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Home My WebLink AboutCO 505 ~ . Conservation Order Cover Page XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. - - !:J- Q..:) Conservation Order Category Identifier Organizing (done) :;-SC::,o, ;Iems DIGITAL DATA OVERSIZED (Scannable with large plotter/scanner) o Diskettes, No. o Maps: o Grayscale items: o Other, Norrype o Other items o Poor Quality Originals: o Other: OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) o Logs of various kinds o Other NOTES: BY: ROBINB DATE: i /2{pj 0 if TOTAL PAGES 1!f-L- /5/ Vv1f Scanning Preparation BY: ROBIN E) DATE: f !;;.fo I D t¡- /51 vY1 P Production Scanning Stage 1 PAGE COUNT FROM SCANNED DOCUMENT: PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: YES NO BY: ROBIN MARIA DATE: /sl Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: YES NO BY: ROBIN MARIA DATE: /51 (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REOUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO OUAllTY, GRAySCALE DR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd . . INDEX CONSERVATION ORDER NO. 505 ORION POOL RULES 1. September 11, 2003 2. October 1, 2003 3. October 20,2003 4. October 29,2003 5. November 20, 2003 6. December 4, 2003 7. December 4,2003 Submission of Confidential (located in vault) Materials for Pre-application Meeting submitted by BPXA Submission of Orion Pool Rules (Confidential exhibits located in Vault) Notice of Hearing, Affidavit of publication, e-mail Distribution list, bulk mailing Submission of Supplemental Exhibits E-mail re: Addition to the Administrative Record Sign In Sheet Transcript Conservation Order 505 ,( 7n~ II{ IZ . E-3(. ->í d. ~ :=.. ~ 3. .lý STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order to establish pool rules for development of an Orion Oil Pool, Prudhoe Bay Unit, North Slope, Alaska ) Conservation Order No. 505 ) Prudhoe Bay Field ) Schrader Bluff Oil Pool ) Orion Development Area ) ) January 5, 2004 IT APPEARING THAT: 1. By application dated October 6, 2003, BP Exploration (Alaska), Inc. ("BPXA") in its capacity as Unit Operator of the Prudhoe Bay U~it ("PBU") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to define a proposed Orion Oil Pool within the PBU and to prescribe rules governing the development and operation of the pool. Concurrently, BPXA requested authorization for water injection to enhance recovery from the pool. 2. BPXA provided supplemental information at the Commission's request on October 29,2003. . 3. Notice of a public hearing was published in the Anchorage Daily News on October 20, 2003. 4. The Commission held a public hearing December 4,2003 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. FIND IN GS : 1. Orion Development Area of the Schrader Bluff Oil Pool a. Operator: BPXA is the Operator of the property in the area proposed for development. BPXA uses the name Orion in reference to this development project. In this order the area proposed for development will be referred to as the Orion development area. b. Development Area: The Orion development area is totally encompassed within the Prudhoe Bay Unit. ( Conservation Order 505 January 5, 2004 ( Page 2 c. Delineation History: Oil was discovered in the Orion development area in 1968 with the Kuparuk State # 1 exploratory well. Over 90 wells have penetrated the Schrader Bluff Formation (Schrader Bluff) in the Orion development area; nearly all were completed in deeper formations. In 1998, the Northwest Eileen 2-01 well was drilled, confirming hydrocarbons within the Schrader Bluff sands. Two producing wells have been completed within the Orion development area in the Schrader Bluff as of October 2003. BPXA utilized data from these wells in conjunction with a 3-D seismic survey to delineate the accumulations extent. d. Pool Identification: The proposed Orion Oil Pool is an accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("MD") of 4,549 feet and 5,106 feet in the PBU V -201 well. This is the same accumulation that is common to and correlates with the interval between the measured depths of 4,174 and 4,800 feet in the Conoco Inc. Milne Point A-I well, which has previously been defined in Conservation Order No. 477 ("CO 477") as the Schrader Bluff Oil Pool. Differences in infrastructure and unit resources, stratigraphic changes and uncertainty in the distribution of oil quality characterize the different areas of the Schrader Bluff Oil Pool. e. Stratigraphy: The Schrader Bluff Oil Pool encompasses reservoirs assigned to the Late Cretaceous-aged Schrader Bluff Formation. The Schrader Bluff Oil Pool contains two stratigraphic intervals that are designated, from deepest to shallowest, the "0 sands" and the "N sands." The 0 and N sand intervals were deposited in a marine shoreface and shallow shelf environment. In general, the 0 and N sand intervals are present across the entire Orion development area and, as a package, thin slightly from southwest to northeast. 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. Sands are unconsolidated, susceptible to local diagenetic alteration and lateral facies changes. 0 Sands The 0 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, to reservoir quality sandstone. OBf and OBe Sands The OBf and OBe intervals, each ranging in thickness from 35 to 55 feet, comprise the basal 0 sand units in the Schrader Bluff Oil Pool and exhibit the lowest net to gross sand facies in the 0 sand section. OBf and OBe sands also contain abundant pore-filling zeolites, which significantly reduce reservoir porosities and permeabilities. I' Conservation Order 505 ( January 5, 2004 ( Page 3 OBd Sands The OBd sand interval ranges between 55 and 70 feet thick and forms one of the primary target horizons. OBd sands are thickest in the Z-Pad area ranging up to 64 feet net sand in well Kuparuk State 1, and thin gradually northward to between 5 and 30 feet net sand in the proposed I-Pad area. The basal 5 to 10 feet of this blocky sand interval forms the highest quality OBd reservoir unit. OBc Sands The OBc sand interval, ranging between 45 and 60 feet thick, comprises a minor reservoir unit with reservoir quality sands present mainly in the V -Pad and Z-Pad areas. Up to 20 net feet of OBc sand is mapped in the V-Pad areas, while at L-Pad net sand thickness is typically 5 to 15 feet. To date, OBc sands have not been perforated in any Orion development area well. OBb Sands The OBb sand interval, also a minor reservoir unit, has a thickness range of between 45 and 60 feet with between 15 and 25 feet of net sand present in the V-Pad area. Regionally, the OBb interval typically contains less than 20 net feet of sand. OBa Sands The Oba sand interval has a 25 to 55 foot thickness range. Two regionally extensive erosion/scour surfaces are identified in the OBa sand, one in the middle of the unit and one at 10 to 15 feet from the top of the unit. Above each erosion/scour surface are bioturbated, blocky to fining upward high permeability sands (1000 millidarcies) that are 5 to 15 feet thick and constitute a primary development target. OA Sands The OA interval is 45 to 80 feet thick, with net sand thickness of 10 to 35 feet. Similar to the OBd and OBa intervals, the high quality sand sits above a regionally extensive erosion/scour surface and is heavily bioturbated. The high quality OA sand is less than 5 feet thick at Z-Pad, and thickens to 15 to 20 feet in the L-Pad and V-Pad areas. N sands The N sands are subdivided into three reservoir units, designated from deepest to shallowest as 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 0 sands at Orion and Milne Point (D, B, and A sands at West Sak) from generally heavier oil and water saturated sands in the overlying N and M sands (Lower U gnu sands at West Sak). t Conservation Order 505 January 5, 2004 ( Page 4 N c Sands Nc net sand is typically less than 15 feet thick across the area. 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. Nc sands have not been perforated or tested in an Orion well. Nb Sands The Nb sand interval ranges from 30 to 50 feet, and comprises the primary N sand interval completion target. Nb net sand character is highly variable in the Orion development area with net sand thickness ranging from 10 to 40 feet. The best Nb reservoir quality sand has local very high permeability (1000 millidarcies) intervals. Na Sands The Na sand interval is a thin, very low net-to-gross interval, which lies at the top of the N sand section and is consistently about 25 feet thick across the area. No N a sand tests or completions have been made in an Orion I well due to poor reservoir characteristics in this area. f. Structure: The top of the Schrader Bluff OA sand in the Orion development area has structural dip ranging from 1 to 4 degrees to the east and northeast, and it is broken by three sets of normal fault that trend from northwest to noutheast, north to south, and east to west. Northwest-Southeast Fault Trend The Northwest-Southeast striking fault trend, with throws of up to 200 feet, provides the predominate structural fabric of the pool. Faults with this orientation occur throughout the area, and form the boundaries of the major structural blocks in the area. The southwestern limit of the pool is formed by a complex fault system of northwest-southeast striking faults that link up and intersect with North-South faults to form a series of fault traps. North-South Fault Trend North-South striking faults, downthrown to the west and east are the second most dominate fault system in the pool. These faults have throws of up to 100 feet. East-West Fault Trend East- West faults are the least common fault trend in the Orion development area. East-west faults form part of the complex fault system that forms the reservoir trap on the southwestern side of the pool. (' Conservation Order 505 January 5, 2004 ( Page 5 g. Reservoir Compartments Elements of the major area fault systems were used to subdivide the pool in the Orion development area into reservoir compartments for development planning. As additional wells are drilled and production data gathered, the reservoir compartment picture could change. Each compartment was defined along seismically mapped fault trends and is 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 in the Orion development area and from analog studies, which show a high probability of clay smear seals forming along faults in the areas low net to gross reservoirs. N and 0 sand oil water contacts are in general poorly defined due to the lack of well control in down structure areas. No gas/oil contacts ("GOCs") have been logged in any sand in the Orion development area nor is the presence of free gas in Schrader Bluff intervals in the area predicted from oil PVT test results. Each sand in the N and 0 interval is assumed to be vertically isolated from overlying and underlying sands by low net-to-gross, non- reservoir, muddy siltstones and is assumed to have a different associated OWC depth. The best defined reservoir compartments are at L-Pad and V-Pad where oil column heights range between 150 and 310 vertical feet. Oil-water contacts have only been logged in three Orion development area wells: Kuparuk State 1 (OBa and OBd sands), L-I01 (Nb sand), and Northwest Eileen 1 well (OA and Nb sands). 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 area. 2. Rock and Fluid Properties a. Porosity/Permeability: No core information is available for the Schrader Bluff Oil Pool within the Orion development area. Porosity and permeability values were derived from routine core analyses of core plugs from Polaris Oil Pool wells S-200PBl and W-200PB1, and Kuparuk Field West Sak wells WSI-01 and lR- 07, and one Milne Point Unit Schrader Bluff Oil Pool well MPE-20. Porosity and permeability values used for reservoir simulation are based upon the Polaris log model. 0 sand reservoir simulation porosities range between 25 and 30% and permeabilities typically range from 50 to 250 md. Net pay thicknesses were derived using a petrophysical log model based upon well log and core data. Log- model cutoffs of 6 md permeability, 65% water saturation and 35% clay volume were used. b. Water Saturations: Water saturations were derived from Polaris airlbrine capillary pressure analyses of cores from wells S-200PB 1 and W -200PB 1. Leverett J - function curves were used to distribute water saturation according to porosity and permeability. Relative permeability curves for the Orion development area are based on analogy to the nearby Schrader Bluff accumulation at Milne Point. (" Conservation Order 505 January 5, 2004 t Page 6 c. Initial Reservoir Pressure: Average initial reservoir pressure in the Orion development area is estimated to be 1970 psi at 4400' TVDss. Reservoir temperature is about 87 degrees Fahrenheit at this datum. d. Fluid PVT Data: A total of 23 PVT analyses have been performed on Orion development area 0 sand oil samples. Geochemical analysis of 19 of these samples suggests that at least two oil charges are present. 0 series sand oil API gravities range from the low twenties to the mid teens. 3. Pool Limits The Schrader Bluff oil-bearing sands extend into the Milne Point Unit to the North and are present to the West in the Kuparuk River Unit West Sak Oil Pool. The Orion development area is the portion of the Schrader Bluff Oil Pool located within the Prudhoe Bay Unit. BPXA has requested a well spacing standoff of 500 feet from the exterior boundary of the Prudhoe Bay Unit, which is consistent with the Milne Point Field Schrader Bluff Oil Pool Rules and statewide regulation (20 AAC 25.055). BPXA as Operator of the Milne Point Unit submitted a letter on September 15, 2003 stating that the Milne Point Owners have no objection to the requested Orion pool rules and Area Injection Order application. On-going development operations in the Western PBU will provide additional information about the productive limits of the Schrader Bluff Oil Pool. 4. Hydrocarbons in Place Original oil in place within the Orion development area of the Schrader Bluff Oil Pool is estimated at 1,070-1,785 million stock tank barrels ("STB"), with 845 to 1,410 MMSTB in the 0 sands and 225 to 375 MMSTB in the N sands. All gas is in solution, and totals 210-345 billion standard cubic feet ("SCF"). 5. Pilot Well Performance Two wells are producing from the Schrader Bluff Oil Pool within the Orion development area, V-201 and V-202. The V-201 was fracture stimulated within the OA, OBa, OBb, and OBd sands. Initial production in April 2002 was 1080 barrels of oil per day ("BOPD") at gas oil ratio of 400 SCF/STB. As of August 2003, the well had declined to 600 BOPD, 7% water, and 400 SCF/STB. Total production was 174,000 barrels. V-202 is a 3000-foot single lateral drilled within the OBd. Initial test in July 2003 was 7100 BOPD, 350 SCF/STB. OA and OBa laterals are scheduled to be drilled in the fourth quarter 2003. No tests of the N sands were reported. Conservation Order 505 ( January 5,2004 (- Page 7 On October 14, 2003, the Commission approved dual injection into the Kuparuk and Schrader Bluff intervals in the Well V-I 05i. The purpose of this initial injection test is to determine the injectivity into the Schrader Bluff formation, determine the operability of commingled injection into two pools, and confirm that geological barriers will contain the injection fluid when injected at injection pressures above fracture gradient. 6. Development Plans Reservoir models have been used to evaluate primary depletion, waterflood, and other enhanced recovery options for development of the Schrader Bluff Oil Pool within the Orion development area. Reservoir predictions are based on fine scale, three- dimensional black oil models. Model studies performed to date for the Orion development area show about 5 to 10% recovery of OOIP under primary production and about 20-25% under waterflood (inclusive of primary). Initial development is planned in three phases, beginning near the crest of the structure and progressively moving toward the outer margins of the pool. a. Phase I Development: Phase I development targets the areas with good seismic quality and/or well control. This includes expansion of the development at V pad and drilling of at least one L pad tri-Iateral producer. A well within the W pad area may be drilled in 2004 testing the southeast area of the field. b. Future Phases of Development: Phase II development will be completion of locations that can be drilled from existing gravel pads. This would include drilling of 10-20 producers and 20-40 injectors in the L, V, Z Pads. An additional 2 producers and 4-8 injectors may be drilled from W pad. Phase III development will target the northwest portion of the field. A new pad will be required for this development. 10-20 producers and 20-40 injectors are envisioned. c. Rate Estimate: Peak production rates are expected to be between 30,000 and 50,000 barrels of oil per day ("BOPD"). Waterflood injection rates are estimated to peak between 100,000 and 125,000 barrels of water per day ("BWPD"). d. Well Spacing: Initial plans are to develop on an average spacing of 160 acres. BPXA requests a minimum well spacing of 20 acres to allow for flexibility in well placement because of local faulting and reservoir stratigraphy. CO 477 for Milne Point Field, Schrader Bluff Oil Pool allows a minimum well spacing of 10 acres. BPXA recommends a minimum offset of 500' from external lease boundaries, which is consistent with CO 477. e. Reservoir Management Strategy: Once water injection begins, voidage replacement ratio will be balanced and reservoir pressure will be maintained above the bubble-point. Conservation Order 505 ( January 5, 2004 ( Page 8 7. Facilities Orion wells will be drilled from existing V, L, Z and W-Pads, and a potential new 1- Pad. Production will be commingled with PBU Initial Participating Area ("IP A") fluids on the surface and will be processed at PBU Gathering Center 2 ("GC-2") to maximize use of existing IP A infrastructure, minimize environmental impacts, reduce costs, and maximize recovery. Some debottlenecking is anticipated for water injection at Orion. The options are currently being reviewed. No modifications will be required at OC-2 to process Orion development area production. Existing low pressure oil, water injection, gas lift and possibly miscible injectant lines will be shared. Existing well test equipment will be utilized at V, L, Z and W pads. Gas lift, jet pumps and electrical submersible pumps are all being evaluated for artificial lift. 8. Drillin2 Orion development area drilling will utilize drilling procedures, well designs, and casing and cementing programs that conform to Commission regulations. Conductors will be spaced 15' 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. c. Well Logs: Measurement while drilling ("MWD") and logging while drilling ("L WD") will typically begin at surface. MWD will include drilling parameters such as direction and inclination. L WD measurements will typically include gamma ray ("OR") and resistivity logs throughout the reservoir section. Openhole electric logs may supplement or replace L WD logging when wellbore conditions allow their use. These openhole logs may include OR, resistivity, density, neutron porosity, and/or other tools. d. Drilling Fluids: Freshwater low solids, non-dispersed fluids will be used to drill the Schrader Bluff and Prince Creek well sections. e. H2S Precautions: No significant H2S has been detected in any Orion development area 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. f Conservation Order 505 January 5, 2004 ,I ( Page 9 9. Well Completion Desi2n Horizontal, multi-lateral and conventional wells may be drilled at Orion. 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 wells. b. Subsurface Safety Devices: BPXA requested that subsurface safety valves not be not be required due to 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. c. Producers: Orion development area producers will not be completed in multiple pools. Artificial lift capability is designed into each producing well. d. Inlectors: Injectors may be completed to enable multi-pool injection where appropriate to the Schrader Bluff, Kuparuk, Sag River and Ivishak Formations. Packers will be installed for zonal isolation in multi-pool injectors. e. Stimulation Methods: Fracture stimulation has been used successfully for Orion development area producers and may be implemented to mitigate formation damage and stimulate future Orion development area 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 of 4,400 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. BPXA also proposes a minimum of two pressure surveys be taken each year in each reservoir compartment as shown in Exhibit 1-13 when at least one Orion development area production well has been completed in the respective compartment. Spinner logs are planned on multi-pool injection well completions to assist in the allocation of flow splits as necessary. ( Conservation Order 505 January 5, 2004 (' Page 10 11. Production Allocation The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 through August 2003, will be used for allocation of production. The GC-2 allocation factor will be applied to adjust total Orion development area production. New wells will be tested a minimum of two times per month during the first three months of production and at least once per month thereafter. CONCLUSIONS: 1. The proposed Orion Oil Pool is equivalent to the Schrader Bluff Oil Pool. 2. Pool Rules for the development of the Schrader Bluff Oil Pool within the Orion development area are appropriate at this time. 3. The Schrader Bluff Oil Pool within the Orion development area is compartmentalized and will require irregular spacing to optimize waterflood and recovery. Minimum well spacing of 10 acres is appropriate for efficient development of the pool and is consistent with pool rules (CO 477) for Schrader Bluff Oil Pool development with the Milne Point Field. 