead to ].3,749' TD, No hole trouble encountered · 'between 12,385'/13,749'. Mud: 10..8~r~ -,70 s~c,--3cc~ . . . .: -: ............ '. ..... ~ .... ?.,~-=..:.., ..... ': . --. '.. ." .' ".~"i'-.',.' .'~ :.:.-.: ,- .. '~:.-.-'-c~. '.. '~":'~i.' ".-.""T';~"~:.":77'I''~'''7'''-''-:'7''','''''-.'-'~?,';':7'77:':' '"-;'7-'-' ...... !"'. ' -' 6/1'3_~5/.2~;' ..' .-'- .'~., !i~!~bg~)i'~de~~!~~:i~'~!'i~~~;C~i~:igg' ~ ~' · '..-'' ', 5..,"-.. '-'.' ':" : 'i~'-~! '"-idt -"':"I~2'''' "'""": ':'"'' '":'::' ''Ii' '~.i'"'t:., "-.....-' .., . '-S,~h'~.~mB.'g~er :also r~.~' sonic'.", FD.C;" SN~,..'~nd 'Caliper"." .":-71'.':'..'?~ :;...'.'../..;"'. ""'.: "l?. "i '..' ." ,'"." Sc~hlumb~.rge'~r Stuci'~. ~:{a~'a:%l '~o.~-e g'(~{{ w.l/i'.ijl'e'io~.~"a.i'~..iti'.g"b'a'.~pl%'~.,:"""i"~".;!".:'' ':" : Str'ipped"bver line i~d recovered ffsh'. Ran 56'jt's',.'7".O..D:,'29~f, N-80, seal~ . ., . l'ock'.c~g.. '.(To. tal: 2257') with .7" x 9-5/8" 'Brown >iI .'T0.0.1...hanger..18'.23' w/hy'd.raulic ' · · ~ 'set Slips ~ota.1 length of' 7" liner a.~d ha.nge~' 2276'-;"7" shoe"at ·'13,749; ~.gP" ' .df/liner l'l,'473','.Dropped ball, could not get ·ball intoTseat' to'.se..t..slips, '- · · Ran' RTTS pkr. tb '11.;474', coUld not' ge.t into. 1.'.l.ner.: ,'.Ri~:E-Z :drill retaina~ , at ~i~0~..'Cemented. with 188 sx'Class "G" ~/6~'Gel a~d 18% sal't, ~followed ' w/200 Sx Class "G" w/18% salt. Drilled ~etainir and"cleanea out 7" liner to float collar. Schlumberger.rNn CBL, and GR-N logs.' Re-ran· GR-N.. Ran Sperry" ' Sun gryoscopic survey. .Displa:ced..mud from 925/8''. x .16" ·annulus ,w/265 bbls'. · , . . . - . · . :....,,..~ ; . ' . . , dies&l.. -. '" ~ · ' '" - - ' ' -. - ... = . ' Wait ~n Orders. ~ " .. .' ,2' ' History of Oil or Page 3 Exhibit VI- 7c Kut..,'uk State ~'~24-1i-i2 7/2-7/6 Perforating and Squeezing a.t 13'~670' and 13~610'. Schlumberger perforated 4-1/2" holes 13,670', ran Howco E-Z drill retainer.. Dowell squeezed 75 sx Cia. ss "G" neat. Schlumberger perforated 4-1/2" holes at 13,610'. Ran HowcO E-Z drill on D.Po Dowell squeezed with 75 sx Class "G" neat. Drilled E-Z drill a.t 13,546' and cleaned out 13,630". Drilled EZZ drill a.t 13,633' and cement to 13,67~." Schlumberger ran CBL.. 7/8-7/9 7/9-7/10 ~erforating and Running DST#1 13~544' - 13,590'. Ran a.nd set E-Z Drill on wire line at 13,600'o .'.'- Perforated with 2 holes/ft. 13,544 -13,590. Ran Halliburton DST tools and set pkr. 13,495'. Opened tool for 5 min. initial flow period with good blow. Closed.for 57 min. initial shut-in'.pressure. Reopened for 185 min second flow perio~ with good blow. Recovered 600' of oil ~/ " ......... 'IHP=4825psi, .IF~=l19psi,..FFP=92psi, ISIP=4349psi, IFP~3.4'%psi,..'F~'R~5.~pai~ ........ .FSIP=4244psi, FHP=4737psi. Recorder at 13,504'. · · Perforating and Running D'ST#2 13~51~ - 13~530'. .. Ran. and set E-Z Drill a.t 13,537'. Perforated with 2 holes/ft. 13,510 - 13,530'. Ran Halliburton DST. tools and set pkn at 13,465'. Opened tool for 5 min. initial flow period. Closed tool for 65 min. initial shut in period. Opened for 120 min. second flow period and Closed for 180 min. final shut-in period. 7/11~7/12 7/13 No recovery reported ' IHP=4914psi, IFP=80psi, FFP=51psi, ISIP=88p~i,IFP-34psi, FFP=27psi, FSIP=124psi, FHP=4914psi. Recorder at"13,479'. Perforating. and Running.DST~3 13~444' - 13,466'. Ran and set E-Z drill bridge plug a.t 13,480'. Perforated with 2 holes/ft. 13,444" - 13,466'. Ran Halliburton DST tools and set pkr.. at 13~400'. Opened tool for 5 min. initial flow period. Closed for 49 min. initial pressure. , Reopened tool for 133 min. second flow period. Recovered"~" of oil. IHP-4715psi, IFP=58psi, FFP=49psi, ISIP=3530psi, IFP=ll2psi, FFP=97psi, FSIP=3000psi, FHP=4727psi, Recorder at 13,416'. Capping. Wello " Set E-Z Drill bridge plug at 13,400 and capped with 15 sx Class "G". Dowell spotted 28 sx Cia. ss "G" at 3000'. Top of cement a.t 2922'. Displaced mud in 9-5/8" csg. w/diesel oil from 2922' to surface. 7/14-7/23 Standing By. Rig released - 2:00pm 7-23-70 . 7/23~8/17 .S,t.anding. B___Z.- ,. ,Stood by without crews. Rigged up again. History of Oil or Gas .Page 4 Exhibit VI- 7c KuParuk State #24-11-12 8/18-8/22 ~icking Up Drill Pipe and Running in Hole. Picked up 5" D.P. Installed B.O.P, and tested to 2000psi. Displaced diese'l from 9-5/8" csg. x~/mu~. Drilled out bridge plug at 3000", Drilled out retainer and cement at 13,400' 13 537' and 13,600' Ran bit to 13,698' , , , , · Perforating and Running DST#4. Perforated 4 holes/ft, at 13,638' to 13,641'. Ran Halliburton test tools and set pkr. at 13,617' ' Opened for initial flow pdriod at 10:35a~ for 10 min. Began 30 min. initial shut-in period at-10:~5a.m. Began final flow period at ll:15am· Shut tool.in at 5-18pm. Tool open 6 hrs. 3 min. Gas to surface a.t ll:38a.m· Flowed gas at 190psi on 1/2" choke. ~urfa.ce pressure decreased to 10.psi at 4:05pm. Mud to surface 4:50pm. Oil to surface 5:10pm. 99.8% oil 0.2%b.s. Gravity 24,3 a.t 60°F. IHP=4729psi IFP=555psi ISIP=4352psi FFP~2244psi FSIP=4385psi 8/25-8/26 Ca:pping Well. Set Howco 7" E-Z Drill bridge plug at 13,539' Set E-Z Drill.Bridge plug at 13,400' and capped w/50' cement. .Spotted 35 sx cement a.t 3000'. Rigged down and released rig at 10:00am - 8-26-70. ', JJB:bf 10-14~70 !~"Exhibit VI- 7c { KUPARUK STATE 24-11-12' ABANDOMMENT OPERATIONS May 5, 1980: Checked wellhead for pressure. Removed tree and tubing adapter ~lange. Cemented 10 cu.ft. (20' plug) to surface. Installed marker post extending approximately four feet. Top of marker' post sealed and the following information bead-welded on: SOHIO P.B.U. KUPARUKSTATE 24-11-12 1700' NSL, 600' EWL, Sec. 23, TllN, R1ZE, UPM -All.~ssible .fib%ings.~-ere removc~.ar~ all openings welded ~U~,... Location cleaned. STATE OF OIL/<NO GAS CONSER ( Exhibit VI - 7c SUNDRY NOTICES AND REPORTS ON WELLS ' (J)L, n~)t u'.c this form fo* prop'~$3l$ tO drill or to U.=ep~n %;°E LL L._J %'IELL OTHER ~ NA,.,~_ o~~o~i1 Corporation ~. ADOR ESS_OF OpF,..l:j,j~fqi:l u. ox b~.~q, Denver, Colorado 80217 il. LOCATION O~ ~VFLL Ats"r~00' FSL and 600' Sec. 23-TllN-R12E, F WL, U.Mo, Alaska 13. ELEVATIONS (S,~ow whett~er DF, RT, GR, etc.) 68' K.B. Check Appropriate Box To Indicate Nature of Notice, Re! 7. IF iI~IDIAN. ALLOTTEE OR '[[IILI;:- NAfvlE WELL no_ ~ '-"<, Kuoa~ 2~ -11-12 '" tO.~ F I E ~WILi)C.q 'i' Prudhoe Bay SadlerochJ. t 11. SEC.. T.. IL. M.. {BOTTOM HOLE. OBJEC'TIVE} Sec. 24-TllN-R12E,. U.[4~ ,.Al~sk. 12. PERMIT NO. · 70-22 '- - --'-4-~- I., ,~ort, Or Other Data . I ~OTiCE-OF-~.~IT£t,.~T IOFI TO: SUBSEQUENT REPORT OF: '' TEST WATER 5HUT-OFF'j~~ PULL or ALTER CASING ~ATER SHUT[OFFI~ ' REPAIRING V/ELL " FRACTURE TREAT MULT. IPLE COMPLETE FRACTURE TREATMENT ALTERING CASING . SHOOT OR AClDIZE ABANDON* ' ' SHOOTI~GOR AClDIZIN~.~ · ABANDONMENT' REPAIR ~'IELL CHANge PLANS ' _ . JOiner) (NOTE: Report re~;{~ of mtlltlp~e comp:erie, o. W~II Completion or R~ompJetio.'~epo~ and Log DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, Including estimated dele of Start'in9 any propose{! work. . .. Notice .of intention to abandon this 'well was sub~itted on April 5~ 1976. However, while 'working on this well the annulus 16"' x 20~ flowed slightly since 9-5/8" casing was' perforated at 2750' and the flow Stopped prior to cementahion of 9-5/8" x 16" annulus, The flow from 16" x' 20" annulus was possibly due to heat. gaine~ from hot mud circul'a{ed inSide 9-5/8" casing, To make sure that the flow from this annulus, was not from.any other source~ we like 'co monitor the well' for some. time and so the wellhead is not remove~." ,. P. K. Paul discussed this .change. of p~an with Mr. Lonnie C. Smith. "'. on June 9, 1976 at l':0'0..p.mo (Den~er time)' on 'the telephone and " obtained a verbal approval~ The subsequent report of suJpen'sion of 'the' well is a5tac~ed. · · · , 2G. I b~.reby certify that the forJ~golng is true and correct ///// ,,'.- · I' ~" ' '~'" Area Engineer T IT LE OAT E June 14r.'i976 _ -- (This ,.p,~cl, for State office use) APPROVED BY ' 'I CONr)lTIONS OF APPROVAL, IF ANY: T I'f I.E .... See ins{ructions, On Rever~e Side .. · OA'T E Exhibit VI- 7c REPORT OF SUSPENSION KUPARUK STA'fE 24-1].-12 .. 5-26-76 to 5-28-76: 5-29-76 to 6-2-76: 6-27-76 to 6-3-76: ,, 6-3-76 to 6-5-76: 6-5-76 .to 6-6-7.6: Noted casi.Bg pressure of 2,10 psi and .9-5/8" × 16" annulus pressure of 205 psi. Bled casing pressure to 0 psi and recovered 9 gallons of diesel. 9-5/8" x 16" annulus pressure dropped to 185 psi. B.Ied annulus to 0 psi and recovered 3 gallons of diesel. Rem. oved blind flange and installed OCT spool with test plug. Blind 'flange had pressure built. up to 50 psi in 12 hours'. Skid rig from Kuparuk 22-11-12 drilling well to Kuparuk '2~,-1].-12, a .dis%.ance of 150'. ~ ~- ~-~ ~-'~ . ....... '~ ,.-~=, ~,~=~. up. Test.ed..BOP . and choke manifO!d'"to-50O0 psi; and annular. 'preventer to 2000 psi. Ran 8%" bit to 1650' and noted obstruction. Washed and reamed 250' and circulated out" gummy ~.qix of oil and mud. P, an' further t'o 2200' and circulated out diesel. Tested 9-5/8" casing to 1000 psi for 15 min.- OK. Ran .further to top of cement plug at 2875' and drilled hard cemen'c plug from 2875' to 2975'. Ran furtherr breaking circulation every ].5'00' to top of liner at 11,478' Circulated out 10.2 ppg mud with 10.6 ppg mud°. Pulled out of hole~ Ran 6" bit, '65' joints' of ~" o..j drill 'pipe a~';d 9-5/8'' .casing s'craper on 4½" drill pipe to 12,840' and noted obstruction. Washed. out' to. EZ drill bridge plug at 13,411' (could not find good hard cement cap expected to be at 13,350'). Circulated out 9.5 ppg mud, 300 sec/qt, viscositY. Weighted up mud to 10.6 ppg %,Tith 600 sx barite. Spotted'" cement plug in 7" liner at 13,411' with 18 sx c].ass G and .003% ~.~R7. Pulled 3 s~ands and reversed out.. pulled out of hole. Schlumberger ran 9-.5/8'~ EZ drill .cement. retainer and set at 11,412' (Schl. tagged 7" liner top. at 11,461' - 17' ].ess than DP measurement). Ran 4Ii" drill pipe and stabbed' into cement retainer'. Pressure..~ to test liner lap to 2000 psi for 30 rains..- OK. Spotked 45 sx Class G cement plug on top of EZ dril! plug (noted DP measurement 1.].,422' for EZ dr'ill.) , Tagged 'top of plug at ].i,342'. Pulled out,.of hole · . Report o f Suspens~-'~'I'''~' Kuparuk 24-11-12 - contd. -2- Exhibit( -7c 6-6-76: 6-7-76: .6-7-76: 6-7-76: ., Schlumberger perforatec! 9-5/8" casing at 9600' and 9300', with 4 shots at each. depth, Schlumberger ran 9-5/8" F..Z drill cement retainer to 9410' (EZ Drill stopped at this depth) and set. Ran 4½" drill pipe, stabbed into cement retainer and attempted to establish circulation. Could not break circulation · up to 2600 psi pressure. Formation broke at" · 2600.psi and could pump. at 5,4 BPM at 2300 psi. Squeezed perforatiens at 9600t with 87 sx class G cement with 23~r~ HR7, ' ." ~umped in at 2400 psi and final squeeze pressure was 3400 psi, 50 s× of cement was. squeezed into formation leaving 37 s× inside casing. No circula~i.on while cemen.~in.~., Pullect o~t of hole' " Ran 9-5/8'" EZ drill, cement retainer on drill pipe and set at 9243.t. Broke down. perforations at 9300' at 2800 psi. and pumped in at 4,.5 BPM at 2500 psi. Cemented with 91 sx c].ass G -- 50 sx of cement was placed into formation' ' leaving 41 sx 'inside casing, Spotted. class G cement on top of EZ drill plug~ Tagged firm solid plug' at Schlumberger perforated. 9-5/8" .casing ak 2750' with 4 shots, Opened. 9-5/8"× 16" and 16" x 20" annUlio Diese'l oil' flowed to' Surface from both annu].i~. Pumped diesel ' ' out of 9-5/8" x 16" annulUs and recovered ' . 195 bbls "of'to,tent stinking 9,.3 ppg.mu.d, Recovered from 16:' x 20" annu]ous appro×imately 3. bbls diesel' .. '": '.' . . ' ., Ran 9-5/8'~ EZ drill cement re%diner on dri'il. Pips' and se% at' 2700',. cemented outside 9-5/8" ~asing through perforations ~'t 2750' .with 104 sx Permafrost cement (left 23 sx .:. inside .casing} 9-5/8" × 16" and .16"× 20" annuli were ope. n {vhile cementing, Had good '.return to surface through 9-5/8" ); 16" annulus and 1/2" stream of diesel, on 16"x20" annulus o "-' .o Report of Suspension Kuparuk. 24-11-12 - contdo -3- Exhii i /I- 7c 6-7-76: ' 6-8-76: 6-8-76: 6-8-76:-. 6-8~76: · · · 6-9-76 to 6-12-76· P.K Paul 6/li/76 . , , ~ , ;~......,~,,.-,..,-. :.,.. ·-~ :'!;.;,.-., ·/.., . .: ';~ ... ~'~ .., · . ' ;~..,,~.~',..,, '~. ,, ;.: ".: .... '., :,;.~;...:.', ' ~ ':~.."5 · ...... :. ?..~.~ .. . · - -' ' ,';.'.5 ~..,:~',,,~' '. ~ ~ ..-~.;,; -? ..: '. '?'-:'2.'-,: .. :.., · .' , :.?..'.... · ..:.':~ :'7~;.¢:';" Ri~ged down from 1 a,.m. on 6/9~76 Schlumberger perforated interval 2503.' - 2504' (3' correction on ]~B due. to ri~ .. changes) with 4 spf using 4" HYper jet gun, Pressured up.on 9-5/8" casing through fill -'' up line with blind rams closed to 380 psi. "...'. Required 3 c'u. fh, to fill casing, Pressure .... dropped in 5 mino. to .300"_ = ~ 15 min to '29.0~.' !~.,. 30 min. to 260~, 45 mi'n to .235~ 3 hr~ 30 min.' to 160~' and 9 hrs o 30 min. to 90~, No 'flow.· ~-.: to surface through 9-5/8" x 16" annulus and' '".... slight flo%,~ from 16" >: 20" annulus (3 to .gallons per.hour)..-Again Pressured up to 480 psi with .2 cu.' ft. mud. Pressure dropped iD !0 min. to '~0~ and 30 min.-.to-2~0~, No return %0 surface.through 9-5/8" x 16"' .- .annulus and 16" x 20" annulus flowing steady stream of. diesel at 3 gallons per hour'' Ran 9-5/8" ~.. drill cement' retaine'r.'and s'et 2400'. Capped. with 42 s× class G cement with 3.% .CaC12. Tagged cement cap a'k 2325'.. · Schlumberger perfora~ed 9-5/8" casing at 2100" with 4 shots. Pressured up keeping 9-5/8': x 16" and ].6" x 20" an'nuli open- circulated with less than 100 psi pressure, Flow was. through 9-5/8" x ]-6" annulus and 16" x 20" · annulus had no flow. .. " ,, ., , Set 9-5/8." ~Z drill cement retainer at 2058~ and cemented 9-5/8" ~.," 16" annulus with t200 sx '.Permafrost, circulated out 25% e~cess, .... 16" x 20" annulus was kept closed dering ., -' cementation o ': · ...:':-..!.. Placed 6e~.ent' Plugs'of 50'~' lengths from '2058' to surface with 850 sx Permafrost, .. . · Nippled down BOP. C~osed valves in the wellhead, Exhibit VI-8:S-03 Well Integrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 3/1/82 12-1/4" 9-5/8" Flowing on Gas Lift None Comments: The 9-5/8" annulus was pressure tested at 3000 psi for 15 minutes and held, on 2/11/82. On 2/13/82 the 9-5/8" x 13-3/8" was downsqueezed with 280 CF cement, plus Arctic Pac, and tested to 3000 psi. Additional Information: Exhibit VI-8a Exhibit VI-8b Exhibit VI-8c Well Diagram Directional Survey Significant Drilling Daily Reports Exhibit VI - 8a TREE: 4"CIW I I WFI LHEAD = FMCS 03SAFETY NOTES ACTUATOR = AXELSON KB. ELEV = 67.10' Max An~lle = 57 @ 6100' i ~ 1997' 3-1/2" OTIS DBE SSSV LANDING NIP, ID = 2.75" Datum MD = 12010' Datum TVD = 8800' SS ,I ~;~ i ~~9-5/8" DV PKR 113-3/8"CSG, 72#,L-80,1D=12.347" ~--~ 2694' I-~~ GAS LIFT MANBRES S'--'~ IVD i %/U ~ TY'~'- V--'~'ILATCH1 PORT DATE' Minimum ID 1.937" '='~ 10248" 7 3039 2915 28 CAMCO RK / ALPHA TBG PATCH II m~ 68594 5211 53 CAMCO RK 5 8558 6405 52 CAMCO RK , I I ITOPOFT" LNR H 7302'6789' ~----- ,__ ,1~ 49316310008739469054548 .CAMCOcAMCO RKRK ~9-5/8"CSG, 47#,L-~0,~D=8.681"H ~ ~' 2 10e32 7796' 49 CAMCO RK 1 111328135 45 CAMCO RK ~ ~-'--~ 11237' HB°TsBRTBGsEALAssYj I 3.1/2. TBG, 9.3#, L_80, 0.0087 bpf, iD = 2.99Z, H 11257. J.~ ~.~ ~ "-~ 11257' H7" BOT FKR' ID = 3'813" I ~ ~ ~1 113a7' [--t2-7/8" ~OT-SOST~G TALC, ~D= 2.441"I H · I I-I I I PERFORATION SUIVIVlARY REF LOG: SWS BHCS 02/22/82 SWS 6BL 02/27/82 ANGLEATTOP PERF.' 39 @ 11855" Note: Refer to Production DB for historical perf data [-~ SIZE SPF INTERVAL Opn/Sqz BATE 2-1/8" 4 11855-11909 O 03/14/89 I =: -------[ 12209' HTEL"NGERI I DATE REV BY COMIVENTS DATE REV BY COIVlVlB',ITS PRUDHOEBAY UNIT 03/01182 ORIGINAL COIVPLErlON WELL: S-03 07/25/92 IVBW LAST WORK OV ER PERIVlT No: 81-1900 03/07/01 SIS-MH CONVERTED TO CANVAS , APl No: 50-029-20695-00 03/12/01 SIS-MD RNAL i i Sec. 35, T12N, T12E 09/21101 RN/KAK CORRECTIONS '1 i BP Exploration (Alaska) SIZE SPF INTERVAL Opn/Sqz BATE 2-1/8" 4 11855-11909 O 03/14/89 2-1/8" 8 12042-12122 O 07/22/90 DATE REV BY COMIVENTS DATE REV BY COIVIVIBqTS 03/01182 ORIGINAL COIVPLErlON 07/25/92 IVBW LAST WORK OVER 03/07/01 SIS-MH CONVERTED TO CANVAS 03/12/01 SIS-MD RNAL 09/21/01 RN/KAK CORRECTIONS . Well S-03 Directional Survel~ Well: iS..