4. The Orion development area is in the early stages of development. Phase I development has focused upon determination of reservoir delivery and well operability. 5. Differences in existing infrastructure and uncertainties in the distribution of oil quality justify, at least for the time being, having separate pool rules for the Milne Point Unit and the Prudhoe Bay Unit (Orion development area) portions of the Schrader Bluff Oil Pool. 6. The full extent of the pool and the individual reservoir compartments are not yet known. 7. A well standoff of 500' minimum from the external boundaries of the Prudhoe Bay Unit is consistent with statewide regulations and with rules for the Milne Point Unit portion of the Schrader Bluff Oil Pool. 8. The Owners of the Milne Point Unit have no objection to BPXA's proposal to establish pool rules to govern development within the Orion development area. 9. Due to the incompletely understood nature of compartmentalization of the reservoir, and communication with the portion of Schrader Bluff Oil Pool located within the Milne Point Unit, pressure monitoring is necessary. ( Conservation Order 505 January 5, 2004 .'1; ~ Page 11 10. 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 and will ensure that future development plans promote greater ultimate recovery. 11. Water injection into the 0 and N Sands will preserve reservoir energy and increase ultimate recovery from the pool. 12. 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. 13. 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. 14. Use of the PBU Western Satellite Production Metering Plan that governs allocation of production from the Western Operating Area of the PBU is appropriate for production from the Orion development area of the Schrader Bluff Oil Pool. NOW, THEREFORE, IT IS ORDERED: 1. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply to the Schrader Bluff Oil Pool within the following affected area referred to here as the Orion development area: i' Conservation Order 505~ January 5, 2004 ( Page 12 Umiat Meridian Township Lease Sections Range. UM T12N-RI0E ADL 025637 13 and 24 N/2 TI2N-RI1E ADL 047446 17, 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27,28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SE/4, and 30 N/2 NE/4 TIIN-R11E ADL 028240 1,2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 ADL 028245 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 TI1N-RI2E ADL 047450 7, and 8 S/2 and NW/4 ADL 028263 16 SW/4 and S/2 NW/4, and 21 SW/4 and S/2 NW/4 and NW/4 NW/4 and W/2 SE/4 ADL 028262 17, 18, 19 N/2 and SE/4 and N/2 SW/4, and 20 ADL 047452 28 W/2 and W/2 E/2 ADL 047453 29 N/2 and N/2 SE/4 Rule 1 Well Spacine: Spacing units shall be a minimum of 10 acres. The Schrader Bluff Oil Pool shall not be opened in any well closer than 500' to an external boundary where ownership changes. Rule 2 Casine: and Cementine: 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. ( Conservation Order 505 January 5, 2004 i , Page 13 Rule 3 Automatic Shut-in Equipment 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 Commingling: a. Production from the Schrader Bluff Oil Pool within the Orion development area may be commingled with production from Prudhoe Bay Oil Pool, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. b. The Prudhoe Bay Unit Western Operating Metering Plan, described by letter from BPXA 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 Schrader Bluff Oil Pool wells within the Orion development area. c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. d. All wells must be tested a minimum of once per month. All new 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. e. Technical process review meetings shall be held at least annually. f. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. 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 one bottom-hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. c. The reservoir pressure datum will be 4400' 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. . ( ConservatIOn Order 505 . January 5, 2004 (" .1, Page 14 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 Schrader Bluff Oil Pool within the Orion development area 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 7 Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations Waterflood is required for purposes of pressure maintenance and enhanced oil recovery in the Orion development area of the Schrader Bluff Oil Pool. Production and injection operations must ensure the average reservoir pressure is maintained above bubble point. Rule 8 Multiple Completion of Water Injection Wells a. Water injectors may be completed to allow for simultaneous 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. f. Progress of plans and tests to expand the productive limits of the pool, including any work within the Prince Creek formation. (' Conservation Order 505 January 5, 2004 ( Page 15 By June I 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. Rule 10: Operation of Development Wells with Pressure Communication or Leaka2e in any Casin2'1 Tubin2'1 or Packer Requirements of Conservation Order No. 492 are incorporated by reference. Rule 11 Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated January 5, 2004. fA-' Daniel T. Seamount, Jr':, Commissioner Alaska Oil and Gas Conservation Commission Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 ( Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 ( David McCaleb I HS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 CO 505, AIO 26 and MPU L-43 Noticf' ( ( I MPU L-43 - Spacing ßxcepti 0 n- N otice.d oc I Con tent-Type: applicationlmsword i lof2 1/5/2004 10:51 AM CO 505, AIO 26 and MPU L-43 Notic~ f ( I Content-Encoding: base64 I . . .. _.-._"" . '.' ..- ... ._. .-.. .. . ..., ! 0 6 I Content-Type: application/msword I ¡AI 2 .doc ¡ I ! I Content-Encoding: base64 .. I I....................................................................................................................................................................................... ........................................................................ ....C'.~'~t~.~~~.T~.~~.~........'..........'...'......~~.~.ï.i.~.~¡i'~~~~.~~~d"..1 . CO 505.doc :1 i Content-Encoding: base64 :1 ,_.:.:::::::~.:.:::::'::._._----~~~~...._._..__._._.......-..--_.....__.__...._-_.._..-_:::::~---_._...._---_._._...._._--..__._--_...._._._._-_....._.._..__.._.._::::'::'..::"~~..:~::':::~..:::.,:::.:' 2 of2 1/5/2004 10:51 AM CO 505 and AIO 26 1 of 1 ( ( Subject: CO 505 and AlO 26 From: Jody Colombie <jody - colombie@admin.state.ak.us> Date: Mon, 05 Jan 2004 10:52:31 -0900 To: Cynthia B Mciver <bren - J:1Xiver@admin.state.ak.us> Please add to web site Content-Type: applicationlrmword. AIO 26.doc . Content-Encoding: base64 : ...---.-...-..---.--....-....-......-..-.-...--..---....---..--...."------"-'-"""-".'---'--"'-."'-"'-"-"'--"""-'.-........-..----.-...-----......-.--.----..---..-..-.-.-----_........ I........... ..... ... ........... ........... ............... ... ................................ ........... ............................. .... ..... ...................... ....'... ........ ........ ..... ........ ....... .... ..... ..... ............, ..... .... .... ........ ......... ........ ....... ............ ....... ...... ............. ......., ....... .... ................ .......... ....... .................. ...... ....................! ........................................ .................................. ........................................................................................................................................................................... i Content-Type: applicationlrnsword ¡ CO 50S.doc : \ Content-Encoding: base64 ............................. ................... ............ .................. ............................................................................................. .......................... .'.'...."""."'..."...""."'..."""."...""""."""'.."'.................................................................... 1/5/2004 10:52 AM #7 ( 6 7 8 9 10 11 12 13 ( 14 15 16 17 18 19 20 21 22 23 24 25 ( ( ({ 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 PUBLIC HEARING 3 ) ) ) ) ) In re: 4 ORION POOL RULES AND AREA INJECTION ORDER HEARING. 5 TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska December 4, 2003 9:00 o'clock a.m. COMMISSIONERS: SARAH PALIN, Chairperson DAN SEAMOUNT * * * * ~~c Oft ~/~D 'hi 11?tl1 & 6., C fJ 411£'h 011,. ~" rJt8ge . D METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ORIGINAL ¡ . ( ~. ,~' 1 TABLE OF CONTENTS 2 3 OPENING REMARKS BY CHAIR PALIN . . . . . . . . . . . . Page 3 4 TESTIMONY OF JONATHAN WILLIAMS. . . . . . . . . . . . . Page 6 5 END OF PROCEEDINGS 6 7 8 9 10 11 12 13 ( 14 15 16 17 18 19 20 21 22 23 24 25 ( . . . . . . . . . . . . . . . . . . Page 16 * * * * * METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 l ¡~ ( ( ( ( 1 PRO C E E DIN G S 2 (On record 9:03 a.m.) 3 CHAIR PALIN: Good morning. This hearing is now called 4 to order. It's Thursday, December 4, 2003, at 9:03 a.m. We're 5 In our AOGCC offices at 333 West Seventh here in Anchorage. 6 I'm Sarah Palin. With me is Commissioner Dan Seamount. We may 7 see our Assistant Attorney General Rob Mintz present himself 8 today. I don't know where he is right now. He may be here. 9 We also have Laura Ferro here of Metro Court Reporting 10 transcribing these proceedings, and if you wish to have a copy 11 of the transcript, please get a hold of Metro if you so desire. 12 These proceedings are held in accordance with 20 AAC 13 25.540, regulations governing public hearings, and these 14 hearings will be recorded. This hearing concerns Orion pool 15 rules and an area injection order. BP requested this, these 16 pool rules, and an area injection order on 10/1/03. We'll be 17 establishing pool rules for the Orion oil pool within the 18 Prudhoe Bay Field, and approve an area injection order 19 authorizing enhanced oil recovery operations in that pool. 20 Anchorage Daily News published this notice on 10/20/03. If BP 21 has any additions to your written application, which we have 22 received, of course, the order of proceedings today will 23 include the applicant presenting testimony. 24 All persons wishing to testify will be sworn in. And 25 if you wish to give expert testimony, we'll ask that you METRO CO UR T REPOR TING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 3 ( ( ( ,1: \ ( 1 provide your qualifications, and the Commission will decide if 2 your testimony will be accepted. Audience members who may have 3 questions may submit those in writing through our Commission 4 staff. Jane and Winton are here, and Jody's here. You can 5 give your questions to those three and they'll forward them on 6 Oral statements may be made after the testimony is to us. 7 presented. And there's a sign-up sheet, and I do have that in 8 front of me. I believe you have all signed in and indicated if 9 you wish to testify or make any statements, and it looks like 10 just Jonathan Williams will be testifying this morning. Thus 11 far no comments have been received, no request for a hearing 12 was received by the public. And, Jody, I assume since I talked 13 to you last, no comments still have been received? Thank you. 14 Okay. Then we will go forward with Jonathan's 15 testimony. And for the record -- and Bob Crandall's here also 16 from the staff. For the record, when Jonathan comes forward to 17 the mike, if he can state his name for the record and we will 18 swear him in. So, Jonathan, you're already here. 19 Yeah. MR. WILLIAMS: 20 Thank you. I'm going to swear you Okay. CHAIR PALIN: 21 in first so if you could raise your right hand? 22 (Oath administered) 23 I do. MR. WILLIAMS: 24 Thank you. And if you wish to be CHAIR PALIN: 25 considered an expert witness, please tell us what your METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 4 I. ( 13 ( 14 15 16 17 18 ( I( ( 1 qualifications are. 2 MR. WILLIAMS: Okay. My name is Jonathan Williams. My 3 surname is spelled W-i-I-I-i-a-m-s. I'm a geologist with BP 4 Exploration Alaska, Inc. I received a Master's of Engineering 5 degree in Civil Engineering from the University of Nottingham, 6 England, and a Master of Science degree in Geology from Oregon 7 State University in 2000. I've been employed by BP in Alaska 8 as a geologist for the last three years. I've worked on the 9 Prudhoe Bay Ivishak reservoir, and the Polaris and Orion 10 Schrader Bluff reservoirs. I joined the GPB Satellites team in 11 I would like to be acknowledged today as an expert 2003. 12 witness as a Geologist. CHAIR PALIN: Any objection? COMMISSIONER SEAMOUNT: No objections at all. CHAIR PALIN: All right. You're an expert. You're accepted. So please proceed, Mr. Williams, with your testimony. MR. WILLIAMS: On behalf of the Prudhoe Bay Unit 19 working interest owners, we have prepared the Orion Pools and 20 Area Injection Order Application submitted on October 6, 2003. 21 During the public notice period, we have answered all questions 22 asked by the Commission, and provided supplements where 23 information as requested. A technical review of the 24 application with representatives of the Commission was 25 conducted on October 28, 2003. Prior to submission, we held METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 5 ( 8 9 10 11 12 13 ( 14 15 16 ( ~ ( 1 several meetings with the Commission to discuss important 2 aspects of the application. 3 We ask that the Commission enter its entirety this 4 application to the record with two corrections as follows: 5 On page 33, under reservoir pressure measurements, the 6 common datum elevation should be 4,400 feet TVD subsea. 7 On page 38, under area injection operations, we request authorization for water injection only. At this time we do not request authorization for a miscible gas injection pilot to enhance recovery from the Orion Pool. CHAIR PALIN: Okay. Do you have any We'll note that. questions? COMMISSIONER SEAMOUNT: I have no questions. I'd like to thank you for a very complete and excellent write-up application. CHAIR PALIN: Thank you, guys. Thanks. I Okay. 17 don't have any questions either. Anybody else from BP with 18 anything else that you would like to add? We thank you Okay. 19 guys then. Mr. Williams, thank you for your testimony. And 20 hearing no questions from my fellow commissioner and I have 21 none also, then we can adjourn this very quick proceeding. And 22 thank you guys for your time for corning over very much, and 23 hopefully we'll get this out soon. Thank you guys. Okay. 24 We'll go off record. We're adjourned. 25 (Off record 9:08 a.m.) METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 6 (' 1 2 SUPERIOR COURT 3 STATE OF ALASKA 4 7 8 9 10 11 12 13 ( 14 15 16 17 18 19 20 21 22 23 24 25 ( I( ~, C E R T I FIe ATE ) ) ss . ) 5 I, Laura C. Ferro, Notary Public in and for the State of Alaska, do hereby certify: 6 THAT the annexed and foregoing pages numbered 2 through 7 contain a full, true and correct transcript of the Public Hearing before the Alaska Oil and Gas Conservation Commission, taken by and transcribed by Laura C. Ferro: 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 9th day of December, 2003. ~~~~~~~" .. .,8. ~ : . ..~~ :.'= ¡ ~~. . :: - '~ :U.~ c~.. :~ \.\'t1).~:ro.f:,1! ':-' .'U"" . .~' c~~?~~~ SIGNED AND CERTIFIED TO BY: ~ t!. 3~ Laura C. Ferro Notary in and for Alaska My Commission Expires: 6/03/05 METRO COURT REPORTING 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 7 #6 ( f ~ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION ORION POOL RULES AND AREA INJECTION ORDER HEARING December 4,2003 AT 9:00 am NAME-AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No 1 (PLEASE PRINT) ,fJ fJUW S> {' It ¡4f é¡ 4 1'- Eýd (; U ::J. ~k ç, \" ':S- ~ ~ t:.. " -.... . Ie N 1.\ T ~ AN iJ ¡ L !:liltj 5 --r- .ff'.. c e .. rei/'/' 5co.\t-Coo \e-y . 11 '~N \)N y-\: .. SoY) / ]'fc-t( JttAI()~)/1-/L .pI( .IIJv( HtV&1c ~ ç,,'i- $7t/' 'do 30'1 fIJ. ßf!JPLEf'ATH ope, À-,ASIl.-l.Â ¡J 0 <6l:3 ~ Vt". \ ~l.. S'llt.5J~ '-I tJ ø ~O3D ~f\lfRf ú,í!..Uf / AtvtnoR~CrE 1 5blt-s'g54- 'YES ,f 6(0 £O;J/¿";ùu!/1-: ß1c/-}t. S'.~\ '1~.JC 1-;;- ö Hc..çlt bZ_LL pc'..I^,,~ AK. .;(jb4S 357,2- 773 Alð ?b.J3 ~. d I~ 99 ? ) 9 ~~ Lf5'-555 3 AI. 0 ¡Jd \Meeting Sign-In #5 [Fwd: Addition to the Administrative Record for Orion Pool {Illes & AIO] II ( ~ Subject: [Fwd: Addition to the Administrative Record for Orion Pool Rules & AID] Date: Thu, 20 Nov 2003 08:32:33 -0900 From: Robert Crandall <Bob - Crandall@admin.state.ak.us> Organization: DOA-AOGCC To: "Aubert, Winton" <winton_aubert@admin.state.ak.us>, "Palin, Sarah" <sarah-palin@admin.state.ak.us>, "Seamount, Dan" <dan- seamount@admin.state.ak.us>, "Williamson, Mary" <jane - williamson@admin.state.ak.us>, "Colombie, Jody" <jody_colombie@admin.state.ak.us> Jody¡ Can you add a paper copy of this e-mail to the Orion applications? AII¡ This will help with two points we should include in the Orion CO and AIO. 1) The Schrader Bluff in the west end of PBU has a huge eor target and maximizing ultimate recovery may require more than waterflood. We should include a progress report on viscous oil recovery in the annual surveillance report. 2) The Orion Pool areal and vertical extent may be revised in the future. Let me know if you'd like to discuss. BC L. Subject: RE: Addition to the Administrative Record for Orion Pool Rules & AIO Date: Wed, 19 Nov 2003 14:55:23 -0900 From: "Huff, Brian D" <HuffBD@BP.com> To: Robert Crandall <Bob- Crandall@admin.state.ak.us>, "Seamount, Dan" <dan_seamount@admin.state.ak.us> CC: "Gustafson, Gary A" <GustafGA@BP.com>, "Williams, Jonathan D" <WilliJD@BP.com>, "Huff, Brian D" <HuffBD@BP.com> Bob, we concur with the clarification we will: 1) continue to study EOR evaluate other wells relative to AOGCC on both. you propose below. It is reasonable to assume that techniques for viscous oil, and 2) continue to their bearing on the Orion Oil pool¡ and update The only edit I would make to what you have below is to change horizontal extent to aerial extent. Please feel free to use the text below to update the administrative record for the proposed Orion Pool. Let me know if this matter requires anything further from the Orion Team. -----Original Message----- From: Robert Crandall [mailto:Bob Crandall@admin.state.ak.us] Sent: Wednesday, November 19, 2003 10:29 AM To: Huff, Brian D¡ Seamount, Dan Subject: Addition to the Administrative Record for Orion Pool Rules & AIO 1 of 2 11/20/2003 3:05 PM [Fwd: Addition to the Administrative Record for Orion Pool :rules & AIO] i ,{ II, '. Brian; As we discussed on the phone this morning, there are several issues related to the proposed Orion development that we feel should be addressed by the subject orders and are not explicitly addressed in the applications you have submitted. Your response to this e-mail can be used to update the administrative record for these orders. Both of the points that need clarification relate to the extent of the proposed Orion development. The vertical extent of the pool is not a function of the distribution of the resource, but rather the distribution of oil BP anticipates will be most amenable to waterflooding. Within the proposed development area, an as yet undetermined amount of resource will not be producable with the proposed waterflood. BP will address this issue by studying EOR techniques for viscous oil. Depending on the success of this work, at some point in the future the vertical extent of the pool may be revised to include oil excluded from the initial development plan. The AOGCC will periodically review (perhaps annually) the progress of your work with viscous oil EOR techniques. The horizontal extent of the proposed Orion Pool is to some degree a function of well control. As development in the Western PBU proceeds, numerous wells to either the Saddlerochit or the Kuparuk Fm. will be drilled. These wells should be routinely evaluated for oil bearing equivalents of the Orion Pool. With your concurrence on these two points, we will update the administrative record for the proposed Orion Pool. Bob Crandall 2 of2 11/20/20033:05 PM #4 October 29, 2003 f BP 1:(" ,ration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 0.'" :,"""" b ~'.., P "',1,"" Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Orion Pool Rules And Area Injection Application - Supplemental Exhibits Dear Commissioners: We have reviewed your October 20, 2003 correspondence regarding confidentiality of eight exhibits in our Orion Pool Rules and Area Injection Order Application. Attached are three (3) copies of the non-confidential version of the following exhibits. Please supplement the record accordingly to include these materials in the Orion Pool Rules and Area Injection Order Application: Exhibit 1-2A Exhibit 1-3A Exhibit 1-4A Exhibit 1-12A Exhibit 1-13A Exhibit 11-1 A Exhibit 11-4A Exhibit 11-7A Orion Pool/Injection Area and Proposed Orion Participating Area Outline Orion Pool/Injection Area Type Log Well V-201 Orion Pool/Injection Area Top Schrader Bluff OA Structure Map Orion Pool/Injection Area Thickness of Mudstone Between Top Na Sand and Base MC Sand Orion Pool/Injection Area Nand 0 Sand Reservoir Compartment Map Orion Model Reservoir Property Ranges Orion MDT Summary Table Orion Waterflood Rate Forecast Please contact myself (564-5110), or Jonathan Williams (564-5854) if you have any questions or comments regarding this response. Sincerely, ~- ~, tJ/f Brian Huff Satellite Resource Manager Greater Prudhoe Bay Attachments CC: (6!Z'þ3 F~) E f.'