~0_..3... ...................................................... Exhibit VI - 8b APZ/UW:[: 500292069500 Survey Type: GYRO Company: Gyrodata Survey Date: 09/09/89 Survey Top: 0' MD Survey Btm: 13,133' MD MD 0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700' 1,800 1,900 2,000 2,100 2,200 2,300 2,400 2,500 2,600 2,700 2,800 2,900 3,000 3,100 3,200 3,300 3,400 3,500 3,600 3,700 3,800 3,900 .4,000 4,100 4,200 4,300 4,400 4,500 4,600 4,700 4,800 4,900 TVD 0.00 100.00 200.00 300.00 399.99 499.99 599.99 699.99 799.99 899.99 999.99 1.099.99 1.199.98 1.299.98 1 ~399.98 1.499.93 1.599.67 1.698.90 1.797.74 1.896.52 1.995.27 2.093.66 2,191.46 2.288.76 2.385.62 2.481.91 2.577.64 2.672.95 2.767.36 2.859.91 2.950.12 3.037.65 3.122.38 3.204.45 3.283.58 3,359.53 3,432.63 3,503.30 3,571.56 3,637.92 3,703.27 3,767.87 3,831.95 3,896.05 3,960.87 4,026.25 4,091.85 4,157.76 4,223.58 4,288.62 SS 67.10 -32.90 -132.90 -232.90 -332.89 -432.89 -532.89 -632.89 -732.89 -832.89 -932.89 -1,032.89 -1.132.88 -1.232.88 -1.332.88 -1.432.83 -1.532.57 -1.631.80 -1.730.64 -1.829.42 -1.928.17 -2.026.56 -2.124.36 -2 ~221.66 -2.318.52 -2,414.81 -2,510.54 -2,605.85 -2,700.26 -2,792.81 -2,883.02 -2,970.55 -3,055.28 -3,137.35 -3,216..48 -3,292.43 -3,365.53 -3,436.20 -3,504.46 -3,570.82 -3,636.17 -3,700.77 -3,764.85 -3,828.95 -3,893.77 -3,959.15 -4,024.75 -4,090.66 -4,156.48 -4,221.52 INCLINE 0.00 0.27 0.42 0.43 0.42 0.32 0.27 0.18 0.18 0.22 0.20 0.23 0.23 0.13 0.93 2.50 5.78 8.37 9.12 8.80 9.33 11.23 12.85 13.83 14.95 16.37 17.25 17.97 20.52 23.93 27.17 30.65 33.48 36.20 39.18 41.97 44.08 45.97 47.93 48.92 49.48 50.03 50.27 50.00 49.18 49.17 48.83 48.72 48.95 49.92 AZI'MUTH 0.00 126.53 157.43 155.08 153.22 144.03 126.32 112.21 106.41 97.79 95.54 95.99 84.01 84.01 298.28 318.38 345.79 340.39 333.42 325.01 323.57 323.18 322.31 319.29 318.05 317.25 314.97 313.09 310.33 312.01 312.27 310.93 311.41 310.84 310.26 311.50 . 311.37 311.72 311.82 311.64 312.68 312.27 311.46 311.45 312.62 312.42 312.57 311.18 310.12 311.97 DOGLEG 0.0 0.0 0.2 0.0 0.0 0.1 0.1 0.1 0.0 0.1 0.0 0.0 0.1 0.1 1.0 1.7 3.7 2.7 1.3 1.4 0.6 1.9 1.6 1.2 1.2 1.4 1.1 0.9 2.7 3.5 3.2 3.5 2.8 2.7 3.0 2.9 2.1 1.9 2.0 1.0 1.0 0.6 0.7 0.3 1.2 0.2 0.4 1.1 0.8 1.7 ASP_X 619,139.1 619,139.3 619,139.6 619,140.0 619,140.2 619,140.6 619,141.0 619,141.2 619,141.6 619,142.0 619,142.3 619,142.7 619,143.1 619,143.5 619,142.8 619,140.6 619.137.8 619.133.9 619.127.8 619.119.5 619.110.2 619.099.3 619.086.5 619.071.5 619.054.9 619.036.3 619.015.9 618.993.8 618.968.8 618.940.1 618.907.6 618.870.9 618.830.5 618,786.8 618,739.7 618,689.9 618,638.0 618,584.4 618,529.1 618,472.4 618,415.6 618,358.5 618,300.4 618,242.1 618,184.8 618,128.2 618,071.8 618,015.0 617,957.1 617,899.0 ASP._Y 5,979,855.2 5,979,855.3 5,979,854.5 5,979,853.8 5,979,853.4 5,979,852.7 5,979,852.4 5,979,852.4 5,979,852.0 5,979,852.0 5,979,852.0 5,979,852.0 5,979,852.0 5,979,852.0 5,979,852.4 5,979,854.5 5,979,860.7 5,979,872.4 5,979,886.2 5,979,899.6 5,979,912.3 5,979,926.4 5,979,942.6 5,979,960.3 5,979,978.7 5,979,998.6 5,980,019.1 5,980,039.6 5,980,061.2 5,980,085.6 5,980,114.0 5,980,145.3 5,980,179.8 5,980,216.8 5,980,255.6 5,980,297.3 5,980,341.8 5,980,387.8 5,980,435.7 5,980,484.5 5,980,534.5 5,980,585.2 5,980,635.6 5,980,685.2 5,980,735.5 5,980,785.5 5,980,835.9 5,980,885.1 5,980,933.3 5,980,982.1 5,000 5/lOO 5,200 5,300 5,4O0 5,500 5,600 5,700 5,800 5,900 6 000 6,100 6,200 6,300 6,400 6,500 6,600 6,700 6,800 6,900 7,000 7,100 7,200 7,300 7,400 7,500 7,600 7,700 7,800 7,850 7,875 7,900 8,000 8,100 8,200 8,300 8,400 8,5OO 8,6OO 8,700 8,800 8,900 9,000 9,100 9,200 9,300 9,400 9,500 9,550 9,575 9,600 9,700 9,800 9,900 10,000 10,100 10,200 10,300 10,400 10,500 10,600 10,700 10,800 10,900 11,000 11,100 11,200 11,300 11,400 11,500 4,352.61 4,416.14 4,479.49 4,542.22 4,604.19 4,664.82 4,722.95 4,779.24 4,835.11 4,890.71 4,945.80 5,000.59 5,056.16 5,112.90 5,170.32 5,228.86 5,288.49 5,349.01 5,410.61 5,473.53 5,536.89 5,599.75 5,662.11 5,723.73 5,784.61 5,845.00 5,904.55 5,963.54 6,022.15 6,051.52 6,066.46 6,081.59 6,142.78 6,203.69 6,263.85 6,323.47 6,382.79 6,442.63 6,503.80 6,566.55 6,630.63 6,695.53 6,761.53 6,828.72 6,896.79 6,965.87 7,036.07 7,107.42 7,143.43 7,161.53 7,179.70 7,251.94 7,323.11 7,393.09 7,461.75 7,528.91 7,594.60 7,658.88 7,722.11 7,785.38 7,849.32 7,914.17 7,979.90 8,047.09 8,116.12 8,186.31 8,257.45 8,329.53 8,402.43 8,476.40 -4,285.51 -4,349.04 -4,412.39 -4,475.12 -4,537.09 -4,597.72 -4,655.85 -4,712.14 -4,768.01 -4,823.61 -4,878.70 -4,933.49 -4,989.06 -5,045.80 -5,103.22 -5,161.76 -5,221.39 -5,281.91 -5,343.51 -5,406.43 -5,469.79 -5,532.65 -5,595.01 -5,656.63 -5,717.51 -5,777.90 -5,837.45 -5,896.44 -5,955.05 -5,984.42 -5,999..36 -6,014.49 -6,075.68 -6,136.59 -6,196.75 -6,256.37 -6,315.69 -6,375.53 -6,436.70 -6,499.45 -6,563.53 -6,628.43 -6,694.43 -6,761.62 -6,829.69 -6,898.77 -6,968.97 -7,040.32 -7,076.33 -7,094.43 -7,112.60 -7,184.84 -7,256.01 -7,325.99 -7,394.65 -7,461.81 -7,527.50 -7,591.78 -7,655.01 -7,718.28 -7,782.22 -7,847.07 -7,912.80 -7,979.99 -8,049.02 -8,119.21 -8,190.35 -8,262.43 -8,335.33 -8,409.30 50.50 (" 62 ~ .,.77 51.52 51.90 53.45 55.47 56.03 56.03 56.42 56.72 56.85 55.63 55.23 54.68. 53.67 53.13 52.38 51.57 50.45 50.92 51.18 51.67 52.25 52.75 52.95 53.95 53.75 54.48 53.58 53.07 52.43 52.13 52.83 53.20 53.60 53.63 52.87 51.70 50.57 49.72 49.35 48.05 47.53 46.68 45.92 44.92 44.03 43.83 43.42 43.33 44.17 45.08 46.10 47.18 48.45 49.42 50.57 51.00 50.50 50.00 49.15 48.65 46.92 45.77 45.07 44.23 43.53 42.88 41.70 .... 310.83 310.97 311.99 310.50 312.17 311.80 310.75 313.45 312.76 313.65 311.14 313.59 312.57 311.59 312.39 309.95 312.10 310.60 310.82 309,94 308,63 309.84 309.39 307.99 308.26 308.25 308,51 308.28 307.95 309,23 312.16 314.07 317.41 316.46 318,57 318.62 319.33 319.47 319.86 318.79 318.96 319.67 317.27 317,88 318.42 317.50 318.95 317.80 317.85 320.07 321.25 319.14 320.60 319.96 321.72 323.21 323.82 322.56 323.84 324.00 323.38 323.81 323.93 323.17 323,60 323.47 323.77 324.71 323.55 324.35 1.1 617,840.6 0.2 617,7~" · 3 Exhibit VI - 8b 5 5 2.3 0.6 0.8 2.1 2.1 1.5 0.9 0.9 2.2 1.8 1.4 0.8 1.3 1.0 0.6 1.3 0.5 0.2 1.0 0.3 0.8 2.7 9.6 6.6 2.7 1.0 1.7 0.4 0.6 0.8 1.2 1.4 0.9 0.7 2.2 0.7 0.9 1.0 1.4 1.2 0.4 6.3 3.3 1.7 1.4 1.1 1.7 1.7 1.1 1.5 1.1 0.5 0.7 0.9 0.5 1.8 1.2 0.7 0.9 1.0 1.0 1.3 0.1. / ,~t.~.!.. S 617,419.3 617,357.9 617,296.4 617,234.0 617,171.2 617,109.6 617,047.7 616,985.9 616,924.1 616,862.7 616,802.1 616,741.6 616,681.6 616,621.0 616,559.9 616,498.9 616,436.6 616,373.4 616,310.1 616,246.3 616,182.3 616,117.7 616,085.7 616,070.2 616,055.5 615,999.5 615,944.4 615,889.5 615,835.5 615,781.6 615,728.6 615,676.5 615,624.7 615,573.4 615,522.9 615,472.2 615,421.4 615,371.5 615,322.3 615,274.0 615,226.7 615,203.0 615,191.5 615,180.3 615,135.2 615,089.1 615,042.6 614,995.8 614,949.7 614,904.0 614,857.2 614,809.7 614,763.1 614,716.6 614 ~670.5 614~625.1 614.580.2 614.536.1 614 492.9 614.450.3 614.408.8 614.367.9 614,327.4 5,981,032.1 5,981,081.7 5,981,132.0 5,981,182.3 5,981,233.4 5,981,285.5 5,981,338.3 5,981,392.6 5,981,448.4 5,981,504.2 5,981,559.6 5,981,615.0 5,981,670.7 5,981,725.0 5,981,778.6 5,981,831.1 5,981,882.9 5,981,934.6 5,981,984.9 5,982,034.5 5,982,082.3 5,982,130.7 5,982,179.6 5,982,227.6 5,982,275.7 5,982,324.1 5,982,372.9 5,982,422.1 5,982,470.9 5,982,495.6 5,982,508.6 5,982,521.9 5,982,577.8 5,982,634.7 5,982,692.8 5,982,752.0 5,982,812.0 5,982,871.9 5,982,931~5 5,982,989.6 5,983,046.7 5,983,103.7 5,983,159.0 5,983,213.1 5,983,266.9 5,983,319.5 5,983,371.9 5,983,423.9 5,983,449.1 5,983,461.8 5,983,474.8 5,983,527.5 5,983,580.2 5,983,634.4 5,983,690.1 5,983,748.3 5,983,808.0 5,983,868.8 5,983,929.9 5,983,991.8 5,984,053.0 5,984,113.8 5,984,173.8 5,984,232.4 5,984,290.0 5,984,346.4 5,984,402.5 5,984,458.2 5,984,512.9 5,984,566.8 ll,bOO 11~oo 11,800 11,900 12,000 12,100 12,833 12,933 13,033 13,133 8,bbl.34 8,627.24 8,704.17 8,781.53 8,859.51 8,938.19 9,516.04 9,594.87 9,673.71 9,752.54 -~,4~4.24 -8,560.14 -8,637.07 -8,714.43 -8,792.41 -8,871.09 -9,448.94 -9,527.77 -9,606.61 -9,685.44 41.22 .- ..,.38 39.28 38.25 37.97 37.97 37.97 37.97 37.97 32b.1' 326.0! I~' w 326.9; Exhibit VI - 8b 330.1; BO.6 331.86 1.b b14,149.4 333.28 0.9 614,120.1 333.28 0.0 613,911.0 333.28 0.0 613,882.4 333.28 0.0 613,853.9 333.28 0.0 613,825.4 b,984,~20.0 5,984,673.3 5,984,725.8 5,984,779.4 5,984,833.9 5,984,888.0 5,985,287.5 5,985,342.3 5,985,396.8 5,985,451.2 Exhibit VI - 8c W~.T. S-3 Spudded well at 0900 hours, January 18, 1982. Installed diverter system. Drilled 17 1/2" vertical hole to 1404' then drilled directionally to 2695' , Ran open hole logs. Ran 70 jts. 13 3/8" 72~ L-80 Buttress casing to 2694'. ~ted with 3720 cu. ft. Arctics'et II cement. Installed and tested BOPE. Cleaned out to 2652', tested casing to 3000 psi, okay. Drilled out to 2730'. Ran leak-off test to 0.82 psi/ft., gradient. Directionally drilled 12 1/4" hole to 11840'. Ran open hole logs. Ran 191 jts. 9 5/8" 47~ L-80 Buttress casing to 7302'. Casing run stopped at 7302' (4300'+ above the program setting depth). Cemented with 862 cu. ft. Class G c~_nt. T~sted casing to 3000 psi, okay. Cleaned out float equipment and directionally drilled 8 1/2" hole to 11848'. Ran 129 Jts. 7" 269 L-80 IJ4S liner to 11840'. Cemented liner with 2300 cu.ft. Class G cement, Down squeezed 13 3/8" x 9 5/8" annulus with 280 c.~.ft.".~"~cti~set ~ ~-~=nt"f~0Wed ~ i20' ~' Arc%lc Pack. Pressurc te~+~ ' liner lap,. broke down at 1300 psi. Set EZ Drill at 6725'. Squeezed lap with 230 cu. ft. Class G cement. Cleaned out to 6789' and tested lap to 3000 psi, okay. Cleaned out to 11796' and pressure tested liner to 3000 psi, okay. Cleaned out float equipment and direct~onally, drilled 6" hole to 12860'. Ran open hole logs. Pan 52 Jts, 4 1/2"' 12.6~ L-80 A/B mod. Buttress liner to 12860'. Cemented with 360' cu,ft, Class G cement with 18% salt, Cleaned out cement to liner top at 11320' anQ pressure tested lap to 3000 psi, okay. Cleaned out to 12730' PBTD and tested liner to 3000 psi, okay. Changed well over to NaCl. Ran CBL. Ran 347 jts. 3 1/2" 9.39 L-80 EUE 8rd tubing to 11348'. !~nded tubing with ~all valve at 1987'. Installed and tested tree. Displaced tubing to diesel, set packer at 11237'. Tested tubing to 3500 psi, okay. - Released rig at 1600 hours, Marc5 1, 1982. · '::' :"':' '"'-" '";:"' '.-':; :' ". ' .-': "-';';:iV ~"rk ..... :,' L-Al IIUIL VI -- OL~ :..,V'..-'Y;C ::'.~.q ',";'.'.:';: ': :'~,';-'.% .~:: ::'"'.L',':;:.'L"'.'~'.-'-,',.."~:,'~7~.'~.~;.[:.',~.?':'-""~,:[ '".~.~':;;':)'.'-'.';::'....-.' :"." ~' -"¥"'"'~.': ,?'~ :'~""'~:.~ "!.'" .'".'~ ".L'"".'.' · 'L;' ..; :.' .......... ' '~;:I' :';.:.~LT..~3'- ,:': ! ..o ...'~ .~ ........ . :*o .. :.. ~ . .~.~-.'.f.} .:.?.oo ..:o;, v ... .-':~.:?'!i.?:::.i:;.'":" '( ,'..':.!7'%~'i.,-..;"" '''~' .-- .............. '.' ........ · :" ':'.,'/'"::."' '.~. .'.".':.."SOHIO/BP DALLY DRILLING ". , ... ,. ' .... '.'.",;',:..'..'.~..:,'eGse-Rot~$:. ...... ;,"; ~ ~ :" ' ' ' '"'"" .. . · . . ~ ' · - A B C "" D :E: ...F'' " '"' .. ~ -, ., . · I DATE ' WELl., RIG DAY NO DEPTH 2'ztHR FTC- WEATHER I- zz-~z, s 3 .- ~.~..g 4, ~s'" _._.~:. P- MEN BEDS FUEL WATER A/F/D 'BOP : SUPUR /4 MUD/WT ~JIS PV-YP GELS ' 5 PH SAND SOLIDS ,BT-HP .. I. TE~P F~! 'CA~E '. I' ~ . CHLOR RM,F 75/~' '.6 , , W£LL COST. ". . . DRLG ASSY l NTAN G , ·, TAN6 Ig~13o' TOTAL BIT NO ,SIZE M~EE 9 BIT NO TYPE .$R NO ' JETS · · . . Ri,~ VS X Li~a s z liT HRS ' W'E!GHT .. GOMDEP AN'G/~D I R '1~ SV NO TVD .. DEPOUT ., FTG GRADE E/WC0 DLS . . ~ : Wor~ ,./-m,a ~,~ ce',~'x,,T ,~'ru,"cx,,r,, .qi~'~.,p '30 , , 11 SUMMARY OF OPERATIONS ~. ;,~ , , ~ t OZe,~ - o 4~ -- A B : DAY NO DEPTH · · MEN BEDS FUEL WATER A/F/D CURRENT OPERATIONS · . I DATE WELL RIG 24HR FT'6. BOP t ' WEATHER I ;.. : S UPVR 4 MUD/WT ~ I S PV-YP GELS TEMP FL ~,AEE q.:C'. ' 39' ' ' 5 PH SAND SOLIDS HT-HP CHLOR RMF ?5"F" . . q T~ ~'. --' ~0 ~ · .-.' , . ,,~ ,,~, 6 WELL COST INTANG TANS ,. ,:,. TOTAL . .. 7 DRLG ASSY' BlT N0~ " ' . .. ~ BIT N0 .SIZE M~F~ :TYPE .ER N0 JSTS 'DEPOUT FTC '"4 ,':7~ ~rc ,.'os~-~x ~ ~' .,~.~.. . . . /'2-" ~, ' . .- " , .... ~ ..... ., '. 11 SUMMARY OF OPERATZONS · . , o'ao~- ,z,t,r' Z,~,, ,up ~o?~, , ~ .... 17a~- t .Iq3o- f zo4~- z/~ ~ t4 ~ - ~Z~"a~ ¢lg'd ~ ¢..a~1,4~'~ . ,. . %z~ zzl~' .. r)F/_tt..a./~$ '7"0 7-730. '~i', .. .ZrZlX' .'1 DATE WELL" MEN BEDS G D RIG DAY NO 70.0' 3 CURRENT OPERATIONS DEPTH A/F/D MUD/WT %/IS PV-YP GELS /0, .3 ¢- 37' ' / 7: q .3-~ PH SAN D $ 0 L ! DS HT.-H P q,$- o. l/ "" 0 . WELL COST. . .. .. DRLG A$$Y I NTANG " BIT NO, . ... · $!ZE M~EE , :TYPE .-, · ... · .. o. · ,.. .'. . ;5 BIT NO ', · · , -, 9. BXT., NO ~z~HR FTG , ~ BOP 2 -?-- ~ WEATHER S UP%/R IM SV NO :. TkMP 71 Ct-ILOR 5-o0 ,.. FL" C~KE ~/,z.,.' , ,'/ RMF TOTAL DEPOUT ,: FT6 · , . GRADE ,, E;'WC0 DL$ .' . .. , I 1 SUMMARY· OF .0P~'-RATIONS '/?,,;' .. ,- , A B Exhibit VI - 8c ' .":'.."... C D ~ F I DATE W£LL 3 CURRENT OPERATIONS 4 ~IUD/WT /o,o' 3;' ' 5 PH SAND 6 WELL COST -, DEPTH 24HR FTC', ~Ll~4~ ,."',9- .' A/F/D BOP " .~ "; Z'-12-....~-,_. 7 DRLG ASSY WATER PV-YP GELS TEMP /~-? ~-~ -- SOLIDS HT-HP CHLOR INTANG - · BIT NO. .. BIT NO ' SIZE MAHE TYPE 9 BIT NO RT HRS 'W'EIGHT RPM 10 SV NO COMDEP AN'G/-D I R TWD TANG s? . ,zo FL c~m: 57.,'., .'1 RMF .'/5 ' F ,: · TOTAL .~.~ SR NO dE'TS DEPOUT i' PS.! "..;.,¥:, L.I~LR SZ I' ', WEATHER S UPVR FT6 GRADE DL$ ....~ ,.¢,u-t..,~- ,.,,,5= ,,~.~- ~t~'~, ' 11 SUMMARY OF OPERATIONS ,I '5 ',6 DAY NO DEPTH_ ~4HR FT£--' MEN BEDS FUEL WATER A/FID ~0P 3 ~ ~'~- o7~o 200 · ~ ~ . . CURRENT OPERATIONS ~0~,.'-/~ /"J/( MUD/WT V I S ~V-YP 8ELS TEMP FL PH SAND SOLIDS HT-HP CHLOR RNF ~5 "F Id.~ r~ /~ ~: ~ ' i~" . wELL COS~ ~NTANG TANG ,. ~. TOTAL DRL~ ASSY' 'BIT N0. ~'/~ .. }', BIT N0 S~ZE MAEE' :TYPS .SR N0 J~,~S DEPOUT FTG "": ;" BIT N0 RT ~RS ' W~E'IGHT RPM PS~ .":':;~,,~:~:. SZ . , .... ..~.. , ~. ..~.a. · -. ~' . -- ' .-. SV N0 COMDEP AN~/~IR TVD 'SECT ...... N/>C0-~' ~' ' E/woO DLS · , ~,.. , .. WEATHER S UPVR 1! sUMMARY OF 0PERATION5 '71 7~ ' · I DATE ~£LL ~ ~EN 'SOHIO/BP DALLY DRILLING · ' ;-;-- " .. A B C D E F~ . RIG DAY N0 DEPTH 2~HR FT ' '"".::.: !:'i"" WF.J%THER S UPUR 4 MUD/WT VIS PU-¥P GELS TEMP ' 5 PH SAND SOLIDS HT-HP CHLOR /,.3. ~'" 72'l / 2 -' ' ~ z~ .o WELL COST INTANG " TANG :" DRLG ASSY BIT N0.~L/~_,~. F/r-v' ~"¢,'~ ~'c,~,~-,,~. +. Z ~c ~J~r p k~'~' ' ,. BIT N0 SZZE MAHE TYPE. 9 BIT NO RT HRS W'EZGHT RPM , 10 S1; NO C0MDEP AN'G/bIR .. TUD F'L' 'CA KE . . I~M'F '/5'F OTAL .$R NO ' OETS ~EPOUT FTG PSI .LNR SZ ~PM GRADE , ., ,.':'.'/.~ '~ '=',, . , " ......... '"' ': ...... Exhibit VI - 8c ': ...... .' .... ,. f.'~., 't:. · ."~· · ,. ~ · . . · ..5.'": _" ,- .'"' SOHIO/BP DALLY DRILLING RE~._~iT~ '060~ ROOR$ ....... r ' · ' A B C D E · I DATE WELL RIG 2-/~, -$/.. f-~ · zz'e' MEN BEDS FUEL 41 gT__ ~7~~ 3 CURRENT OPERATIONS DAY NO DEPTH WATER A/F/D' GELS TEMP HT-HP CHLOR TANG 77" DRLG ASSY BIT NO. ~,T-/- J,,,/,,,c, 3,, ~' ¢--xo -r BIT NO SIZE MAF~ 'TYPE .$R NO 9 BIT NO RT HRS W'EIGHT RPM PSI · 10 S1; NO C0MDEP AN'G/'DIR TVD, 2'.4 HR FTG · BOP ! ,. ',,~ f dk'rs LNR SZ ,% /, ..... .'. ,.4,'i !, ,! / WF~%THER S UPVR ,TOTAL ~EPOUT FTG ¥ SPM GRADE , -- E/WC0 DLS 11 SUMMARY OF OPERATIONS Exhibit VI-9: S-24A Well Integri _ty Report Original Completion Date: S-24A: 9/7/99 (S-24: 6/5/90) Schrader Bluff Penetration Hole Diameter: 9-7/8" Schrader Bluff Penetration Casing Diameter: 7" Well Status as of 9/2002: WAG Injector, currently on MI Cement Logs Across Schrader Bluff: None Comments: S-24 was originally drilled in 6/90. On 4/27/90 the 13-3/8" casing was tested to 3000 psi and held. On 5/6/90 the 9-5/8" casing was tested to 3000 psi and held. The original well was abandoned in 8/99 by setting a bridge plug in the 9-58" casing at 3020', cutting and milling 9-5/8" casing to 2739' and cement plugging back. Final PBTD 2669' pressure tested to 2500 psi and held. On 8/28/99 the 7" intermediate casing of the new well was tested to 4000 psi for 30 minutes and held. Additional Information: Exhibit VI-9a Well Diagram Exhibit VI-9b Directional Survey Exhibit VI-9c Drilling Daily Repons TREE= 4-1/8" CIVV ~_...~1111JIL V I -- WELLHEAD = McEVOY SAFETY NOTES: 9-5/8" CSG CUT, PULLED & MILLED ,ACTUATOR= AXELSON S 24A FROM SURFACE TO STUB @ 2739' HORIZONTAL LNR. K~. B_EV = 64.77' u 70° @ 10383' AND 90" @ 11758' BF. FIEV = 35.43, --~ ,,,=--=~-,,,==,--,~=~" KOP= 2782' I . i Max Angle =Datum IVD = 97@12411'10430, , [--~ t 2195' H4-1/Z'I-ESSSSV I~IP, ID=3.813" I Datum TV D = 8800' SS 4-1/2"MinimumlDxN NIPPLE = 3.725 @ 9996' 99941' ~4-1/2"XN~P,~D=3.813" , ~ X'~ ~ 9975' ~-'~4-1/2"X NIP, ID = 3.813" IOgD 9-5/8" cssl ~ ~,,\ ' ,' ' ' '°°°°' 4'°°" I I 4-1/2" 'IBG, 12.~#, L-80, 0.0152 bpf, ID= 3.9 Note:RefAeNrtGoL~rAo~uTcOtbPnP~F;o9r7his~2ri2c3a71~erfdata I PBTD H 12599' = SIZE SPF INTERVAL Opn/Sqz DATE . 