. ~:::.:TV' .E~.:'.C'~.'. ¡ ~ .... ....."! t.... ~. "" . .O:CT 2 9 ?;OO"~~ .. 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Exhibit 1-13A Exhibit II -IA - Orion Model Reservoir Property Ranges Average Property Ranges SAND LAYERS NET FEET POROSITY PERMEABILITY md OA 9 14.4 - 29 0.271 - 0.3 163 -194 OBa 7 14.4 - 27.5 0.283 -0.302 181 -236 ODd 8 24 - 37.8 0.277 - 0.282 57 - 89 ---, Exhibit II -4A - Orion MDT Summary Table SAND UNIT OA DBa OBb-d BP, psia 1324-1743 1134-1872 1207 -2045 Rs, set/stb 167-194 131-324 117-354 API Gravity 15.6-18.3 15.2-22.5 17.8-22.8 ""-"'-, Viscosity, cp 41.2-118.2 7.4-132 6.1-62 FVF, rb/stb 1.048-1.086 1.154 (1sample only) 1 . 121-1 . 165 Exhibit II-7A - Orion Waterflood Rate Forecast 120 Orion Oil Production 100 I Orion Water Production :E I - - .Orion Water Injection E .. CI) ..... C'G 0:: '- CI) ..... C'G ~ "'C C C'G - .- 0 80 60 40 20 0 2000 ,.. , ~ , .,. 2005 2010 2015 2020 Year -~. - - ~~---. ----- - - ~.þc'. 2025 2030 #3 STATE OF ALASKA '~ NOTICE TO PUBLISHER (' ADVERTISING ORDER NO. ADVERTISING INVOIC~ jT BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., <TIFIED AO-O2414010 ORDER AFFJDAVn OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE I' "SfEEBOJ'TOMFOR 'INVOICi:,AD[)RE$S " I" "", '", ", " " F AOGCC AGENCV CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jodv Colombie October 16, 2003 0 J\nchorage,AJ( 99501 PHONE PCN M IYU/\ 791 -1221 - DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News October 20, 2003 0 POBox 149001 Anchorage, AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement X Legal D Display 0 Classified DOther (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 \\'. 7th A "e., Suite 100 PAGE 1 OF TOTAL OF TO Anchorage. AK 99501 2 PAGES ALL PAGES $ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 3 4 FIN AMOUNT Sy CC PGM LC ACCT FY NMR DIST LlO 1 04 02140100 73540 2 3 4 ~ REQUISITIONED~Y:-,-..", (' t1 (/( D~1PPROVA~: & ' ,..,'~ ,/ .-~O\A.^ .r--- t&- xJ, J~ ¿7' ( -' () " 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM ( ~t Notice of Public Hearing ST ATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Orion Oil Pool, Prudhoe Bay Field Area Injection Order and Pool Rules BP Exploration (Alaska), Inc Alaska, Inc. by application dated October 6, 2003, 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 Orion Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. The Commission has set a public hearing on this application for December 4, 2003 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on November 6, 2003. 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 November 24,2003. ~~~ Randy Ruedrich Commissioner Published Date: October 20,2003 ADN AO 02414010 RE: Ad Order \. ¡J~ ,. Subject: RE: Ad Order Date: Thu, 16 Oct 2003 17:22:34 -0800 From: "legal ads" <legalads@adn.com> To: "Jody Colombie" <jody_colombie@admin.state.ak.us> Hi Jody: Following is the confirmation information on your legal notice. Please let me know if you have any questions or need any further information. Account Number: STOF 0330 Legal Ad Number: 978425 Publication Date(s): October 20,2003 Your Reference or PO#: AO-024140 1 0 Cost of Legal Notice: $107.16 Additional Charges Web Link: E-Mail Link: Bolding: Total Cost to Place Legal Notice: $107.16 Add Will Appear on www.adn.com: XXXX Add Will Not Appear on www.adn.com : Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 ---------- From: Jody Colombie Sent: Thursday, October 16, 20032:51 PM To: legalads Subject: Ad Order «File: Orion Pool AIO.doc»«File: Ad Order form.doc»«File: jody colombie.vet» Please publish on Monday October 20,2003. Jody I of 1 10/20/2003 8:25 AM >( Anchorage Daily News Affidavit of Publication ( 10/21/2003 IDOl Northway Drive. Anchorage. AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARG ES #4 CHARGES #5 TOTAL 978425 10/20/2003 02414010 STOF0330 $107.16 $107.16 $0.00 $0.00 $0.00 $0.00 $0.00 $107.16 ST ATE OF ALASKA THIRD JUDICIAL DISTRICT Kimberly Kirby, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. Notice of Public Hearing STATE OF ALASKA Alaska 011 and Gas Conservation Commission Re:Orion Oil PoOl, Prudhoe Bay Field Area Iniectlon Order and Pool Rules ~P ~xploration (Alaska), Inc Alaska, Inc. by op- '. , pllcatro.n dqted October 6, 2003, has applied for an I area Inlectlon order and pool rules under 20 AAC . ~5.460 and 20 AAC 25.520, respectively to govern ~veopment of the Orlan Oil Pool, Pr'udhoe Bay Field, on the North Slope of A/ask". Th~ Cof1îmission h'as seta ¡:ìtib/j~ hearing on this! apPJlcatlo.n for December 4, 2003 at 9:00 am at the. Alaska all and Gas Conservation Commission at ~~lo~est 7th;Avenue, Suite 100, Anchorage, Alaska In addition, a person may SU'bmit written com ments regarding this application to the Alaska oli ! and Gas Co.nservatlon Comm.ission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Writ- ten comments must be received no later than 4'30 I pm on November 6, 2003. . I I If YOU are. a per~on with a disability who may! need a SpecIal mO~Ifi.cation in order to comment or . to atte~d the public h.earlng, please contact Jody ColombIe at 793-1221 b~fore November 24, 2003. 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 said time 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 worn to me efore this date: /r;Øf/& Publish: October 20, 2003 Randy Ruedrich Commissioner I ADN AO 02414010 I , .'" Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska ~ MY COMMISSI E~IRE: ~:ß-fJ§.., \\\(( ({{((It: \.'\\o.\9I~'~' ~: ð%~ \.: ~ . -.... . ~ ". ~. ~'~OTAð"....~ ~ . ~ IIT,.- "-. ..... .- ... . I!J.. . - ::: r',....~.:-- STATE OF ALASKA ADVERTISING ORDER . . SEE BOTTOM FORINVOICEAODRESS , . , '. ':1 NOTICE TO PUBLISHER J ADVERTISING ORDER NO. INVOIC~ jT BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO.~ ,TIFIED AO-O241401 0 AFFIDAVII ùF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 West ih Avenue, Suite 100 0 i\nchorage,AJ( 99501 M 907-793-1221 AGENCY CONTACT DATE OF A.O. T 0 i\nchorage Daily News POBox 149001 Anchorage, AK 99514 DATES ADVERTISEMENT REQUIRED: October 20, 2003 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION r United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published 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 2003, and thereafter for - consecutive days, the last publication appearing on the day of ,2003, 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 2003, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER Public Notice ~.. ;( Subject: Public Notice Date: Thu, 16 Oct 2003 14:55:39 -0800 From: Jody Colombie <jody_colombie@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission BCC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, John Tanigawa <JohnT@EvergreenGas.com>, Terrie Hubble <hubbletl@bp.com>, Sondra S tewman <S tewmaSD@BP .com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, trmjrl <trmjrl @ao1.com>, jbriddle <jbriddle@marathonoi1.com>, rockhill <rockhill@aoga.org>, shaneg <shaneg@evergreengas.com>, rosew <rosew@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <nelson@gci.net>, cboddy <cboddy@usibelli.com>, "mark. dalton" <mark. dal ton@hdrinc.com>, "shannon.donnelly" <shannon.donnelly@conocophillips.com>, "mark. p. worcester" <mark. p. worcester@conocophillips.com>, "jerry.c.dethlefs" <jerry.c.dethlefs@conocophillips.com>, bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, burgin - d <burgin - d@niediak.com>, "charles.o'donnell" <charles.o'donnell@veco.com>, "Skillern, Randy L" <SkilleRL@BP.com>, "Dickey, Jeanne H" <DickeyJH@BP.com>, "Jones, Deborah J" <JonesD6@BP.com>, "Hyatt, Paul G" <hyattpg@BP.com>, "Rossberg, R Steven" <RossbeRS@BP.com>, "Shaw, Anne L (BP Alaska)" <ShawAL@BP.com>, "Kirchner, Joseph F" <KirchnJF@BP.com>, "Pospisil, Gordon" <PospisG@BP.com>, "Sommer, Francis S" <SommerFS@BP.com>, "Schultz, Mikel" <Mikel.Schultz@BP.com>, "Jenkins, David P" <JenkinDP@BP.com>, "Glover, Nick W" <GloverNW@BP.com>, "K.leppin, Daryl J" <KleppiDE@BP.com>, "Platt, Janet D" <PlattJD@BP.com>, "Jacobsen, Rosanne M" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, collins_mount <collins - mount@revenue.state.ak.us>, mckay <mckay@gci.net>, "barbara. f. fullmer" <barbara.f. fullmer@conocophillips.com>, eyancy <eyancy@seal-tite.net>, bocastwf <bocastwf@bp.com>, cowo <cowo@chevrontexaco.com>, ajiii88 <ajiii88@hotmail.com>, doug_schultze <doug_schultze@xtoenergy.com>, "hank.alford" <hank.alford@exxonmobil.com>, yesnol <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, "gregg.nady" <gregg.nady@shell.com>, "fred.steece" <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, jroderick <jroderick@gci.net>, eyancey <eyancey@seal-tite.net>, "j ames.m.ruud" <j ames.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr.state.ak.us>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com>, "Emeka. C.Ezeaku" <Emeka. C.Ezeaku@spdc.shel1.com>, mark - hanley <mark - hanley@anadarko.com>, loren _leman <loren _leman@gov.state.ak.us>, Harry R Bader <harry_bader@dnr.state.ak.us>, julie_houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, lof2 10/1 6/2003 2:55 PM Public Notice ( (' Suzan J Hill <suzan_hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, jimwhite <jimwhite@satx.rr.com>, Stephanie _Ross <Stephanie - Ross@thomson.com>, "john.s.haworth" <john.s.haworth@exxonmobil.com>, marty <marty@usalaska.biz> Orion Oil Pool, Prudhoe Bay Field, Area Injection Order and Pool Rules. Name: Orion Pool AIO.doc ~Orion Pool AIO.doc Type: WINWORD File (application/msword) Encoding: base64 F Co1 o~b i e < i ody co 10mb ie@admin. state. ak.us~ . 2 of2 1011 6/20032:55 PM Public Notice (' Subject: Public Notice Date: Thu, 16 Oct 2003 14:54:24 -0800 From: Jody Colombie <jody_colombie@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Nancy Norton <Nancy _Norton@admin.state.ak.us> Please publish on the web site. Jody r--'--------- .--.--------- (' - -..---- -----..-- -- -----"'-- ..------- _--_m'- Jody Colombie <iody colombie@admin.state.ak.us> I of 1 10/16/2003 2:55 PM Ad Order ( o( ~ \ Subject: Ad Order Date: Thu, 16 Oct 2003 14:51:47 -0800 From: Jody Colombie <jody_colombie@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish on Monday October 20, 2003. Jody Name: Orion Pool AIO.doc Œ90rion Pool AIO.doc Type: WINWoRD File (application/msword) Encoding: base64 Name: Ad Order form.doc Œ9Ad Order form.doc' Type: WINWORD File (application/msword): . Encoding: base64 . . " . . ., " ."" ., ",. " "',"',""'" *",. .,.",'" , Jody Colombie <lady colombie@admin.state.ak.us> of 1 1 OIl 6/2003 2:56 PM SO Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SO 57702 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Kenai Peninsula Borough Economic Development Distr 14896 Kenai Spur Hwy #103A Kenai, AK 99611-7000 Penny Vadla 399 Riverview Ave Soldotna, AK 99669.7714 (' Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 W. Allen Huckabay ConocoPhillips Petroleum Company Offshore West Africa Exploration 323 Knipp Forest Street Houston, TX 77079-1175 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 l ~. Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 II; , North Slope Borough PO Box 69 Barrow, AK 99723 I~ \ Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 #2 bp (' (" A";! " ',. ."," ,-" .',.,.". '.,' ." BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 October 1 , 2003 DELIVERED BY HAND Commissioners Alaska Oil and Gas Conservation Commission Ji>A',.. 333 West ih Avenue, Suite 1 00 '(,,~/,I ~ Anchorage, AK 99501 -4G.." 0c7-. Vl::t; RE: Orion Pool Rules and Area Injection Order Application ""~I~ 06 <>Pod Dear Commissioners: ~, Enclosed for your review and action is the Prudhoe Bay Unit (PBU) Working Interest Owners' application for Pool Rules and Area Injection Order for the Orion reservoir, submitted pursuant to 20 AAC 25.520 and 20 AAC 25.460. BP Exploration (Alaska) Inc.(BPXA), as Orion Operator and Unit Operator, respectfully requests that the Commission schedule a hearing as early as possible on this application. Please maintain as confidential those certain exhibits attached and labeled "CONFIDENTIAL" in accord with AS 31.05.035 and 20 AAC 25.537. Please contact myself (564-5110) or Jonathan Williams at 564-5854 if you have any questions or need additional information. Sincerely, --¡) f ,'ì, ,/ ..-. v Brian Huff Satellite Resource Manager Greater Prudhoe Bay ~ -l{¡ Attachments Cc: Francis Sommer, BPXA Marc Vela, ExxonMobil Dan Kruse, CPAI G.P. Forsthoff, Chevron Ken Griffin, Forest Oil Jonathan Williams, BPXA Gary Gustafson, BPXA (' ( ( '. Orion Pool Rules and Area Injection Order At .ttion ( October 6, 2003 Orion Pool Rules and Area Injection Order Application October 6, 2003 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 Table of Contents I. Geo logy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 4 Introduction.................................................. .......,............... ............................................. """"" .......4 Stratigraphy....................................................................................................................................... 5 Schrader Bluff Formation - Geologic Structure ............................................................................. 10 Fluid Contacts """"""""""""""""""""""""""""""""""""""""""""""""""""""""""""'"...... 12 Oil-Water Contacts..................... ........ .... .......................,.......... ...... ................................................. 12 Net Pay and Pool Limits ..,.............................................................................................................. 13 II. Reservoir Description and Development Planning................. 15 Rock and Fluid Properties ......................................................................."...................................... 15 Hydrocarbons in Place """"""""""""""""""""""""""""""........................................................ 17 Reservoir Perforlnance """""""""""""""""""""""""""""'".......................................... """""'" 18 Development Planning ....................................................................................................................19 Development Options.................................................."""""""""""""""""""""""""""'"...........20 Development Plan ................................................,..........................................................................21 Reservoir Management Strategy .....................................................................................................23 III. Facilities................................................................................ 25 General Overview ...........................................................................................................................25 Pad Facilities and Operations..........................................................................................................26 Gathering Center ............................... .........................................................................................,.... 28 IV. Well Operations .................................................................... 29 Existing Wells ...................................................,.............................................................................29 2 Orion Pool Rules and Area Injection Order At .!tion (' October 6, 2003 (' Drilling and Well Design .... .......................... .................................... ........ ............................. ......... 29 Reservoir Surveillance Program ............ ..... ......... ......... ............... ...... ..... .......... ........ ........... ...... ..... 33 V. Production Allocation............................................................. 37 VI. Area Injection Operations ..................................................... 38. Plat of Project Area......................... ..................... ............................................................. ......... ..... 38 Operators/Surface Owners .............................................................................................................. 38 Description of Operation................................................................................................................. 38 Pool Information.................................... ...................................... ...... ....................... ................. .....39 Geologic Information........................................ ..................................... .............. ........................... 39 Log Information ................................ ............ ....................................... ..................... ......................39 Injection Well Casing Information.. ..... ..................... ......................................... ................ ............. 39 ( Injection Fluids............................................................................................... ................................. 40 Injection Pressures.......... ............... .... ....... .......................... ............................................................ 41 Fracture Information .......................................................... .................... .................................... ..... 41 Formation Water Quality.................... .................................................. ................ ..................... ..... 42 Freshwater Strata............................................................................................................................. 42 Hydrocarbon Recovery................. ........ ........................................................ .................................. 42 Mechanical Integrity of Wells....... ..... ....................................... .................... .................................. 42 VII. Proposed Orion Pool Rules.................................................. 44 VIII. Proposed Area Injection Order........................................... 51 IX. List of Exhibits........ ............ .......... ....................................... 