2-7/8" 4 12377-12597 O 09/99 I 4'112"LNR'~2'fl#'L'80'O'O152bpf'ID=3'~38"H ! DATE REV BY COIVIVIENTS DATE REV BY COMIVENTS PRUDHOEBAY UNIT ; 05/12/90 ORGINAL COIVPLErlON WELL: S-24A i 09/07/99 SIDETRACK COMFLETION PERMIt No: 198-2450 I 03/14/01 SIS-IVH CONVERTED TO CANVAS AR No: 50-029-22044-01 ' 03/15/01 SIS-IVD FINAL SEC35, T121~ T12E 03/02/02 RN/TP CORRECTIONS BP Exploration (Alaska) SIZE SPF INTERVAL Opn/Sqz DATE 2-7/8" 4 12377 - 12597 O 09/99 DATE REV BY COIVIVIENTS DATE I:;aEV BY COMIVENTS 05/12190 ORGINAL COIVPLETION 09/07/99 SIDETRACK COMR. ETION 03/14/01 SIS-IVH CONVERTED TO CANVAS 03/15/01 SIS-IVD FINAL 03/02/02 RN/TP CORRECTIONS Well S:24A Directional Surv~~ Exhibit VI- 9b { AP:Z/UW]:: 500292204401 Survey Type: COMP Company: Schlumberger- Anadrill Survey Date: 09/02/99 Survey Top: 0' MD Survey Btm: 12,700' MD MD TVD SS I'NCLZNE AZI*MUTH DOGLEG ASP._X ASP_Y 0 0.00 63.77 0.00 0.00 0.0 619,212.3 5,979,854.9 6 5.88 57.89 0.42 116.35 0.0 619,212.3 5,979,854.9 14 14.38 49.39 0.42 110.28 0.5 619,212.4 5,979,855.0 24 23.78 39.99 0.30 94.68 1.6 619,212.4 5,979,855.0 33 33.38 30.39 0.17 74.68 1.6 619,212.4 5,979,855.0 45 44.58 19.19 0.15 30.16 1.1 619,212.5 5,979,855.0 56 55.98 7.79 0.17 342.01 1.2 619,212.5 5,979,855.0 67 67.33 -3.56 0.18 328.07 0.4 619,212.5 5,979,855.0 79 78.73 -14.96 0.15 326.52 0.3 619,212.4 5,979,855.0 90 90.13 -26.36 0.12 335.52 0.3 619,212.4 5,979,855.0 102 101.53 -37.76 0.10 347.61 0.3 619,212.4 5,979,855.0 113 112.93 -49.16 0.08 348.69 0.2 619,212.4 5,979,855.0 124 124.43 -60.66 0.08 324.81 0.3 619,212.4 5,979,855.0 136 135.88 -72.11 0.07 288.77 0.4 619,212.4 5,979,855.0 147 147.38 -83.61 0.08 259.82 0.3 619,212.4 5,979,855.0 159 158.78 -95.01 0.10 236.88 0.4 619,212.4 5,979,855.0 170 170.18 -106.41 0.13 219.89 0.4 619,212.4 5,979,855.0 182 181.58 -117.81 0.15 209.80 0.3 619,212.4 5,979,855.0 193 192.78 -129.01 0.17 206.95 0.2 619,212.3 5,979,854.9 204 204.08 -140.31 0.18 204.10 0.1 619,212.3 5,979,854.9 215 215.33 -151.56 0.20 194.91 0.3 619,212.3 5,979,854.9 227 226.63 -162.86 0.22 183.42 0.4 619,212.3 5,979,854.9 238 237.93 -174.16 0.23 175.17 0.3 619,212.3 5,979,854.9 249 249.23 -185.46 0.25 166.64 0.4 619,212.3 5,979,854.9 261 260.53 -196.76 0.27 155.87 0.5 619,212.3 5,979,854.6 272 271.83 -208.06 0.27 144.10 0.5 619,212.4 5,979,854.6 283 283.03 -219.26 0.28 130.55 0.6 619,212.4 5,979,854.6 294 294.33 -230.56 0.28 117.01 0.6 619,212.4 5,979,854.6 306 305.53 -241.76 0.28 104.30 0.6 619,212.5 5,979,854.6 317 316.83 -253.06 0.27 89.78 0.6 619,212.5 5,979,854.6 328 328.03 -264.26 0.23 76.95 0.6 619,212.5 5,979,854.6 339 339.28 -275.51 0.22 68.01 0.3 619,212.6 5,979,854.6 351 350.58 -286.81 0.17 59.42 0.5 619,212.6 5,979,854.6 362 361.88 -298.11 0.12 49.69 0.5 619,212.6 5,979,854.6 373 373.18 -309.41 0.05 27.29 0.7 619,212.6 5,979,854.6 384 384.48 -320.71 0.03 290.86 0.5 619,212.6 5,979,854.6 396 395.78 -332.01 0.12 206.77 1.1 619,212.6 5,979,854.6 407 407.08 -343.31 0.17 199.57 0.5 619,212.6 5,979,854.6 418 418.33 -354.56 0.22 191.68 0.5 619,212.6 5,979,854.6 430 429.58 -365.81 0.23 184.15 0.3 619,212.6 5,979,854.6 441 440.88 -377.11 0.23 175.67 0.3 619,212.6 5,979,854.6 452 452.18 -388.41 0.25 161.59 0.6 619,212.6 5,979,854.6 463 463.48 -399.71 0.27 145.86 0.7 619,212.6 5,979,854.6 475 474.78 -411.01 0.25 129.96 0.7 619,212.8 5,979,854.2 486 486.08 -422.31 0.23 114.24 0.6 619,212.8 5,979,854.2 497 497.33 -433.56 0.20 99.89 0.5 619,212.8 5,979,854.2 509 508.63 -444.86 '0'.15 ' 85.09 0.6 '6'19,212.9 5,979,854.2 520 519.88 -456.11 0.10 66.36 0.6 619,212.9 5,979,854.2 531 531.18 -467.41 0.07 41.78 0.4 619,212.9 5,979,854.2 542 542.43 -478.66 0.05 350.03 0.5 619,212.9 5,979,854.2 554 565 576 588 599 610 622 633 644 655 667 678 689 701 712 723 734 745 757 768 779 791 802 813 824 836 847 858 870 881 892 903 915 926 937 948 960 971 982 993 1,005 1,016 1,027 1,038 1,049 1,060 1,071 1,083 1,094 1,105 1,116 1,127 1,138 1,149 1,160 1,171 1,183 1,194 1,205 1,216 1,227 1,238 1,249 1,261 1,272 1,283 1,294 1,305 1,316 1,327 553.73 565.03 576.33 587.68 598.98 610.28 621.53 632.83 644.18 655.43 666.73 678.03 689.28 700.58 711.78 722.98 734.23 745.48 756.73 768.03 779.33 790.58 801.83 813.13 824.43 835.73 846.98 858.28 869.58 880.88 892.18 903.38 914.58 925.88 937.08 948.28 959.58 970.83 982.13 993.43 1.004.63 1.015.73 1.026.83 1.037.98 1.049.13 1.060.28 1.071.43 1,082.58 1.093.68 1.104.78 1.115.88 1.126.92 1.138.02 1.149.07 1.160.22 1.171.37 1,182.52 1,193.72 1,204.87 1,216.02 1,227.17 1,238.32 1,249.47 1,260.62 1,271.77 1,282.92 1,294.07 1,305.12 1,316.22 1,327.27 -489.96 -501.26 -512.56 -523.91 -535.21 -546.51 -557.76 -569.06 -580.41 -591.66 -602.96 -614.26 -625.51 -636.81 -648.01 -659.21 -670.46 -681.71 -692.96 -704.26 -715.56 -726.81 -738.06 -749.36 -760.66 -771.96 -783.21 -794.51 -805.81 -817.11 -828.41 -839.61 -850.81 -862.11 -873.31 -884.51 -895.81 -907.06 -918.36 -929.66 -940.86 -951.96 -963.06 -974.21 -985.36 -996.51 -1,007.66 -1,018.81 -1,029.91 -1,041.01 -1,052.11 -1,063.15 -1,074.25 -1,085.30 -1,096.45 -1,107.60 -1,118.75 -1,129.95 -1,141.10 -1,152.25 -1,163.40 -1,174.55 -1,185.70 -1,196.85 -1,208.00 -1,219.15 -1,230.30 -1,241.35 -1,252.45 -1,263.50 _xhibit VI - 9b 0.17 205.50 0.17 191.58 0.18 173.02 0.18 154.60 0.17 135.37 0.15 116.19 0.15 91.98 0.12 62.50 0.08 38.17 0.08 9.56 0.07 333.95 0.07 298.27 0.05 255.33 0.08 222.57 0.10 200.54 0.12 176.75 0.13 157.09 0.15 138.58 0.17 120.10 0.18 102.52 0.17 85.26 0.15 69.91 0.15 55.37 0.12 34.21 0.10 15.55 0.07 2.09 0.02 330.32 0.02 266.23 0.05 186.32 0.10 137.70 0.13 126.13 0.15 116.31 0.17 98.94 0.18 78.21 0.17 59.94 0.13 41.64 0.12 23.01 0.10 2.32 0.08 345.03 0.05 341.72 0.02 44.27 0.07 107.26 0.15 105.68 0.22 98.64 0.25 90.86 0.27 84.15 0.28 75.15 0.32 64.96 0.32 58.19 0.32 52.12 0.30 48.97 0.28 49.23 0.27 51.36 0.27 56.40 0.27 64.14 0.27 78.19 0.32 92.31 0.40 96.44 0.47 94.76 0.52 94.10 0.55 93.08 0.55 89.09 0.55 85.33 ' 0.53 81.42 0.53 77.11 0.52 74.53 0.5 0.6 0.5 0.3 0.3 0.4 0.5 0.5 0.5 0.5 0.6 0.7 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.5 0.5 0.4 0.3 0.5 0.4 0.3 0.5 0.2 0.5 0.7 0.3 0.3 0.5 0.6 0.5 0.6 0.4 0.4 0.3 0.3 0.4 0.6 0.7 0.7 0.4 0.3 0.4 0.6 0.3 0.3 0.2 0.2 0.1 0.2 0.3 0.6 0.8 0.8 0.6 0.5 0.3 0.3 0.3 0.4 0.4 0.2 - . 619,212.9 619,2~" · 619,21~.. 3 619,212.8 619,212.8 619,212.8 619,212.8 619,212.8 619,212.8 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,212.9 619,213.0 .619,213.0 619,213.0 619,213.0 619,213.0 619,213.0 619,213.0 619,213.0 619,213.0 619,213.0 619,213.1 619,213.1 619,213.1 619,213.1 619,213.3 619,213.3 619,213.3 619,213.3 619,213.3 619,213.3 619,213.3 619,213.3 619,213.3 619.213.3 619.213.4 619.213.4 619.213.5 619.213.5 619.213.5 619.213.6 619.213.6 619 ~213.8 619.213.7 619.213.7 619.213.9 619.213.9 619.214.0 619.214.0 619.214.1 619.214.2 619.214.2 619.214.4 619.214.5 619.214.6 619.214.7 619.214.9 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 .'5,979,854.2 5,979,854.2 '.5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.2 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 '5,979,854.6 5,979,854.6 5,979,854°6 5,979,854.6 1.338 1 ~349 1.361 1.372 1 ~383 1,394 1,405 1,416 1,428 1,439 1,450 1,461 1,472 1,483 1,495 1,506 1,517 1,528 1,539 1,550 1,561 1,572 1,583 1,595 1,606 1,617 1,628 1,639 1,650 1,662 1,673 1,684 1,695 1,706 1,717 1,729 1,740 1,751 1.762 1.773 1.784 1.796 1,807 1.818 1 829 1 840 1 ~851 1,862 1,873 1,884 1,895 1,906 1,917 1,928 1,939 1,950 1,961 1,972 1,983 1,994 2,005 2,016 2,027 2,038 2,049 2,060 2,071 2,082 2,093 2,104 1,338.37 1,349.47 1,360.57 1,371.77 1,382.87 1,394.07 1,405.17 1,416.37 1,427.51 1,438.66 1,449.86 1,461.01 1,472.16 1,483.31 1,494.51 1,505.56 1,516.61 1,527.76 1,538.85 1,549.95 1,561.10 1,572.25 1,583.45 1,594.65 1,605.75 1,616.95 1,628.15 1,639.30 1,650.45 1.661.65 1.672.85 1.683.99 1.695.14 1.706.24 1.717.34 1.728.49 1.739.59 1.750.69 1.761.88 1,773.08 1,784.28 1,795.48 1,806.48 1,817.53 1,828.58 1,839.58 1,850.63 1.861.62 1.872.67 1.883.72 1.894.72 1.905.67 1.916.62 1.927.62 1.938.57 1.949.51 1.960.51 1.971.56 1.982.61 1.993.61 2,004.66 2,015.66 2,026.76 2,037.76 2,048.76 2,059.86 2,070.86 2,081.91 2,092.91 2,103.86 -1,274.b0 -1,285.70 -1,296.80 -1,308.00 -1,319.10 -1,330.30 -1,341.40 -1,352.60 -1,363.74 -1,374.89 -1,386.09 -1,397.24 -1,408.39 -1,419.54 -1,430.74 -1,441.79 -1,45'2'.84 -1,463.99 -1,475.08 -1,486.18 -1,497.33 -1,508.48 -1,519.68 -1,530.88 -1,541.98 -1,553.18 -1,564.38 -1,575.53 -1,586.68 -1,597.88 -1,609.08 -1,620.22 -1,631.37 -1,642.47 -1,653.57 -1,664.72 -1,675.82 -1,686.92 -1,698.11 -1,709.31 -1,720.51 -1,731.71 -1,742.71 -1,753.76 -1,764.81 -1,775.81 -1,786.86 -1,797.85 -1,808.90 -1,819.95 -1,830.95 -1,841.90 -1,85.2.85 -1,863.85 -1,874.80 -1,885.74 -1,896.74 -1,907.79 -1,918.84 -1,929.84 -1,940.89 -1,951.89 -1,962.99 -1,973.99 -1,984.99 -1,996.09 -2,007.09 -2,018.14 -2,029.14 -2,040.09 ~, ,libit VI- 9b 0.58 0.58 0.58 0.60 0.62 0.65 0.70 0.78 0.82 0.83 0.82 0.83 0.83 0,82 0.77 0.72 0.68 0.67 0.65 0.62 0.62 0.62 0.62 0.63 0.72 0.80 0.83 0.85 0.87 0.90 0.92 0,92 0.88 0.85 0.85 0.85 0.83 0.80 0.80 0.83 0.82 0.80 0.82 0.82 0.80 0,85 0.93 0.92 0.88 0.83 0.83 0.82 0.75 0.70 0.68 0.65 0.57 0,50 0,45 0,38 0.32 0.25 0.13 0.05 0.12 0.17 68.81 69.71 71.53 72.49 71.80 72.33 74.59 74.40 72.64 72.32 71.74 70.19 66.24 61.61 57.74 55.54 56.03 58.33 62.59 66.70 70.25 73.93 77.03 80.61 84.73 85.57 85.13 86.11 86.20 85.27 84.18 83.61 84.69 86.73 89.09 91.09 92.59 95.84 98.54 99.49 102.37 106.54 108.94 109.55 111.14 113.66 114.68 114.96 115.54 116.50 116.08 115.52 115.89 114.72 113.23 111.02 108.70 109.47 113.18 114.60 113.88 113.08 11'3.71 179.17 215.66 184.55 0.2 0.2 0.3 0.5 0.0 0.1 0.2 0.2 0.2 0.3 0.5 0.7 0.4 0.1 0.1 0.2 0.5 0.6 0.7 0.5 0.4 0.3 0.5 0.5 0.4 0.4 0.3 0.4 0.9 0.7 0.3 0.2 0.2 0.3 0.2 0.1 0.4 0.4 0.3 0.3 0.3 0.5 0.3 0.3 0.4 0.6 0.4 0.1 0.3 0.6 0.7 0.1 0.4 0.5 0.1 0.1 0.6 0.5 0.2 0.4 0.8 0.6 0.5 0.6 0.5 0.6 1.1 1.1 0.8 0.8 019,214.9 619,2~" q 619,2~ . 619,215.2 619,215.3 619,215.3 619,215.5 619,215.6 619,215.7 619,215.8 619,216.0 619,216.1 619,216.2 619,216.4 619,216.6 619,216.7 619,216.8 619,217.1 619,217.2 619,217.2 619,217.3 619,217.4 619,217.5 619,217.7 619,217.8 619,217.9 619,218.0 619,218.2 619,218.3 619,218.4 619,218.5 619,218.8 619,218.9 619,219.1 619.219.3 619.219.4 619.219.6 619.219.8 619.219.9 619.220.1 619.220.2 619.220.4 619.220.6 619,220.7 619,220.9 619,221.1 619,221.2 619,221.4 619,221.5 619,221.6 619,221.9 619,222.0 619,222.1 619,222.2 619,222.5 619,222.6 619,222.7 619,222.8 619,223.0 619,223.1 619,223.2 619,223.2 619,223.3 619,223.5 619,223.5 619,223.6 619,223.6 619,223.6 619,223.6 619,223.6 b,979,Sb4.0 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,854.6 5,979,855.0 5,979,855.0 5,979,855.0 5,979,855.0 5,979,855.0 5,979,855.0 5,979,855.0 5,979,855.0 5,979,855.4 5,979,855.4 5,979,855.4 5,979,855.4 5,979,855.4 5,979,855.4 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,856.1 5,979,856.1 5,979,856.1 5,979,856.1 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,856.2 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.8 5,979,855.5 5,979,855.5 5,979,855.5 5,979,855.5 5,979,855.5 5,979,855.5 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,855.1 5,979,854.8 2,126 2,137 2,148 2,159 2,170 2,181 2,192 2,203 2,214 2,225 2,236 2,247 2,258 2,269 2,281 2,292 2,303 2,314 2,324 2,335 2,346 2,357 2,369 2,380 2.391 2.402 2 2.424 2.435 2.446 2.457 2.468 2.479 2.490 2,501 2,512 2,523 2,534 2,545 2,556 2,567 2,578 2,589 2,600 2,611 2,621 2,632 2,643 2,654 2,665 2,670 2,700 2,730 2,760 2,782 2,818 2,849 2,880 2,911 2,942 2,977 3,004 3,035 3,068 3,099 3,132 3,163 3,193 3,225 '~ ~7 /, .L J."t'. O0 2,125.81 2,136.81 2,147.81 2,158.81 2,169.91 2,181.01 2,192.01 2,203.10 2,214.15 2,225.20 2,236.25 2,247.30 2,258.35 2,269.40 2,280.44 2,291.44 2,302.44 2,313.44 2,324.34 2,335.34 2,346.34 2,357.38 2,368.43 2,379.43 2,390.48 2,401.53 2,412.58 2,423.58 2,434.58 2,445.67 2,456.67 2,467.67 2,478 67 2,489 67 2,500 57 2,511 57 2,522 56 2,533 51 2,544.46 2,555.51 2,566.56 2,577.60 2,588.60 2,599.55 2,610.40 2,621.30 2,632.19 2,642.99 2,653.89 2,664.69 2,669.85 2,699.79 2,729.62 2,759.35 2,781.07 2,816.62 2,847.08 2,876.94 2,906.50 2,936.36 2,969.52 2,995.59 3,025.52 3,056.07 3,085.48 3,115.57 3,144.04 3,171.78 3,200.45 -/_,UD J..U~ -2,062.04 -2,073.04 -2,084.04 -2,095.04 -2,106.14 -2,117.24 -2,128.24 -2,13g.33 -2,150.38 -2,161.43 -2,172.48 -2,183.53 -2,194.58 -2,205.63 -2,216.67 -2,227.67 -2,238.67 -2,249.67 -2,260.57 -2,271.57 -2,282.57 -2,293.61 -2,304.66 -2,315.66 -2,326.71 -2,337.76 -2,348.81 -2,359.81 -2,370.81 -2,381.90 -2,392.90 -2,403.90 -2,414.90 -2,425.90 -2,436.80 -2,447.80 -2,458.79 -2,469.74 -2,480.69 -2,491.74 -2,502.79 -2,513.83 -2,524.83 -2,535.78 -2,546.63 -2,557.53 -2,568.42 -2,579.22 -2,590.12 -2,600.92 -2,606.08 -2,636.02 -2,665.85 -2,695.58 -2,717.30 -2,752..85 -2,783.31 -2,813.17 -2,842.73 -2,872.59 -2,905.75 -2,931.82 -2,961.75 -2,992.30 -3,021.71 -3,051.80 -3,080.27 -3,108.01 -3,136.68 {~ _xhibit VI - 9b 0.62 0.77 0.87 0.92 0.93 0.93 0.93 0.95 0.97 0.97 0.97 0.98 0.97 0.90 0.85 0.85 0.83 0.83 0.87 0.90 0.90 0.88 0.87 0.85 0.83 0.83 0.85 0.93 0.98 1 02 1 02 1 02 1 03 1 05 1 03 1 02 1 O0 1 02 1 05 1 10 1 13 I 18 1 25 1 30 1 37 1.42 2.20 5.09 6.92 8.47 9.84 12.17 14.07 14.91 15.24 15.51 17.58 17.56 19.27 19.17 21.39 23.48 23.35 25.30 28.49 356.29 349.15 345.53 343.22 341.50 340.13 339.31 338.54 338.06 337.87 337.68 336.52 330.51 326.00 327.45 329.39 331.86 333.98 335.13 335.91 336.78 337.69 338.95 342.32 346.75 349.97 352.04 352.66 352.79 353.85 354.52 354.06 352.78 .351.12 351.16 352.10 352.29 353.48 355.12 356.17 357.12 358.67 359.83 0.45 1.31 1.74 5.20 354.30 356.00 354.45 352.16 351.60 350.62 348.84 340.88 337.60 331.84 331.91 329.59 328.16 325.08 323.68. 322.13 320.17 319.38 ~1~ ~1 0.8 1.4 1.7 2.0 2.2 1.6 1.0 0.6 0.3 0.2 0.1 0.2 0.2 0.0 0.0 0.2 0.9 0.9 0.5 0.3 0.4 0.3 0.4 0.3 0.1 0.2 0.2 0.5 0.6 0.4 0.3 0.7 0.5 0.4 0.1 0.1 0.2 0.3 0.2 0.2 0.2 0.3 0.4 0.5 0.3 0.5 0.7 0.5 0.7 0.5 15.2 9.9 6.1 5.2 6.4 6.4 6.1 3.1 6.8 2.9 7.6 0.1 5.9 1.5 7.9 6.6 2.0 6.9 10.0 0 J.~,-' Z.-~.O 619,22~? 6 619,2~ 619,223.6 619,223.7 619,223.7 619,223.6 619,223.6 619,223.6 619,223.5 619,223.5 619,223.3 619,223.3 619,223.2 619,223.2 619,223.1 619,222.9 619,222.9 619,222.8 619,222.7 619,222.7 619,222.6 619,222.4 619,222.4 619,222.3 619,222.3 619,222.2 619,222.2 619,222.1 619,222.1 619,222.0 619,221.9 619,221.9 619,221.9 619,221.9 619,221.9 619,221.9 619,221.8 619,221.8 619,221.8 619,221.8 619,221.7 619,221 6 619,221 6 619,221 6 619,221 6 619,221 6 619,221 6 619,221 6 619,221 6 619,221 6 619,221.6 619,221.5 619,221.2 619,220.7 619,220.3 619,219.2 619,218.0 619,216.5 619,214.3 619,211.2 619,206.9 619,203.0 619,197.9 619,192.2 619,186.2 619,178.7 619,171.1 619,163.2 619,153.5 ~10 1~.~ '~ 5,979,854.8 5,979,854.8 5,979,854.8 5,979,854.8 5,979,855.1 5,979,855.1 5,979,855.5 5,979,855.5 5,979,855.9 5,979,855.9 5,979,855.9 5,979,856.2 5,979,856.2 5,979,856.6 5,979,856.6 5,979,856.9 5,979,856.9 5,979,857.3 5,979,857.3 5,979,857.3 5,979,857.7 5,979,857.7 5,979,858.0 5,979,858.0 5,979,858.0 5,979,858.4 5,979,858.4 5,979,858.8 5,979,858.8 5,979,859.1 5,979,859.1 5,979,859.5 5,979,859.5 5,979,859.9 5,979,859.9 5,979,860.2 5,979,860.2 5,979,860.6 5,979,860.6 5,979,861.0 5,979,861.0 5,979,861.3 5,979,861.3 5,979,861.7 5,979,861.7 5,979,862.1 5,979,862.4 5,979,862.4 5,979,862.8 5,979,863.2 5,979,863.2 5,979,865.0 5,979,868.3 5,979,872.3 5,979,875.6 5,979,882.5 5,979,889.4 5,979,897.1 5,979,904.8 5,979,912.4 5,979,921.1 5,979,928.4 5,979,937.1 5,979,946.1 5,979,954.8 5,979,965.0 5,979,974.7 5,979,984.5 5,979,995.3 3,288 3,320 3,351 3,380 3,473 3,567 3,660 3,754 3,848 3,941 4,034 4,128 4,220 4,311 4,403 4,496 4,591 4,686 4,778 4,872 4,965 5,059 5 ~151 5.244 5.338 5 5.524 5.619 5,713 5.807 5,894 5,987 6,080 6,173 6,266 6,358 6,452 6,546 6,641 6,733 6,828 6,922 7,016 7,108 7,201 7,295 7,389 7,481 7,574 7,666 7,762 7,855 7,948 8,041 8,135 8,226 8,319 8,418 8,507 8,599 8,693 8,787 8,881 8,973 9,066 9,161 9,254 9,347 9,441 9.534 3,254.65 3,281.61 3,307.55 3,331.24 3,403.49 3,474.37 3,542.38 3,609.57 3,677.47 3,747.35 3,818.22 3,889.88 3,960.48 4,031.01 4,101.62 4,173.05 4,245.32 4,317.36 4,388.79 4,460.47 4,531.07 4,601.90 4,672.01 4,743.44 4,814.50 4,884.86 4,955.26 5,027.81 5,098.94 5,171.22 5,236.65 5,305.93 5,375.07 5,443.80 5,513.13 5,581.19 5,651.14 5,721.23 5,791.49 5,860.57 5,931.92 6,003.38 6,073.75 6,143.69 6,213.82 6,285.12 6,356.10 6,426.48 6,498.47 6,571.48 6,648.47 6,725.02 6.802.00 6.878.96 6.957.75 7.033.72 7.111.71 7.195.86 7.271.25 7.350.23 7.430.82 .7.512.05 7.594.03 7.673.10 7.753.45 7,834.47 7,914.79 7,995.03 8,076.86 8.157.91 -3,190.88 -3,217.84 -3,243.78 -3,267.47 -3,339.72 -3,410.60 -3,478.61 -3,545.80 -3,613.70 -3,683.58 -3,754.45 -3,826.11 -3,896.71 -3,967.24 -4,037.85 -4,109.28 -4,181.55 -4,253.59 -4,325.02 -4,396.70 -4,467.30 -4,538.13 -4,608.24 -4,679.67 -4,750.73 -4,821.09 -4,891.49 -4,964.04 -5,035.17 -5,107.45 -5,172.88 -5,242.16 -5,311.30 -5.380.03 -5.449.36 -5 ~517.42 -5.587.37 -5.657.46 -5.727.72 -5.796.80 -5.868.15 -5.939.61 -6.009.98 -6.079.92 -6.150.05 -6,221.35 -6,292.33 -6,362.71 -6,434.70 -6,507.71 -6,584.70 -6,661.25 -6,738.23 -6,815.19 -6,893.98 -6,969.95 -7,047.94 -7,132.09 -7,207.48 -7,286.46 -7,367.05 -7,448.28 -7,530.26 -7,609.33 -7,689.68 -7,770.70 -7,851.02 -7,931.26 -8,013.09 -8.094.14 !' :hibit Vl-9b 37.14 40.02 42.05 44.39 44.25 42.93 40.48 40.09 39.72 39.76 39.89 39.20 40.41 40.63 40.03 39.34 40.80 40.90 40.76 40.28 39.71 40.83 41.04 40.61 40.63 40.17 40.03 41.75 42.34 42.07 42.01 42.03 41.99 41.95 42.02 41.74 41.32 41.08 41.06 40.93 40.82 40.73 40.70 40.71 40.09 38.40 37.28 35.19 34.42 34.20 33.83 32.98 33.03 32.43 31.98 31.42 30.81 30.21 30.03 30.03 30.24 30.87 31.23 30.57 29.68 28.69 29.94 319.09 319.33 315.74 314.12 313.41 312.73 313.33 314.59 314.63 317.92 318.95 318.33 319.65 319.97 320.56 319.83 320.02 319.47 319.98 320.43 319.64 319.57 319.32 320.17 320.17 319.08 317.68 316.85 316.09 315.44 316.61 316.61 315.92 315.89 316.90 317.28 320.35 320.33 320.27 320.48 320 02 319 26 320 13 320 01 320 11 320 56 321.10 321.53 321.22 322.05 321.88 321.97 323.25 323.24 324.47 324.72 324.58 325.00 325.77 323.72 325.01 324.43 325.26 325.53 325.65 328.13 325.45 6.8 8.4 2.0 8.4 3.1 3.3 2.8 0.6 1.5 2.7 1.0 0.4 2.3 0.7 0.9 1.6 0.3 0.8 0.9 1.6 0.4 0.4 0.6 0.8 1.2 0.3 0.8 0.0 0.9 1.0 2.1 0.8 0.6 0.9 0.0 0.5 0.1 0.7 0.4 2.3 0.3 0.1 0.2 0.4 0.5 0.6 0.1 0.7 1.8 1.3 2.2 0.9 0.6 0.4 0.9 0.8 0.7 0.8 0.7 0.7 0.7 0.5 1.1 0.7 0.7 0.6 0.7 1.0 1.7 2.0 619, 619,109.8 619,098.3 619,060.1 619,017.6 618,971.7 618,923.6 618,875.7 618,829.5 618,785.6 618,742.2 618,701.0 618,661.3 618,622.1 618,582.3 618,541.7 618,501.9 618,463.3 618,423.6 618,383.5 618,343.2 618,304.1 618,264.8 618,225.2 618,184.7 618,144.7 618,104.0 618,064.2 618,022.9 617,983.9 617,940.2 617,895.7 617,852.0 617,808.3 617,765.3 617,720.7 617,676.6' 617,632.9 617,591.9 617,551.2 617,510.7 617,471.0 617,431.6 617,391.7 617,351.2 617,311.3 617,272.1 617,233.8 617,197.3 617,161.4 617,127.5 617,094.3 617,061.6 617,029.0 616,998.3 616,967.7 616,935.7 616,908.2 616,880.0 616,851.9 616,824.6 616,796.7 616,769.3 616,741.4 616,712.5 616,684.7 616,657.8 616,632.2 616.606.6 5,980,018.4 5,980,031.4 5,980,044.8 5,980,057.8 5,980,100.7 5,980,145.4 5,980,189.7 5,980,234.4 5,980,277.9 5,980,319.6 5,980,360.7 5,980,402.1 5,980,443.5 5,980,487.2 5,980,530.1 5,980,574.5 5,980,621.1 5,980,667.3 5,980,712.5 5,980,758.0 5,980,803.8 5,980,850.0 5,980,895.2 5,980,940.7 5,980,985.8 5,981,031.7 5,981,077.5 5,981,124.5 5,981,170.0 5,981,215.1 5,981,255.8 5,981,300.5 5,981,344.8 5,981,388.4 5,981,433.1 5,981,476.8 5,981,521.5 5,981,566.5 5,981,612.0 5,981,657.1 5,981,704.7 5,981,752.1 5,981,798.3 5,981,844.2 5,981,889.7 5,981,93.5.9 5,981,982.1 5,982,027.3 5,982,072.1 5,982,115.4 5,982,158.8 5,982,200.0 5,982,240.8 5,982,280.9 5,982,321.4 5,982,360.1 5,982,399.9 5,982,442.2 5,982,479.5 5,982,518.2 5,982,556.6 5,982,595.0 5,982,633.0 5,982,669.9 5,982,708.3 5,982,747.7 5,982,786.8 5,982,824.8 5,982,862;5 5.982.900.2 9162'7 9,721 9,814 9,909 10,002 10,094 10,106 10,169 10,198 10,229 10,260 10,289 10,321 10,352 10,383 10,412 10,447 10,477 10,513 10,540 10,570 10,603 10,634 10,663 10,697 10,728 10,757 10,789 10,819 10,848 10,882 10 ~914 10 ~943 10 ~979 11,010 11,036 11,073 11,105 11,132 11,164 11,198 11,223 11,260 11,292 11,318 11,3S2 11,383 11,412 11,445 11,477 11,506 11,537 11,568 11,598 11,630 11,664 11,691 11,723 11,758 11,784 11,820 11,851 11,878 11,912 11,944 11,972 12,006 12,038 12,065 12,097 81239.15 8,320.84 8,401.51 8,483.04 8,564.24 8,645.27 8,656.17 8,712.17 8,737.84 8,762.94 8,786.09 8,805.56 8,823.48 8,837.77 8,848.74 8,857.83 8,869.65 8,878.63 8,885.28 8,888.22 8,891.17 8,893.83 8,895.60 8,896.94 8,898.57 8,900.08 8,901.49 8,902.94 8,904.62 8,906.51 8,908.68 8,910.81 8,912.81 8,915.35 8,917.64 8,919.47 8,922.41 8,925.52 8,928.64 8,932.27 8,936.35 8,939.54 8,944.59 8,949.11 8,952.93 8,957.98 8,962.57 8,967.17 8,972.51 8,977.83 8,982.58 8,987.87 8,992.98 8,997.22 9,001.02 9,004.36 9,006.41 9,007.71 9,007.85 9,007.62 9,005.98 9,003.23 9,000.66 8,997.61 8,994.96 8,992.51 8,989.56 8,986.61 8,984.05 8,980.99 -8~175.38 -8,257.07 -8,337.74 -8,419.27 -8,500.47 -8,581.50 -8,592.40 -8,648.40 -8,674.07 -8,699.17 -8,722.32 -8,741.79 -8,759.71 -8,774.00 -8,784.97 -8,794.06 -8,805.88 -8,814.86 -8,821.51 -8,824.45 -8,827.40 -8,830.06 -8,831.83 -8,833.17 -8,834.80 -8,836.31 -8,837.72 -8,839.17 -8,840.85 -8,842.74 -8,844.91 -8,847.04 -8,849.04 -8,851.58 -8,853.87 -8,855.70 -8,858.64 -8,861.75 -8,864.87 -8,868.50 -8,872.58 -8,875.77 -8,880.82 -8,885.34 -8,889.16 -8,894.21 -8,898.80 -8,903.40 -8,908.74 -8,914.06 -8,918.81 -8,924.10 -8,929.21 -8,933.45 -8,937.25 -8,940.59 -8,942.64 -8,943.94 -8,944.08 -8,943.85 -8,942.21 -8,939.46 -8,936.89 -8,933.84 .-8,931.19. -8,928.74 -8,925.79 -8,922.84 -8,920.28 -8,917.22 ~hibit VI- 9b ..iU.UU 28.75 27.63 27.39 27.55 30.91 38.06 45.38 51.77 59.21 66.50 72.16 70.65 69.96 75.09 83.47 84.16 84.68 86.02 87.43 87.29 87.19 87.22 87.26 87.43 86.33 86.23 86.29 86.13 86.02 85.81 85.89 85.92 85.02 83.58 83.40 83.30 83.06 82.51 81.88 81.67 81.61 81.30 81.26 80.92 80.46 80.40 80.33 80.15 80.94 82.75 83.54 85.33 85.95 89.31 90.24 90.75 94.60 95.49 95.35 94.87 94.80 95.01 95111 95.49 95.39 95.39 3zb.44 327.49 328.29 327.55 327.55 324.64 321.63 318.57 315.46 312.46 308.34 305.65 298.86 289.20 283.79 283.22 283.28 287.36 289.28 290.42 290.45 289.84 289.98 289.68 290.98 292.04 292.72 292.55 291.98 292.46 291.22 291.38 291.38 291.42 288.58 288.35 289.57 289.59 288.61 287.55 287.86 288.77 289.40 289.20 289.18 288.18 288.20 289.18 289.06 286.96 288.49 288.02 288.60 287.72 288.93 290.25 288.26 288.93 289.45 289.97 289.29 289.72 289.80 290.81 290.46 291.01 291.23 0.7 0.9 0.1 0.5 1.5 1.3 3.4 0.3 12.4 24.1 24.5 23.1 24.8 26.0 19.9 23.2 26.1 24.3 23.5 2.6 13.5 7.1 5.8 0.5 1.8 0.5 1.0 4.2 5.0 2.4 0.5 1.8 1.7 3.5 0.6 0.1 2.4 10.1 1.1 3.9 0.7 4.4 3.3 1.2 3.4 2.1 0.7 1.2 3.3 0.2 3.4 0.7 7.1 7.9 2.9 5.5 4.0 11.3 4.6 7.7 11.1 3.3 2.0 2.4 1.4 0.8 3.0 1.6 2.1 0.7 6161579.6 616,5( t 616,52~.3 616,498.4 616,472.8 616,449.1 616,446.1 616,430.0 616,421.9 616,411.2 616,397.6 616,382.4 616,363.4 616,341.8 616,318.3 616,295.3 616,265.0 616,237.6 616,203.3 616,176.8 616,147.5 616,116.3 616,087.0 616,059.7 616,027.8 615,998.5 615,970.9 615,941.3 615,912.6 615,885.6 615,854.8 615,824.8 615,797.5 615,764.5 615,734.7 615,710.9 615,676.1 615,646.6 615,620.6 615,590.9 615,558.6 615,534.7 615,499.5 615,469.6 615,444.7 615,412.8 615,384.4 615,356.6 615,325.5 615,295.4 615,268.8 615,239.6 61.5,210.2 615,181.9 615,151.7 615,119.0 615,093.4 615,063.3 615,030.0 615,004.8 614,971.2 614,941.7 614,916.1 614,883.8 614,854.1 614,827.1 614,795.6 614,765.7 614,740.4 614,710.0 5:982:937.8' 5,982,975.8 5,983,013.8 5,983,052.2 5,983,090.3 5,983,126.9 5,983,131.6 5,983,155.9 5,983,167.4 5,983,181.2 5,983,196.7 5,983,212.6 5,983,230.6 5,983,248.2 5,983,265.0 5,983,279.3 5,983,292.0 5,983,299.7 5,983,307.5 5,983,313.4 5,983,320.6 5,983,330.7 5,983,340.5 5,983,350.3 5,983,361.6 5,983,371.4 5,983,380.8 5,983,391.3 5,983,402.2 5,983,412.8 5,983,425.1 5,983,436.8 5,983,447.3 5,983,460.0 5,983,471.2 5,983,480.0 5,983,493.0 5,983,503.2 5,983,511.6 5,983,521.0 5,983,532.2 5,983,539.9 5,983,550.7 5,983,559.8 5,983,567.4 5,983,577.9 5,983,587.4 5,983,596.8 5,983,606.6 5,983,616.0 5,983,624.7 5,983,634.2 5,983,643.2 5,983,652.0 5,983,661.4 5,983,671.5 5,983,679.5 5,983,688.9 5,983,700.1 5,983,708.5 5,983,719.0 5,983,728.8 5,983,737.6 5,983,748.4 5,983,758.6 5,983,767.7 5,983,778.9 5,983,789.4 5,983,798.6 5,983,809.8 12,128 .1R,f58 12,190 12,224 12,252 12,284 12,315 12,345 12,377 12,411 12,440 12,474 12,505 12,531 12,625 12,644 12,700 8,978.00 8,974.99 8,971.57 8,967.73 8,964.59 8,960.93 8,957.40 8,954.06 8,950.45 8,946.41 8,943.05 8,939.61 8,936.74 8,934.28 8,925.34 8,923.51 8,918.10 -8,914.23 -8,911.22 -8,907.80 -8,903.96 -8,900.82 -8,897.16 -8,893.63 -8,890.29 -8,886.68 -8,882.64 -8,879.28 -8,875.84 -8,872.97 -8,870.51 -8,861.57 -8,859.74 -8,854.33 (" Exhibit VI - 9b 96.49 290.40 96.56 289.28 96.66 289.76 96.32 288.38 96.60 288.93 96.77 289.66 96.63 288.79 95.15 286.06 95.29 286.14 95.53 286.38 95.46 287.67 95.53 288.54 95.53 288.54 2.2 3.5 1.6 4.8 1.9 2.1 3.0 9.2 0.5 1.3 1.4 4.6 0.0 614,680.9 614,6~' ~ 614,62_ ~ 614,590.8 614,564.6 614,534.4 614,505.4 614,477.6 614,447.3 614,414.5 614,387.4 614,355.4 614,325.1 614,300.0 614,210.7 614,192.5 614,139.2 5,983,820.7 5,983,830.5 5,983,840.7 5,983,851.5 5,983,860.7 5,983,871.2 5,983,880.6 5,983,890.1 5,983,899.5 5,983,910.3 5,983,919.4 5,983,928.8 5,983,937.2 5,983,944.1 5,983,969.8 5,983,975.4 5,983,992.5 Exhibit VI- 9c { CHECK HOLE ~ ~ PiT 12 MAKe. EL ~B ,.. I CUM OIL WATER I~JMPS ~1 OFF 1ORQ ON BtM TYPE JETS 10 ml'~ FL ""'" 100' . SOLIDS q .too . c, ./~ sA.D 7~ ~ 13M~EI.~,~ I AVDC ~R ~R UP xl~ DN xl~ R~ . P/U S~ COND SERIAL NO BHA CHANGE LENGTH ?~w~-Y H2. I I, II Az TRIP IN. SKg3D N/.S PORE "r'.-7' PRESS DLS DLS ACTIVITY LOG , ACCIDENT~ POLLUTION ~¢lh, o~.~ TRBLE TRBLE CODE WIND/~ BAROMETEP, TOTAL PERSONNE~ SAPC Exhibit VI-9c (' .i' SUPV. INIT ~ .OLE ~ SAND SOUD$ 3 1ORO OFF } ON 1ORQ WOB =1,.~,, , MAX 4000 JETS TYPE AVDP , AVDC JAR .IAR SERIAL NO CHANGE (Y/N) LENGTH SURVEY MD ANGLE AZ 1"VD SURVEY ~ID I ANGLE ' TVD iURVEY MD I ANGLE TVD ti.-~ I. N/.$ N/.S ' . E/-W ! 8HALE DLS LDL$ DL$ DELTA !t TRBLE I TRBLE I coD.. BAROMETER.~...<~i..-~ m TOTAL PERSONNEu ,~,~¢ ,~APC I rTRBLE do I s~Rv,c~ Co TRBLE COST "~ I WAT E F' ~,lUS~) / 7~ ~ JAVA',.BEC.~ 8 Exhibit VI ' 9c { WEU. N,U~E- NO. OPEI~'ION MUD I CHECK MW FV APl OIL DAILY -CSG ~L I',, PV yp GELS WATER MBT PUMPS ~'1 MAKE/MODE #2 MAKE/MODEL #3MAKE./MODE. L ; /_.~.'rz"~'co " v · PUMP 2 ' 3 PRESS ,', 1ORQ WOB RC~ UAX w'~(,~' JETS · ..Z-"~2.~ co ,,~ SIZE 1 I 1ORQ OFF TORO ON m'M BTM BIT# TYPE // CUM. HTP MUD TEMP · AVDP I AVDC JAR I JAR . UP xl000i ON i P/U "xl000 xlO00 I OIcF VV'r COND SERIAL NO x1000 BHA CHANGE (Y/N) HR. mi,ICE ORILL BHA AIR ~, SURV~.Y # SURVEY # SURVEY ANGLE AZ TVD SECT MD ANGLE AZ TVD # , SURVEY .' MD ANGLE AZ TVD TRIP ,CONN. IPORE ~ I PAS o,s PRESS OPERATING LENGTH DIS N/-S EJ-W DLS N/-S , . ,; E/*W DLS SHALE DELTA OTAL PERSONNEL ,~APC ~ CONTRACTOR ~ I CATERING~ I I:'il ~ I OTHER . BED? Exhibit VI- 9c WElL NAME $/ ~L T~" ~"~"q~ PUMPS I'1 MAKE/MODEL SUPV. :. ~.' HRS. #2 MAKFJ~OOEL Pu~P PRESS JAR COND SERIAL NO BHA NO, CHANGE ;BHA~ LENG'rH BI.IA AIR ~ SURVEY MD ANGLE AZ TVD # .SURVEY . MD I A~GI.~ IAZ TVD .SURVEY MD IPORE PRESS I SECT ' ,' N/.$ f, SEC'r , 'i ! N/.S ,. SECT ,~ ~u.s ., SECT ,: N/-S ',, ,,, . I' E/-W FJ-W FJ-W DIS DIS DLS Imm ACTIVITY LOG ,/? 'IND ~ALPERSONNE[ TRBLE CO~ ~PC ~ :TRBLE COD£ TRBLE COSt Exhibit VI- 90( s --zSr OIL WATER PUMPS ~ MAKE/MODEL ._F/v~5 cc> F /0 ~,5,t/z XlO 3 1ORQ ON TYPE 8~ OELS J Mt Cl C- '1 SOLIDS #2 MAKE/MODEL #3MAKFJMOOEL AVDP AVDC 2 '7~ 3 PRESS J I UP xl000 DN xl00O TORO , WOB P/U SLACK MAX xl000 xl000 JEI~ COND SERIAL NO C~GE (Y/N) LENGTH SURVEY MD ANGLE TVD # SURVEY MD J ANGLE TVD # SURVEY# MD J ANGLE TVD OPERATING j WATER.4 bbl USED ~"" ~""" Facility PBS Pad Exhibit VI- 9c Progress Re'port Well S-24A Page 2 Rig Nabors 9ES Date 08 September 99 Date/Time 01:30-02:00 02:00 02:00-06:00 02:00-03:00 03:00 03:00-06:00 06:00 06:00-06:30 06:30 06:30-08:00 06:30-07:30 07:30 07:30-08:00 08:00 08:00-14:30 08:00-10:30 10:30 10:30-11:00 11:00 11:00-13:00 13:00 13:00-14:30 14:30 14:30-15:30 14:30-15:30 15:30 15:30-03:30 15:30-17:30 17:30 17:30-18:30 18:30 18:30-23:00 23:00 23:00-01:00 Duration 1/2 hr 4 hr 1 hr 3 hr ... 112 hr' .- 1/2 hr 1-1/2 hr I hr 1/2 hr 6-1/2 hr 2-1/2 hr 1/2 hr 2 hr 1-1/2 hr I hr 1 hr 12hr 2 hr I hr 4-1/2 hr 2 hr Activity Retrieved Hanger plug Equipment work completed Pull Single completion, 4-1/2in O.D. Pulled Tubing on retrieval string to 24.0 ft MFU landing jt and BOLDS. Pulled tubing to floor. L/D landing jt and tubing hanger. Completed operations Laid down 4512.0 ft of Tubing L/D tubing at report time. Installing thread protectors to salvage tubing. 107 joints laid out Recovered 107 jts tbg plus XN nipple plus 20.50' cut jt. · 'Pull'Single:completion, 4-.-t./2in O.D~"(,C°iat...) ..... "" .-' "' Removed Tubing handling equipment Equipment work completed Test well control equipment Tested Bottom ram P/U test jt and tested lower pipe ram to 250/4000 psi. R/D equipment. Pressure test completed successfully - 4000.000 psi Installed Wear bushing Eqpt. work completed, running tool retrieved 4-l/2in. Drillpipe workstring run Ran Ddllpipe in stands to 3020.0 ft P/U EZSV bridge plug and RIH. At Setting depth: 3020.0 ft Installed Bridge plug Set and released form EZSV. Set 25K down to confirm set. Equipment work completed Circulated at 3020.0 ft Pump 30 bbls water spacer and displaced to 9.6 ppg mud. 10 bpm, 375 psi. Mixed and spotted 18 ppg milling pill to 2820'. Hole displaced with Water based mud - 100.00 % displaced Pulled Drillpipe in stands to 0.0 ft At Surface: 0.0 ft Planned maintenance Serviced Block line Line slipped and cut BHA run no. 1 Made up BHA no. 1 P/U section milling BHA. BHA no. 1 made up R.I.H. to 2799.0 ft Locate casing collar at 2799. Stopped: To correlate depth Milled Casing at 2794.0 ft P/U 6' above collar and begin section milling @ 2794'. Milled to 2797'. Recovered 150g metal. At Kick off depth: 2797.0 ft Circulated at 2797.0 ft Mix and pump sweep. Circ 14 bpm, 1325 psi. Exhibit VI- 9c Progress Report Facility PBS Pad Well S-24A Page 3 Rig Nabors 9ES Date 08 September 99 Date/Time 09 Aug 99 01:00 01:00-02:00 02:00 02:00-03:30 03:30 03:30-04:30 03:30-04:30 04:30 o4i:30-o6:oo , 04:~9-05:00. 05:00 05:00-06:00 05:00-06:00 06:00-08:00 06:00-08:00 08:00 08:00-10:00 08:00-10:00 10:00 10:00-11:00 10:00-11:00 11:00 11:00-13:30 11:00-13:30 13:30 13:30-14:30 13:30-14:00 14:00 14:00-14:30 14:30 14:30-15:30 14:30-15:00 Duration 1 hr 1-1/2 hr 1 hr 1 hr I ',I!2 hr 'i/2 hr 1 hr 1 hr 2 hr 2 hr 2 hr 2 hr 1 hr 1 hr 2-1/2 hr 2-1/2 hr 1 hr I/2 hr 1/2 hr 1 hr 1/2 hr Activity Hole swept with slug - 400.00 % hole volume Pulled out of hole to 673.0 ft At BHA Pulled BHA Stand back HWDP and DC's. L/D jars and section mill. BHA Stood back Fluid system Circulated at 26.0 ft R/U and circ to clean stack. Attempted to circulate thru 13-3/8" annulus, pressure to 400 psi, 12.5 ppg EMW, no circulation. Stopped' To change handling equipment Wellhead wdfk .... ' ........ -- ......... Removed Wear bushing Equipment work completed Removed Seal assembly Pulling 9-5/8" packoff at report time. Removed Seal assembly Pull 9-5/8" packoff thru stack. Packoff damaged, had to modify running tool. Recovered packoff. Wellhead work (cont...) Removed Seal assembly (cont...) Pull 9-5/8" packoff thru stack. Packoff damaged, had to modify running tool. Recovered packoff. Equipment work completed Pull Casing, 9-5/8in O.D. Pulled Casing on retrieval string to 25.0 ft PFU 9-5/8" spear and packoff assembly. Catch casing below hanger. Worked pipe to 350K, 400 psi on pump. 2' pipe movement at surface, no circulation. Stopped · To flowcheck well Well control Flow check Gas breaking out of crude/diesel freeze protect in annulus. Closed annular and took gas expansion to gas buster. Well unloaded 37 bbls fluid. No shut in pressure. Lubricate well, took 37 bbls to fill. Observed well static Pull Casing, 9-5/8in O.D. Worked stuck pipe at 2797.0 ft Work pipe to 400K. Pressure to 600 psi attempting to bread circulation. Unable to free casing. Release spear. Aborted attempts to work Casing free at 2797.0 ft Wellhead work Installed Seal assembly Eqpt. work completed, running tool retrieved Installed Wear bushing Eqpt. work completed, running tool retrieved Fluid system Reverse circulated at 2797.0 ft Attempted to circulate down casing annulus. Pumping away at 2 bpm, ' ..... : ,,, ............ ,, ~,o,, Exhibit VI- 9c {' Progress Report Facility PBS Pad Well S-24A Page 4 Rig Nabors 9ES Date 08 September 99 Date/Time 10 Aug 99 15:00 15:00-15:30 15:30 15:30-21:00 15:30-16:00 16:00 16:00-17:00 17:00 17:00-18:00 18:00 18:00-19:30 19:30 19:30-20:30 20:30 20:30-21:00 21:00 21:00-21:30 21:00-21:30 21:30 21:30-23:00 21:30-23:00 23:00 23:00-23,:30 23:00-23:30 23:30 23:30-06:00 23:30-00:30 00:30 00:30-03:00 03:00 03:00-03:30 03:30 03:30-06:00 03:30-06:00 06:00-13:00 Duration 1/2 hr 5-1/2 hr 1/2 hr 1 hr I hr 1-1/2 hr 1 hr 1/2 hr 1/2 hr 1/2 hr 1-I/2 hr 1-1/2 hr 1/2 hr 1/2 hr 6-1/2 hr 1 hr 2-1/2 hr 1/2 hr 2-1/2 hr 2-1/2 hr 7 hr Activity casing. Stopped: To hold safety meeting Held safety meeting Held Technical Limit/Safety Meeting with T. Bunch and D. Abert. Completed operations BHA run no. 2 Made up BHA no. 2 P/U hydraulic multicutter tool. BHA no. 2 made up R.I.H. to 2659.0 ft At 13-3/8in casing shoe To cutting point 10' above 13-3/8" casing shoe. Cut Casing at 2659.0 ft .... ..:.. "-Cut casing ,;i, ith mu!ticutter ...........': ~7- '. Completed operations :'? ..