55 ( ,~ 3 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 I. Geology Introduction The proposed Orion Pool Rules area is located within the Prudhoe Bay Unit (PBU) on Alaska's North Slope, as illustrated in Exhibit I-I. The Orion Pool overlies the Prudhoe Oil Pool (also referred to herein as the "Prudhoe Pool" or "Prudhoe") in the vicinity of PBU L, V, Wand Z Pads and overlies the Borealis Oil Pool (also referred to herein as the "Borealis Pool" or "Borealis") in the vicinity of PBU L and V Pads. The Kuparuk State No. 1, drilled in 1968, was the first well to penetrate and log hydrocarbons in the Orion Pool. In 1998, the Northwest Eileen 2-01 well was drilled. Sidewall cores in that well confirmed hydrocarbons in the Schrader Bluff sands. Exhibit 1-2 shows the location of the Orion Pool area. The boundaries of the Orion Pool Rules area coincide with the boundaries of the proposed Orion Participating Area (OP A). The Orion Pool hydrocarbon accumulation is bounded by faults on the up-dip west and south sides and by closure down-dip into the regional aquifer on the down-dip east side. To the north, the Orion Pool hydrocarbon accumulation is interpreted to extend to the boundary of the Schrader Bluff Oil Pool. To the northeast, although seismic evidence suggests the hydrocarbon accumulation may extend beyond the Prudhoe Bay Unit boundary, this has not yet been confirmed. The Orion Pool is comprised of the ten distinct Nand 0 sand intervals of the Schrader Bluff formation. Hereafter, applicants request the Commission define the Orion Oil Pool (also referred to herein as the "Orion Pool" or simply "Orion") as including all of the hydrocarbon bearing sands within the described area that correlate with the Schrader Bluff Nand 0 sand intervals detailed on the V -201 type log depicted in Exhibit 1-3. As shown on the Schrader Bluff OA structure map in Confidential Exhibit 1-4, the Orion structure crests in the northwest Orion Pool region (3980 feet TVDSS at the Schrader Bluff OA mapping horizon) and trends down dip to the east through faulting and regional dip. North-south, east-west, and northwest-southeast trending faults subdivide the Orion Pool into discrete fault blocks. Fluid 4 Orion Pool Rules and Area Injection Order At ltion (' October 6, 2003 ( isolation between several fault blocks is interpreted by log data from adjacent fault-separated wells that show water structurally higher than oil in the same sands on opposites sides of faults. Sealing faults are predicted in the Orion Pool based on the prevalent low net to gross reservoir lithologies. Commerciality of the Orion Pool was confirmed in April 2002 through the f~acture-stimulated completion and production of the Schrader Bluff 0 sands in well V-201. Well V-202 was the first Orion high-angle development well at V-Pad and began production from the OBd sand interval in June 2002. Additional laterals will be added to well V-202 in the OBa and OA sands to make it a high-angle trilateral producer. Stratigraphy Exhibit 1-3 shows the open-hole wireline log character of the Schrader Bluff 0 and N sands in a type log from the V -201 well. This type log illustrates the vertical stratigraphic extent of the Orion Pool that comprises the 0 and N sands. In the V-201 well, the top of the Orion Pool occurs at 4,126 feet TVDSS (4,549 feet MD) and the base occurs at 4,650 feet TVDSS (5,106 feet MD). ( As shown in Exhibit 1-3, the Orion 0 and N sands are further subdivided into seven 0 sands, and three N sands. A general description of the thickness and character for each of the Orion sands follows. A detailed description of the rock properties associated with individual sands is given in Section II. In general, the 0 and N sand intervals are present across the entire Orion Pool area and, as a package, thin slightly from southwest to northeast across the Orion 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 Schrader Bluff Formation Nand 0 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 U gnu Formation M sands. ( 5 Olion Pool Rules and Area Injection Order ¡cation October 6, 2003 The contact between the basal Schrader Bluff Formation 0 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 Orion, form the basal confining unit of the Orion Pool. The contact between the upper Schrader Bluff Formation N sands and the overlying U gnu M sand section is generally abrupt and lies at the base of a regionally continuous 4 to 12 foot thick muddy siltstone layer. Exhibit 1-12 is a thickness map of this mudstone. Mapping using 3D seismic and well control shows no areas in the Orion Pool area where this mudstone is not present between the Mc and N sands. 0 Sands The Schrader Bluff 0 sand interval is the primary development target in the Orion Pool and is subdivided into seven separate reservoir horizons, from deepest to shallowest - the OBf, OBe, OBd, OBc, OBb, OBa, and OA. OBe and OBf Sands The OBf and OBe intervals, each ranging in thickness from 35 to 55 feet, comprise the basal Orion Pool's 0 reservoir units and exhibit the lowest net to gross sand facies in the 0 sand section. Both intervals are characterized by basal muddy siltstones that grade upward into thin very fïne-grained, laminated sands. Abundant lithic feldspar grains are present in both the OBf and OBe intervals, which result in an abnormally high OR 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. OEd Sands The OBd sand interval in the Orion Pool ranges between 55 and 70 feet thick and forms one of the primary Orion reservoir target horizons. OBd sands are thickest in the Z-Pad area ranging up to 64 feet net sand in well KUPST -01, and thin gradually northward to between 5 and 30 feet net sand in the proposed I-Pad area. The OBd interval grades upward, from a basal muddy siltstone into low 6 Orion Pool Rules and Area Injection Order Ai.' .ltion (" October 6, 2003 ( quality laminated and bioturbated reservoir sands that gradually clean upward. A 10 to 30 foot thick blocky to fining upward sand unit caps the OBd interval over most of the Orion Pool area. The basal 5 to 10 feet of this blocky sand interval forms the highest quality OBd reservoir unit, but thins to the north of L-Pad. Reservoir quality OBd sands are unconsolidated and almost entirely very fine to fine-grained. Initial production rates from a single horizontal leg of well V -202 drilled in this sand with oil-based mud exceeded 7000 bopd. OBc Sands The OBc sand interval, ranging between 45 and 60 feet thick, comprises a minor Orion reservoir unit with reservoir quality sands present mainly in the V -Pad and Z-Pad areas. The OBc interval coarsens upward from basal muddy siltstones to a low net to gross silty sand, with a moderate net to gross laminated to layered very fine-grained sand at the top of the unit. Up to 20 net feet of OBc sand is mapped in the V -Pad areas, while at L-Pad net sand thickness is typically 5 to 15 feet. To date, OBc sands have not been perforated in any Orion Pool well. ( OBb Sands The OBb sand interval, also a minor Orion Pool reservoir unit, has a thickness range of between 45 and 60 feet with between 15 and 25 feet of net sand present in the V-Pad area. Regionally, the OBb interval typically contains less than 20 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 interval, and higher net to gross than the underlying OBc interval. Individual clean OBb sand layers, observed in core from Polaris wells, are typically less than one foot thick and are separated by silts and muds of comparable or greater thickness than the sands. There are occasional blocky sands greater than one foot thick. OBb sands in the V-201 well were hydraulically fractured and produce commingled with the overlying OBa sands. 0 Ba Sands The OBa sand interval within the Orion Pool, with a 25 to 55 foot thickness range, cleans gradually upward from a basal siltstone into interbedded thin sands and mudstones to an upper cross-laminated ( 7 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 sand unit. Two regionally extensive erosion/scour surfaces are identified in the OBa sand, one in the middle of the unit and one at 10 to 15 feet from the top of the unit. Above each erosion/scour surface are bioturbated, blocky to fining upward high permeability sands (1000+ md.) that constitute a primary development target of the Orion Pool. The high permeability sand interval above the lower erosion/scour surface thins from southeast to northwest across the Orion region and is 5 to 10 feet thick. The upper high permeability sand is 5 to 15 feet thick, caps the OBa unit and thins to the southeast across the Orion Pool such that it is missing in the Z-Pad area. Hydraulically fractured OBa sands were produced in well V-201. OA Sands The OA sand interval comprises a 10 to 25 foot thick basal silty mudstone that coarsens upward, gradually or abruptly, into stacked sets of cleaning upward reservoir sand units. As a package, the OA interval is 45 to 80 feet thick, with net sand thickness of 10 to 35 feet. OA sands show a dominantly coarsening upward log profile with the highest quality sands present in the upper third of the OA gross interval. OA sands are very tine to fine-grained, faintly laminated to massive and moderately to strongly bioturbated, particularly in the upper fining upward sand section. Similar to the OBd and OBa intervals, the high quality sand sits above a regionally extensive erosion/scour surface and is heavily bioturbated. The high quality OA sand is less than 5 feet thick at Z-Pad, and thickens to 15 to 20 feet in the L-Pad and V-Pad areas. The high quality reservoir sand caps the OA interval and is truncated abruptly at the top OA sand contact. Basal and middle OA sands are generally poor to non-reservoir in quality. OA sands have been completed in the 1 1 ... 11 {" , 1'<Y,",A' 11 llyuraullcallY uaCLUreu v -.LVI well. N Sands The Schrader Bluff N sand interval overlies the Schrader Bluff 0 sand interval and ranges between 140 and 180 feet thick in the Orion Pool area. Orion 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 lowennost N 8 Orion Pool Rules and Area Injection Order Ai ¡rion ( October 6, 2003 ( sand interval form an important regional vertical reservoir barrier which segregates lighter, higher quality, oil in the main development horizon 0 sands at Orion 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 U gnu sands at West Sak). Nc Sands The Nc interval, ranging from 75 to 105 feet thick, is dominated by mudstone and muddy siltstone in the Orion Pool area and contains thin interbedded reservoir quality sands only in the upper 15 to 30 feet of the interval. Nc net sand is typically less than 15 feet thick across the Orion Pool area. 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. Nc sands have not been perforated or tested in an Orion Pool well. (' Nb Sands The Nb sand interval ranges from 30 to 50 feet thick in the Orion Pool and comprises the primary N sand interval completion target. Nb net sand character is highly variable in the Orion Pool area with net sand thicknesses ranging from 10 to 40 feet. The best Nb reservoir quality occurs near L-Pad where blocky to fining upward sand with very high permeability (1000+ md.) occurs above an erosional surface. This high quality interval is some of the coarsest grained sand in the Orion Pool, but it is not laterally extensive and it may be a channelized deposit. Other channel deposits in the Nb sand may be present near V-Pad, Z-Pad, and the possible new I-Pad, but existing penetrations do not delineate these features. Outside of the known channel sands, Nb sands are less than 10 feet thick and are interbedded with similar or greater thicknesses of mud and silt. No Nb sand completions have been made in the Orion Pool area. Na Sands The Na sand interval is a thin, very low net-to-gross interval, which lies at the top of the N sand section and is consistently about 25 feet thick across the Orion Pool. Na reservoir sands are generally very fine-grained, laminated, and bioturbated. Individual Na sands are two to four feet thick, exhibit ( ~ 9 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 a spikey log character, and are interbedded with thicker non-reservoir siltstones. No Na sand tests or completions have been made in an Orion Pool well due to poor reservoir characteristics in this area. Schrader Bluff Formation - Geologic Structure Exhibit 1-4 is a structure map on the top of the Schrader Bluff OA sand in the Orion Pool area, with a contour interval of 20 feet. Although the Schrader Bluff interval generally dips eastward and northeastward at one to four degrees in the western portion of the Prudhoe Bay Unit, it is broken up into a series of distinct fault blocks in the Orion Pool, as indicated by 3D seismic data and by well penetrations. The structural character at the Schrader Bluff level in the Orion Pool and vicinity 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, provides the predominate structural fabric of the Orion Pool. Faults with this orientation occur throughout Orion, and form the boundaries of the major structural blocks in the area. The southwestern limit of the Orion Pool is formed by a complex fault system of northwest-southeast striking faults that link up and intersect with north-south faults to form a series of fault traps. The northwest-southeast faults more often are downthrown to the southwest, but can also be downthrown to the northeast. North-South Fault Trend North-South striking faults, downthrown to the west and east are the second most dominant fault system in the Orion Pool. These faults have throws of up to 100 feet. Some of the north-south trending faults can be demonstrated to have relatively recent movement, with offsets as shallow as 1000 feet tvdss in the permafrost. East- West .Fault 'I'rend East -West faults are the least common fault trend in the Orion area. East -west faults form part of the complex fault system that forms the reservoir trap on the southwestern side of Orion. 10 Orion Pool Rules and Area Injection Order At .1tion (' October 6, 2003 ( Reservoir Compartments Elements of each of the major area fault systems were used to subdivide the Orion Pool into reservoir compartments for development planning purposes. As additional wells are drilled and production data gathered, the reservoir compartment picture could change. The location and areal extent of these reservoir compartments is marked by the polygon boundaries shown in Confidential Exhibit 1-13. Each compartment was defined along seismically mapped fault trends and is 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 Orion and from analog studies, which show a high probability of clay smear seals forming along faults in the Orion low net to gross reservoirs. Polygon nomenclature and boundary character is summarized below. i ( Reservoir PoIV2on Boundarv Character Polygon 1 Fault bounded on the southwest, southeast and northwest sides. On the northeast side of the polygon, reservoir sands dip to the northeast into the aquifer. Polygon 1A Fault bounded on the west, northwest, south sides. On the northeast side of the polygon, reservoir sands dip to the northeast into the aquifer. Polygon 2 Polygon is fault bounded on all sides. Wells in the down- dip southeast portion of polygon are wet. Polygon2A Polygon is fault bounded all sides, extent of filling unknown on down-dip east side. Polygon 3 Fault bounded on northeast, west, northwest, and southwest side. Down-dip east side of block is bound by dip into aquifer. Polygon 3A Fault bounded on west, southwest, and east side. North- south fault on east side of polygon has up to 200' of throw, and separates Orion from Polaris. Dip within fault block to northeast, with two well penetrations in the aquifer. Polygon 4 Polygon 4 is down thrown to Polygon 1 by a northwest- southeast fault with up to 180' of throw. Polygon 4 is a complexly faulted graben that is fault bounded on all sides. (". 11 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 Polygon 5 Polygon 5 is fault bounded on all sides. Dip within polygon is to the east; wet wells in down-dip east side of block define OWC. Polygon 6 Fault bounded on all sides, with complex internal faulting indicated by seismic. No well penetrations in polygon 6 inside PBU. However, down-dip penetrations of fault block in MPU show presence of hydrocarbons. Fluid Contacts Confidential Exhibits 1-6 through 1-11 show the depths of interpreted Oil/Water Contacts (OWCs) in the Nand 0 sands on cross-sections across the Orion Pool. Nand 0 sand OWCs are in general poorly defined due to the lack of well control in down structure areas. No Gas/Oil Contacts (GOCs) have been logged in any Orion sand nor is the presence of free gas in Orion Pool intervals predicted from oil PVT test results. Each sand in the Orion Nand 0 interval is assumed to be vertically isolated from overlying and underlying sands by low net-to-gross, non-reservoir, muddy siltstones and is assumed to have a different associated OWC depth. Oil-Down-To (ODT) limits and Water-Up-To (WUT) limits constrain Orion Pool area oil column heights. The best defined reservoir compartments are at L-Pad and V -Pad where oil column heights range between 150 and 310 vertical feet. Oil-Water contacts have only been logged in three Orion Pool area wells: KUPST-OI (OBa and OBd sands); L-lOl (Nb sand); and NWEILEEN-l (OA and Nb sands). 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 Orion Pool. Oil- Water Contacts Orion Nand 0 sand OWCs were interpreted for each sand using one of the following methods as most appropriate to that situation: 1) at the midpoint between the deepest Oil-Down-To (ODT) levels logged in upstructure wells and the down-dip structural spill point (defined at fault tips), 2) at the midpoint between the updip ODT levels and down-dip Water-Up-To (WUT) levels, or 3) at the midpoint between fault leak points (defined at fault intersections) and the down-dip structural spill 12 ,0' f ( (- Orion Pool Rules and Area Injection Order At. "ation (' October 6, 2003 point. Based on the described methodology, the N and 0 sand expected case oil column heights across the Orion Pool range between 0 feet (Nb-Polygon lA) and 433 feet (Oa-Polygon 3). Orion area N and 0 sand OWC depth uncertainties between the minimum possible and maximum possible OWC cases average 190 vertical feet per reservoir unit sand. The wide range in OWC depth uncertainty is due to the lack of down-dip penetrations in the majority of the reservoir polygons. The best OWC depth definition occurs at L-Pad and V -Pad where there is a concentration of Borealis wells penetrating the Schrader Bluff Formation. At L-Pad and V-Pad the OWC depth uncertainty range is 17 vertical feet to 59 vertical feet. In the main target horizons OA, OBa, and OBd at L-Pad and V-Pad the average most likely oil column range is 156 vertical feet (Polygon 5) to 308 vertical feet (Polygon 2). Net Pay and Pool Limits The limits of the Orion Pool are defined up-dip by fault barriers and down-dip at the zero foot limits of Nand 0 sand most likely case net pay. Orion is bounded on the southwest by northwest- southeast faults where the reservoir is juxtaposed against impermeable silts and mudstones of the upper Schrader Bluff Formation and overlying U gnu Formation. To the north and northwest, the Orion Pool limit is established by the Prudhoe Bay Unit boundary, not by a geologically defined trap. Rule 2 of the Milne Point Field, Schrader Bluff Oil Pool Rules (CO 477) requires, consistent with the statewide rule (20 AAC 25.055), that wells be open no closer than 500 feet from the exterior boundary of the Milne Unit. A similar restriction is proposed for the Orion Oil Pool (see Proposed Rule 1 in Section VII.). These restrictions should be sufficient at this time to protect correlative rights and avoid waste. To the east, the Orion Pool limit is defined by the down-dip intersection of the top of the reservoir with the most likely case Nand 0 sand oil-water contact depths defined by structural spill points. The precise down-dip reservoir boundaries have not been verified with well control. Orion Pool net pay thicknesses were derived using a petrophysical log model developed for the Schrader Bluff Formation. Reservoir lithologies and porosities were based on a multi-log analysis calibrated to conventional core from Polaris wells S-200PBl and W-200PBl, Milne well MPE-20, and West Sak wells lR-07 and WSI-01. Water saturations were calculated using the Waxman- 13 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 Smits model calibrated to the S-200PBl and lR-O7 core samples. Depth trends were used to vary the resistivity of water and the relationship between porosity and permeability. Log-model cutoffs of 6 millidarcies permeability, 65% water saturation and 35% clay volume were used to define Orion net pay. Confidential Exhibits 1-14, and 1-15 show the 0 and N sand composite net pays. Confidential Exhibit 1-14 is an Orion Pool composite-O-sand net-pay map showing the combined thickness and extent of the Orion area OA through OBf sand net pays. Confidential Exhibit 1-15 is an Orion Pool composite N sand net pay map showing the combined Na through Nc sand net pay thickness. Confidential Exhibits 1-16, and 1-17 show the 0 and N sand oil pore-foot thickness, respectively. Similar to the net pay maps in Contïdential Exhibits 1-14 and 1-15, the 0 and N oil pore-foot thickness maps represent the combined oil pore-foot thickness for all of the 0 sands (Confidential Exhibit 1-16) and all of the N sands (Confidential Exhibit 1-17). 14 Orion Pool Rules and Area Injection Order At' ation ( October 6, 2003 { II. Reservoir Description and Development Planning Reservoir management and development scenarios for Orion have been evaluated using pattern and partial field reservoir simulation models. Low recovery estimates for primary depletion are influenced by low gas oil ratio (GOR), low initial reservoir pressure and viscous oil. The models have identified water flooding as a viable secondary recovery mechanism and are being used to optimize well spacing and pattern configurations. Orion development, as currently planned, will utilize the existing footprint of Pads L, V, Z and W, with minor modifications, that were constructed by the Initial Participating Area ("IP A") and Borealis Owners to develop the Prudhoe Pool and the Borealis Pool. In addition, the Orion Owners are evaluating the possible construction of a new pad (I-Pad), located northwest of L-Pad for Orion development. Rock and Fluid Properties Porosity and Permeability ( Orion Pool rock properties were derived using conventional core data from two Polaris wells (S- 200PB1 and W-200PB1), two West Sak wells (WS1-01 and lR-07), and one Milne well (MPE-20). Although Orion core was recently obtained in well V-Ill, rock properties from this well are not yet available. Rock properties were distributed across the Orion Pool area using log model transforms. Pending receipt of Orion core analysis results, log models derived from Polaris (which is considered to be a close analog for Orion) and other Schrader Bluff fields, have been used in reservoir simulation and analysis. Polaris 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. Typical plug kv/kh values ranged from 0.001 to 1.0. Porosity and permeability for reservoir simulation were upscaled from the Orion static 3D geologic model (RMS), which is based on the Polaris log model (PLM). A 6 millidarcies permeability cut- off was utilized. Thick shale intervals representing the low net-to-gross, low-permeability shelf deposits between the reservoir sands were explicitly included in the layering, while the thinner shales within the sands were built into the vertical permeability during upscaling. ~' \ '<"", 15 Orion Pool Rules and Area Injection Order cation October 6, 2003 Confidential Exhibit II-I shows typical ranges for porosity and horizontal permeability by zone that were used in the reservoir simulation. Water Saturation Water saturations have been characterized using mercury injection data from Polaris S-200PB 1 and W-200PBl cores. 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 Orion reservoir models under capillary pressure equilibrium. Each interval was assumed to have a separate oil/water contact; the contacts were adjusted in the models to match observed water saturations from logs. Relative Permeability Relative permeability curves were based on unsteady state relative permeability experiments on S- 200PB 1 and W - 200PB I 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. Confidential Exhibit 11-2 shows the relative permeability curves used in the reservoir simulation. End point scaling has been used to adjust the curves for differences in initial water saturation. Initial Pressure and Tem~erature Initial reservoir pressure is taken from V-I 00, which had MDT samples over the range 3954' to 4623' TVDSS, at a datum depth of 4400' TVDSS, which has been chosen as the pressure datum depth for the Orion Pool. Average initial reservoir pressure is estimated to have been 1970 psi at 4400' TVDSS. Reservoir temperature is approximately 87° Fahrenheit at this datum. 16 Orion Pool Rules and Area Injection Order At.. .lrion (' October 6, 2003 { Fluid PVT Data Three types of fluid data have been gathered at Orion - fluids extracted from sidewall core plugs, MDT samples and production samples from surface and downhole. Oil samples obtained from sidewall core plugs in seven wells, using two different extraction methods (solvent extract, or retort), show API gravity variations of up to 10°. This range is not considered unusual, since extraction tends to under-predict API gravity, while retorting tends to over-predict. The uncertainty range means that these samples are of limited value for oil quality determination. A total of 23 PVT analyses have been performed on Orion oil samples and they are shown in Confidential Exhibit II-3. All of these samples were obtained from MDT's and 35% of the main sand/fault block reservoir units have been sampled to date. There appears to be a relationship between oil viscosity and the GOR of the samples. Confidential Exhibit 4 lists number of samples and property ranges for the MDT samples, at reservoir temperature and pressure, in each major sand. , { \ Geochemical (GC) analysis has been performed on 19 Orion oil samples and the coverage is shown in Confidential Exhibit II-5. Results are interpreted to indicate that at least two oil charges are present in the reservoir, distinguished by the presence, or absence, of a GC "light end". The PVT properties used for reservoir simulation are derived from measured values in the area being studied. Where no measurements are available, a range of possible values is used, to quantify the impact on results. The current set of PVT tables is shown in Confidential Exhibit II-6. Hydrocarbons in Place A full-field reservoir simulation model for Orion has not been developed. Estimates of hydrocarbons in place for Orion 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 for the major sands are as follows: ~. \ \~ 17 Orion Pool Rules and Area Injection Order cation October 6, 2003 Sand 0 N Total OOIP (mmstb) 845-1410 225-375 1070-1785 OGIP (bscf) 170-280 40-65 210-345 The ranges in OOIP and OGIP are due primarily to uncertainty in individual fault block oil-water contacts, reservoir properties «1>, So) and oil properties (Bo, Rs). The Orion Pool is under-saturated. Fluid saturations obtained from Orion partial field models have been compared to those calculated in the Orion log model and are in good agreement. Reservoir Performance Well Performance Two wells, V -201 and V -202 are producing from the Orion Pool. V -201 was drilled in early 2002 and put on production in April 2002. V-202 was drilled in May 2003 and put on production in July 2003. Both wells are currently producing under primary depletion. V-201 was the first producing well drilled in Orion. The well received two fracture stimulation treatments targeting the OA, OBa, OBb, and OBd, sands. The fracture stimulation was performed to decrease skin and control sand production by using a resin-coated propp ant. V-201 production was initiated in April 2002 and initially produced 21.5 API oil at 1080 bopd, 400 GOR and 0% WC, on gas-lift. The low rate and low flowing wellhead temperature (330 F) caused problems with gas hydrates and the well was converted to jet pump. After 16 months, the well was producing 600 bopd, at 7% WC and 400 GOR, and had produced approximately 174 mbo. V - 202 is a 3000 foot single lateral, drilled with oil-base mud and completed with slotted liner in the OBd. The well was put on production in July 2003 and initially tested at 7100 bopd, 350 GOR (est.) and 0% WC. After 1 month the well was producing 2000 bopd at 0% WC and 1000 GOR, and has 18 Orion Pool Rules and Area Injection Order A{ ation (' October 6, 2003 { produced over 100 mho. V-202 had the highest initial rate of any Schrader Bluff viscous-oil development well drilled to date and appears to be relatively undamaged. Oil quality is excellent in the OBd at this location at 22.9 API. OA and OBa laterals are scheduled to be drilled and completed in this well in fourth quarter 2003. Aquifer Influx The aquifer to the east of Orion could provide limited 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 Conine! Under-Runnine There are no indications of a free gas column in the Orion Pool; coning or under-run mechanisms are not anticipated. , I , , , Development Planning Several reservoir models, using data from the Orion Pool, have been constructed to evaluate development options, investigate reservoir management strategies and generate rate profiles. Reservoir Model Construction Partial field models built from the Orion static model have grid blocks upscaled from approximately 95 x 95 x 1-2 feet to 150 x 150 x 3-7 feet. These are black-oil models, with a total of 25 active layers representing the net sand in the OA, OBa and OBd intervals. Shale and minor sand intervals (N, OBb and OBc) are gridded in the models, but properties are zeroed out at this time. Faults (internal and boundary) are included in all of the models and assumed to be sealing. Fine-grid models have been completed for about 60% of the field area to support development and appraisal drilling activity. ~ I 19 "-- Orion Pool Rules and Area Injection Order, cation October 6, 2003 Development Options Development options evaluated for the Orion 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 Orion Pool. The primary recovery mechanism was a combination of solution gas drive and reservoir compaction. 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 the main development option for Orion. It is anticipated that overall field development will involve 40-80 injectors and 30-45 producers, depending upon the type of well designs utilized. In the major sands that will be developed with horizontal wells and full waterflood patterns, recovery may reach 20 to 25% of OOIP. The minor sands and N sands are likely to be produced through vertical fractured producers and horizontal laterals as reservoir quality permits. Waterflood patterns in these secondary layers may not be fully developed and recovery could be as low as 5% of OOIP in areas of poor rock quality and crude quality. These estimated waterflood recoveries are inclusive of primary recovery and assume 1.5 hydrocarbon-pore volumes injected (HCPVI). Oil production rate is estimated to peak at 30-50 mbd, with a maximum water injection rate of 100-125 mbd. The Orion waterflood oil and water production and water injection forecasts are shown in Exhibit II-6. Enhanced Oil Recovery (EOR) Enhanced recovery techniques such as miscible-gas injection and water-alternating with miscible- gas injection are under evaluation. Preliminary evaluations indicate that EOR could yield incremental recovery from the Orion Pool. Milne Point Unit Schrader Bluff equation of state data 20 Orion Pool Rules and Area Injection Order A( ation (" October 6, 2003 ( have been reviewed in conjunction with slim tube simulation to assess potential EOR benefits at Orion. Upon completion of these and additional technical and economic evaluations, forward action plans will be determined. Injection wells are being engineered to accommodate the potential for enhanced oil recovery service. Horizontal Wells Favorable results have been obtained with horizontal multi-lateral (ML) wells in Orion and other pools within the Schrader Bluff Formation (Milne Point and West Sak) and the initial development plan for Orion is primarily based on ML wells. Simulation and development planning efforts show that horizontal wells have the potential to enhance rate and recovery, while reducing development costs and minimizing facility expansion requirements. Horizontal well potential is currently being evaluated in the V -Pad area where the target is the three major sands - OA, OBa, and OBd. The V- 202 tri-Iateral well (initially drilled as an OBd single-lateral) encountered approximately 2100 net feet of horizontal section and is currently on production. The V -202 well was drilled with oil-base mud to provide horizontal well productivity information, and appears to be relatively undamaged, based on initial rate. ( Injection well designs evaluated and employed to date in the Schrader Bluff formation pools within the PBU (Polaris and Orion) are vertical. Horizontal injection wells will be considered in the future, using single, multi-lateral and/or undulating wellbore profiles. . Development Plan Reservoir simulation supports implementation of a waterflood in the Orion Pool. Initial development will take place in a phased manner, working from the areas of least reservoir/fluid risk towards the less well defined areas of the Pool, incorporating data gathering necessary to refine development plans. In this context, uncertainty includes structure/faulting (areas of poor-quality seismic and/or lack of early well control), oil quality (possible compartmentalization) and rock properties (areal and vertical variations in net-to-gross, porosity, and permeability). A phased development plan allows for evaluation of the Schrader Bluff in deeper Kuparuk and Ivishak (~- 21 Orion Pool Rules and Area Injection Order, cation October 6, 2003 development wells prior to proceeding with development in each field area. The Operator will determine the optimal field off-take rate based upon sound reservoir management practices. Phase I Develo)!ment Phase I development focuses on developing and establishing waterflood operations in areas with good seismic quality and/or well control. Several water flood development options have been studied using the Orion reservoir simulation models. The results of those simulations provided criteria for spacing of wells and identifying the number of injectors necessary for adequate voidage replacernent. Phase I developlllent results will be used to validate development assumptions and refine Phase II and Phase III development plans. Phase I drilling in Orion is a combination of development and appraisal wells, designed to provide early production and injection well performance information, while evaluating the fluid and rock quality in previously untested areas of the field. V-Pad currently includes the V -201 and V -202 wells, which are currently on production and the V-I05 dual (with Borealis) water injector. Tri- lateral producers and vertical or multi-lateral injectors are under consideration. V -201 may be converted to water injection in the future. The central V -Pad line drive patterns will provide early data on flood performance and operation. L-Pad area development consists of drilling one tri-Iateral producer, L-200, in late 2003/early 2004, with immediate support available from the existing dual (with Borealis) water injector, L-117. 2004 drilling anticipates the addition of tri-Iateral producers and vertical or multi-lateral injectors. W -Pad currently has no Orion wells. Tri-Iateral producers and vertical or multi-lateral injectors are being considered to access Orion fro.m W -Pad in 2004. These wells will test the southeast area of the field, which has relatively poor well control and no recent test data. Phase II Develo)!ment Orion Phase II development is directed to completing development of locations that can be reached from existing gravel pads. Development of these areas will involve an additional 10-20 producers 22 Orion Pool Rules and Area Injection Order A( .ation ( October 6, 2003 ( and 20-40 injectors in the UV /Z Pad area plus approximately two producers and four to eight injectors in the W -Pad accessible area. Locations will be determined 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 areas with poor fault resolution, including higher-risk, structurally complex areas. Phase III Development Orion Phase III development will target areas in the northwest portion of the field that cannot be reached from L-Pad. The installation of I-Pad is being evaluated for this purpose. An estimated 10 -20 producers and 20-40 injectors will be required in this phase of the development. Well Spacine ( Initial production well spacing for development is nominally 160 acres with ML producer/vertical injectors. Due to faulting, the patterns are expected to be irregular and wells may be relatively 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 developing the Orion 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 field average 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 Orion reservoir management strategy is to operate the Pool in a manner that will maximize recovery consistent with good oil field engineering practices. Waterflood support and injection conformance are key to minimizing well decline rates. The reservoir management goal is to maintain a balanced voidage-replacement ratio. To accomplish this objective, reserVOlf ( 23 Orion Pool Rules and Area Injection Order, cation October 6, 2003 management will be a dynamic process. The initial strategy will be derived from reservoir-model studies and limited well-test information, and will utilize multiple packer assemblies to control water injection. Development well results and reservoir surveillance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. l11anagel11ent strategy for the Orion Pool will be evaluated throughout the life of the field. Reservoir Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Orion Pool. Peak production rates are expected to be 30-50mbd. After waterflooding commencement, peak injection rates will be 100-125 mbd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management and facility operational practices. Orion production performance can be divided into two aspects - reservoir delivery and well operability. Early production tests in the OBd sand at Polaris were significantly lower than expected, possibly due to formation damage. Recent success in V -202 suggests drilling with oil- based mud and ensuring that the wellbore stays in the best quality rock can offset formation damage. Producer to injector ratios of 1: 1 to 1:3 will be needed to maintain reservoir pressure without high injection pressures in individual wells, depending on well types selected. Keeping Orion wells on line with a combination of low rates, cool production temperatures, presence of water, and lift-gas composition and temperature, has proven both challenging and costly. V-201 well operability, affected primarily by hydrate formation during gas-lift, was a problem when the well was first put on production. The V-201 well was switched to jet pump during the first month of production and has produced without problems for over 1 year. Artificial-lift will be provided using either artificial-lift gas, or with jet pumps using injection water as the power t1uid, or electrical sublnersible pulnps (ESPs), or SOll1e combination as a function of the needs of the individual producer. 24 ( Orion Pool Rules and Area Injection Order A( ,ation f October 6, 2003 ( III. Facilities General Overview Orion wells will be drilled from existing PBU drill sites (L-Pad, V-Pad, Z-Pad and W-Pad) and a possible new I-Pad. Existing pad facilities and pipelines will be used to the extent possible to produce Orion fluids to Gathering Center 2 (GC-2) for processing and shipment to Pump Station No. 1 (PS 1). Orion fluids will be commingled with fluids from other fields on the surface at the respective well pads to maximize use of existing 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. IP A field facilities that will be used include low-pressure large-diameter flowlines, gas-lift supply lines and water-injection supply lines. Existing MI supply lines may be utilized for potential future EOR applications. The oil-sales line from GC-2 to PS 1 and the power distribution and generation facilities will also be utilized. Exhibit III-l provides a schematic overview of the relationship of these pads and pipelines relative to GC-2. Drill Pads and Roads Existing Well Pads L, V, Z and W have been identified as the surface locations for Orion wells to access the expected extent of the reservoir from existing facilities to the extent possible. This use of existing facilities minimizes new gravel placement and well step-out. The addition of a new well pad, I-Pad, adjacent to the Milne Road, as shown in Exhibit III-l and Exhibit III-2 is being evaluated as part of the Orion conceptual engineering effort. Expansions of existing well pad facilities at L- Pad and V-Pad are ongoing and expansions of Z-Pad and W -Pad are being considered to support IP A and Borealis development. The potential needs of Orion development will be considered in these activities. The expansions at L-Pad and V-Pad will not require new gravel. Additional gravel likely would be required at Z-Pad and W-Pad. Efforts will be made to stay within the existing ( 25 Orion Pool Rules and Area Injection Order cation October 6, 2003 permitted footprint of these well pads. Schematics of existing pads L, V, Z and Ware included as Exhibits III-3, 4, 5 and 6. New pipelines would be required to connect possible drill site I-Pad to existing pipelines at L-Pad. The relationship of I-Pad to L-Pad is shown in Exhibit III-I. Pipelines would transport lift gas, water and potentially MI from the Prudhoe infrastructure to I-Pad and would transport produced fluids from I-Pad to the existing pipeline system. Orion production will be routed to GC-2 via the existing low-pressure, large-diameter flowlines. The need to expand existing infrastructure by looping pipelines or through the addition of processing facilities to accommodate Orion development is being evaluated as part of Orion conceptual engineering activities. Pad Facilities and Operations Orion wells at existing pads will be tied in as dictated by facilities available at the pad. The type of facility to be installed at the possible drill site I-Pad is being evaluated. The Borealis owners installed L-Pad, V-Pad, and the associated production facilities to support development of the Borealis Pool. Each pad allows 48 new wells (see Exhibits 111-3 and Exhibit 111- 4). On-pad facilities included production and injection manifolding for 24 wells, well test facilities, safety shutdown valves, pigging facilities, controls, communications, production support and utilities. These well pads are being modified to allow for the injection of Miscible Injectant in a Water-Alternating-Gas (WAG) EOR process into any of the underlying pools. This expansion will be implemented using a WAG trunk and lateral design, which will allow all of the existing manifold slots to be used to support production wells. The balance of the surface slots on each pad will be occupied by injection wells. Exhibit 111-7 and Exhibit 111-8 show typical production and injection tie-ins at L-Pad and V -Pad. The existing Z-Pad wells are tied-in to production and injection manifold skids as shown in Exhibit 111-5. All of the facilities are being used by wells producing from the Prudhoe Pool and the Borealis Pool, but the owners of these facilities are evaluating options for expansion. The potential needs of Orion development and possible expansion of Borealis development will be considered in this evaluation. 