~. ....... Circulated at 2659.0 ft Open 13-3/8" annular valve and allow 9.6 ppg mud to U-tube crude/diesel freeze protect to outside tank. Recovered 100 bbls freeze protect. Hole displaced with Water based mud - 100.00 % displaced S/I to allow oil/gas/mud mixture to separate. Pulled out of hole to 654.4 ft At BHA Pulled BHA L/D casing cutter. BHA Stood back Wellhead work Removed Wear bushing Equipment work completed Fluid system Circulated at 2659.0 ft Closed blind rams and circulated thru cut in 9-5/8" casing. Obtained bottoms up (100% annulus volume) Wellhead work Retrieved Seal assembly Pulled 9-5/8" packoff. Equipment work completed Pull Casing, 9-5/8in O.D. Pulled Casing on retrieval string to 40.0 ft RIH. Latch casing w/spear. Pulled to floor, 145K. Released spear. Fish at surface Rigged up Casing handling equipment Equipment work completed Circulated at 2659.0 ft Pump pill. Heavy slug spotted downhole Laid down Casing of 1200.0 ft Lay down 9-5/8" casing at report time. Laid down Casing of 1200.0 ft L/D 9-5/8" casing. Recovered 67 its + 15' cutjt. Recovered 11 turbulators. Pull Casing, 9-5/8in O.D. (cont...) Exhibit VI- 9c Facility I PBS Pad Progress Report Well S-24A Page Rig Nabors 9ES Date 5 08 September 99 Date/Time 11 Aug 99 06:00-11:00 11:00 11:00-13:00 13:00 13:00-22:00 13:00-14:30 14:30 14:30-15:30 15:30 ~.~.30-I~:30 17:30 17:30-19:30 19:30 19:30-20:30 20:30 20:30-21:30 21:30 21:30-22:00 22:00 22:00-22:30 22:00-22:30 22:30 22:30-23:00 22:30-23:00 23:00 23:00-06:00 23:00-00:30 00:30 00:30-01:30 01:30 01:30-06:00 01:30-06:00 06:00-04:30 06:00-16:30 16:30 16:30-17:30 17:30 Duration 5 hr 2 hr 9 hr 1-1/2 hr 1 hr 2 hr 2 hr 1 hr I hr I/2 hr 1/2 hr 1/2 hr 1/2 hr 1/2 hr 7 hr 1-1/2 hr 1 hr 4-1/2 hr 4-1/2 hr 22-1/2 hr 10-1/2 hr I hr Activity Laid down 2659.0 ft of Casing (cont...) L/D 9-518" casing. Recovered 67 jts + 15' cutjt. Recovered 11 turbulators. 67 joints laid out Rigged down Casing handling equipment R/D and clean rig floor. Equipment work completed BHA run no. 3 Made up BHA no. 3 Fishing BHA, spear. BHA no. 3 made up. R.I.H. to 2659.0 ft At Top of fish: 2659.0 ft Fished at 2659.0 ft ":"?'-""i-i .... - -: Latched fish. Jm'rcd 225K to 275K. ':Attempted to pump. No-go. Good jarring action. Released fish Abandoned effort to pull fish free. Serviced Top drive Inspected derrick and top drive. Repaired sheared bolts in top drive cover plate. Equipment work completed Pulled out of hole to 700.0 ft At BHA Pulled BHA L/D fishing spear, bumper sub, accelerator jars. BHA Stood back Removed Drillfloor ! Derrick Clear floor, P/U Baker tools. Equipment work completed Planned maintenance Serviced Top drive Equipment work completed Wellhead work Installed Wear bushing Eqpt. work completed, running tool retrieved BHA run no. 4 Made up BHA no. 4 Milling BHA. BHA no. 4 made up R.I.H. to 2659.0 ft At Top of fish: 2659.0 ft Milled Casing at 2670.0 ft Milling ahead, 4.5'/hr. 2670' at report time. Milled Casing at 2670.0 ft Milled casing to 2726'. S/D to make a connection. BHA run no. 4 (cont...) Milled Casing at 2726.0 ft (cont...) Milled casing to 2726'. S/D to make a connection. Began precautionary measures Investigated pressure change Wad of mill cuttings backing up flowline and bell nipple. Clean same. Completed operations Facility PBS Pad Exhibit VI- 9c Progress Report Well S-24A Page Rig Nabors 9ES Date 6 08 September 99 Date/Time 12 Aug 99 17:30-20:00 20:00 20:00-20:30 20:30 20:30-23:30 23:30 23:30-02:00 02:00 02:00-03:00 03:00 03:00-04:30 04:30 04:30-06:00 04:30-05:30 05:30 05:30-06:00 06:00 06:00-09:15 06:00-08:00 08:00 08:00-08:15 08:15 08:15-08:30 08:30 08:30-09:00 09:00 09:00-09:15 09:15 09:15-10:00 09:15-10:00 10:00 10:00-13:00 10:00-10:30 10:30 10:30-12:00 Duration 2-1/2 hr 1/2 hr 3 hr 2-1/2 hr 1 hr 1-1/2 hr 1-1/2 hr 1 hr 1/2 hr 3-1/4 hr 2 hr 1/4 hr 1/4 hr 1/2 hr 1/4 hr 3/4 hr 3/4 hr 3 hr I/2 hr 1-1/2 hr Activity Milled Casing at 2739.0 ft Finished milling 70' window for kick off. At Window: 2739.0 ft Circulated at 2739.0 ft Circulate sweep. Flowline plugged off before sweep returns. Stopped: To service drilling equipment Rigged down Flowline Break flowline apart and unplug flowline. Cuttings ball plugging flowline. Equipment work completed Circulated at 2739.0 ft Obtained clean returns - 400.00 % hole volume '""% "5'"'.Primp sweeps, dean metal fro.~' hbl6. ". Puilcfl out of hole to 672.0 ft At BHA Pulled BHA L/D mills. 20% wear on mill. BHA Stood back 4in. Drillpipe workstring run Ran Dfillpipe in stands to 2669.0 ft RIH w/muleshoe. At 13-5/8in casing shoe Washed to 2820.0 ft Wash to 2820' at report time. (Top of 18 ppg pill.) At Setting depth: 2820.0 ft Bottom of cement plug. 4in. Drillpipe workstring run (cont...) Circulated at 2820.0 ft Hole swept with slug - 200.00 % hole volume Pulled Drillpipe in stands to 2615.0 ft At top of check trip interval Ran Dfillpipe in stands to 2820.0 ft No resistance. Stopped: To circulate Circulated at 2820.0 ft Stopped: To hold safety meeting Held safety meeting Held PJSM w/Dowell. Completed operations Cement: Kickoff plug Mixed and pumped slurry - 65.000 bbl Pump 5 bbls H20. Test lines to 3000 psi. Pump 35 bbls H20, 65 bbls cmt, 3 bbls H20. Displace with 17.5 bbls 9.6 ppg mud. Cement pumped CIP 1000 hrs 8/12/99. 4in. Dfillpipe workstfing run Pulled Drillpipe in stands to 2150.0 ft Stopped: To circulate Circulated at 2150.0 ft Circulate and clean hole. Got 2 bbls cmt contaminated mud to surface. Exhibit VI- 9c Progress Report Facility PBS Pad Well S-24A Rig Nabors 9ES Page 7 Date 08 September 99 Date/Time 13 Aug 99 12:00 12:00- ! 3:00 13:00 13:00-14:30 13:00-13:30 13:30 13:30-14:00 14:00 14:00-14:30 14:30 14:30- ! 7:00. 14:30-15:00 15:00 15:00-17:00 17:00 17:00-06:00 17:00-19:00 19:00 19:00-20:00 20:00 20:00-20:30 20:30 20:30-22:30 22:30 22:30-23:00 23:00 23:00-06:00 06:00-12:00 06:00-07:00 07:00 07:00-10:00 10:00 10:00-11:00 11:00 11:00-12:00 12:00 12:00-18:00 12:00-17:00 17:00 17:00-18:00 Duration 1 hr 1-1/2 hr 1/2 hr 1/2 hr 1/2 hr , .9.,-IL.z n;: 1/2 hr 2 hr 13hr 2 hr 1 hr 112 hr 2 hr 1/2 hr 7 hr 6 hr I hr 3 hr 1 hr 1 hr 6 hr 5 hr I hr Activity Obtained clean returns - 150.00 % hole volume Pulled Drillpipe in stands to 0.0 ft Pump pill and POH. L/D muleshoe. At Surface' 0.0 ft Wellhead work Removed Wear bushing Equipment work completed Circulated at 25.0 ft Washed stack with perforated joint. Functioned BOP's. Stopped · To service drilling equipment Installed Wear bushing Eqpt. work completed, running tool retrieved Play. ned maintenan'ce ........ :. ' ....................... ::-'-"-:----.-..:: :' . .... Serviced Drillfloor / Derrick ' Cleared and cleaned rig floor. Equipment work completed Serviced Rotary table Level rig. Settling moved rig off center. Equipment work completed BHA run no. 5 Made up BHA no. 5 BHA no. 5 made up R.I.H. to 2364.0 ft RIH to 2100'. Washed to 2364', TOC. Observed 20.00 klb resistance Drilled cement to 2397.0 ft Stopped to test casing Circulated at 2397.0 ft Obtained clean returns - 150.00 % hole volume Cement contaminated mud. Tested Casing - Via annulus Tested 13-3/8" casing to 2500 psi for 30 min, bled off 178 psi, OK. Pressure test completed successfully - 2500.000 psi Drilled cement to 2610.0 ft Drilling hard cement. (Very hard) 30K wob, 100 rpm, 650 gpm. Drilling cement at report time. BHA run no. 5 (cont...) Drilled cement to 2669.0 ft Finished drill cement to 13-3/8" csg shoe. Completed operations Circulated at 2669.0 ft Circ and cond cement contaminated mud. Obtained clean returns - 300.00 % hole volume Pulled out of hole to 932.0 ft At BHA Pulled BHA ldD steel DC' s, stood back HWDP. BHA Laid out BHA run no. 6 Made up BHA no. 6 BHA no..6 made up R.I.H. to 2400.0 ft Facility !, PBS Pad Exhibit VI- 9c i' Progress Report Well S-24A Page 16 Rig Nabors 9ES Date 08 September 99 Date/Time 09:00-14:00 14:00 14:00-15:00 15:00 15:00-17:00 17:00 17:00-18:30 18:30 18:30-20:30 '":" .... ..18:30-20:30 20:30 20:30-06:00 20:30-23:00 23:00 23:00-04:30 26 Aug 99 04:30 04:30-06:00 06:00-15:30 06:00-12:30 12:30 12:30~13:00 13:00 13:00-15:00 15:00 15:00-15:30 15:30 15:30-22:00 15:30-19:00 19:00 Duration 5 hr 1 hr 2 hr 1-1/2 hr 2 hr .2-h~ ..... 9-1/2 hr 2-1/2 hr 5-1/2 hr 1-1/2 hr 9-1/2 hr 6-1/2' hr 1/2 hr 2 hr I/2 hr 6-1/2 hr 3-1/2 hr Activity Pulled out of hole to 2669.0 ft At 13-3/8in casing shoe POOH. Kingak 20-30 klbs o/pull. Hole in good shape. Serviced Block line Line slipped and cut Pulled out of hole to 1000.0 ft At BHA Pulled BHA BHA Laid out Laid out BHA. Top stabiliser balled in water courses. Bit balled on one water course plugging one jet. Bit in excellent condition. BOP/riser operations - BOP stack ' stall d-T p .... n ~ ' O rat-Il ........... '~ ...... ~ ....... --'" · .-. Equipment work completed . Pull wear bushing. Change top rams to 7" and test same to 3500 psi. Pull test plug. Run Casing, 7in O.D. Rigged up Casing handling equipment Work completed - Casing handling equipment in position Clear rigfloor. R/U casing handling equipment and Fill up tool. Hold PJSM. Ran Casing to 2669.0 ft (7in OD) At 7in casing shoe Check Floats. Bakerlock shoetrack. Run 7", 26 lb/ft casing to 13.3/8" shoe @ 2669 ft. Circulated at 2669.0 ft Circulate casing contents - 5 BPM/205 psi. Run Casing, 7in O.D. (cont...) Ran Casing to 7684.0 ft (7in OD) Observed 10.00 klb resistance RIH. Up and down drags following consistent trend. At 7,684 ft unable to pull up- overpull= 350 Klbs. In HRZ formation. Circulated at 7684.0 ft Broke circulation Circulate @ 2 BPM/300 psi- OK. Able to breakover pull @ 335-350 KLbs. Decision made to RIH without attempting any further pick up weights. Ran Casing to 10180.0 ft (7in OD) On bottom RIH. Tag bottom circulating last 20 ft. Final slack-off weight @ 155 klbs. 251 joints of 7", 26 lb/ft casing run. Rigged down Casing handling equipment Equipment work completed R/D Franks Fill up tool. Packer element damaged but intact. R/IJ Dowell cement head. Cement' Casing cement Circulated at 10180.0 ft Obtained clean returns - 120.00 % hole volume Stage up pumps very slowly from 1 BPM to 6.6 BPM over a two hour period. Final circulating pressure @ 6.6 BPM/500 psi. Circulating 130% string contnets, ......... ' ........... '""'~ PJSM .... :'- ' I ' g Exhibit VI- 9c i" Progress Report Facility PBS Pad Well S-24A Page 17 Rig Nabors 9ES Date 08 September 99 Date/Time 19:00-19:15 19:15 19:15-20:15 20:15 20:15-21:30 21:30 21:30-22:00 22:00 22:00-00:30 22:00-00:30 27 Aug 99 00:30 00:30-06:00 00:30-06:00 06:00 06:00-06:15 06:00-06:15 06:15 06:15-I0:00 06:15-10:00 10:00 10:00-12:00 10:00-10:30 10:30 10:30-12:00 12:00 12:00-03:30 12:00-13:00 13:00 13:00-17:00 Duration 1/4 hr I hr 1-1/4 hr 1/2 hr 2-1/2 hr 2-1/2 hr 5-1/2 hr 5-1/2 hr 1/4 hr 1/4 hr 3-3/4 hr 3-3/4 hr 2 hr 1/2 hr 1-1/2 hr 15-1/2 hr 1 hr 4 hr Activity Pumped Water based mud spacers - volume 30.000 bbi Required volume of spacer pumped Pump 5 bbl 11.0 ppg spacer. Test lines. Pump remainder of spacer. Mixed and pumped slurry - 250.000 bbl Cement pumped Mix and pump 195 bbls Lead Slurry @ 11.5 ppg ( 393 sx). Drop Bottom PLug. Mix and pump 55 bbls Tail slurry @ 15.8 ppg ( 267 sx). Drop Top Plug. Displaced slurry - 383.000 bbl Plug bumped Displace slurry @ 6.6 BPM/170 psi. Final pressure pii6r to .bump @-,?)7~"BPlg!~T20iiSsi. Efficiency of-. pumps @ 97%. Pressure.up to'3000 psi. Bleed off. Check floats- OK. CIP @ 2130 hrs.Total volume lost = 10 bbls. Flow check Observed well static Observe well 30 minutes while clearing rigfloor and preparing cellar. BOP/riser operations - BOP stack Rigged up BOP stack Equipment work completed Nfl) BOP to set emergency slips. Wellhead work Installed Slip & seal assembly Equipment work completed With 220 klbs string tension- set emergency slips. Evacuate 7" landing joint of fluid. Make rough cut. LID jr. Redress tubing spool. Make final cut. Install Tubing Spool and prepare to test @ report time. Wellhead work (cont...) Tested Tubing head spool Pressure test completed successfully - 4300.000 psi Test Tubing Spool and pack-off to 4300 psi. BOP/riser operations - BOP stack Installed BOP stack Equipment work completed Nipple up BOP. BHA run no. 10 Rigged down Casing handling equipment Equipment work completed Change out Long bails to short bails. Clear rigfloor. Made up BHA no. 10 BHA no. 10 made up MFLI Cleanout assembly and stand back in derrick. BOP/riser operations - BOP stack Installed Top ram Equipment work completed Change out top 7" rams back to 3.1/2" x 6" Variables. Tested BOP stack ' Facility PBS Pad Dated'rime 17:00 17:00-03:30 28 Aug 99 03:30 03:30-06:00 03:30-06:00 , 06:00-09:30 · .506:00-07:00 07:00 07:00-07:30 07:30 07:30-09:30 09:30 09:30-10:30 09:30-10:30 10:30 10:30-23:30 10:30-11:30 11:30 11:30-12:30 12:30 12:30-16:00 16:00 16:00-17:00 17:00 17:00-19:00 19:00 19:00-19:30 19:30 19:30-23:30 23:30 23:30-06:00 Exhibit VI - 9c {' Progress Report Well S-24A Page 18 Rig Nabors 9ES Date 08 September 99 Duration 10-1/2 hr 2-1/2 hr 2~1/2 hr 3-1/2 hr !' hr 1/2 hr 2 hr 1 hr 1 hr 13hr 1 hr 1 hr 3-1/2 hr I hr 2 hr 1/2 hr 4 hr 6-1/2 hr Activity Suspended pressure test on Annular preventor, observed leak RJU test string and run test plug. Test BOPE to 250 psi/4000 psi. Unable to obtain satisfactory test on Annular Installed Annular preventor Equipment work completed Change out Annular element. Run Test string and retest element to 250/3500 psi. Test Blinds to 4000 psi. R/D Test string, run wear ring. BHA run no. 10 R.I.H. to 3400.0 ft RIH picking up 100 joints of 3.1/2" drillpipe. BHA run no. 10 (cont...) s~:,.~,a2,:?: !i:.:-crfin:~ip'e:to 35'~t0.o ft ................................ ............ irv"i . . cO,:omts picked up RIH picking up 3. liT' drillpipe for 6.1/8' hole section. Circulated at 3540.0 ft Broke circulation Circulate string contents. R.I.H. to 9691.0 ft Stopped: To circulate Fluid system Freeze protect well - 100.000 bbl of Fresh water Completed operations Line up on 7" x 13.3/8" annulus. Pump 100 bbls of Fresh water @ 5 BPM/450 psi ( staging up rate). Line up to HB & R. BHA run no. 10 Washed to 10100.0 ft At Top of cement: 10100.0 ft Wash down @ 5 BPM/1700 psi and tag Float Collar 3 ft deep. While washing down HB & R freeze protect outer annulus with 210 bbls diesel @ 3 BPM/1450 psi. Tested Casing - Via annulus and string Pressure test completed successfully - 4000.000 psi Line up and test 7" casing to 4000 psi/30 minutes. ( 4.2 bbls pumped/returned). Drilled cement to 10187.0 ft Stopped: To circulate Drill hard cement @ 30-40 fph, 8 Kibs WOB. Circulated at 10187.0 ft Obtained bottoms up (100% annulus volume) Circulated at 10187.0 ft Hole displaced with Water based mud - I00.00 % displaced Displace well to 8.4 ppg Quikdrill mud while reciprocating/rotating pipe.Off bottom tq @ 8,000 ft lbs. Flow check Observed well static Pulled out of hole to 0.0 ft At Surface: 0.0 ft BHA run no. 11 Exhibit VI-10:S-3 lA Well Integri _ty Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: Schrader Bluff Penetration Casing Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 12/21/90 12-1/4" 9-5/8" Producer None Comments: The initial 9-5/8" primary cement job consisted of 1380 sacks (2343 ft3) of cement, after cementing, floats failed to hold and cement was encountered 173' above in the 9-5/8" casing shoe. An estimated 2250 ft3 of cement was placed behind the pipe 9-5/8" casing. Additional Information: Exhibit VI- 10a Well Diagram Exhibit VI-1 Ob Directional Survey Exhibit VI- 10c Significant Workover & Drilling Daily Reports TREE = 4" OW WB_L~cAD= FMI ACTUATOR = OTIS KB. ELEV = 66.50' BF. ELEV = 38.30' KOP = 2449' MaxAngle= 98@ 11000' Da~m MD= 13119' Daluml'VD = 8800'SS I13-3/8" CSG, 68#, NT-80, ID = 12.415" H Exhibit VI- lOa S-31A 2708' SAFETY NOTES: CTD HORIZ SIDETRACK IN SAG RIVER FORMATION -70°@ 10869' AI~) 90° @ 10928' CHROME TBG AI~D LNR 2144' H4-1/2" OTIS SSSV NIP, ID= 3.813" 2707' H-~ GAS LIFT MANDRELS IMinimum ID = 2.313" @ 10551 2-7/8" OTIS X NIPPLE ITOPOF2-7/8" LNR H 10510' ITOPOF7" LNR H 10534' I4-1/2"TBG, 12.6~, NT-13-CR-80, 0.0152 bpf, ID= 3.958" I 9-5/8" CSG, 47#, NT-80-S, ID=8.681" I--~ 10571' 10783' 10782' 10482' ~--~4-1/2" PARKERSWS NIP, D=3.813" I 10485' HTnNT~GANCHOR I 10486' ~--~9-5/8" X4-1/2"TIWPKR, ID=4.0(7' I 10539' H 4-1/2" PARKER SWS NIP, D=3.813" 10551' H2-7/8'' OTISX NIP, D =2.313" I 10559' H4-1/Z' PARKERSWN NIP, ID= 3.725" 10571' H4-1/2" TBG TAILW/LEG I 10562' H ELMD 1-r LOGGED 01/06/91I IWHPSTOCK H 10791' MILLOUT WINDOW: 10785' - 10792' I PBTD H 11338' 7- LNR, 26~, NT-13-CR, 0.0383 bpf, ID = 6.27E' H 11428' DATE REV BY COIVIVlENTS DATE REV BY COMIVENTS 12/20/90 DFF ORIGINAL COIVPLETION 03/01/02 RN/'[P CORRECTIONS 11/05/98 WHITLOV~ SIDETRACK COMPLETION 01/21/99 GLM LAST WORKOV ER 03/15/01 SIS-IVH CONVERTEDTO CANVAS 03/16/01 SIS-CS FINAL PRUDHOE BAY UNIT WELl. S-31A PERMIT No: 198-2200 APl No: 50-029-22109-01 SEC35, T121~ T12E BP Exploration (Alaska) Well ,S-31A Directional Surv~" Exhibit Vi - 10b APZ/UWZ: 500292210901 Survey Type: COMP Company: Baker Tool Company Survey Date: 03/24/99 SurveyTop: 0' MD Survey Btm: 13,038' MD MD TVD SS ZNCLZNE AZZMUTH 0 0.00 66.50 0.00 0.00 92 92.00 -25.50 0.00 0.00 98 98.35 -31.85 