26 Orion Pool Rules and Area Injection Order A( ation (" October 6, 2003 ( Existing W-Pad wells are tied into production manifold, water header and MI header facilities installed by the IPA owners. Existing W-Pad facilities are shown in Exhibit ill-6. There are facilities for nine new producers and an undetermined number of injectors to be tied in at W -Pad. The need to expand these facilities is being evaluated by the IP A owners. Exhibits ill-9 and Exhibit ill-l0 show typical production and water injector tie-ins at W-Pad. Initially, water for waterflood operations will be obtained from the existing pipeline and distribution facilities at existing pads. Water for waterflooding wells at the potential new I-Pad will be supplied by extending the existing 12" water-injection supply line to L-Pad. Additional water wells are also under consideration as a source of injection water. Supplying the water rate required by Orion will potentially require either line looping and process expansions at GC-2 or the installation of processing facilities on or near the well pads. These alternatives are being reviewed as part of Orion conceptual engineering activities. ( " Artificial-lift will be provided using either artificial-lift gas, or with jet pumps using injection water as the power fluid, or electrical submersible pumps (ESPs), or some combination as a function of the individual producer. Artificial-lift gas will be obtained from the existing pipelines and distribution systems on existing pads and by extending the 12" gas-lift supply line to L-Pad for possible future 1- Pad. Looping of existing artificial lift lines may be necessary. Well control will include data acquisition as well as actuated divert and choke valves. Wells will be tested using existing well test facilities at existing Pads. Anew, two-phase test separator would be installed at the new pad. Wells will be 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 Orion wells and drill site equipment. The data gathering system will continuously monitor the pressures and temperature of the producing wells. ( 27 Orion Pool Rules and Area Injection Order. cation October 6, 2003 Gathering Center The need for process modifications to the GC-2 production center is being evaluated as part of Orion conceptual engineering activities. 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 of commingled fluids at GC-2, including that from the Orion Pool, is not expected to be limited by oil handling capacity, but is expected to be limited by gas and/or water handling capacity. 28 Orion Pool Rules and Area Injection Order Afation {" October 6,2003 ( " IV. Well Operations Existing Wells A number of exploration, appraisal and development wells that targeted the deeper Kuparuk and Ivishak have been drilled and logged in the Schrader Bluff Formation. However, only the V-201 and V-202 have been drilled and completed in the Orion Pool. The Orion Pool is currently producing from these two wells. Recent well test data for V-201 and V-202 are shown in Exhibit IV-I. These well locations are shown in Exhibits 1-2 and 1-4. Drilling and Well Design Orion 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 inch conductor casing will be set 80 to 120 feet 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 Orion. 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. ( 29 Orion Pool Rules and Area Injection Order cation October 6, ZO03 No significant HzS has been detected in the Schrader Bluff Formation while drilling other development wells or in any Orion well drilled to date. However, with planned waterflood operations there is potential of generating HzS over the life of the field. Consequent! y, HzS gas- drilling practices will be followed, including continuous monitoring for the presence of HzS. A readily available supply of HzS 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 HzS, and all rig pad supervisors will be trained for operations in an HzS environment. Well Desie:n and Completions Multi-lateral, horizontal and conventional wells may be drilled at Orion. 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 inch depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Orion wells. The following table indicates typical casing and tubing sizes for proposed Orion wells: Surface Inter/Prod Production Production Casing Casing Liner Tubing Conventional 10-3/4" to 7" 7" to 3-1/2" Not Planned 4-1/2" to 2-3/8" Horizontal & Multi-lateral 10-3/4" to 7" 7" to 4-1/2" 5-1/2" to 2-7/8" 4-1/2" to 2-3/8" 30 Orion Pool Rules and Area Injection Order A( ation ( October 6, 2003 ( Plans are to run L-80 grade casing in the Orion wells. Tubing strings will be completed with either I3-Chrome or L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/lMoly, which is compatible with both L-80 and 13-Cr. Use of 13- super chrome or equivalent is possible on certain completion jewelry. Each multi-lateral leg of Orion horizontal producers will be completed in a single horizon (Schrader Bluff Formation). Vertical injectors and producers 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 horizontal multilateral production wells, Exhibit IV -3 for conventional production wells, Exhibit IV -4 for conventional injector wells, and Exhibit IV -5 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. r The Orion owners may utilize surplus IP A wells for development provided they meet Orion 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. Multi-lateral undulating injector wells are also being evaluated. No exhibit has been included depicting this well type since it is still in the conceptual stage. Measurement-While-Drilling (MWD) and Logging-While-Drilling (LWD) will typically begin after setting the surface casing. Production hole will be drilled to below the Schrader Bluff Formation and a 7-5/8" 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. L WD 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 L WD ( '-" 31 Orion Pool Rules and Area Injection Order cation October 6, 2003 logging, including GR, resistivity, density and neutron porosity and other logging tools when well bore 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 7-5/8" casing point. If any horizontal section is drilled, the mud system parameters may be optimized for that hole section, including the use of oil-based mud. 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-Yz" or 3-Yz" 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 Orion 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 Subsurface safety valves are not required in Orion 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 in the pool rules for the existing Schrader Bluff formation pools (Polaris Oil Pool, Schrader Bluff Oil Pool, and West Sak Oil Pool). 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 32 Orion Pool Rules and Area Injection Order A( ation f October 6, 2003 ( Drilline Fluids Freshwater low-solids, non-dispersed fluids or oil-based mud consisting of 80% mineral oil, emulsified with 20% water will be used to drill the Schrader Bluff Formation. Typically KCl will be added to this mud system for weight and to reduce formation damage caused by reactive clays in the water based systems. Other muds may be used in the future to minimize skin damage from drilling and enhance well performance. Stimulation Methods Fracture stimulation has been implemented for the one vertical Orion producer drilled to date and may be implemented in the future to mitigate formation damage, for sand control and to stimulate Orion wells. It may be necessary to stimulate horizontal wells, depending upon well performance. Acid or other forms of stimulation may be performed as needed. 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 common datum elevation of 4,500' 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 Orion reservoir polygon areas identified in Exhibit 1-13, when at least one Orion production well has been completed in the respective polygon. It is anticipated that the operator will collect more pressure measurements during initial field development to identify potential compartmentalization c 33 Orion Pool Rules and Area Injection Order cation October 6, 2003 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 periodically run on comlningled injection wells to assist in the allocation of t10w splits. Completions - Producin2: 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 TO which will typically be set 1 00 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-bearing interval in the U gnu section. Production tubing will be run inside the longstring and sealed in the long string at least above theMc 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 will also be utilized to enhance recovery and rate while reducing development costs, facility requirements, and downtime associated with lower flow rates from conventional wells. 34 Orion Pool Rules and Area Injection Order Af ation ( October 6, 2003 ( Artificial-lift The primary artificial-lift methods will either be gas-lifting with lift gas supplied from the gas-lift system or jet pumping using injection water as the power fluid as a possible alternative. Utilization of electrical submersible pumps (ESP's) is also under consideration. It is anticipated that all Orion 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. The producing wells may be 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°F. Jet pumps are being tested and are expected to mitigate the hydrate problems associated with gas-lift. Orion will likely experience a mix of gas-lifted, jet pumped, and/or ESP lifted wells throughout field life. Completions - In iection Wells f 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 -4 shows a typical vertical 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 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 run 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. Multi-lateral injection wells are also being evaluated. ML injection wells could be tri-Iateral wells with one lateral drilled horizontally into each producing sand or some combination of undulating laterals could be employed. ML injection wells would look similar to the ML producer depicted in Exhibit IV -2. 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. ( \- 35 Orion Pool Rules and Area Injection Order cation October 6, 2003 Commin,;ded Injection Approval is requested for commingled water injection in wells L-I03i, L-l1li, L-115i, L-117i, and V-I05i in the Borealis and Orion pools. These wells were 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 periodically. Additional opportunities may arise to take advantage of commingled injection wells. Wells L-I08i and L-I09i were also completed such that they could be utilized for commingled water injection. Approval to inject into these two wells is not requested at this time. 36 Orion Pool Rules and Area Injection Order At' ation (' October 6, 2003 ( V. Production Allocation Orion 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 Orion production. All new Orion 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 Orion wells. All Orion gas delivered into GC-2 will be considered as having been used or consumed as fuel, flared or lost gas, with the effect that all residue gas from production operations at GC-2 that is injected into Prudhoe Oil Pool will be deemed indigenous to the Prudhoe Pool. ¡' ( (, 37 Orion Pool Rules and Area Injection Order cation October 6, 2003 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 Orion Pool. The proposed area for Area Injection Operations is the proposed Orion Pool area 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 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Orion Pool, as of July 1, 2003. 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. 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 Orion Participating Area, which is coextensive with the Orion Pool. Exhibit VI-l is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area and within the proposed Orion 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 Orion Pool are described in Section II. Drill pad facilities and operations are described in Section III. 38 Orion Pool Rules and Area Injection Order At ation ( October 6. 2003 , " Pool Information 20 AAC 25.402(c)(5) This application for area injection operations is being submitted in conjunction with an application for establishing an Orion Pool and pool rules Geologic Information 20 AAC 25.402(c)(6) The geology of the Orion Pool is described in Section I. Log Information 20 AAC 25.402(c)(7) Logs of the injection wells are already on file with the commission. / \ Injection Well Casing Information 20 AAC 25.402(c)(8) Seven wells, L-I03i, L-I08i, L-I09i, L-Illi, L-115i, L-l17i, and V-I05i, were permitted and drilled for injection service for the Orion Pool. The casing programs for these wells were permitted and completed in accordance with 20 AAC 25.030. The completion diagram in Exhibit N-4 is representative of a typical vertical Orion injection well. Multi-lateral injection wells are being evaluated and may be utilized. Exhibit N-5 depicts a typical Orion-Borealis commingled injector. Cement-bond-Iogs have been run on all seven of the commingled injectors and demonstrate isolation of injected fluids to the Kuparuk River and Schrader Bluff Formations. Each well was completed in accordance with 20 AAC 25.412. Cement-bond-Iogs will be obtained on future injection wells drilled to demonstrate zonal isolation prior to water injection. \, 39 Orion Pool Rules and Area Injection Order cation October 6, 2003 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) Tme of Fluid/Source Fluids requested for injection for the Orion Oil Pool are: (a) Produced water from Orion or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; (b) Source Water from the Prince Creek Formation (also known as the U gnu formation) (c) Tracer survey fluid to monitor reservoir performance; (d) Fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); (e) Source water from the Seawater Treatment Plant; (f) Non-hazardous water collected from well-house cellars and standing ponds. Water Composition and Compatibility with Formation The injection-water composition in the Orion Pool, based on water analysis from Polaris W -200 well, GC-2 produced water, and sea water, are provided in Exhibit VI-2. The composition of Orion produced water will be a mixture of connate water and injection water, and will change over time depending on the rate and composition of injection water. Based on analyses of Polaris water 40 Orion Pool Rules and Area Injection Order A( .ltion (' October 6, 2003 ('I' samples, no significant compatibility problems are expected between Orion connate water and injection water. Injection Pressures 20 AAC 25.402(c)(10) The expected average surface manifold water injection pressure is 2300 psig. The estimated maximum surface manifold injection pressure is 2800 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing and flow control devices. To meet a target of 100% reservoir voidage replacement, experience in the Schrader Bluff formation at Polaris has shown that it is optimum to inject above fracture pressure. The Orion injection wells will be managed to keep injected fluids within the approved injection strata. Maximum fluid injection requirements at the Orion Pool are estimated at 100,000 to 125,000 BWPD. ( Fracture Information 20 AAC 25.402(c)(11) It is not expected that the maximum injection pressure for Orion Pool injection wells will propagate fractures through the confining strata, which would allow fluids to enter any freshwater strata. V - 201 was hydraulically fracture stimulated in the OA Sand. The overlying Mc Sand is considered wet with approximately 70% water saturation. Production from V-201 has shown very little water production indicating that the fracture did not extend vertically to the Mc Sand. Directly above the top of the injection zone in the OA sand, there is a mudstone at the base of the overlying Nc, which is approximately 60 ft thick. This is expected to provide fracture confinement to the 0 sands. To ensure injection conformance, injection performance will be monitored for each injection well. Any significant change in injectivity, which would indicate injection out-of-zone, will be followed (- 41 Orion Pool Rules and Area Injection Order, cation October 6, 2003 up with surveillance. The surveillance could include spinner/temperature logs and if necessary, a tracer survey to determine the location of the injection anomaly. Formation Water Quality 20 AAC 25.402(c)(12) Although no produced water is available to perform a water analysis, it is expected to be similar to Polaris pool water quality. Freshwater Strata 20 AAC 25.402(c)(13) 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 Orion Area Injection Order. Hydrocarbon Recovery 20 AAC 25.402(c)(14) Orion 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. Mechanical Integrity of Wells 20 AAC 25.402(c)(l5) Mechanical Inte2ritv of Wells Within % mile of Injectors Seven injection wells have been drilled L-I03i, L-I08i, L-I09i, L-illi, L-115i, L-117i, and V,-105i. Approval to inject into L-I08i and L-I09i is not requested at this tillIe. A map showing all 42 ( (' ( I'" Orion Pool Rules and Area Injection Order 4' (' October 6,2003 ation penetrations through the Schrader Bluff Orion Pool, and wells within lA mile of the injection wells are shown as Exhibit VI-3. The wells within the lA mile radius of requested injection wells are, L- 02, L-II0, L-112, L-114, and L-120. A report of the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of an injection well is included as Exhibit VI-4 to VI-8. 43 Orion Pool Rules and Area Injection Order. cation October 6, 2003 VII. Proposed Orion Pool Rules BP Exploration (Alaska) Inc., in its capacity as Orion Operator and Unit Operator, respectfully requests that the Commission adopt the following Pool Rules for the Orion Oil Pool: Pool Name, Definition and Classification The field is the Prudhoe Bay Field and the pool is the Orion Oil Pool. The Orion Pool is classified as an Oil Pool. The Orion Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 4,549 feet MD and 5,106 feet MD in the PBU V-201 well (4,126 and 4,650 feet TVDSS, respectively), within the area described below. Affected Area (Umiat Meridian): Township Range TI2N-RI0E Lease ADL 025637 TI2N-RIIE ADL 047446 ADL 047447 ADL 028238 ADL 028239 ADL 047449 TIIN-RIIE ADL 028240 ADL 028241 ADL 028245 Sections 13 and 24 N/2 17, 18, 19, and 20 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 25 SW/4, 26, 35, and 36 27,28,33 E/2 and N/2 NW/4, and 34 29 N/2 and SE/4, and 30 N/2 NE/4 1,2, 11 E/2 and E/2 NW/4, and 12 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 44 Orion Pool Rules and Area Injection Order A( ation (' TIIN-RI2E ADL 047450 ADL 028263 ADL 028262 ADL 047452 ADL 047453 (' October 6, 2003 7, and 8 S/2 and NW 14 16 SW 14 and S/2 NW 14, and 21 SW 14 and S/2 NW/4 and NW/4 NW/4 and W 12 SE/4 17, 18, 19 N/2 and SE/4 and N/2 SW 14, and 20 28 W 12 and W 12 E/2 29 N/2 and N/2 SE/4 Rule 1: 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 Orion Oil Pool shall not be opened in any well closer than 500 feet 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 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 3: 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) Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems and associated equipment are in proper working condition. ( 45 OIion Pool Rules and Area Injection Order. cation October 6, 2003 Rule 4: Common Production Facilities and Surface Commingling (a) Production from the Orion Pool may be commingled with production from other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer. (b) Production allocation is to be performed in accordance with the Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002, subject to ongoing review. All Orion wells must use the Gathering Center 2 well allocation factor for oil, gas and water. (c) All wells must be tested a minimum of once per month. All new Orion 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. (d) Technical meetings must be held quarterly to review progress of the implementation of the Western Satellite Production Metering Plan. (e) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. 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 one pressure survey will be taken annually in each of the Orion reservoir compartInents where Orion production wells exist. (c) The reservoir pressure datum will be 4,400' 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. 46 Orion Pool Rules and Area Injection Order Þ(r ation (' October 6, 2003 ( (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 Orion 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 7: Pressure Maintenance Project Average reservoir pressure will be maintained above saturation pressure. Rule 8: Multiple Completion of Water Injection Wells (a) Water injector wells into the Orion Pool may be completed to allow for simultaneous injection in the Orion Pool and other pools, 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. ( ( \ (c) Results of logs or surveys used for determining the allocation of water injection must be supplied in the yearly reservoir surveillance report. (d) An approved injection order is required prior to commencement of injection in each pool through a common wellbore. Rule 9: Reservoir Surveillance Report An annual reservoir surveillance report for the prior calendar year must be filed by April 1st. 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 fluids and injected fluids and cumulative status for each producing interval. ( 47 Orion Pool Rules and Area Injection Order cation October 6, 2003 (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 log 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 techniques. Rule 10: Operation of Development Wells with Pressure Communication or Leakage in any Casing, Tubing, or Packer (a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b) The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. (c) The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig for all Orion Pool development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. (d) The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC 48 Orion Pool Rules and Area Injection Order A( ,ation ( October 6, 2003 (: approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. (' (f) Before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig for all Orion Pool development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. (g) For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. ( 49 '~ Orion Pool Rules and Area Injection Order. :::ation October 6, 2003 Rule 11: Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into fresh water. 50 (~ Orion Pool Rules and Area Injection Order A ltion (" October 6,2003 { VIII. Proposed Area Injection Order BP Exploration (Alaska) Inc., in its capacity as Orion Operator and Unit Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class n fluids for enhanced oil recovery in the Orion Pool and consider the following rules to govern such activity: Affected Area (Umiat Meridian): Township Range TI2N-RI0E Lease ADL 025637 TI2N-RIIE ADL 047446 ADL 047447 ( " ADL 028238 ADL 028239 ADL 047449 TIIN-RIIE ADL 028240 ADL 028241 ADL 028245 TI1N-RI2E ADL 047450 ADL 028263 ADL 028262 ADL 047452 ADL 047453 ( Sections 13 and 24 N/2 17,18,19, and 20 16 S/2 and NW 14 and S/2 NE/4, 21, and 22 25 SW/4, 26, 35, and 36 27, 28, 33 E/2 and N/2 NW 14, and 34 29 N/2 and SE/4, and 30 N/2 NE/4 1, 2, 11 E/2 and E/2 NW/4, and 12 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 7, and 8 S/2 and NW 14 16 SW 14 and S/2 NW 14, and 21 SW 14 and S/2 NW 14 and NW 14 NW 14 and W/2 SE/4 17, 18, 19 N/2 and SE/4 and N/2 SW 14, and 20 28 W/2 and W/2 E/2 29 N/2 and N/2 SE/4 51 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 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 log measured depths 4,549 feet MD and 5,106 feetMD in the PBU V-201 well (4,126 and 4,650 feet TVDSS, respectively). Rule 2: 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, or through a well that existed as a service well for injection purposes on the effective date of this AIO. 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 3: Authorized Injection Fluids Fluids authorized for injection within the affected area are: (a) Produced water from Orion or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; (b) Source Water from the Prince Creek Formation (also known as the Ugnu formation); (c) Tracer survey fluid to monitor reservoir performance; (d) Fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); (e) Source water from the Seawater Treatment Plant; 52 Orion Pool Rules and Area Injection Order At ltion f October 6, 2003 , , (f) Non-hazardous water collected from well house cellars and standing ponds. Rule 4: Injection Pressure Normal injection pressures must be maintained slightly above the parting pressure of the Schrader Bluff sandstone to allow economic injection rates while keeping the injected fluids confined in the authorized injection strata. Rule 5: 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 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity 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. If \ Rule 7: Multiple Completion of Water Injection Wells (a) Water injector wells into the Orion Pool may be completed to allow for simultaneous injection in the Orion Pool and other pools so long as mechanical isolation between pools is demonstrated and approved by the Commission. (b) Prior to initiation of commingled 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 through a common wellbore. ( 53 Orion Pool Rules and Area Injection Order ¡cation October 6, 2003 Rule 8: Well Integrity Failure Whenever operating pressure or pressure tests indicate communication or leakage of any casing, tubing or packer within an injection well, the operator must notify the Commission on the first working day following the observation and obtain Commission approval to continue injection. Commission approval of an Application for Sundry Approval (Form 10-403) is required before initiating corrective action. Rule 9: 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 10: 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. 54 Orion Pool Rules and Area Injection Order Ai. Irion t IX. 1-1 1-2 1-3 1-4 1-5 Sections 1-6 A" (' October 6, 2003 List of Exhibits Location of the Orion Pool Alaska North Slope Orion PoollInjection Area and Proposed Orion Participating Area Outline Orion PoollInjection Area Type Log Well V-201 Orion Pool/Injection Area Top Schrader Bluff OA Structure Map Orion Pool/Injection Area Top Schrader Bluff OA Structure Map Showing Structural Cross- Orion Pool/Injection Area Structure and Interpreted Oil/W ater Contacts Cross Section A - 1- 7 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/W ater Contacts Cross Section B - B' ( ( 1-8 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section C - C' 1-9 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section D - D' 1-10 Section E - E' Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/W ater Contacts Cross 1-11 Orion Pool/Injection Area Structure and Interpreted Most Likely Oil/Water Contacts Cross Section F - F' 1-12 Orion Pool/Injection Area Isochore Thickness of Mudstone Between Top Na Sand and Base Mc Sand 1-13 ( Orion Pool/Injection Area Nand 0 Sand Reservoir Compartment Map 55 Orion Pool Rules and Area Injection Order ication October 6, 2003 1-14 I-IS 1-16 1-17 II-I II-2 II-3 II-4 II-5 11-6 II-7 11-8 III-I III - 2 III - 3 III -4 III - 5 III-6 III - 7 Orion Pool/Injection Area 0 Sands Composite Net Pay Thickness Orion Pool/Injection Area N Sands Composite Net Pay Thickness Orion Pool/Injection Area 0 Sands Composite Oil Pore Foot Thickness Map Orion Pool/Injection Area N Sands Composite Oil Pore Foot Thickness Map Orion Model Reservoir Property Ranges Orion Relative Permeabilities Orion Fluid Properties Orion MDT Summary Table Orion Geochemical Samples Orion Model PVT Properties Orion Waterflood Rate Forecast Orion PVT Match Using MPU Schrader Bluff EOS Orion Facility Plan - Planned Facilities - P/L & Utility Map I-Pad Location Map Orion L-Pad - Surface Facilities Orion V -Pad - Surface Facilities Orion Z-Pad - Surface Facilities Orion W-Pad - Surface Facilities Typical L and V-Pad Production Tie-in 56 ,.., Orion Pool Rules and Area Injection Order AI .tion III-8 Typical L and V-Pad Injection Tie-in ~ ID-9 Typical L and V-Pad WAG Injector III-I0 Typical W-Pad Production Tie-in III-II Typical W -Pad Injection Tie-in IV-I Orion Representative Well Test Summary IV-2 Typical Tri-Lateral Production Well IV -4 Typical Vertical Hydraulically Fractured Producer IV-5 Typical Injection Well IV-5 Typical Orion-Borealis Commingled Injector VI-l Affidavit ; i 'I. , VI-2 Polaris Injection Water Compositions VI-3 Orion Pool/Injection Area Injection Well Location Map VI-4 L-O2 Well Integrity Report VI-5 L-II0 Well Integrity Report VI-6 L-114 Well Integrity Report VI-7 L-116 Well Integrity Report VI-8 L-120 Well Integrity Report t l ( October 6, 2003 57 ~ ,.-., Location of tt Ie Orion Pool Alaska North Slope 8e .ufort Se. ~~ North Star Unit , K u paruk Ri ver Unit West Sa( Prudhoe Bay Unit 0 3 6 Mi les North Exhibit 1-1. ~. ~ --. ,-. ...-. "-"". Orion Facility Plan - Milne S-Pad Exhibit 111-1 Planned Facilities - P/L & Utility Map ~ I-Pad r ~ U -P a d Z-p ad Pipelines Existing P ro duct ion -- Water Inj -- G as Lift -- MI -- Power ..- ""'~. EWE Proj WAD Proj ...... ...... ~~ Fiber Optic Cable ( Á- en (J) .- +-' .- - .- (.) co LL. (1) (.) ~ :J en I -c -co ... (.1. co 0); I "- ...J c: 0 .- L.. 0 CI) I - - - ... .- .c .- ..c: >< W ( ,- ... 1.0 ,.... , I i I --...'-.---.,--------.. ---'¡-------- í ) ...... 506 ,,--" ~ ---=--~ ¡ I I I . I . " \"'--~' ---:< / ~L " '--r,...-œ ~ L-1208..-" ,,',"1] i \ 11,1 "". l..102 L-NW 0 j : tð . L~SW l-1,,1941 ," t,' , " , /~,illi , 8' L-104, L..NU 0 1.- ' 0 l-SU '- . r-' L-NT 0 - .-: I L-106 i1~~" ~ - t~~ L..NO 0 0 L-SQ L..NP 0 : -'- °L-SP L-NO 0 1/ l..ä9U 0 l.SO L-"NNO Y ! c. 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WELL, 4101 PRODUCTiON LINE AND 3" GlT LINE ~ GAS OR WATER INJECTION WELL, SOURCE WATER W CELLAR, 41Þ PRODUCTION LINE AND 3" GlT LINE - NO WELL HEAD 0 CELLAR ONLY -- NO LINES OR WELl HEAD ir SUBSIDENCE WELL SUMP ~I 0 19 1:8 200 ~~ * 2.3 * 0')-") ~* ~1 * Zú 5:>:) SOlC 17 Hì 15 ~. --: 118 I ¡- i- _I. 5018- 001 A ... 1 :2 M :) .3* 4* 5* '1 * ¡ß 3B 3:; 4.~ .g ~* 1(1 :i : '!!g 44 SUMP' ( a.. CD U :J " 0 a.. a. t:-" ca a. ( ... I .a> . ~-a >< c wca -I ( '- ca u . c. ~ (' ('" t/) C'a " 10. Q) - C'a ;:: Q - := ..J 1- - - - - - I~ --------------~ UI I I .... 1 1 .- E I I ~ I I .. I I .!! 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Exhibit IV-1 Orion Representative Well Test Summary Oil Flow Well T est Date Rate Watercut (bpd) (%) Gas/Oil Ratio (scf/bbl) 2,226 0 V-201 * 6/24/2003 7 67 720 8/5/2003 948 * On Jet Pump, prior to conversion to Gas Lift .. . .. . ** OBd single horizontal lateral ~o Gas Lift Rate (mmscf) Tubing Temp (OF) Tubing Pressure (psia) 0 108 375 0 54 344 ~. .", í Typ ic a I T ri-L atera I Pro d I TR ( u ct i 0 f1 Well Exhibit IV-2 (' E E: ..-11' 1 6' 5M W ELL H EA [J : 11', 5M o~ r. 5 s~~ Ie m 21J' X 3.." 2155 Ibl'1'I, A53 ERW h~ul~I~1:I 1u9' --- ---------I O..J / ~" P I) r I C (Ilia r X-Nipple (3.813" 10) I 1,uuu' I 2,2UU' TVD I G[J.,.14-1l2"x 1" KBG-2 /' " 'IJ\l'ith 0 CK She;ar Valve in middle m;andrel / l . t l /l ) / / ¡'-1t2", 12.6 Ibm, L-8D, Ð TC-U Co~pll'g 0 0: S.2" 0 rlttliO : 3 .83 3'1J .9 S 8" 10-3/4", 45.:Ht L~O BTC cig g (I I 1I1H 1001 TVDII b(llow SV1 or ~O' niDI I b(llow SV3 1-{;,(j' .29.U, L-8D. a TC-II / JO"'--"" C ;a;!: h 9 0 rIft: 6 .7 S" C ;a;!: h 9 10: 6,87 S" 4.5" Sliding sleeve with 3.813 II 10 ... 7 -5,G" X 5-1 nil p;acker X- t-.ipple (3.813" 10) .5" \OlLEG ............--- Downhole Pressure G;auge with rontrollines to surt3œ 91 P P G Vers;apro MO BM below ColTpletion ( U u ilia I! ra I L! u! I 3 lu n c III) n @ I G -3 /4" 0 BI La tHa I I p;acker X N-Nipple (3.725" 10) U uilia I! ral L! U! 13 lunclll)n @ kip 0 Ð a ¡ and IG-3/4" O~ L3Dr31 RA Tag / Uner Top P ;adt:er & -timger -----"'"" 1-5/3" C a¡lng Sh(l! @ ...120' UP In ki h! 0 Ð d ¡ and ---- IG-3M" OBd LatlHall ( tI ... r£o R£oV , R-'" r::1J MM £ON r '5- GPaUwr ~~ ., ,l2S,l200S MI K T Fi!O to L ..'J..I ::I p., IJI~I-L..I:II r..I, .: ',~" -:. L 0:.:0:"1 : I"~IO:" ".I"'" ELL: Trl-L a t.;. ral t- ( ( Exhibit IV-3 Typical Vertical Hydraulically Fractured Producer C~III' 8rõl'a100 Nl;þ:.rr,;¡ 9E8 Rt::B TREE: 40-11'168 5M 1,1\1 ELL H E.I\ [I : 118 I 5M 13 I: rt 5 8~' ~ II: m 2C8 X 3408 215.5 Ibfll, A53 ERI,I\I h~ut:!ll:d 114 ' I' Port Ccll..... 11,000' I 9- 6'1;"1 4û II'f1¡ L-I;C\ BTC 3-1 fl." 'X' Landing Nipple W ittt 2.813" se;:11 bore. I 3,üüü'TVD I G u...1 3 -1 fl." x 1- 1 fl." M'u1 G Vthh 0 CR Sh ear \lalve pinned to 2,500 Either 100' TVDss tel aw tcp SV1 cr 90' NOss œl aw top SV3 J -1 /2 8 , 9.J b ftt, L -80 , TC II Dr IftI'I D : 2.8618/2 .9928 ( Sliding Slee\E! with 2.813" Polish Bore r x 3-1 re Production Pa.cker -=: ;2 00 1 I'd) Qb OVQ f1 oil M s.:n d 3-112 II rx~ Landing Nipple Wìh 8. 2.81 3 10 3-11211 'WireLine Entry Guide .....50" abo"l'e the OA sand ao. $:M d Perfs OB8. $:Md Perfs OBd sand Perfs r PBID ~ 71~ 26 :¡!ffl; L80~ BTC-M od I ^'150' M 0 below base 0 Ef I ( Date 7128103 Rev By MikT Comments GI6Jj ¡1 ~,. ~' , . ~. '~' , ,,:', " ", ,', ",,- "", " ¿'!" '-,'r?; , . ',- .", , - . ' _.' - . ' Proposed Go mpletion WEll: Producer f Exhibit IV-4 Typical Injection Well f' C .¡ liar E I tÖI'1A 1 crI ~ 9æ Rt::B P ortCol1i'J' 11.000' I €I- QI1;". 40 IYft, I.: 130. BTC Eith:!r 90 I lVOss below SV3 IT 100' NOss below SV1 4-112" X 3-112" T CII X 0 7« Short Joint 8: RA T s.g f " ... TBD' T~JD. . ... TBD' T~lD. . ( Date 7/28/03 Rev By MikT C omrnents Proposed Co m pletion GIêI~ ~i ~- i8Il" . ." "', ..,' ,.'. f." ' ,~,:"",W:'-,',,,'-':\,- ¡,~" ,.'if' ."s. TR E E: "'-1.'16. SO ll\l ELL H E.I\ [J : 1 P x so 13 e n S 8)' ~ lem 20. X 3.... 21S5 Ibrfl. .l\S3 ERll\1 h~ul2!lled 114' 4-1 fl" 'X' Landing t-ipple with 3.813" seal bore. I 2,~Üü' TVD I G Uv1 4-1 fl" x 1" KB G"2 \fliith 0 CR Shear Vahe pinned to "2 ;500 I 3,1üü' T~.JD I 4.-1/2., 12.15 brrt, L-3[] , TC II 0 rift I 10 : 3.833./3.958. 3-1/2.. 9.3 b tn, L -8 [] , T C II 0 rltt /10 : 2.861.12 .992. 4-111." 'X' Landing Npple with 3 .813" seal bore. r x 3-1/~ Production Packer 2) rJ PJD .Ð:o 'iQ tJ.¡¡ 'to P (XI, P rõIf f 3-111." 'X' Landing Npple with "2 .813" seal bore. Qð. æ.n d P e rfu: Carmo 3-112" x 1-112" G u..~ r x 3-1 ~ Production P$.cl::er 3-111." 'X' Landing Npple with "2 .813" seal bore. Carmo 3-1 fl" x 1-1/2" G lNI DBa æ.nd Perfu: r x 3-1/~ Produ ction Packer 3-111." 'X' Landing t-ipple with "2 .813" seal bore. 3-1/2" Vv'ireLine Errtry Guide (....50 i abO'l'e me top Oed per(! r PBTO ~ r~ 26 #fiJ L80J BTC-Mod I .....1.5ü' MD b¿-Ic..",.I"Hh¿- bas¿- 0 B1 I VUE LL: Injector , ('" Typical Orion-Borealis Commingled Injector (' C.¡IIU E 1rwII.1on t-.8booI ø E 8 R IŒ: PortCcll1OT 1'1,000' I 9-6Æ': 4) Wft¡ L- 00. B 11:: Eiiher 90' TV[);s bal CIW SV3 cr 100' TV[);s be low SV1 4-112"X 3-1a" TCII XO ( ( Date 7/2&'03 Rev By MikT Exhibit IV-5 TREE: 4--H16" SO lQI ELL H EA. [J : 11" x 9~ 13 ~r. S 8:i~ ~ m 2[]" X 34-" 21 S S Ib r'11,.AS3 E RIAl 1r.~uI8 ~ d 114' I L,Sùù'TVD 4-112" 'X' landing Nipple with 3.813" seal bore. G L1v1 4-1 a" x 1" KB G2 \I1Ji1h DC R Shear \..alve pin ned to 2,500 "-112",12.15 tim, L-8[],TCII 0 rift 110 : 3.833"/3 .958" 3-112",9.3 Ibltt, L-8[], TC II 0 rift 110 : 2.861"/2 .992" 4-112" 'X landing tipple with 3.813" seal bore. r x 3-1 ~ Production Pad<er ;XII) r...Ð 1å1.b:o...... 1f1IiI q:. (¥I, P'" f 3-112" 'X landing tipple with 2.813" seal bore. Schrader Perfs 3-1 a" x 1-1 a" G LM Sd-trader Perfs r x 3-1/~ Production Pad<er 3-112" 'X landing tipple with 2.813" seal bore. 3-11211 Vv'ireLine Entr,' Guide (.....1 50" wove the top per(! Kup~k Perfs 711 PBTD ) 71~ 26 =Wft;. L80) BTC-Mod 1---1Sù' MD b~lúwth~ bas~ ¡";uparu k C I Conments GEIêi ~. **~.. , , ,;' ", . "", '" , ".:;ff..;.:"""" ")",,i .."þ Proposed Co mp letion WELL: Injector Exhibit VI-I. (' { ( AFFIDA VIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Brian D. Huff, declare and affirm as follows: 1. I am the Greater Prudhoe Bay Orion Manager for BP Exploration (Alaska) Inc., the designated operator of the proposed Orion Participating Area, and as such have responsibility for Orion operations. 2. On 10 10 ( ( 0.3 , I caused copies of the Orion Pool Rules and Area Injection Order Application to 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: MAUREEN JOHNSON P.O. BOX 196612 ANCHORAGE, AK 99519-6612 ( Surface Owners: STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES ATTENTION: DR. MARK MYERS 550 WEST 7TH AVENUE, SUITE 800 ANCHORAGE, AK 99501-3510 Dated: Oú~ber J I ~~ 3 I Brian D. Huff ( Declared and affirmed before me this ¡ & day of cr b kR J\( <9r03 \t\l(l({(¡lr¡: \\~~1? e~.~~..~jjrr \.' ~'.' .. . 8'TO ~ ~ CJ'r.' -.; A R ~;.1::) ~ :::: Ill: 0' ,.... r. ~ -::. ~O'~ .."...,- ..~:::. ::: < ; PUB' \v : N :::: - ø. 1'-" ¡ trJ-.. - . -, ::. -z...'. \P _..- . ~ ...... -' &. ~ .tÞ:.. ~ ~" . :'!1'e Of þ.~ . ~ ~ . . . . . . \\' /.1) 'It \\ :I)}}))])}))" r\\~ Notary Public in and for aska ~ "Î" ^' ) I My commission expires:;=I\Âne :p-UJt .~ "-..,, ~ Exhibit VI-2: Polaris Injection Water Compositions "-"'.. Barium 16.9 2.17 0 - - Bicarbonate 4640 1640 140 Calcium 55 247 407 - --- Chloride 13529 12600 15770 Iron < 0.02 4.32 - Magnesium 109 156 1290 - - pH 8 6.9 Potassium 271 107 ~. - Sodium 7221 8080 8400 Strontium 10.3 26.2 5 - Sulfate 479 560 2670 TDS 26322 23427 28687 . ~ '\ / /. '/ ' ~ì /'-(t lj - dl \ (J ']7\ \" ""' "-.. 1 6 1 5 11 J3 1 \. I I ..... ~ J .....:. ~ to.. ~~.. ~-,:--..... T .... ~ .' In... ... r- ~ C' "'\ ....... '- . ~ - ). \ < Ì\" .. ~ '" n.. . --=- me"""" - .......... - ~ ',-/" \. ~ ) ~ ,,/ ~ 1---, - " k-ì ~~ /- - 2'" :~/ 23 2~ ~1 ~ 2, (~me] 1. ",,' " '~ .... '\ '.J. \ / 3Q 11 2~ ",<1'-\ ~f ~ ~'" \~ ~ 26 25 30 ':::':9 \. '- ~ ~ L-¡t1711. l L '\, \ ."¥ ........./ I'~~ .~~ ' '.....:.~ ,\ ~ ~~"lILL~ 1~ )~~f\~_1 \O31~ ~ ~ ,.1.- r ~I V-J jfl-~-2 ä]e~ '~~35 'I, '~ 32 '3 flL-'Hrr:~ ¡F -¡f~~r~95~~~ 31 32 , .," ~ -~ ~8 ~ - " "- HI. - , ... ~ ~ \ ~R \) -J' ~-~ ~ ' ~ l~ ",",~y .\\t.;'y ~~]51 6\ 5 ""\. /1I,~~1 .... \ ') I~:~~'~."~ " "'\ \ \ \, Ì\ 1 ø .. '" 1 2 "-~" I \ ~ t ...~~" ~ / ~87~ 12 . J -.............. ~ "" ~ p e 9 5 q " I ~ '"""~ '\ , .... ~ ~ -- -~8 ,if~8l-~fô ~'J7 H ~5 ¡ J 6 = '- ...... ~ N .t:' b._..""""" ~~';".I ..':\" r" I Tø4 ø4". r-t. A ~1 ~. Z Padl "", ....."'1 - -. I I'-~ . 5.988,899 . . . I'" ". "'"" ~- ~ ~~ ~-1] ~-~-~ -- 1iO..-,- - -?e . ~ N- 5 i .......: 6 N-q - ~ 3~ " - \Z-19 WEl 1!;aW- . , T : t 1 ïii.lW Padl N:811 83 , J 9 20 2 N-.. "" -:ßA . I-~' "~5 On] 11 ! I> ~..' ~!I...c ¡-~~~ . ----. '- W'~ I 1"- L ....... 5.955,899 '- '- ~8~_~]., 'K' .. J2A :- '" ~..¡r~8R ~\ \- 30 ... ~ 2ô 27 I "' ~ -"""(: -.1 ' 5.958,8['8 ( ,.99\.~.;~ ,.9"i.~';~ 5.98~.808 5. 98Q .808 5.97~.888 ( 5. 97Q .888 5.96~.888 S.96Q.888 S. 95~ .888 ( S. 95Q .808 (' ( (" 5131],IH'8 578.1][«3 ,,8 Q. 8 08 ,,88.81)8 ,,85.8')13 131][,,81)8 131]5.888 1310.>]813 13¡ 5.>]':'>] 585.81»] 5135, '](11) 57~ .>]1)8 . f<liOHOE->]1 I ]6 15 25 -... ft.... .. ... ft- I I,.~.r~ I~I:. ~2 '-- 22- ~ ......--.. ~ " ..- - /' ^ """"', ' "f.... -, "" , --\\' ""'\11 ~ '\ \. 1.IS Pad .t ~ ~- ~\,' -, ~, r 7 1 '1 ~~ t J , I' . i - T~"'C 1 '" 38 3J 6 . 5 5Rr.-~q " J 2 7 8 9 J3 J 8 17 2'3 J 9 20 21 22 23 24 ~.- t"li G~L ..",' ~ 25 30 29 28 27 28 25 I :"'01 --... --- 58ß. ß~ß 57ß .ß~ß 5".ßßß 58~ .ß.;ß 5,,~.ßßß 5,,5.ßßß BJ 5.ßßß 8ß~.ßßß Bß5.ßßß BI ~.ßßß 585.ßßß 5B5. ß~ß 1320.801] - ,.99,.;.J~ß ,. 99ß . ;.J~" 5.985,8«<) 5.988,891) 5.975,8M 5.978,899 , 5.985,899 B,,~.ßßß I ( Orion Pool/Injection Area Injection Well Location Map Red Outline - Orion Poolll njection Area and Proposed Orion Participating Area . IV-2011 Production Well IV-2021 High Angle Production Well .. IV-1051 Injection Well E9 114 Mile Radius Circle around existing Orion I njection wells 1 :?i08Ø ~JlOÞ\E1E~58 .5 .9~JLOt¡E1ERS ...:I 51R'LJ'E ~JLE5e .? .~ .1> .3 l.e5'RTUTE ~JLE5 t......:I I:......J I:......J I:......J I:......J t Exhibit VI-3 ,~ /-- '-', Exhibit VI-4: L-O2 Well Integrity Report Original Completion Date: Schrader Bluff Penetration Hole Diameter: 12/31/2002 8-3/4" Schrader Bluff Penetration Casing Diameter: 7" Well Status as of 8/2003: Oil Producer Gas Lift Cement Logs Across Schrader Bluff: None Comments: The intermediate casing in this well was cemented in two stages. The second stage utilized an HES 2nd Stage Cementer to place cement across the Schrader Bluff from approximately 200' below the interval. The 2nd stage cement job was pumped as planned with the cementer located at 5253'MD. With a gauge hole, 1289'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 790'MD of cement above the top of the Na sand. The plug bumped and held at 1700psi. Additional Information: Well Diagram - Exhibit VI-4 a Drilling Daily Reports (Cementing) - Exhibit VI-4 b .-.... -" TREE = Frvc4-1/6" 5M ---------------- - - ..-.--.-..----- ----_.---- --- _.- .------- .--.--.------- --- ----------- -----.------ --.-- --.--- -----.--.----- ----.---.-- --------------------.----- JOTES: INCLINATKJN > 70° @ 10310' WELLHEAD= Frvc GEN 5 AC1UA TOR = KB. ELEV = 82' BF. ELEV = 53' L(OP= 900' xAngle= 98° @ 10722' I uatum rvÐ = 10042' Datum lV D = 8800' SS ~. 