0.22 123.53 111 111.00 -44.50 0.20 113.14 125 125.35 -58.85 0.17 107.92 142 142.05 -75.55 0.12 109.29 159 158.75 -92.25 0.08' 122.04 175 175.45 -108.95 0.10 142.75 192 192.05 -125.55 0.13 155.32 209 208.75 -142.25 0.15 157.04 225 225.45 -158.95 0.18 154.40 242 242.05 -175.55 0.20 146.79 259 258.75 -192.25 0.20 139.20 275 275.40 -208.90 0.20 133.99 292 292.10 -225.60 0.22 124.68 309 308.65 -242.15 0.20 115.83 325 325,30 -258,80 0,15 110.53 342 341,90 -275,40 0,12 108,00 358 358,40 -291,90 0,07 117,19 375 375,00 -308,50 0,03 141,22 392 391,55 -325,05 0,07 153,82 408 408,15 -341,65 0,08 149,11 425 424,75 -358,25 0,10 151,11 441 441,40 -374,90 0,12 157,32 458 458,15 -391,65 0.13 156,91 475 474,85 -408,35 0,15 152,43 492 491,65 -425,15 0,17 147,32 508 508,30 -441,80 0,17 142,88 525 525,00 -458,50 0,17 138,48 542 541,70 -475,20 0,15 131,08 558 558,45 -491,95 0,13 124,83 575 575,10 -508,60 0,12 122,13 592 591,80 -525,30 0.08 123,68 609 608,50 -542,00 0,05 139,16 625 625,10 -558,60 0,05 168.05 642 641,80 -575,30 0,07 186,71 659 658,50 -592,00 0,08 193,00 675 675,15 -608,65 0,10 .193,43 692 691,85 -625,35 0,12 180,49 708 708,45 -641,95 0,13 169,58 725 725,15 -658,65 0,15 158,94 742 741,65 -675,15 0,15 147,42 758 758,15 -691,65 0,12 139,19 775 774,55 -708,05 0,10 129,30 791 790,95 -724,45 0,10 122,52 807 807,35 -740,85 0,08 118,61 824' 823,65 -757,15 0,'07 '112,58 840 840,00 -773,50 0,05 111,29 856 856,35 -789,85 0,05 113,89 873 872,65 -806,15 0,03 164,75 DOG LEG 0,0 00 35 03 02 03 03 02 0,2 0,1 0,2 0,2 0,2 0,1 0,2 0,2 0,3 0,2 0,3 0,3 0,3 0,1 0,1 0,1 0,1 0,1 0,2 0,1 0,1 0,2 0,2 0,1 0,2 0,2 0,2 0,2 0,1 0,1 0,2 0,2 0,2 0,2 0,2 0,2 0,1 0,1 0,1 0,1 0,0 0,2 ASP_X ASP_Y 619,611.9 5,979,855.1 619,611.9 5,979,855.1 619,611.9 5,979,855.1 619,611.9 5,979,855.1 619,612.1 5,979,855.1 619,612.1 5,979,855.1 619,612.1 5,979,855.1 619,612.2 5,979,855.1 619,612.2 5,979,855.1 619,612.2 5,979,855.1 619,612.2 5,979,854.7 619,612.2 5,979,854.7 619,612.2 5,979,854.7 619,612.3 5,979,854.7 619,612.3 5,979,854.7 619,612.3 5,979,854.7 619,612.4 5,979,854.7 619,612.4 5,979,854.7 619,612.4 5,979,854.7 619,612.4 5,979,854.7 619,612.6 5,979,854.7 619,612.6 5,979,854.7 619,612.6 5,979,854.7 619,612.6 5,979,854.4 619,612.6 5,979,854.4 619,612.6 5,979,854.4 619,612.6 5,979,854.4 619,612.6 5,979,854.4 619,612.7 5,979,854.4 619,612.7 5,979,854.4 619,612.7 5,979,854.4 619,612.8 5,979,854.4 619,612.8 5,979,854.4 619,612.8 5,979,854.4 619,612.8 5,979,854.4 619,612.8 5,979,854.4 619,612.8 5,979,854.4 619,612.8 5,979,854.0 619,612.8 5,979,854.0 619,612.8 5,979,854.0 619,612.8 5,979,854.0 619,612.8 5,979,854.0 619,612.8 5,979,854.0 619,612.8 5,979,854.0 619,612.9 5,979,854.0 619,612.9 5,979,854.0 619,612.9 5,979,854.0 619,612.9 5,979,854.0 619,612.9 5,979,854.0 619,612.9 5,979,854.0 889 905 922 938 955 971 988 1,004 1,021 1,037 1,053 1,070 1,086 1,103 1,119 1.135 1.152 1.168 1,185 1.201 1,217 1,234 1,250 1,267 1,283 1,299 1,316 1,332 1,349 1,365 1.381 1.398 1.414 1.431 1.447 1.464 1,480 1,497 1,513 1,530 1,546 1,562 ].,579 1,595 1,611 1,627 1,643 1,660 1,676 1,692 1,708 1,724 1,740 1,757 1.773 1 789 1.805 1.821 1.837 1,854 1,870 1.886 1.902 1.918 1.934 1,950 1,966 1,983 1,999 2,015 889.05 905.40 921.85 938.30 954.80 971.25 987.65 1,004.10 1,020.60 1,037.00 1,053.35 1,069.75 1,086.20 1,102.60 1,119.05 1,135.45 1,151.85 1,168.25 1,184.65 1,201.05 1,217.45 1,233.85 1,250.35 1,266.70 1,283.05 1,299.45 1,315.85 1,332.25 1,348.64 1,364.99 1,381.39 1,397.89 1,414.39 1,430.89 1,447.34 1,463.79 1,480.34 1,496.79 1,513.29 1,529.74 1,546.19 1,562.39 1,578.59 1,594.79 1,610.94 1,627.19 1,643.34 1,659.54 1,675.74 1,691.89 1,708.04 1,724.24 1,740.39 1,756.54 1,772.74 1,788.84 1,805.04 1,821.19 1,837.34 1,853.54 1,869.64 1,885.79 1,901.94 1,918.04 1,934.19 1,950.29 1,966.44 1,982.69 1,998.84 2,015.04 -822.55 -838.90 -855.35 -871.80 -888.30 -904.75 -921.15 -937.60 -954.10 -970.50 -986.85 -1,003.25 -1,019.70 -1,036.10 -1,052.55 -1,068.95 -1,085.35 -1,101.75 -1,118.15 -1,134.55 -1,150.95 -1,167.35 -1,183.85 -1,200.20 -1,216.55 -1,232.95 -1,249.35 -1,265.75 -1,282.14 -1,298.49 -1,314.89 -1,331.39 -1,347.89 -1,364.39 -1,380.84 -1,397.29 -1,413.84 -1,430.29 -1,446.79 -1,463.24 -1,479.69 -1,495.89 -1,512.09 -1,528.29 -1,544.44 -1,560.69 -1,576.84 -1,593.04 -1,609.24 -1,625.39 -1,641.54 -1,657.74 -1,673.89 -1,690.04 -1,706.24 -1,722.34 -1,738.54 -1,754.69 -1,770.84 -1,787.04 -1,803.14 -1,819.29 -1,835.44 -1,851.54 -1,867.69 -1,883.79 -1,899.94 -1,916.19 -1,932.34 -1,948.54 hibit VI- lOb -.. 0.17 270.37 0.18 268.55 0.20 266.02 0.22 265.03 0.25 266.34 0.25 266.67 0.23 267.01 0.23 266.39 0.22 265.02 0.20 264.86 0.17 265.45 0.15 267.83 0.17 272.05 0.17 278.87 0.17 286.94 0.18 290.15 0.18 291.20 0.22 292.01 0.25 290.71 0.27 289.43 0.28 289.45 0.28 288.58 0.30 284.72 0.32 280.99 0.30 278.51 0.32 275.81 0.30 273.62 0.30 272.64 0.28 270.30 0.28 267.59 0.27 268.87 0.25 270.70 0.25 270.73 0.27 271.06 0.27 273.12 0.27 274.80 0.28 275.04 0.28 276.10 0.28 277.11 0.30 278.44 0.30 278.89 0.30 278.94 0.30 279.49 0.32 278.28 0.33 276.77 0.33 278.32 0.33 278.76 0.35 279.72 0.35 279.33 0.35 276.70 0.37 276.57 0.37 276.88 0.38 276.82 0.38 277.64 0.35 277.39 0.33 274.17 0.30 275.22 0.27 275.51 0.25 271.22 0.18 270.71 0.15 267.83 0.13 263.36 0.08 254.71 0.07 246.96 0.08 247.79 0.08 239.72 0.2 0.4 0.1 0.2 0.2 0.1 0.1 0.1 0.2 0.0 0.1 0.0 0.1 0.1 0.2 0.1 0.1 0.1 0.2 0.1 0.0 0.2 0.2 0.1 0.1 0.0 0.2 0.2 0.2 0.2 0.1 0.0 0.1 0.1 0.1 0.1 0.0 0.1 0.1 0.1 0.1 0.0 0.0 0.1 0.0 0.0 0.0 0.1 0.1 0.1 0.0 0.1 0.0 0.1 0.1 0.0 0.1 0.0 0.2 0.2 0.2 0.2 0.2 0.4 0.2 0.1 0.3 0.1 0.1 0.1 - - 619,612.9 619,6~"" q 619,6~. 3 619,612.9 619,612.8 619,612.8 619,612.7 619,612.7 619,612.6 619,612.6 619,612.5 619,612.5 619,612.3 619,612.3 619,612.2 619,612.2 619,612.2 619,612.1 619,612.1 619,612.0 619,612.0 619,612.0 619,611.8 619,611.8 619,611.7 619,611.6 619,611.6 619,611.5 619,611.3 619,611.2 619,611.2 619,611.1 619,611.0 619,611.0 619,610.9 619,610.9 619,610.7 619,610.6 619,610.6 619,610.5 619,610.4 619,610.4 619,610.2 619,610.2 619,610.1 619,610.0 619,609.9 619,609.9 619,609.7 619,609.6 619,609.5 619,609.5 619,609.4 619,609.2 619,609.1 619,609.1 619,609.0 619,608.9 619,608.8 619,608.6 619,608.5 619,608.5 619,608.4 619,608.4 619,608.3 619,608.3 619,608.3 619,608.3 619,608.1 619,608.1 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,97.9,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.0 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 2,031 2,0~47 2,064 2,080 2,096 2,112 2,128 2,144 2,160 2,177 2,193 2,209 2,225 2,241 2,257 2,273 2,289 2,305 2,322 2,338 2,354 2,370 ' 2,386 2,402 2,418 2,433 2,449 2,465 2,481 2,497 2,513 2,529 2,545 2,561 2,577 2.593 2.609 2.625 2.641 2.657 2.673 2.689 2.705 2,720 2,736 2.752 2,768 2,784 2,800 2,816 2,832 2,848 2,864 2,879 2,895 2,911 2,927 2,943 2,959 2,975 2,991 3,007 3,022 3,038 3,054 3,070 3,086 3,102 3,118 3,133 2,031.19 2,047.29 2,063.49 2,079.59 2,095.79 2,111.88 2,128.08 2,144.17 2,160.26 2,176.44 2,192.52 2,208.69 2,224.65 2,240.61 2,256.66 2,272.69 2,288.76 2,304.83 2,320.92 2,336.86 2,352.72 2,368.58 2,384.41 2,400.23 2,416.02 2,431.70 2,447.35 2,463.08 2,478.73 2,494.36 2,509.95 2,525.53 2,541.02 2,556.64 2,572.12 2,587.58 2,603.04 2,618.38 2,633.79 2,649.07 2,664.32 2,679.55 2,694.75 2,709.93 2,725.08 2,740.20 2,755.29 2,770.34 2,785.34 2,800.35 2,815.28 2,830.18 2,845.07 2,859.93 2,874.72 2,889.48 2,904.24 2,918.96 2,933.64 2,948.27 2,962.85 2,977.37 2,991.83 3,006.20 3,020.61 3,034.93 3,049.25 3,063.47 3,077.44 3,091.36 -1,964.69 -1,980.79 -1,996.99 -2,013.09 -2,029.29 -2,045.38 -2,061.58 -2,077.67 -2,093.76 -2,109.94 -2,126.02 -2,142.19 -2,158.15 -2,174.11 -2,190.16 -2,206.19 -2,222.26 -2,238.33 -2,254.42 -2,270.36 -2,286.22 -2,302.08 -2,317.91 -2,333.73 -2,349.52 -2,365.20 -2,380.85 -2,396.58 -2,412.23 -2,427.86 -2,443.45 -2,459.03 -2,474.52 -2,490.14 -2,505.62 -2,521.08 -2,536.54 -2,551.88 -2,567.29 -2,582.57 -2,597.82 -2,613.05 -2,628.25 -2,643.43 -2,658.58 -2,673.70 -2,688.79 -2,703.84 -2,718.84 -2,733.85 -2,748.78 -2,763.68 -2,778.57 -2,793.43 -2,808.22 -2,822.98 -2,837.74 -2,852.46 -2,867.14 -2,881.77 -2,896.35 -2,910.87 -2,925.33 -2,939.70 -2,954.11 -2,968.43 2,982.75 -2,996.97 -3,010.94 -3,024.86 .hibit VI- 1 Ob 0.80 327.35 1.25 325.20 1.65 325.28 2.10 325.67 2.50 325.70 2.82 325.24 3.15 324.63 3.55 323.61 3.97 322.54 4.48 321.53 4.95 320.93 5.37 320.55 5.80 320.10 6.23 319.59 6.70 319.06 7.12 318.70 7.57 318.52 8.03 318.54 8.48 318.79 8.90 319.00 9.37 319.15 9.88 319.35 10.30 319.32 10.83 319.09 11.37 318.89 11.85 318.70 12.30 318.47 12.70 318.30 13.17' 318.21 13.58 318.23 14.12 318.25 14.62 318.22 15.03 318.29 15.48 318.44 15.85 318.56 16.23 318.64 16.55 318.66 16.87 318.76 17.18 318.90 17.47 318.89 17.87 318.73 18.20 318.57 18.58 318.41 19.10 318.02 19.58 317.52 19.98 317.11 20.25 316.87 20.50 316.69 20.70 316.60 20.92 316.57 21.20 316.51 21.60 316.49 22.03 316.48 22.38 316.48 22.82 316.52 23.25 316.53 23.77 316.48 24.35 316.43 24.78 316.41 25.18 316.42 25.53 316.44 25.97 316.36 26.38 316.23 26.82 316.17 27.35 316.13 27.75 316.12 0.2 0.3 0.6 1.4 3.0 2.8 2.5 2.8 2.5 2.0 2.1 2.5 2.7 3.2 2.9 2.6 2.7 2.7 2.9 2.6 2.8 2.9 2.8 2.6 2.9 3.2 2.6 3.3 3.4 3.0 2.8 2.5 3.0 2.6 3.4 3.1 2.6 2.8 2.3 2.4 2.0 2.0 2.0 1.8 2.5 2.1 2.4 3.4 3.2 2.7 1.8 1.6 1.3 1.4 1.8 2.5 2.7 2.2 2.8 2.7 3.3 3.7 2.7 2.5 2.2 2.8 2.6 2.8 3.4 2.6 ,-% ,- 619,608.1 619,69~ ~ 619,66 619,608.1 619,608.0 619,607.9 619,607.6 619,607.3 619,606.9 619,606.5 619,606.0 619,605.5 619,604.9 619,604.1 619,603.2 619,602.4 619,601.2 619,600.1 619,599.0 619,597.7 619,596.3 619,594.8 619,593.3 619,591.7 619,589.9 619,588.2 619,586.3 619,584.4 619,582.3 619,580.2 619,577.9 619,575.6 619,573.1 619,570.6 619,568.1 619,565.4 619,562.6 619,559.8 619,556.8 619,554.0 619,550.9 619,547.8 619,544.7 619,541.5 619,538.3 619,535.0 619,531.6 619,528 1 619,524 5 619,520 7 619,517 0 619,513 2 619,509 2 619,505 3 619,501 3 619,497 3 619,493 2 619,488.9 619,484.7 619,480.3 619,475.9 619,471.3 619,466.7 619,462.0 619,457.3 619,452.4 619,447.4 619,442.5 619,437.4 619,432.2 b,979,Sb4.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.3 5,979,854.7 5,979,855.0 5,979,855.4 5,979,856.1 5,979,856.5 5,979,857.2 5,979,857.9 5,979,859.0 5,979,859.7 5,979,860.8 5,979,861.9 5,979,863.0 5,979,864.4 5,979,865.9 5,979,867.3 5,979,868.8 5,979,870.2 5,979,872.0 5,979,873.8 5,979,875.6 5,979,877.8 5,979,879.9 5,979,882.1 5,979,884.3 5,979,886.4 5,979,889.0 5,979,891.5 5,979,894.4 5,979,896.9 5,979,899.8. 5,979,902.7 5,979,905.6 5,979,908.8 5,979,912.1 5,979,915.3 5,979,918.5 5,979,921.8 5,979,925.4 5,979,929.0 5,979,932.6 5,979,936.2 5,979,939.8 5,979,943.4 5,979,947.4 5,979,951.4 5,979,955.3 5,979,959.3 5,979,963.3 5,979,967.2 5,979,971.6 5,979,975.5 5,979,979.9 5,979,984.2 5,979,988.5 5,979,992.8 5,979,997.5 5,980,002.2 5,980,006.5 5,980,011.6 5,980,016.3 5,980,021.3 5,980,026.3 5,980,031.4 5,980,036.4 5,980,041.5 3,1.65 3,180 3,196 3,212 3,227 3,243 3,258 3,274 3,290 3,305 3,321 3,337 3,352 3,368 3,383 3,399 3,415 3,430 3,446 3,462 3,477 3,493 3,509 3,524 3,540 3,556 3,571 3,587 3,603 3,619 3,634 3,650 3,666 3,681 3,697 3.713 3.729 3,744 3,760 3 376 3,793 3,813 3,836 3,853 3,866 3,869 3,884 3,905 3,930 3,955 3,981 4,007 4,032 4,058 4,084 4,110 4,136 4,162 4,188 4,214 4,240 4,266 4,291 4,317 4,343 4,369 4,395 4,421 4,446 ,4 ,47') -%, J. UD. J.'-~ 3,118.91 3,132.62 3,146.24 3,159.83 3,173.46 3,186.95 3,200.41 3,213.92 3,227.34 3,240.73 3,254.08 3,267.34 3,280.55 3,293.71 3,306.78 3,319.87 3,332.79 3,345.72 3,358.60 3,371.35 3,384.13 3,396.84 3,409.41 3,421.92 3,434.45 3,446.91 3,459.32 3,471.70 3,483.93 3,496.08 3,508.15 3,520.22 3,532.17 . 3,544.07 3,555.98 3,567.75 3,579.46 3,591.03 3,602.63 3,614.18 3,626.74 3,641.89 3,658.41 3,671.18 3,680.01 3,682.67 3,693.13 3,708.91 3,726.68 3,744.50 3,763.18 3,781.92 3,800.57 3,819.24 3,837.83 3,856.43 3,875.10 3,893.67 3,912.24 3,930.75 3,949.15 3,967.53 3,985.88 4,004.32 4,022.70 4,041.02 4,059.27 4,077.37 4,095.34 -.D, U.~O. O'-I' -3,052.41 -3,066.12 -3,079.74 -3,093.33 -3,106.96 -3,120.45 -3,133.91 -3,147.42 -3,160.84 -3,174.23 -3,187.58 -3,200.84 -3,214.05 -3,227.21 -3,240.28 -3,253.37 -3,266.29 -3,279.22 -3,292.10 -3,304.85 -3,317.63 -3,330.34 -3,342.91 -3,355.42 -3,367.95 -3,380.41 -3,392.82 -3,405.20 -3,417.43 -3,429.58 -3,441.65 -3,453.72 -3,465.67 -3,477.57 -3,489.48 -3,501.25 -3,512.96 -3,524.53 -3,536.13 -3,547.68 -3,560.24 -3,575.39 -3,591.91 -3,604.68 -3,613.51 -3,616.17 -3,626.63 -3,642.41 -3,660.18 -3,678.00 -3,696.68 -3,715.42 -3,734.07 -3,752.74 -3,771.33 -3,789.93 -3,808.60 -3,827.17 -3,845.74 -3,864.25 -3,882.65 -3,901.03 -3,919.38 -3,937.82 -3,956.20 -3,974.52 -3,992.77 -4,010.87 -4,028.84 _,4 I'1,4~ -;~ xhibit VI - lOb 29.97 316.44 30.27 316.53 30.53 316.60 30.78 316.68 31.07 316.74 31.33 316.77 31.60 316.79 31.95 316.84 32.27 316.85 32.75 316.82 33.32 316.78 33.82 316.75 34.33 316.73 34.72 316.72 35.03 316.70 35.35 316.67 35.72 316.65 36.13 316.69 36.48 316.71 36.90 316.70 37.27 316.70 37.60 316.77 37.98 316.89 38.37 316.96 38.83 317.07 39.30 317.17 39.78 317.21 40.23 317.25 40.58 317.27 40.93 317.31 41.23 317.34 41.58 317.33 41.98 317.33 42.27 317.34 42.50 317.35 42.67 317.35 42.85 317.33 43.02 317.33 43.07 317.39 43.18 317.41 43.20 317.39 43.25 317.40 43.58 317.41 43.65 317.38 43.83 317.39 43.85 317.38 43.83 317.33 43.92 317.31 43.97 317.36 43.98 317.40 44.07 317.35 44.12 317.29 44.08 317.25 44.12 317.24 44.27 317.24 44.48 317.23 44.72 317.22 44.70 317.20 44.58 317.12 44.67 317.04 44.87 317.00 45.10. 316.95 45.33 316.88 45.55 316.78 45.75 316.68 ,4c an ~1~ c~ 3.2 2.4 1.6 1.9 2.6 1.9 1.7 1.6 1.9 1.7 1.7 2.3 2.1 3.1 3.7 3.2 3.3 2.5 2.0 2.1 2.4 2.6 2.2 2.7 2.4 2.1 2.5 2.5 3.0 3.0 3.1 2.9 2.2 2.2 1.9 2.2 2.6 1.9 1.5 1.1 1.1 0.8 0.3 0.6 0.2 1.4 2.3 0.3 0.7 0.1 0.2 0.4 0.2 0.1 0.4 0.3 0.2 0.2 0.6 0.8 0.9 0.1 0.5 0.4 0.8 0.9 0.9 0.9 0.8 619,4~~ .8 619,4( $ 619,411.2 619,405.8 619,400.4 619,394.9 619,389.4 619,383.8 619,378.1 619,372.5 619,366.9 619,361.1 619,355.3 619,349.6 619,343.6 619,337.6 619,331.4 619,325.3 619,319.0 619,312.8 619,306.4 619,299.9 619,293.5 619,287.0 619,280.5 619,273.7 619,267.1 619,260.3 619,253.5 619,246.7 619,239.8 619,232.9 619,225.9 619,218.7 619,211.6 619,204.4 619,197.2 619,189.9 619,182.7 619,175.4 619,167.4 619,157.6 619,147.0 619,138.8 619,133.0 619,131.4 619,124.5 619,114.1 619,102.5 619,090.7 619,078.3 619,065.9 619,053.5 619,041.1 619,028.7 619,016.3 619,003,8 618,991.4 618,978.9 618,966.5 618,953.8 618,941.3 618,928.8 618,916.1 618,903.5 618,890.8 618,878.1 618,865.3 618,852.4 ;D, ~OU, U"-I'O. ~ 5,g80,051.g 5,980,057.3 5,g80,062.7 5,980,068.1 5,980,073.9 5,980,079.3 5,980,085.1 5,980,090.9 5,980,096.6 5,980,102.4 5,980,108.2 5,980,114.3 5,980,120.1 5,980,126.2 5,980,132.3 5,980,138.4 5,980,144.6 5,980,151.1 5,980,157.5 5,980,164.0 5,980,170.5 5,980,177.0 5,980;183.9 5,980,190.4 5,980,197.2 5,980,204.0 5,980,210.9 5,980,218.1 5,980,225.0 5,980,232.2 5,980,239.4 5,980,246.6 5,980,254.2 5,980,261.4 5,980,269.0 5,980,276.5 5,980,284.1 5,980,291.7 5,980,299.2 5,980,306.8 5,980,315.5 5,980,325.6 5,980,336.7 5,980,345.4 5,980,351.5 5,980,353.3 5,980,360.5 5,980,371.4 5,980,383.6 5,980,396.2 5,980,409.2 5,980,422.2 5,980,435.2 5,980,448.2 5,980,461.2 5,980,474.5 5,980,487.5 5,980,500.5 5,980,513.4 5,980,526.4 5,980,539.8 5,980,552.7 5,980,566.1 5,980,579.1 5,980,592.4 5,980,605.4 5,980,618.7 5,980,631.7 5,980,645.0 4,498 4,524 4,549 4,575 4,601 4,627 4,652 4,678 4,703 4,728 4,754 4,779 4,804 4,829 4,855 4,880 4,905 4,931 4,956 4,981 5,0O7 5,032 5,058 5,083 5,108 5,134 5,159 5,184 5,210 5,235 5,261 5,286 5,312 5,337 5,363 5,388 5,413 5,438 5,463 5,488 5,513 5,538 5,563 5,588 5,613 5,638 5,663 5,688 5,712 5,737 5,762 5,787 5,812 5,837 5,862 5,887 5,912 5,937 5,962 5,987 6,012 6,037 6,062 6,087 6,112 6,136 6,161 6,185 6,210 6.234 4,131.19 4,149.06 4,166.93 4,184.74 4,202.44 4,220.14 4,237.56 4,255.02 4,272.41 4,289.77 4,307.10 4,324.43 4,341.76 4,359.16 4,376.63 4,394.22 4,411.84 4,429.65 4,447.34 4,465.07 4,482.87 4,500.75 4,518.72 4,536.70 4,554.82 4,573.00 4,591.19 4,609.51 4,627.90 4,646.43 4,664.94 4,683.52 4,702.24 4,720.97 4,739.72 4,758.08 4,776.54 4,794.93 4.813.39 4.831.74 4.849.99 4.868.31 4.886.62 4.904.83 4.922.97 4.941.14 4,959.15 4,977.16 4,995.08 5,013.10 5,031.02 5,048.89 5,066.77 5,084.70 5,102.59 5,120.45 5,138.29 5,156.10 5,173.81 5,191.56 5,209.28 5,226.99 5,244.69 5,262.37 5,279.74 5,297.09 5,314.46 5,331.77 5,349.06 5.366.31 -4,064.69 -4,082.56 -4,100.43 -4,118.24 -4,135.94 -4,153.64 -4,171.06 -4,188.52 -4,205.91 -4,223.27 -4,240.60 -4,257.93 -4,275.26 -4,292.66 -4,310.13 -4,327.72 -4,345.34 -4,363.15 -4,380.84 -4,398.57 -4,416.37 -4,434.25 -4,452.22 -4,470.20 -4,488.32 -4,506.50 -4,524.69 -4,543.01 -4,561.40 -4,579.93 -4,598.44 -4,617.02 -4,635.74 -4,654.47 -4,673.22 -4,691.58 -4,710.04 -4,728.43 -4,746.89 -4,765.24 -4,783.49 -4,801.81 -4,820.12 -4,838.33 -4,856.47 -4,874.64 -4,892.65 -4,910.66 -4,928.58 -4,946.60 -4,964.52 -4,982.39 -5,000.27 -5,018.20 -5,036.09 -5,053.95 -5,071.79 -5,089.60 -5,107.31 -5,125.06 -5,142.78 -5,160.49 -5,178.19 -5,195.87 -5,213.24 · .-5,230.59 -5,247.96 -5,265.27 -5,282.56 -5.299.81 :xhibit VI- lOb 46.53 316.16 46.57 316.17 46.65 316.20 46.68 316.24 46.75 316.25 46.78 316.27 46.73 316.32 46.63 316.33 46.47 316.31 46.38 316.33 46.30 316.42 46.00 316.56 45.75 316.65 45.65 316.70 45.63 316.74 45.62 316.70 45.38 316.54 45.10 316.38 44.90 316.17 44.52 316.01 44.22 316.00 44.12 316.04 43.95 316.05 43.72 316.01 43.52 315.97 43.28. 315.93 43.15 315.90 43.07 315.94 42.93 316.04 42.80 316.22 42.75 316.38 42.72 316.48 42.63 316.51 42.63 316.53 42.70 316.58 42.85 316.58 42.88 316.57 42.85 316.54 43.00 316.51 43.25 316.49 43.45 316.48 43.58 316.47 43.72 316.47 43.87 316.48 43.88 316.50 43.88 316.52 44.05 316.53 44.23 316.52 44.20 316.46 44.15 316.36 44.23 316.31 44.37 316.30 44.53 316.30 44.62 316.22 44.72 316.16 44.83 316.29 44.88 316.38 44.90 316.38 44.95 316.39 45.05 316.36 45.13 316.34 45.12 316.31 45.05 316.25 45.07 316.23 45.17 316.24 45.30 316.22 0.5 0.5 0.8 0.6 0.4 0.2 0.3 0.2 0.3 0.1 0.2 0.4 0.6 0.4 0.4 1.3 1.0 0.4 0.1 0.1 1.1 1.2 1.0 1.6 1.2 0.4 0.7 0.9 0.8 1.0 0.5 0.3 0.6 0.7 0.5 0.3 0.4 0.1 0.3 0.6 0.1 0.2 0.6 1.0 0.8 0.5 0.6 0.6 0.1 0.1 0.7 0.7 0.2 0.3 0.4 0.6 0.6 0.4 0.4 0.6 0.3 0.1 0.2 0.4 0.3 0.1 0.3 0.1 0.4 0.5 618,826.6 618,~" 5 618,80u.6 618,787.4 618,774.3 618,761.1 618,748.1 618,735.1 618,722.2 618,709.2 618,696.2 618,683.3 618,670.5 618,657.6 618,644.9 618,632.0 618,619.3 618,606.6 618,593.9 618,581.4 618,568.6 618,556.1 618,543.5 618,530.8 618,518.3 618,505.9 618,493.5 618,481.0 618,468.8 618,456.4 618,444.0 618,431.7 618,419.5 618,407.2 618,394.9 618,383.0 618,371.1 618,359.3 618,347.5 618,335.6 618,323.7 618,311.8 618,299.9 618,288.0 618,276.0 618,263.9 618,251.9 618,239.8 618,227.7 618,215.6 618,203.6 618,191.4 618,179.3 618,167.0 618,154.9 618,142.6 618,130.2 618,117.9 618,105.6 618,093.2 618,080.9 618,068.5 618,056.1 618,043.7 618,031.5 618,019.2 618,006.9 617,994.8 617,982.5 617.970.4 5,980,671.4 5,980,684.7 5,980,698.0 5,980,711.0 5,980,724.3 5,980,737.7 5,980,750.6 5,980,764.0 5,980,777.0 5,980,790.3 5,980,803.3 5,980,816.2 5,980,829.6 5,980,842.6 5,980,855.5 5,980,868.5 5,980,881.5 5,980,894.8 5,980,907.4 5,980,920.8 5,980,933.8 5,980,946.4 5,980,959.4 5,980,972.0 5,980,984.2 5,980,996.8 5,981,009.4 5,981,021.7 5,981,034.3 5,981,046.6 5,981,058.8 5,981,071.4 5,981,083.7 5,981,095.9 5,981,108.2 5,981,120.4 5,981,132.7 5,981,144.6 5,981,156.9 5,981,169.1 5,981,181.0 5,981,193.3 5,981,205.5 5,981,217.8 5,981,229.7 5,981,241.9 5,981,254.5 5,981,266.8 5,981,279.1 5,981,291.3 5,981,303.6 5,981,316.2 5,981,328.4 5,981,341.1 5,981,353.3 5,981,365.9 5,981,378.2 5,981,390.8 5,981,403.1 5,981,415.7 5,981,428.3 5,981,440.9 5,981,453.5 5,981,466.1 5,981,478.4 5,981,491.0 5,981,503.3 5,981,515.5 5,981,527.8 5.981.540.4 61259 6,~83 6,308 6,332 6,357 6,381 6,406 6,430 6,455 6,480 6,504 6,528 6,553 6,578 6,602 6,626 6,651 6,675 6,700 6,724 6,749 6,773 6,798 6,822 6,847 6,871 6.895 6.919' 6.943 6.968 6.992 7,016 7 ,O4O 7,064 7,089 7,113 7,137 7,161 7,186 7,210 7,235 7,259 7,283 7,308 7,332 7,356 7.381 7.405 7.429 7.453 7.478 7.502 7.526 7.550 7,574 7,597 7,621 7,645 7,669 7,693 7,716 7,740 7,764 7,787 7,811 7,835 7,859 7,882 7,906 7,930 5;383.57 5,400.78 5,418.04 5,435.34 5,452.66 5,469.97 5,487.26 5,504.54 5,521.86 5,539.23 5,556.55 5,573.90 5,591.36 5,608.83 5,626.27 5,643.69 5,661.19 5,678.61 5,696.10 5,713.54 5,731.07 5,748.69 5,766.33 5,783.75 5,801.19 · 5,818.63 5,836.13 5,853.67 5,871.25 5,888.84 5,906.39 5,923.92 5,941.42 5,959.06 5,976.82 5,994.59 6,012.35 6,030.14 6,048.04 6,065.88 6,083.79 6,101.74 6,119.78 6,137.75 6,155.72 6,173.75 6,191.78 6,209.86 6,228.06 6,246.13 6,264.37 6,282.48 6,300.39 6,318.26 6,336.17 6,354.11 6,372.06 6,390.04 6,408.08 6,426.06 6,444.02 6,462.03 6,480.11 6,498.14 6,516.20 6,534.25 6,552.39 6,570.50 6,588.73 6,606.89 -51317.07 -5,334.28 -5,351.54 -5,368.84 -5,386.16 -5,403.47 -5,420.76 -5,438.04 -5,455.36 -5,472.73 -5,490.05 -5,507.40 -5,524.86 -5,542.33 -5,559.77 -5,577.19 -5,594.69 -5,612.11 -5,629.60 -5,647.04 -5,664.57 -5,682.19 -5,699.83 -5,717.25 -5,734.69 -5,752.13 -5,769.63 -5,787.17 -5,804.75 -5,822.34 -5,839.89 -5,857.42 -5,874.92 -5,892.56 -5,910.32 -5,928.09 -5,945.85 -5,963.64 -5,981.54 -5,999.38 -6,017.29 -6,035.24 -6,053.28 -6,071.25 -6,089.22 -6,107.25 -6,125.28 -6,143.36 -6,161.56 -6,179.63 -6,197.87 -6,215.98 -6,233.89 -6,251.76 -6,269.67 -6,287.61 -6,305.56 -6,323.54 -6,341.58 -6,359.56 -6,377.52 -6,395.53 -6,413.61 -6,431.64 -6,449.70 -6,467.75 -6,485.89 -6,504.00 -6,522.23 -6,540.39 xhibit VI- lOb 44.98 316.10 45.08 316.06 45.18 316.02 45.08 316.04 44.97 316.03 44.95 316.02 44.87 316.01 44.72 315.96 44.63 315.90 44.62 315.87 44.60 315.81 44.55 315.77 44.48 315.71 44.45 315.65 44.40 315.63 44.37 315.56 44.30 315.50 44.20 315.45 44.13 315.32 44.05 315.22 43.98 315.15 43.80 315.04 43.55 314.97 43.57 314.90 43.53 314.79 43.47 314.68 43.50 314.55 43.48 314.40 43.35 314.26 43.08 314.08 42.97 313.95 43.08 313.81 43.00 313.64 42.85 313.53 42.80 313.40 42.72 313.28 42.58 313.10 42.40 312.93 42.28 312.86 42.32 312.80 42.30 312.73 42.18 312.65 42.03 312.58 41.83 312.57 41.70 312.59 41.68 312.61 41.58 312.63 41.48 312.58 41.43 312.58 41.27 312.69 41.13 312.72 41.05 312.77 40.97 312.82 40.90 312.83 40.82 312.93 40.77 313.00 40.72 313.16 40.63 313.44 40.52 313.58 40.40 313.69 40.35 313.96 40.42 314.24 40.27 314.56 40.07 314.95 39.92 315.25 39.75 315.41 0.4 0.0 0.4 0.8 0.4 0.4 0.4 0.4 0.5 0.1 0.3 0.6 0.4 0.1 0.2 0.2 0.3 0.2 0.2 0.2 0.3 0.4 0.5 0.4 0.4 0.8 1.1 0.2 0.4 0.4 0.4 0.4 0.7 1.2 0.6 0.6 0.6 0.7 0.4 0.5 0.8 0.9 0.5 0.2 0.2 0.5 0.7 0.8 0.5 0.1 0.4 0.4 0.2 0.7 0.6 0.4 0.4 0.3 0.4 0.3 0.5 0.9 0.6 0.6 0.8 0.8 1.4 1.0 0.8 6171958.0 617,~''~ B 617,9L~.5 617,921.2 617,909.1 617,896.8 617,884.6 617,872.3 617,860.0 617,847.8 617,835.7 617,823.5 617,811.3 617,799.1 617,787.0 617,774.7 617,762.6 617,750.5 617,738.2 617,726.1 617,713.9 617,701.7 617,689.4 617,677.4 617,665.3 617,653.3 617,641.3 617,629.3 617,617.3 617,605.3 617,593.1 617,581.1 617,569.1 617,557.0 617,544.9 617,532.8 617,520.7 617,508.4 617,496.2 617,484.1 617,471.8 617,459.7 617,447.5 617,435.2 617,423.1 617,410.9 617,398.8 617,386.5 617,374.4 617,362.4 617,350.3 617,338.3 617,326.6 617,314.7 617,303.1 617,291.5 617,279.7 617,268.1 617,256.6 617,245.0 617,233.5 617,222.2 617,210.8 617,199.4 617,188.2 617,177.1 617,165.8 617,154.8 617,143.8 617,133.1 5:981;552.6 5,981,564.9 5,981,577.5 5,981,589.8 5,981,602.0 5,981,614.3 5,981,626.9 5,981,639.1 5,981,651.4 5,981,663.7 5,981,675.9 5,981,688.2 5,981,700.4 5,981,712.3 5,981,724.6 5,981,736.8 5,981,748.7 5,981,761.0 5,981,772.8 5,981,785.1 5,981,797.0 5,981,808.9 5,981,821.1 5,981,832.7 5,981,844.5 5,981,856.4 5,981,868.0 5,981,879.5 5,981,891.0 5,981,902.5 5,981,914.1 5,981,925.6 5,981,937.1 5,981,948.3 5,981,959.8 5,981,970.9 5,981,982.1 5,981,993.3 5,982,004.8 5,982,015.9 5,982,026.7 5,982,037.9 5,982,049.0 5,982,059.8 5,982,070.6 5,982,081.8 5,982,092.6 5,982,103.4 5,982,114.2 5,982,124.6 5,982,135.7 5,982,146.2 5,982,156.6 5,982,167.0 5,982,177.5 5,982,188.3 5,982,198.7 5,982,209.1 5,982,219.2 5,982,229.6 5,982,240.1 5,982,250.5 5,982,260.9 5,982,271.4 5,982,281.8 5,982,292.3 5,982,303.1 5,982,313.5 5,982,324.3 5,982,334.8 7,953 · 7,c]77 8,001 8,024 8,048 8,072 8,096 8,119 8,143 8,167 8,191 8,214 8,237 8,261 8,284 8,307 8,331 8,354 8,377 8,400 8,424 ~ 8,447 8,470 8,494 8,517 8,541 8,564 8,587 8,611 8,634 8,657 8,681 8,704 8,800 8,900 9,000 9,100 9,200 9,300 9,400 9,500 9,600 9,700 9,800 9,900 10,000 10,100 10,200 10,300 10,400 10,500 10,600 10,700 10,782 10,812 10.842 10.869 10.899 10.928 10.967 11.002 11.042 11,083 11,117 11,154 11,192 11,226 11,276 11,311 11,342 6,625.08 6,643.30 6,661.45 6,679.58 6,697.79 6,715.98 6,734.16 6,752.32 6,770.46 6,788.63 6,806.81 6,824.78 6,842.64 6,860.59 6,878.44 6,896.30 6,914.22 6,932.19 6,950.09 6,968.00 6,985.96 7,003.90 7,021.92 7,039.91 7,058.01 7,076.14 7,094.23 7,112.31 7,130.38 7,148.51 7,166.67 7,185.01 '7,203.51 7,279.36 7,358.17 7,436.92 7,515.14 7,592.33 7,668.28 7,743.32 7,817.66 7,890.87 7,962.90 8,033.68 8,103.33 8,172.56 8,241.78 8,311.08 8,380.58 8,450.55 8,521.25 8,593.09 8,666.25 8,726.24 8,746.16 8,762.18 8,771.89 8,778.30 8,779.85 8,777.58 8,773.67 8,768.42 8,763.77 8,761.20 8,759.77 8,759.54 8,759.97 8,761.75 8,762.94 8,763.52 -6,558.58 -6,576.80 -6,594.95 -6,613.08 -6,631.29 -6,649.48 -6,667.66 -6,685.82 -6,703.96 -6,722.13 -6,740.31 -6,758.28 -6,776.14 -6,794.09 -6,811.94 -6,829.80 -6,847.72 -6,865.69 -6,883.59 -6,901.50 -6,919.46 -6,937.40 -6,955.42 -6,973.41 -6,991.51 -7,009.64 -7,027.73 -7,045.81 -7,063.88 -7,082.01 -7,100.17 -7,118.51 -7,137.01 -7,212.86 -7,291.67 -7,370.42 -7,448.64 -7,525.83 -7,601.78 -7,676.82 -7,751.16 ~7,824.37 -7,896.40 -7,967.18 -8,036.83 -8,106.06 -8,175.28 -8,244.58 -8,314.08 -8,384.05 -8.454.75 -8.526.59 -8.599.75 -8.659.74 -8.679.66 -8.695.68 -8.705.39 -8.711.80 -8,713.35 -8,711.08 -8,707.17 -8,701.92 -8,697.27 -8,694.70 -8,693.27 -8,693.04 -8,693.47 -8,695.25 -8,696.44 -8,697.02 {' xhibit VI- lOb ~u.uu 315.50 39.88 315.42 39.85 315.34 39.97 315.31 40.02 315.24 40.08 315.21 40.07 315.31 40.02 315.36 39.95 315.42 39.93 315.48 39.95 315.48 39.97 315.58 39.95 315.67 39.80 315.71 39.62 315.66 39.63 315.57 39.62 315.66 39.58 315.75 39.68 315.81 39.58 315.88 39.38 316.03 39.23 316.24 39.20 316.48 39.25 316.81 39.30 317.36 39.27 318.39 38.88 320.09 38.40 322.02 37.98 323.98 37.68 325.75 38.00 327.97 37.98 328.08 38.12 328.48 38.95 329.00 40.00 330.57 41.17 331.42 41.58 331.93 42.37 332.10 43.50 332.12 44.35 332.02' 45.53 332.28 46.18 332.85 46.20 333.50 46.18 333.57 46.08 333.37 45.88 333.10 45.30 333.18 44.72 334.03 43.43 334.73 42.53 335.80 43.45 336.64 52.00 337.50 64.19 338.90 72.80 340.10 82.60 336.50 91.30 332.50 95.40 335.60 97.60 340.'20 97.40 344.10 95.50 342.80 93.33 349.60 91.00 351.90 89.70 355.30 88.80 356.00 87.20 2.90 88.80 2.50 89.10 9.40 0.4 0.4 0.5 0.4 0.6 0.3 0.5 0.3 0.3 0.3 0.3 0.3 0.2 0.1 0.3 0.3 0.7 0.8 0.3 0.3 0.3 0.5 0.5 1.0 0.9 0.7 0.9 1.5 2.8 4.9 5.6 5.5 4.8 1.5 0.1 0.3 0.9 1.5 1.3 0.5 0.8 1.1 0.9 1.2 0.8 0.5 0.1 0.2 0.3 0.6 0.8 1.4 1.2 1.3 28.6 40.3 32.7 34.6 32.8 13.2 14.7 9.6 5.6 21.3 8.7 9.6 3.4 13.9 4.8 22.1 617,122.3 617,1 ' 617,1bv.7 617,089.9 617,079.0 617,068.2 617,057.3 617,046.4 617,035.5 617,024.6 617,013.6 617,002.9 616,992.3 616,981.5 616,970.9 616,960.2 616,949.6 616,939.0 616,928.5 616,918.0 616,907.5 616,896.8 616,886.3 616,875.8 616,865.4 616,855.1 616,844.7 616,834.5 616,824.4 616,814.6 616,805.3 616,796.4 616,788.0 616,755.0 616,721.5 616,688.3 616,655.1 616,622.3 616,589.9 616,557.6 616,525.3 616,492.5 616,459.0 616,424.9 616,391.0 616,357.4 616,324.1 616,290.9 616,257.5 616,224.3 616,191.8 616,160.8 616,131.1 616,107.8 616,097.7 616,087.7 616,078.7 616,067.5 616,054.5 616,036.9 616,023.4 616,010.7 615,998.4 615,989.9 615,983.3 615,978.4 615,975.4 615,974.1 615,975.1 615,977.9 5,982,345.6 5,982,356.0 5,982,366.8 5,982,377.7 5,982,388.1 5,982,398.9 5,982,409.4 5,982,420.2 5,982,430.6 5,982,441.4 5,982,452.2 5,982,462.7 5,982,473.1 5,982,483.6 5,982,494.4 5,982,504.8 5,982,515.3 5,982,525.7 5,982,536.2 5,982,546.7 5,982,557.1 5,982,567.6 5,982,578.0 5,982,588.8 5,982,599.3 5,982,609.7 5,982,620.2 5,982,631.0 5,982,641.8 5,982,652.7 5,982,663.9 5,982,675.4 5,982,687.0 5,982,735.6 5,982,787.4 5,982,839.2 5,982,892.1 5,982,946.5 5,983,002.8 5,983,060.5 5,983,118.9 5,983,178.8 5,983,239.4 5,983,301.5 5,983,364.6 5,983,428.5 5,983,492.4 5,983,556.4 5,983,620.3 5,983,683.4 5,983,746.3 5,983,808.4 5,983,869.8 5,983,920.7 5,983,940.6 5,983,964.3 5,983,987.2 5,984,014.5 5,984,040.6 5,984,075.1 5,984,106.8 5,984,144.3 5,984,183.6 5,984,215.7 5,984,253.0 5,984,290.6 5,984,323.8 5,984,374.3 5,984,408.8 5,984,439.9 11,375 11,420 11,452 11,486 11,528 11,564 11,614 11,656 11,700 11,739 11,774 11,818 11,887 11,949 11,979 12,035 12,114 12,170 12,218 12,303 12,341 12,412 12,448 12,493 12,526 12,555 12,598 12,635 12,674 12,712 12,753 12,802 12,831 12,860 12,895 12,925 12,975 13,007 13,038 8,763.93 8,764.98 8,766.61 8,769.20 8,773.12 8,776.86 8,782.07 8,786.43 8,791.09 8,794.95 8,797.06 8,798.53 8,800.83 8,802.80 8,803.73 8,803.99 8,801.35 8,798.27 8,795.71 8,792.84 8,792.14 8,792.20 8,792.28 8,790.92 8,789.58 8,788.45 8,785.91 8,784.02 8,784.48 8,787.44 8,792.07 8,797.40 8,799.25 8,799.91 8,801.64 8,804.13 8,808.57 8,811.13 8,813.04 -8,697.43 -8,698.48 t" -8,7OO.ll ~-xhibit VI- lOb -8,702.70 -8,706.62 84.40 2.10 -8,710.36 83.90 359.70 -8,715.57 84.00 359.00 -8,719.93 84.10 356.28 -8,724.59 83.80 1.05 -8,728.45 84.95 7.93 -8,730.56 88.15 11.17 -8,732.03 88.02 8.99 -8,734.33 88.11 11.99 -8,736.30 88.28 16.57 -8,737.23 88.19 20.62 -8,737.49 91.28 23.79 -8,734.85 92.51 33.84 -8,731.77 93.80 39.30 -8,729.21 92.33 44.23 -8,726.34 91.54 54.80 -8,725.64 90.57 56.57 -8,725.70 89.34 57.45 · -8,725.78 90.40 57.27 -8,724.42 93.04 57.60 -8,723..08 91.54 56.21 -8,721.95 92.95 50.58 -8,719.41 93.92 45.82 -8,717.52 91.89 44.41 -8,717.98 86.78 42.29 -8,720.94 84.05 40.36 -8,725.57 83.08 33.13 -8,730.90 84.41 35.07 -8,732.75 88.28 33.84 -8,733.41 89.16 31.37 -8,735.14 85.20 31.02 -8,737.63 85.29 29.25 -8,742.07 84.32 28.55 -8,744.63 86.52 22.21 -8,746.54 86.52 22.21 7.3 3.9 18.5 4.9 7.7 6.7 1.4 6.4 10.8 17.7 12.9 5.0 4.4 7.3 13.4 8.0 12.7 10.0 10.7 12.5 5.3 2.1 3.1 5.9 6.1 20.1 11.5 6.6 14.0 9.0 17.6 4.8 14.0 8.9 11.3 5.9 2.4 20.8 0.0 615,983.4 615,9~ ~ 615,99~.2 615,998.8 616,000.8 616,000.8 615,999.4 615,997.1 615,995.4 615,997.8 616,003.0 616,010.0 616,021.4 616,035.8 616,045.0 616,065.1 616,102.3 616,134.8 616,166.1 616,229.5 616,260.5 616,320.0 616,349.3 616,387.0 616,414.8 616,437.6 616,468.7 616,494.7 616,521.3 616,545.4 616,569.4 616,595.9 616,611.9 616,627.5 616,645.2 616,659.8 616,682.7 616,695.9 616,707.3 5,984,472.6 5,984,516.6 5,984,548.6 5,984,581.9 5,984,623.7 5,984,659.9 5,984,709.3 5,984,751.0 5,984,794.9 5,984,833.7 5,984,868.6 5,984,911.5 5,984,979.1 5,985,039.7 5,985,068.4 5,985,120.3 5,985,190.4 5,985,235.6 5,985,272.0 5,985,327.9 5,985,349.6 5,985,389.7 5,985,409.2 5,985,433.9 5,985,452.6 5,985,470.2 5,985,498.9 5,985,525.6 5,985,555.0 5,985,583.2 5,985,616.5 5,985,656.8 5,985,681.2 5,985,706.3 5,985,736.6 5,985,762.5 5,985,805.7 5,985,834.8 5,985,863.9 ALASKA PRODUCTION Exhibit VI- 10'c (' · .,~ OO. IlCjO ; i ALASKA PRODUCTION i,/. ,~--,~/ ~,~ 6 c o ,~' 4, o'"o Exhibit V!-- I~L. 743 T~ Exhibit VI- 1~' : PBU DRILLING PROGRAM S-31 (32-27-12-12) AFE.' 125346 CEMENTATI(~N 13-3/8" Casino: Tail Slurry: 3723 cu ft (4000 sacks) ARCTICSET II -. 20" Conductor '~-- 13-3/8" 68# L80 Butt Base Permafrost Encapsulated Control Line 4-1/2" Ball Valve w/Flow Couplings 13-3/8" Shoe 17-1/2" Open Hole MDBKB .146' 1967' 2100' 2680' 2700' 9-5/8" Casin(~: ,/ Lead Slurry: Tail slurry: 7" Liner; Slurry: 2113 cu ft (1180 sacks) See Program 230 cu ft (200 sacks) See Program BATCH MIX 300 cu ft (258 sacks) See Program KOP: 2100' at surface hole MAX. ANGLE: 43.29° Target Departure -- 5610' WELLHEAD: FMC TAILPIPE SIZE: 4-1/2" DRILLING ENGINEER ',;' W/O & RVlSOR , 9-5/8" 47# L80 NSCC 4-1/2" 12.6# Tubing NT13CR-80 TDS Non-IPC w/5 GLM's TIW 9-5/8" Packer TIW 7" Liner Hanger 9-5/8" Shoe 12-1/4" Open Hole 7" 26# NSCC Liner NT13CR-80 10472' 10522' 10772' 10782' 7" Shoe 11401' 8-1/2" TD 11401' DRLG. ENG. SUPERVISOR DRILLING SUPERINTENDENT Exhibit VI-11: S-200 & S-200 PB 1 Well Integri _ty Report Original Completion Date: Schrader Bluff S-200 PB1 Penetration Hole Diameter: Schrader Bluff S-200 Penetration Hole Diameter: Schrader Bluff Liner Diameter: Well Status as of 9/2002: Cement Logs Across Schrader Bluff: 1/23/98 8-1/2" 3-1/2" Shut in Producer None Comments: This well was originally named SB-01. It was drilled as an S-pad data gathering and pilot production well. The well was cored in the S-200 PB 1 leg, plugged back with cement and then sidetracked to the current S-200 bottom hole location. Cementing reports for the surface, plug back, 7" casing and 3.5" liner are attached. This well currently is shut in due to a collapse at 5746'md in the 3- 1/2" liner. Future proposed plans for this well include converting it to a water injector to support S-201. Additional Information: Exhibit VI- 11 a Well Diagram Exhibit VI- 1 lb Directional Survey Exhibit VI- 11 c Drilling Daily Reports Exhibit VI- 11 a ACTUATOR = BAKER " KB. ELEV = 62_18' BF. ELEV = 37' , KOP = 220g' Max An~lle = 4385~ Datum MD = 10284' Datum TVD = 8800' SS ; GAS LIFT MANDRELS I~-~,~,,c~.~#.,-~o.,~=~.~-H ~s~' I--~ i i~ ~r ~--~ ~v--C-~-~-~ ~ ~H ,o----~ ~^~ 4 1582. 1518 3 CAMCO TG ----"~--~ 3 2577 2502. 18 CAMCO TG 2 3826:3493~'~,.,o CAMCO TG 1 4229 ~~_'c^uco T__~_~ I I t 425,' H3-1/2"x~P.D=2.8,3"I Minimum ID = 2.8'13" @ 1466' 3-1/2"X Nl~t_E ~ ~ ~[ 4284' ~7"e~RS-3P~,~D=3.875"I I I I .~o' H~-~,,x ~., ~=~.s~"l I I 4~a' k-l~uDrr~oc,~m05/o?1981 17"¢SG, 26#,L-80. ID=6,276"H 4478'! ANGLEATTOPPmF:19~5755' I I t 5625' H3-1/2"XNIP, D=2.813"I Note: Refer to Production ~ for historical perf data S~E SPF I~E~AL OpWS~ DA~ U ~7.~,,.-,,~,,x.,... ~..~,,I I 2-1/2" 4 5~5' -5~3' 0 07/0 ~98 2-1/2" 2 5~2'-5~6' O 05/27/98 5~6'-5~9' O 05/27/98 ~ ' 5874' ~3-1/2"XNIP, D=2.813';~ 2-1/2" 2 2-1/2" 2 5~9'-5895' O 05/27/98 2-1/2" 4 5916'-5926' O 05/27/98 2-1/2" 4 6012'-6022' O 05/17/98 2-1/2" 4 6066' -6072' O 05/17~98 I ~ I ~.0' H ,',~,''x"","=~.~,~''l I"~D H 623* I I ~TE R~ BY ~TS I DA~ 01~3/98 ORGI~ L CO~L~I~ I W~E ~2~ 03/15/01 SI~SLT COUrT. TO ~AS I P~ME No: 97-~90 03/16/01 SI~ FINAL I AR No: ~-029-22~6~0 09~4/01 ~P CO~TDNS SEC35, T12N, T12E i 05~1/02 GOKAK PE~ ~E~I~S BP~lorat~n {Al~ka) SIZE SPF INTERVAL Opn/Sqz DATE 2-1/Z' 4 5755'-5765' O 08/15/98 2-1/2" 4 5835' -5843' O 07/08/98 2-1/Z' 2 5882'-5886' O 05/27/98 2-1/2" 2 5886' -5889' O 05/27/98 2" 4 5886' -5889' O 05/27/98 2-1/2" 2 5889' -5895' O 05/27/98 2-1/2" 4 5916' -5926' O 05/27/98 2-1/2" 4 6012' -6022' O 05/17~98 2-1/2" 4 6066' -6072' O 05/17~98 DATE REV BY COIVIVIENTS DATE REV BY COMIVENTS 01/23198 ORIGINAL COIVPLETION 03/15/01 SIS-SLT CONVICTED TO CANVAS 03/16/01 SIS-CS FINAL 09/24101 RN/TP COI:~ECTIONS 05/21/02 GC/KAK PERI:: CORRECTIONS Well S-200 Directional Surv(' { We.: IS-200 Query '1 Exhibit VI- 1 lb I~D 0 117 251 339 431 520 611 701 790 883 979 1,074 1,168 1,262 1,357 1,452 1,548 1,644 1,740 1,835 1,930 2,020 2,113 2,209 2.303 2.399 2.495 2,590 2,687 2,781 2,876 2,972 3,067 3,102 3,185 3 ~249 3,343 3,440 3,533 3,629 3,726 3,821 3,917 4,011 4,106 4,198 4,292 4,385 4,471 `4 ,4(5,4 APZ/UW:[: 500292284600 Survey Type: MWD Company: Sperry-Sun Survey Date: 01/16/98 Survey Top: 0' MD Survey Btm: 6,310' MD TVD SS I'NCLI'NE AZ'rt4UTH DOGLEG ASP_X 0.00 66.58 0.00 0.00 0.0 618,929.6 117.06 -50.48 0.18 105.08 0.0 618,929.7 251.00 -184.42 0.22 105.08 0.0 618,930.2 339.19 -272.61 0.28 125.59 0.1 618,930.6 431.03 -364.45 0.14 326.02 0.5 618,930.7 520.08 -453.50 0.62 308.78 0.6 618,930.2 610.96 -544.38 1.28 320.73 0.8 618,929.2 700.68 -634.10 2.30 316.85 1.1 618,927.3 789.95 -723.37 3.33 314.71 1.2 618,924.2 882.88 -816.30 3.34 314.25 0.0 618,920.3 978.03 -911.45 3.21 312.16 0.2 618,916.2 1,073.22 -1,006.64 3.24 314.39 0.1 618,912.3 1,166.87 -1,100.29 3.19 314.65 0.1 618,908.5 1,260.69 -1,194.11 3.09 318.61 0.3 618,904.8 1,355.92 -1,289.34 3.03 322.15 0.2 618,901.6 1,450.58 -1,384.00 3.13 322.60 0.1 618,898.4 1,546.90 -1,480.32 2.68 322.39 0.5 618,895.4 1,642.92 -1,576.34 3.31 323.45 0.7 618,892.3 1,738.00 -1,671.42 3.32 326.20 0.2 618,889.0 1,833.08 -1,766.50 3.23 327.79 0.1 618,886.0 1,927.82 -1,861.24 3.30 317.62 0.6 618,882.7 2,017.61 -1,951.03 5.05 310.18 2.0 618,877.8 2,110.15 -2,043.57 6.88 309.58 2.0 618,870.3 2,205.30 -2,138.72 9.36 311.56 2.6 618,859.9 2,298.14 -2,231.56 11.66 309.14 2.5 618,846.5 2,392.06 -2,325.48 11.50 311.35 0.5 618,831.6 2,485.81 -2,419.23 14.38 311.75 3.0 618,815.3 2,576.85 -2,510.27 18.41 311.50 4.3 618,795.1 2,667.47 -2,600.89 21.77 311.79 3.5 618,770.0 2,754.35 -2,687.77 23.94 311.52 2.3 618,742.1 2,839.83 -2,773.25 26.43 309.98 2.7 618,711.3 2,924.54 -2,857.96 29.94 308.39 3.7 618,675.6 3,005.43 -2,938.85 33.57 308.37 3.8 618,635.9 3,034.89 -2,968.31 34.45 308.92 2.6 618,620.2 3,102.07 -3,035.49 35.72 309.15 1.6 618,583.0 3,153.47 -3,086.89 38.20 309.61 3.9 618,552.8 3,226.43 -3,159.85 40.38 310.80 2.5 618,506.5 3,299.02 -3,232.44 42.33 311.63 2.1 618,457.8 3,365.87 -3,299.29 45.35 310.91 3.3 618,408.9 3,431.17 -3,364.59 49.24 312.72 4.3 618,355.5 3,493.39 -3,426.81 50.74 311.13 2.0 618,299.5 3,552.44 -3,485.86 52.56 312.67 2.3 618,243.2 3,609.31 -3,542.73 55.05 313.02 2.6 618,185.4 3,663.21 -3,596.63 55.09 313.86 0.7 618,128.5 3,717.95 -3,651.37 54.03 313.94 1.1 618,072.3 3,771.56 -3,704.98 55.25 313.58 1.4 618,016.9 3,824.99 -3,758.41 55.14 314.16 0.5 617,960.7 3,877.30 -3,810.72 56.91 312.49 2.4 617,903.3 3,924.31 -3,857.73 56.65 311.38 1.1 617,849.3 'D t"~'D'2 /'~/~ "J' 0"~"~ ,4"'~ ~'1~ ,4t "DIA ,41'"1 "' ,4 ~'t'? O'D,4 0 ASP_Y 5,980,505.7 5,980,505.7 5,980,505.3 5,980,505.4 5,980,505.4 5,980,505.7 5,980,506.8 5,980,509.0 5,980,511.8 5,980,515.8 5,980,519.4 5,980,523.0 5,980,526.6 5,980,530.2 5,980,534.2 5,980,538.2 5,980,541.8 5,980,545.7 5,980,550.4 5,980,554.8 5,980,559.1 5,980,563.4 5,980,569.6 5,980,578.2 5,980,589.3 5,980,601.5 5,980,615.5 5,980,632.8 5,980,654.4 5,980,678.4 5,980,704.3 5,980,732.3 5,980,762.8 5,980,775.0 5,980,804.0 5,980,828.1 5,980,865.8 5,980,907.1 5,980,948.8 5,980,995.2 5,981,043.7 5,981,092.6 5,981,144.8 5,981,197.0 5,981,249.1 5,981,300.6 5,981,353.2 5,981,405.4 5,981,452.5 4,503 4,535 4,566 4,598 4,629 4,663 4,695 4,728 4,760 4,792 4,822 4,853 4,885 4,917 4,950 4,980 5,013 5,045 5,077 5,109 5,140 5,169 5,201 5,233 5,262 5,294 5,326 5,358 5,389 5,423 5,517 5,613 5,707 5,803 5,898 5,993 6,088 6,182 6,248 6,310 3,942.27 3,960.23 3,977.90 3,996.75 4,016.53 4,038.01 4,059.08 4,080.38 4,101.74 4,122.82 4,142.75 4,163.54 4,185.69 4,208.17 4,230.85 4,253.20 4,277.24 4,301.07 4,325.94 4,351.75 4,376.91 4,401.38 4,428.62 4,455.54 4,481.44 4,509.67 4,538.28 4,567.55 4,596.51 4,628.08 4,716.12 4,806.17 4,895.41 4,985.49 5,074.70 5,164.68 5,254.90 5,343.98 5,406.72 5,466.04 -3,875.69 -3,893.65 -3,911.32 -3,930.17 -3,949.95 -3,971.43 -3,992.50 -4,013.80 -4,035.16 -4,056.24 -4,076.17 -4,096.96 -4,119.11 -4,141.59 -4,164.27 -4,186.62 -4,210.66 -4,234.49 -4,259.36 -4,285.17 -4,310.33 -4,334.80 -4,362.04 -4,388.96 -4,414.86 -4,443.09 -4,471.70 -4,500.97 -4,529.93 -4,561.50 -4,649.54 -4,739.59 -4,828.83 -4,918.91 -5,008.12 -5,098.10 -5,188.32 -5,277.40 -5,340.14 -5,399.46 ~ 91 54.95 52.23 50.53 49.70 49.04 49.04 48.59 48.17 48.17 47.56 45.84 45.62 44.83 42.42 42.01 41.03 37.79 35.61 34.70 32.60 . 31.84 29.72 27.66 26.65 24.26 23.83 22.82 20.93 20.21 19.15 18.53 19.89 19.60 19.04 18.58 17.68 17.68 17.68 Exhibit VI- 1 lb -~v'-~./_ · 305.65 4.1 307.90 5.7 307.99 0.2 309.50 3.8 312.39 6.9 312.67 0.7 312.03 2.5 311.16 5.7 311.05 0.7 310.64 2.6 310.23 7.9 311.04 2.1 310.91 3.1 311.44 10.1 311.86 6.8 311.33 3.1 310.41 7.4 309.83 2.6 310.18 6.8 310.47 7.0 310.51 3.2 310.45 7.5 310.93 1.5 311.43 3.3 313.31 5.9 315.31 1.1 316.74 1.2 318.46 0.9 314.37 2.0 314.02 0.3 314.75 0.6 316.77 0.8 318.10 1.1 319.14 0.5 319.14 0.0 ID1/,/4b.4 617,724.1 617,704.2 617,684.6 617,665.3 617,647.2 617,630.6 617,613.3 617,595.5 617,577.9 617,560.3 617,543.8 617,527.1 617,511.0 617,495.4 617,480.8 617,467.3 617,454.9 617,441.6 617,429.2 617,418.2 617,407.1 617,396.5 617,386.5 617,377.0 617,367.4 617,343.4 617,320.8 617,299.8 617,277.8 617,254.5 617,231.6 617,209.8 617,189.8 617,176.3 617,163.7 5,981,469.3 5,981,485.1 5,981,500.2 5,981,514.5 5,981,528.1 5,981,542.4 5,981,556.7 5,981,571.4 5,981,586.5 5,981,601.6 5,981,616.3 5,981,631.8 5,981,646.9 5,981,662.0 5,981,676.7 5,981,690.0 5,981,704.0 5,981,717.7 5,981,731.0 5,981,743.5 5,981,755.0 5,981,765.5 5,981,776.2 5,981,786.3 5,981,795.3 5,981,804.6 5,981,813.2 5,981,821.5 5,981,829.8 5,981,838.0 5,981,860.7 5,981,883.4 5,981,905.8 5,981,928.1 5,981,950.1 5,981,971.7 5,981,993.3 5,982,014.6 5,982,029.4 5,982,043.5 FRO~: N~BORS RIG 2E$ Operator BP Exploration Field Prudhoe Bay · , Exhibit VI- 1 lc ,,~,.- Morning Drilling Report II Well SB-OI Rig Nabor$ 2ES Progress Log 84-85-98 Report 6. page 3 Date 06:00, 21 Dec.97 06:00-11:00 OG:O0-10:O0 lO:O0 10~00~11=00 11:00 11:00-21:00 11;00-11:15 ll:IS 11:1~-12:00 12:00 ,12:00-13:,30 13:30 13:~0-15:30 1S:30 15:30-1~:~0 1~:30 17:~0-19:30 19:30. 19:30-20:00 20:00 20:00-21:00 21:00 21t00- 21:00-02:00 02:00 ,02:00'05:00 05:00 05:00- Run Casing, 9-5/8in O.D. *'~ACCIDENTS "*NO SPILLS*w7% OF Ai~E'*1047 DAYS LA~"~ LTA**282 DAYS LAST SPILL'' R~n Casing Uo 3158.0 .fa (9-5/$in OD) Ran 67 J=;. 9-$/8 475 L-SO Casing, washed las: 20' to bottom. On bottom circulated a= 3158.0 f= Obtmined clean re~urn~ -200.00 ~ hole volume C~ment : Casing cement Held safety meeting PJS~, c~nent Safe~y and Mixing and p~mping proceedures. Complete4 oDeratlonm Pumped Water spacers - volume'75.000 bbl P~p 10 bb~s waker, T~st l~nes Co 3500 psi. OK. 'Dropped bo[tom plug. Pump 65 bbls' water. Required volume of spacer pumped Mixed ana pun%~ed slurry -10.0,000 bbl BJ pumped bbls. water, 52 bbls. Co[d Set III at 1~.2 ppg ppg. then~ 15.8~9~ Class G tail slurry, shut down, drop Rig displaced cement to shoe with 1674 strokes. Bump plug and seaced with i500 psi., floats held. Cement mi~ed . Displaced slurz'y - 218.000 bt1 Drop shut off plug. BJ p~mp 10 bbls. water, pumped 218 bbls, ac 1654 strokes. Bumped plug with 1500 psi. floates he]d. loade4 clovis9 plug, to 2~00 p~i co'shear ES Cemetex open. Plug Circulated at'3158.0.ft opened HES ES Cemeter, with .2800 psi, circulate and condition mud in hole. Had 31 bbls. wster. 61 bbls. cement return, continue to circulate, haul cement returns. Obtained req. £1uid properties - 300.00 %, hole vol. circulate with 9.6 mud with 50 risc. ~ixed ~nd pumped slurry - 484.000 bt1 l Stage cwo: ~ix and pua~ 484 bbls..12.2 pp~. f~ ~et III cement. ~ixea l~a aye fir, u 10 ~bbls. ~ement. Red dye appear~ at surface a= 4~0 bbls., con£1rme= cemenu wiuh mud weigh=, total pumped 484 bbls.. Cement Dumped Displaced slurry'.- 150.000 Displace with 150 bbls/mud Final. pump pressure 800 psi. Close HHS ES Cemen=ex ~o 2000 psl Bleed back pressure Check Cemen:er OK. ~lug bumped Kigged down Casin~ handling e~uipment ' Ri~ down Casing equip., BJ Cementing head. 'lay lanain~ joint. Equipment work co~pl=t=a ~ipDle down Diveruor Kemoved Divertor E~uipmen= Rigge~ up Casing head Nippl~ up Casing hea~ .~n~ :ublng spool, =~sU to 1000 psi.~or 10 min,, OK. Equipment work con%~le=ed FROM: NABORS RIG 2ES m Operator B P Exploration Exhibit VI- 1 lc i Morning Un,, ng Heport Well SB-O1 Ri~, N~d~r~: 2RS 01-~-1-98 06 ~'~2~ P.OS Report 8, page 3 Data 06:00. 21 Jan 98 06:00-06:!0 06:30 11:00 11:00-12':00 12:00 12:00-12:30 12:30-Ig.'~)0- 14~0a 14:00-14:30 1&:30-16'00 1fi:00 16;00-16:30 Progress Log 16;50 1'6~.25 31 .-.~0 18:30 10.30-19:00 19:00 1~00-.1g~30 19:30 19:30-20:00 20:00 20:00-20:30 2.0,2~'- 21:30- 21=30-23:00 00:30 00:30-03:00 U~:UU Ran Liner to 1954.0 f: [3-1/2in OD) 2--Centra~liecro gcx Jr. T:~aL--~-la ~n~ ~ o~i~ Stopped : To pick up/lay out tubular= Run Inter-String, Pick uP and run in 3.5' liner J=s. 2-1/16 3.5% CS Hydril TbS. I~stallea Lzner hanger Make up Liner top Packer ~d Hanger to 2-1/16 Tbs. E~ipment work completed ~eld Operational Procedures, Bar{~6~ Baker, Nabors, BP~. ... R~n'gr%i%~i~ i~ands :o 4455.0 ft Run Liner on 3-1/2' DP. to 7' Shoe. Circulated at 4455.0 it Circ DP. ~d L~ner Vol~e. ~Pw~nu R%~D]ac~d w4th Water based mud - 100.00 % displaced Ran ~D in stands to 6300.O f~ Began precautionary ~easures Washed =o 6310.0 ft Mak~ um Cemenu ~ead, Break Circ, Wash 6300' 6310' Hole in Good Shape. OD bounom Circ. 5 bDm 2400 Dsi, Max D~ Dressure 2600 psi C~cnt F~ing ecaed~, a~g Obtained clean returns - 200.00 % hole vol~e P~po~ Lo/~i ViD co~ina~ion ~pacex~ - vol~e 70.000 PU~ 5 bbl water, Test lines =o 4500 psi, P~p 15 Released Dare wash l,~ne~ Re].eaze WiDer Dar:. Displaced slurry - 24,000 bbl S~t Liner II=n~er. Plug b~ped B~p plug to 4000 psi. Functioned Tie back packer Set Liner top Packer. Release o~f Liner. Pull Drillpip~, 3-1/2in O.D. Lmi~ ~o~ 2006.0 ~= of 3-1/2in OD ~r{~_~ ~ick up Kelly and break ~l]~ewvire Equipmen~ work completed Laid do~ 2000,0 fU of DrillDipe Operator BP Exploration Field Prudhoe Bay Exhibit VI- 1 lc Morning Drilling Report Well SB-01 Rig Nabors 2ES Report 27, page 3 Date 06:00, 11 Jan 98 06:00-19:30 06:00-07:00 07:00 07:00-09:30 09:30 09:30-10:30 10:30 10:30-15:00 15:00 15:00-18:00 18:00 18:00-19:30 19:30 19:30-20:30 19:30-20:15 20:15 20:15-20:30 20:30 20:30-21:00 20:30-21:00 21:00 21:00-23:30 21:00-22:00 22:00 22:00-23:00 23:00 23:00-23:30 23:30 23:30-00:30 23:30-00:30 00:30 00:30-03:00 00:30-01:15 01:15 01:15-03:00 03:00 03:00-05:30 03:00-04:00 04:00 04:00-05:30 5in. Drillpipe workstring run **NO ACCIDENTS**NO SPILLS**62% OF AFE** Ran Drillpipe in stands to 5850.0 ft Observed 25.00 klb resistance Washed to 6150.0 ft Ream 5850' to 6000' Wash 6000' to 6150' On bottom Circulated at 6150.0 ft Obtained bottoms up (100% annulus volume) Pulled out of hole to 0.0 ft At Surface : 0.0 ft Ran Drillpipe in stands to 6150.0 ft Make up Mule Shoe, RIH to TD~ at 6150' On bottom Circulated at 6150.0 ft Circ, 60 spm 400 psi, 80 sDm 500 ps±, F/O 135 S/O 105, PJSM-Nabors, Bariod, BJ, BPXA, Cementing Safety and procedures. Obtained bottoms up (100% annulus volume) Cement : Kickoff plug Mixed and pumped slurry - 83.000 bbl Mix and pump 83 bbls 17.0~ cl "G" cement ( 470 sx ) at 5.0 bpm and 1400 psi, 13 bbls water ahead and 5 bbls behind. Tested lines to 3500 psi. Cement pumped Displaced slurry - 77.000 bbl Displace at 8.5 bpm and 650 psi. Slurry at required depth, stopped the displacement Pull Drillpipe, 5in O.D. Pulled Drillpipe in stands to 5300.0 ft POOH to 5300' 9 stds. At Top of cement : 5300.0 ft Cement : Kickoff plug Reverse circulated at 5289.0 ft Rev out, 35 spm ( 2.5 bpm ) at 350-500 psi, Had 40 bbls of Mud contaminated cement. Obtained req. fluid properties - 200.00 %, hole vol. Mixed and pumped slurry - 83.000 bbl Mix and pump 83 bbls "G" cement, ( 470 sx ) at 5.0 bpm and 1400 psi. 13 bbls water ahead and 5 bbls behind. Cement pumped Displaced slurry - 63.000 bbl Displaced 8.5 bpm and 400-500 psi Slurry at required depth, stopped the displacement Pull Drillpipe, 5in O.D. Pulled'Drillpipe in stands to 4471.0 ft Pull 8 stds and 1 single plus 22' At Top of cement : 4471.0 ft Cement : Kickoff plug Reverse circulated at 4471.0 ft Rev-out 38 spm ( 2.7 bpm ) and 290 - 410 psi, 41.5 bbls cement contaminated mud Heviest 12.2 ppg. Obtained clean returns - 200.00 % hole volume Circulated at 4450.0 ft Pick up 21' circ the long way, DP. and annulas volume. Obtained clean returns - 150.00 % hole volume 5in. Drillpipe workstring run Pulled out of hole to 2300.0 ft POOH stand back 22 stds, 40 total in derrick Stopped : To pick up/lay out tubulars Laid down 2300.0 ft of Drillpipe Lay down excess DP. FROM: POOL RIG ? Operator BP Exploration Field Pmdho¢ Bay Exhibit VI- 1 lc ( Morning Drilling Report Well SB-01 Rig Nabo~ 2E$ Progresa Log 06:00-12:30 81-13-98 B6:50R P.Oi I I I ii Report 29, page 3 Date 06:00, 13 Jan 98 06:00-09:00 09:00 0g:00-10:00 lO:OO io:oo-ii:oo 11:00 11:00-11:30 11:30 11:30-12:30 12:30 12:30-14:00 12;30-13:00 13:00 13:00-13:30 13:30 13: 30-14: 00 14:00 14:00-17:30 14:00-15:30 15:30 15:30-17:50 17:30 17:30-19:30 17:30-19:30 19:30 19:30-03:30 19:30-03:30 03 03: 30- 03:30-06:30 04:30 04:30- Run Casing, 7in O.D. ''No ACCIDE/TT$~NO ~PILLS'~66% OF AI~'' Ran C~sing to 3108.0 ft (7in OD) At 9-5/Bin casing shoe Circulated at 3108,0 ft Circ string volume. obtained bottoms up (100% annulus volume) Ran Casing to 4445.0 ft 17in OD) Run-108 its. 7' 26~ L-SO BTC/MOD Casing At Top of hanger : ~AS.0 ft .Installed Casing hanger rutting tool ~ke uD landing jo, and DJ cemen~ head. ~quipmenc work completed Circulated at 4475.0 ft Wash 35' to bottom ( No problems running casing hole in good shape. PJSM-BJ, Nabors, B~rio~, Peak, ~P:u%; Cepenuing procedure~ Sofcty, Pumping""and plug dropping schedule. Obtained clean returns - 200.00 % hole ~olume Cement : casin~ cement Mixed and pumped slurry - 4B.000 bbl Test lin~s to 4500 psi OK. ~ix ~nd pump Cement as Der well plan ( 20 bbls H20, 50 bbls. Spacer, 48 bbls. 15.8 ~ Cement.) Tail cement pumped Displaced slurry - 165.500 bbl Displace cement a= 9 b~m, 500-700 psi slow =o 3 bpm 390 psi bump plugs a~ 2339 stks, talc. 2317 stks a~ 165.5 bbls. CIP at 1320 hrs. PlUg bumped ,Flow check Bu~p plu~ :o 3500 p~i OK~Relea~e pressure check ~loats OK. Observed well statio Wellhead work Rigged down Casing hanger ruru~ing tool Rig down cement lines, Back-off lan~ing jr. and ].ay down same. Work completed, equipment laid out Installed Seal assembly Install pack-off and test to 5000 psi OK. E~iDment work completed, seal enerGised Test well control equipment Tesce~ BOP stack Test ~.5" pipe rams to 250/low and 5000 psi/high OK. Attempt to test annular, Had failure. Freeze protect $" X 9-5/8' annulus, P~p 88 bbls mud , ICP 2200 psi 1/2 bbl/min Final 850 psi 2 bpm. followed by ~ bbls ~ry cru~e and 5 bbls Die,el. Suspended pressure tes~ on Annular preven~or, observed 'leak ~epair Repaired Annular preventor Chan~e out element in Annular. Work completed, Annular preventor changed out Test well control e~uipmenC Tested Ar~nular preven~or Test Annular to 250/low and 3000 psi/high OK. Pull Tes~ plug and ins~a11 Wear bushing. Pre~sure ~est completed successfully - 3000.000 Rigged up Kelly Chang~ out $' Kelly to 3-1/2"