9-5/8" CSG, 40#, L-80, ID = 8.835" 2581' Minimum 10 = 3.725" @ 9768' 4-112" HES XN NIPPLE 14-1/2", 12.6#, L-80, .0152 bpf, ID = 3.958" 1 9779' I 7" CSG, 26#, L-80, ID= 6.276" I 9953' PERFORATION SUMvlARY REF LOG: ANGLEA TTOP ÆRF: 96 @ 10876' I\bte: Refer to Production DB for historical perf data SIZE SPF INTER\! AL OpnlSqz DATE SLOlTED 10876 -11318 0 12/30/02 11525 - 12287 0 12/30/02 12370 - 12571 0 12/30/02 12775 - 13570 0 12/30/02 14-1/2" SL 1D LNR, 12.6#, L-80, .0152 bpf, ID= 3.958" I L""-O2 I SAF~ ~ 13570' 13572' ST rvÐ 7 3005 6 4263 5 5939 4 7248 3 8263 2 9031 1 9594 DATE REV BY CO MvlENTS DA. TE REV BY COMMß\J1S Î 1 /01 /03 DAC/KK ORIGINAL COrvPLETION )2/15/03 GJB/tlh GL V UFDA TE 04/15/03 JJ/KA K GL V C/O 05/07/03 TH/KA K ŒPrH CORRECTIONS 05/31/03 MI-VTL P GLV C/O 954' 2119' 9662' 9726' 9747' 9768' 9779' 9783' I-iTAM PORT COLLAR -14-1/2" rES X NlP,ID = 3.813" I GAS LIFT MANDRELS TVD DEV TYÆ VLV LATCH 2979 20 KBG-2 DOME BK 4080 30 KBG-2 SlO BK 5532 32 KBG-2 DMY BK 6603 40 KBG-2 DMY BK 7396 38 KBG-2 DMY BK 7991 38 KBG-2 DMY BK 8438 37 KBG-2 DMY BK PORT DATE 16 05/31/03 22 05/31/03 05/31/03 05/31/03 04/15/03 04/15/03 04/15/03 -14-1/2" HES X NIP, ID = 3.813" I -17" X 4-1/2" BKR &3 PKR, ID = 3.875" I -14-1/2" HESX NIP, ID= 3.813" I ~4-1/2" HES XN NIP, D = 3.725" I -i5" X 7" BKR ZXPLNRTOP A<R, ID= 5.610" I -14-1/2" WLEG, ID= 3.958" I I~ ELMD TT NOT LOGGED FRUDHOE BA Y UNIT WELL: L-02 PERrvlIT No: 2012070 A A No: 50-029-23048-00 SEC 34, T12N, R11 E. 2528' SNL & 3860' WEL Exhibit VI-4 a ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Current Well Status Casing Size: 7.000 (in) Costs in: USD Casing (MD): 9,953.0 (ft) Daily Mud: 8,926 Next Casing Size: 4.500 (in) Cum. Mud: 259,578 Next Casing (MD): 13,842.0 (ft) Daily Well: 69,648 Next Casing (TVD):8,857.0 (ft) Cum. Well: 1,355,062 Depth MD: 9,953.0 (ft) Est. TVD: 8,733.0 (ft) Progress: (ft) Auth Depth: 13,842.0 (ft) Hole Size: 8.750 (in) DOLlDFS/Target: 10.30/9.80/28.68 Geologist: Ray Engineer: Triolo Supervisor: MADSEN / GALLOWAY Current Status: 24hr Summary: 24hr Forecast: Comments: Days Since Last DAFWC: 343 Last Csg Test Press.: 3,500 (psi) Last BOP Press. Test: 12/3/2002 Next BOP Press. Test: 12/10/2002 Last Divertor Drill (D3): 12/1/2002 No. Stop Cards: FIRE: 12/8/2002 ( LOT TVD: 2,580.0 (ft) LOT EMW: 13.24 (ppg) MAASSP: 287 (psi) Test Pressure: 475 (psi) Kick Tolerance: (ppg) Kick Volume: (bbl) (ft/hr) (ft/hr) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM Min.: RPM DH: Torq. on Bottom: (ft-Ibf) Torq. off Bottom: (ft-Ibf) f ( ( Exhibit VI-4 b Report: 12 Date: 12/10/2002 Rig Accept: Rig Release: Spud Date: WX Date: Elev Ref: 17: 00 11/30/2002 12/1/2002 SEA LEVEL Program: Weather: KB Elev: 82.00 (ft) Tot. Personnel: 42 Cost Ahead 300,000 USD, Days Ahead 4.00 2 deg, 10 mph SSW, WC -15 deg erationalParameters Daily Bit Hrs: 0.00 (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: (hr) Ann. Vel. Riser: (ftlmin) ! Ann. Vel. DC: 414.8 (ft/minll) Ann. Vel. DP: 261.4 (ftlmin) Last Trip Drill (D1): Last Safety Meeting: 12/8/2002 12/10/2002 11 Last Spill Drill: 12/8/2002 Regulatory Agency Insp: N Non-compliance Issued: N KICK WHILE DRILL (D2)12/7/2002 WELL KILL (D5): 12/4/2002 Pump! Slow Pump Rates (Circ) : Slow Pump Rates (Choke): Slow Pump Rates (Kill) j Stroke Rate PressureO i Stroke Rate PressureO I Stroke Rate PressureO ! ' Manuf. ,-- -, .. , , Smith Bha No: 4 Depth In: Bha Type: CLEAN OUT Depth Out: Component I Component Detail I I I \ , . Smith PDC : Integral Blade Stabilizer . NM FLEX DRILL COLLAR ¡ Mill I Drill : NM FLEX DRILL COLLAR : Integral Blade Stabilizer . NM FLEX DRILL COLLAR 'HWDP ~ JAR 0 Rotating Weight: (Ibs) Pick Up Wt.: (Ibs) Slack Off Wt.: (Ibs) Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: (psi) Circ. On Bottom: (psi) Jar Hrs since Inspect: (hr) Pump Status - Drilling and Riser Pump IType Eff,' ¡Strokes! Liner Size Cire. Rate 0 0 i 0 0 I I Bit Run # IRe-Run Size (in) 4 Y 8.750 , Cum Prog(~) i RPM Min/Max WOB Min/Max I i / / \ Bits Serial # Nozzles - " , JS8755 12/12/12/12/12/12/12 12// Cum ROP \ I 2 I 4 N / D BOP Stack POOH LID 5" DP, Ran 7" Csg to 9,953', Circ Cement 7" Csg, N/D BOP, Set Slips, N/U & Tst BOPs, P/U 4" DP NO ACCIDENTS, NO INCIDENTS, NO SPILLS, 2 deg, 10 mph SSW, WC -15 deg, Visibility 0.2 Miles HSE & Well Control All Free Days: ( BIT STAB COLLAR HOLE OPENE COLLAR STAB COLLAR HWDP JAR BHA Bha Weight: Wt Below Jars: Length ¡Cum Length! OD ID IBlade ODIBend Angle: Connection , I 'I I (ft) . (ft) ¡ (in) (in): (in) (O)! Size (in) Type l' 0.80 II 0.80' 8.750 2.0601 : 4.500 REG I I 1, 4.08 i 4.88 6.590 2.810, 8.440 I 4.500 IF \ , 1 I 31.14: 36.02 6.870 2.875, 4.500 IF I 1 6.06 . 42.081 6.500 2.810: 8.750' 4.500 IF : 1 31.09 ' 73.17 6.830 2.875 . 4.500 IF 1 1 4.75 77.92 6.770, 2.810 8.500 I I 4.500 IF I 1, 30.79 108.71 6.390 2.875 4.500 IF 15: 449.83 i 558.54 5.000 3.000 4.500 IF I 1 I 31.00 \ 589.54 6.450 2.750 ¡ 4.500 IF Make I I S86EHVPX : Cum Hrs 9,953.0 9,953.0 Jts I I TD : 0 : P/B P B B B B B B B B Printed: 12/11/2002 6:05:18 AM BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: BHA Bha Weight: Wt Below Jars: Cum Length 00 10 Blade 00 Bend Angle (ft) (in) (in) (in) (°) 739.00 5.000. 3.000 Drillin Fluid 6 (lb/100ft2) Ca: 9 (lb/100ft2) K+: 2.4 (cc/30min) CaCI2: 180 (OF) NaCI: 5.5 (cc/30min) CI-: 1 (/32") Sand: 19.00 (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY Bha No: 4 Depth In: 9,953.0 Bha Type: CLEAN OUT Depth Out: 9,953.0 Component Component Detail Jts Length (ft) 5 149.46 HWDP HWDP Type: Time/Loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: LSND 16:00/PIT 9,953.0 (ft) 106 (OF) 11.10 (ppg) 41 (s/qt) (ppg) 13 ( cp ) 22 (lb/100ft2) 9.3 " 10 see gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: From-To Hrs ' Phase Task Activity Op. Depth (hr) , " 00:00-01 :00 1.00 ~ INT1 ! CASE' POH 5,000 01 :00-02:00 1.00 INT1 : CASE ~ CIR 5,000 ! I I 02:00-04:30 2.50 INT1 I CASE: POH 739 I i 04:30-05:30 : 1.00 . INT1 CASE: BHPULD I I I 05:30-06:00 0.50 INT1 CASE: RU ( , I 06:00-06:30 0.50 INT1 IBOpsul WEAR , 1 06:30-07:00 0.50 INT1 I CÁSE' RU 07:00-20:30 13.50 INT1 ! CASE RIH 9,944 20:30-22:00 1.50 INT1 ICASE 9,953 WASH ( f' 0 60 (mg/L) (mg/L) (%) (%) 450 (mg/L) 0.25 (%) 123.29 (ppb) 39.24 (ppb) 0.08/1.5 (mL/mL) 0 erations Summa Code NPT P P P P P P P P P Exhibit VI-4 b Report: 12 Date: 12/10/2002 Connection Size (in) Type 4.500 IF P/B B ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (mV) 12.70 (%) 3.0 (%) 84.1 (%) / (bbl) (bbl) (bbl) 16.1 (bbl) : Held PJSM. POOH L / D 5" DP from 5,700' to 5,000'. Operation Pumped and Spotted 200 bbl Steel Seal Pill from 5,000' to 2,500'. Pump Rate 7 bpm, 900 psi. POOH L / 0 5" DP from 5,000' to 739'. 1 POOH, Broke Out and L / D Clean Out BHA. : Cleared and Cleaned Rig Floor. 1M / URetrievingTool. RIH, Latched and Pulled Wear Bushing.L / IS I Retrieving Tool. . Held PJSM. R / U 7" Casing Equipment. . M / U and RIH w/ 7" 26# L-80 BTC-M Casing to 9-5/8" Casing Shoe at 2,581' at 80' / min, Broke Circulation and Staged Pumps Up to 5 bpm, 350 psi, No Losses. RIH to 4,000' at 60' / min, Broke Circulation every 15 Joints, Pump Rate 2.5 bpm. RIH at 20' / min while Circulating. RIH 6,500' at 60' / min, Broke Circulation every 10 Joints, Pump Rate 2.5 bpm. RIH at 20' / min while Circulating. Circulated f/ 30 minutes at 6,500'. RIH to 8,500' at 60' / min, Broke Circulation every 10 Joints, Pump Rate 2.5 bpm. RIH at 20' / min while Circulating. RIH to 9,300', Broke Circulation at 9,300', Pump Rate 3 bpm, No Losses. Circulated Down 3 Joints from 9,300' to 9,450', Pump Rate 3 bpm, 650 psi, No Losses. RIH to 9,944', Tagged Up at 9,944'. Staged Pumps up to 7 bpm, 950 psi, No Losses. Washed Down and : Worked Casing Down to 9,953' at 6' / hr. String Weight Up 300,000#, String Weight Down 175,000#. Ran a Total of 242' Joints of 7" 26# L-80 BTC-M Casing, M / U Torque 9,000 ft / Ibs. 7" Casing Set As Follows: Item . Float Shoe i 1 Jt 7" 26# L-80 BTC-M Csg ! Float Collar 1 Jt 7" 26# L-80 BTC-M Csg Baffle Collar 112 Jts 7" 26# L-80 BTC-M Csg HES 2nd Stage Cementer 128 Jts 7" 26# L-80 BTC-M Csg Length 1.65' 40.90' 1.00' 40.12' 0.97' 4,608.11' 2.35' 5,247.04' Depth 9,953.00' 9,907.65' 9,906.65' 9,866.53' 9,865.56' 5,255.63' 5,253.28' 0.00' Printed: 12/11/2002 6:05:18 AM ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY From-To Hrs Phase Task Op. Depth (hr) 22:00-00:00 2.00 INT1 CASE 9,953 From-To Hrs Phase Task Op. Depth (hr) 00:00-02:30 2.50 INT1 CEMT 9,953 ( 02:30-03:00 i 0.50 9,953 ¡ i : I I I I I INT1 : CEMT 03:00-04:00 1.00: INT1 : CEMT 9,953 i: ! I i I ( : ( Activity CIR Activity CMT CIR CMT ( BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Operations Summary Code NPT Exhibit VI-4 b Report: 12 Date: 12/10/2002 Operation P Circulated to Cool and Condition the Mud and Clean the Hole. Pump Rate 7 bpm, 950 psi. No Losses. After 3 Bottoms Up, Shut Down Pumps, RID Franks Tools and M I U Cement Manifold. Established Circulation, Pump Rate 7 bpm, 950 psi. Reciprocated the Pipe 15' While Circulating. 06:00 Update NPT Code Operation P Held PJSM wI Dowell Crews, Rig Crews and Peak Truck Drivers. Switched over to Dowell. Pumped 5 bbls of Water to Clear the Lines of Air. Shut in Cement Manifold and Tested Lines to 4,000 psi, OK. Pumped 35 bbls of MudPush at 4 bpm, 700 psi. Dropped Bottom I Plug, Pumped 123 bbls (500 sx) 15.8 ppg Expando Cement wI 3.00% bwoc High Temp Expanding Agent, 0.45% bwoc Dispersant, 0.20 gal/sk AntiFoam, 2.00 gallsk GASBLOK, 0.25% bwoc Retarder, 10.20% bwoc Silica Pumped Cement at the Following Rates: i Pumped Rate Pressure : 20.0 bbls 5.00 bpm 1,050 psi ; 40.0 bbls 5.00 bpm 825 psi i 60.0 bbls 5.00 bpm 700 psi : 80.0 bbls 5.00 bpm 650 psi I ¡ 100.0 bbls 5.00 bpm 650 psi 1123.0 bbls 5.00 bpm 650 psi ~ Dropped Top Plug and Displaced wi 5 bbls of Water at 5 bpm, 280 : psi. Switched to Rig Pumps and Displaced wi 373 bbls of Mud at the ; Following Rates: I Pumped Rate Pressure I 50.0 bbls 7.0 bpm 160 psi 100.0 bbls 7.0 bpm 160 psi 150.0 bbls 7.0 bpm 160 psi 200.0 bbls 4.0 bpm 60 psi 250.0 bbls 7.0 bpm 160 psi 300.0 bbls 5.0 bpm 300 psi 350.0 bbls 5.0 bpm 800 psi 372.0 bbls 3.0 bpm 900 psi Wiper Plug Bumped wi 372 bbls Pumped. Pressured up to 1,400 psi, Held fl 5 minutes, OK. Cement in Place @ 0215 Hrs. Bled off Pressure, Floats Held. Reciprocated Casing while Pumping Cement, Casing Started Hanging Up wi 250 bbls of Displacement Pumped, Landed Casing on Bottom. ... '... .. .. . .. '.. ".. .... . .... Pressure up on Casing at 3 bpm to 3,200 psi and Opened HES Cementer. Circulated Bottoms Up at 7 bpm, 550 psi, No Losses. Circulated Back Apx 20 bbls of Mud Push. . . .. . . . . . Switched over to Dowell. Pumped 15 bbls of Chemical Wash at 5 bpm, 550 psi, Shut in Cement Manifold and Tested Lines to 3,000 psi, OK. Pumped 35 bbls of MudPush at 5.5 bpm, 725 psi. Pumped 58 ; bbls (120 sx) 11.5 ppg LiteCRETE Cement wi 41.00% bwoc Extender, 1.00% bwoc Dispersant, 0.20 gal/sk AntiFoam, 21.00 %bwoc Stabilizer, 0.20% bwoc Fluid Loss, 1.00% bwoc Accelerator. Pumped Cement at the Following Rates: Pumped Rate 10.0 bbls 5.70 bpm , 20.0 bbls 5.70 bpm ; 30.0 bbls 5.70 bpm . 40.0 bbls 5.70 bpm i 50.0 bbls 5.70 bpm I 58.0 bbls 4.00 bpm P P Pressure 1,040 psi 980 psi 930 psi 930 psi 950 psi 600 psi Printed: 12/11/2002 6:05:18 AM ( I' ( BP EXPLORATION Daily Operations Report Exhibit VI-4 b Operator: BP EXPLORATION Rig: DOYON 14 Report: 12 Well: L-02 Event: DRILL +COMPLETE Date: 12/10/2002 Field: PRUDHOE BAY Well Type: 06:00 Update From-To Hrs Phase Task Activity Code NPT Operation Op. Depth (hr) 03:00-04:00 1.00 INT1 CEMT CMT P Dropped Closing Plug and Displaced wI 5 bbls of Water at 6 bpm, 660 9,953 psi. Switched to Rig Pumps and Displaced wI 195 bbls of Mud at the Following Rates: Pumped Rate Pressure 50.0 bbls 7.0 bpm 520 psi 100.0 bbls 7.0 bpm 540 psi 150.0 bbls 7.0 bpm 500 psi 195.0 bbls 3.5 bpm 300 psi Closing Plug Bumped wI 195 bbls Pumped. Pressured up to 1,450 psi and Closed HES Cementer, Increased Pressure to 1,700 psi and Held fl 5 minutes, OK. Cement in Place @ 0400 Hrs. Bled off Pressure, Cementer Closed. 04:00-05:00 1.00 INT1 CEMT RD P Held PJSM. RID Cement Head and Lines. Cleaned and Cleared Rig 9,953 Floor. 05:00-06:00 1.00 INT1 :Bopsu1 ND P ; Held PJSM. N I D BOP Stack. 9,953 . N I D BOP Stack Mud Log Information Formation SAG RIVER , Form. Top MD. 9,950.0 (ft) i Bkgrnd Gas (ppm) I Trip Gas (ppm) Lithology SANDSTONE I Conn. Gas (ppm) I Pore. Press (ppg) Materials I Consumption Item I, Units i Usage,: On Hand I Item : Units I Usage 1 On Hand DIESEL GAL ¡ 2500, 8070 i i Personnel Company i No. 'Hours Company i No. ! Hours Company I No. i Hours FAIRWEATHER I 21 " DOYON I 261 DOYON I 51 SPERRY-SUN 41 BAROID 21 PETROTECHNICAL RESOUR I 1 i SPERRY-SUN I 21 I i Cumulative Phase Breakdown ' " Planned Change of Scope Total Total Cost Phase Prod % Total NPT % Total I WOW % Total Prod % Total: NPT % Total I WOW % Total Hours USD PRE 25.50 78.5% I 7.00 21.5% I I 32.50 122,630.00 SURF 65.00 100.0% 1 I 65.00 461,345.58 I 0.0%1 INT1 158.00 91.1% 15.50 8.9%1 I 173.50 771,086.19 I TOTALS 248.50 91.7% 15.50 5.7%[ 7.00 2.6% 0.00 0.0%; 0.00 0.00 0.0% 271.00 1,355,061:? Remarks PJSM held for all Operations (' ( ( Printed: 12/11/2002 6:05:18 AM BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Current Well Status Casing Size: 7.000 (in) Costs in: USD Casing (MD): 9,953.0 (ft) Daily Mud: 2,255 Next Casing Size: 4.500 (in) Cum. Mud: 261,833 Next Casing (MD): 13,842.0 (ft) Daily Well: 284,125 Next Casing (TVD):8,857.0 (ft) Cum. Well: 1,639,187 (' ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY Depth MD: 9,953.0 (ft) Est. TVD: 8,733.0 (ft) Progress: (ft) Auth Depth: 13,842.0 (ft) Hole Size: 8.750 (in) DOLlDFSlTarget: 11.30/10.80/28.68 Geologist: Ray Engineer: Triolo Supervisor: MADSEN / GALLOWAY Current Status: 24hr Summary: 24hr Forecast: Comments: Program: Weather: ( Exhibit VI-4 b Report: 13 Date: 12/11/2002 Rig Accept: Rig Release: Spud Date: WX Date: Elev Ref: 17:0011/30/2002 12/1/2002 SEA LEVEL KB Elev: 82.00 (ft) Tot. Personnel: 42 Cost Ahead 400,000 USD, Days Ahead 3.00 5 deg, 2 mph SSW RIH w/ 6-1/8" Dirc BHA Set & Cmt'd 7" Csg @ 9,953', Chg'd Pipe Rams, Tst'd BOPE, P/U 4" DP RIH w/6-1/8" Dirc BHA, Tst Csg, Drlg Out, Displ, FIT, Drlg NO ACCIDENTS, NO INCIDENTS, NO SPILLS, 5 deg, 2 mph SSW, Visibility 20.2 Miles Days Since Last DAFWC: 344 Last Csg Test Press.: 3,500 (psi) Last BOP Press. Test: 12/11/2002 Next BOP Press. Test: 12/18/2002 Last Divertor Drill (03): 12/1/2002 No. Stop Cards: FIRE: HSE & Well Control All Free Days: 12 Last Trip Drill (01): Last Safety Meeting: 12/8/2002 12/12/2002 12/11/2002 Last Spill Drill: 12/11/2002 Regulatory Agency Insp: N KICK WHILE DRILL (02)12/7/2002 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Non-compliance Issued: N WELL KILL (05): 12/4/2002 : Slow Pump Rates (Choke)' Slow Pump Rates (Kill) I Stroke Rate PressureO Stroke Rate PressureO I ( LOT TVD: 2,580.0 (ft) LOT EMW: 13.24 (ppg) MAASSP: 287 (psi) Test Pressure: 475 (psi) Kick Tolerance: (ppg) Kick Volume: (bbl) i . ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM Min.: RPM DH: Torq. on Bottom: Torq. off Bottom: i i Ope rational Pa ra meters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: (hr) Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND 01 :OO/PIT 9,953.0 (ft) 84 (OF) 11 .10 (ppg) 40 (s/qt) (ppg) 13 (cp) 19 (lb/100fF) ¡ 9.5 I 10 sec gels: 10 min gels: Fluid Loss: HTHP Temp: : HTHP WL: , Cake: MBT: Lime: PM: From-To Hrs I Phase I Task I Op. Depth (hr): : ' 00:00-02:30 2.50' INT1 : CEMT I 9,953 Activity CMT ( . . .,... .... ..',: Pump Status - Drilling and Riser Pump Type! Eff. Strokes Liner Size Circ. Rate ,0 0 0 0 Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) .:'. .' Drilling Fluid 6 (lb/100ft2) I Ca: 11 (lb/100ft2) i K+: 2.6 (cc/30min): CaCI2: 180 (OF) ~ NaCI: 5.5 (cc/30min) i CI-: 1 (/32") Sand: 19.00 (ppb) HGS: (ppb) LGS: 0.15 (mL) Pf/Mf: Operations Summary : Code ~ NPT i I ' I . ! P I I I I 60 (mg/L) (mg/L) (%) (%) 450 (mg/L) 0.10 (%) 121.81 (ppb) 41.06 (ppb) 0.10/2.5 (mL/mL) '. ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (mV) 12.80 (%) 3.0 (%) 84.0 (%) / (bbl) (bbl) (bbl) (bbl) Operation Held PJSM w/ Dowell Crews, Rig Crews and Peak Truck Drivers. Switched over to Dowell. Pumped 5 bbls of Water to Clear the Lines of Air. Shut in Cement Manifold and Tested Lines to 4,000 psi, OK. Pumped 35 bbls of MudPush at 4 bpm, 700 psi. Dropped Bottom I Plug, Pumped 123 bbls (500 sx) 15.8 ppg Expando Cement w/ 3.00% i bwoc High Temp Expanding Agent, 0.45% bwoc Dispersant, 0.20 Printed: 12/12/2002 5:36:13 AM ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY From-To Hrs Phase Task Op. Depth (hr) 00:00-02:30 2.50 INT1 CEMT 9,953 ( ! . 02:30-03:00 0.50: INT1 I CEMT 9,953 . I 03:00-04:00 1.00 I INn, CEMT 9,953 : i I 04:00-04:30 0.50' INT1 9,953 . I CEMT: I ( Activity CMT CIR CMT RD ( BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: 0 erations Summa Code NPT Exhibit VI-4 b Report: 13 Date: 12/11/2002 Operation P gal/sk AntiFoam, 2.00 gallsk GASBLOK, 0.25% bwoc Retarder, 0.20% bwoc Silica Pumped Cement at the Following Rates: Pumped Rate Pressure 20.0 bbls 5.00 bpm 1,050 psi 40.0 bbls 5.00 bpm 825 psi 60.0 bbls 5.00 bpm 700 psi 80.0 bbls 5.00 bpm 650 psi 100.0 bbls 5.00 bpm 650 psi 123.0 bbls 5.00 bpm 650 psi Dropped Top Plug and Displaced wi 5 bbls of Water at 5 bpm, 280 psi. Switched to Rig Pumps and Displaced wi 373 bbls of Mud at the Following Rates: . Pumped Rate Pressure 50.0 bbls 7.0 bpm 160 psi 100.0 bbls 7.0 bpm 160 psi ,150.0 bbls 7.0 bpm 160 psi '200.0 bbls 4.0 bpm 60 psi i250.0 bbls 7.0 bpm 160 psi : 300.0 bbls 5.0 bpm 300 psi : 350.0 bbls 5.0 bpm 800 psi i 372.0 bbls 3.0 bpm 900 psi Wiper Plug Bumped wi 372 bbls Pumped. Pressured up to 1,400 psi, . Held fl 5 minutes, OK. Cement in Place @ 0215 Hrs. Bled off ! Pressure, Floats Held. Reciprocated Casing while Pumping Cement, ! Casing Started Hanging Up wi 250 bbls of Displacement Pumped, I Landed Casing on Bottom. . Pressured up on Casing at 3 bpm to 3,200 psi and Opened HES Cementer. Circulated Bottoms Up at 7 bpm, 550 psi, No Losses. Circulated Back Apx 20 bbls of Mud Push. . . ... . . Switched over to Dowell. Pumped 15 bbls of Chemical Wash at 5 bpm, 550 psi, Shut in Cement Manifold and Tested Lines to 3,000 psi, OK. Pumped 35 bbls of MudPush at 5.5 bpm, 725 psi. Pumped 58 bbls (120 sx) 11.5 ppg LiteCRETE Cement wi 41.00% bwoc Extender, 1.00% bwoc Dispersant, 0.20 gal/sk AntiFoam, 21.00 %bwoc I Stabilizer, 0.20% bwoc Fluid Loss, 1.00% bwoc Accelerator. Pumped I Cement at the Following Rates: : Pumped Rate Pressure : 10.0 bbls 5.70 bpm 1,040 psi I . 20.0 bbls 5.70 bpm 980 psi I i 30.0 bbls 5.70 bpm 930 psi 40.0 bbls 5.70 bpm 930 psi i 50.0 bbls 5.70 bpm 950 psi I 58.0 bbls . 4.00 bpm 600 psi I Dropped Closing Plug and Displaced wi 5 bbls of Water at 6 bpm, 660 : psi. Switched to Rig Pumps and Displaced wi 195 bbls of Mud at the I : Following Rates: ! Pumped Rate Pressure : 50.0 bbls 7.0 bpm 520 psi 100.0bbls 7.0bpm 540 psi ¡150.0bbls 7.0bpm 500 psi : 195.0 bbls 3.5 bpm 300 psi ; Closing Plug Bumped wi 195 bbls Pumped. Pressured up to 1,450 psi I and Closed HES Cementer, Increased Pressure to 1,700 psi and Held ! fl 5 minutes, OK. Cement in Place @ 0400 Hrs. Bled off Pressure, . Cementer Closed. , . Held PJSM. RID Cement Head and Lines. Cleaned and Cleared Rig Floor. P P P Printed: 12/12/2002 5:36:13 AM ~ ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY From-To Hrs Phase Task Activity Op. Depth (hr) 04:30-05:30 1.00 INT1 BOPSU NO 9,953 05:30-06:30 1.00 INT1 WHSU MISC 9,953 06:30-07:30 1.00 INT1 WHSU MISC P 9,953 07:30-08:30 1.00 INT1 WHSU MISC P 9,953 08:30-10:00 1.50 INT1 BOPSU NU P 9,953 10:00-11 :00 1.00 PROD1BOPSU MAINT P , : : 11 :00-14:00 3.00 !PROD1 'BOPSU' MAINT P ¡, , 14:00-14:30 ~ 0.50 ]PROD1 iBOPSU: TSTPRS P I 14:30-18:00 3.50 PROD1 iBOPSU! TSTPRS ¡ P I' I I ! I ( 18:00-18:30 0.50 PROD1 BOPSUI TSTPRS 18:30-19:00 ö.501pRÖD1 DRILL: PU 19:00-22:00 3.00 PROD1 DRILL RIH I I 22:00-23:00 1.00 ¡PRÖD1 -bRiLl I RIGSER , i 23:00-00:00 , 1.00 PROD1 DRILL; ! POH From-To Hrs Op. Depth (hr): 00:00-00:30 0.50 iPROD1 DRILL I i Activity POH 00:30-03:00 2.50 PROD1 DRILL BHPULD I i I I 03:00-03:30 0.50 ipROD1 DRILL I BHPULD 03:30-06:00 2.50 PROD1: DRILL: RIH RIH w/ 6-1/8" Dirc BHA ( (' BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: 0 erations Summa Code NPT Exhibit VI-4 b Report: 13 Date: 12/11/2002 Operation P Held PJSM. N / 0 BOP Stack. P Installed and Set 7" Casing on Slips. P / U Weight 195,000#, Block Weight 55,000#, Weight to Energize Slips 30,000#, Set 110,000# on Slips. Held PJSM and Checked Cellar w/ Gas Detector. Cut off 7" Casing and Prepped for Packoff. FMC Installed 7" x 9-5/8" Packoff. Tested Packoff to 4,000 psi f/10 minutes, OK. Held PJSM. N / U BOP Stack. Changed Out Upper Pipe Rams to 2-7/8" x 5" V.ariable Rams. R / U and Pressured up on 9-5/8" x 7" Annulus, Formation Broke Down at 350 psi, Pumped 5 bbls of Mud into Annulus at 1.5 bpm, 450 psi. Held PJSM. Changed Out Saver Sub on Top Drive from 4-1/2" IF to 4" HT. M / U Double Valve on 9-5/8" x 7" Annulus. Cleaned Mud Pits and : Loaded 4" DP into Pipe Shed. ¡ R / U Test Joint and Equipment to Pressure Test BOPE. P : Held PJSM. Tested BOPE. Tested Upper and Lower Rams, Blind ¡ Rams, Stand Pipe Manifold, Choke Manifold, Valves, HCR, Kill Line, : Choke Line, Floor Valves and IBOP to 3,500 psi High / 250 psi Low. : Tested Annular Preventer to 3,000 psi High /250 psi Low. All Tests i Held f/ 5 Min. All Pressure Tests Held w/ No Leaks or Pressure Loss. Witnessing of BOPE test Waived by AOGCC Rep John Crisp. Pumped 5 bbls of Mud down 9-5/8" x 7" Annulus, 1.5 bpm, 400 psi R / 0 BOPE Test Equipment. Ran and Set Wear Bushing. ' P ¡ I Held PJSM. R / U Equipment to Run 4" HT DP. ! P ,p / U, Drifted and RIH w/ 120 Joints Of 4" HT DP. Pumped 5 bbls of Mud down 9-5/8" x 7" Annulus, 1.5 bpm, 400 psi , , "'" '" , ,,',' " , , Held PJSM. Slipped and Cut Drilling Line, Serviced Top Drive. P P POOH and Racked 4" HT DP in Derrick. Code 06:00 Update NPT Operation P ; ¡Held PJSM. POOH w/ 4" HT DP and Racked in Derrick. I SIMOPS: Held PJSM w/ Hot Oil Crew, R / U Hot Oil to 9-5/8" x 7" Annulus to Freeze Protect. Pressure Tested Line to 3,500 psi, OK. Started Pumping at 0.5 bpm, 350 psi, Bullheaded Fluid into Annulus. Staged Pump up to 5 bpm, 1,200 psi. Pumped 56 bbls of Dead Crude down 9-5/8" x 7" Annulus to Freeze Protect to 2,200'. R /0 Hot Oil. Held PJSM. M / U BHA. 6-1/8" HTC DP0796 PDC Bit, Ser#7101485, dressed w/ 6x1 0 jets, 4-3/4" SperryDrili Lobe 4/5 6.3 Stg Motor w/ 1.50 deg Bent Housing, NM Float Sub, GR-Res, OM, SLD-CTN, PWD, Hang Off Collar, 3 x Flex Collars, Drilling Jars, XC. Total BHA Length - 241.77'. Set Motor Bend and Oriented to MWD. M / U Top Drive and Tested MWD Tools, w/ 250 gpm, 1,050 psi, OK. Cleared Rig Floor. Sperry Sun Loaded Radioactive Sources into MWD !Tools. I, , ! RIH w/ 6-1/8" Directional BHA on 4" DP to 3,000'. Picked up Single I Joints of DP from Pipe Shed. P P P Printed: 12/12/2002 5:36:13 AM ( BP EXPLORATION Daily Operations Report Rig: DOYON 14 Event: DRILL +COMPLETE Well Type: Mud Log Information Form. Top MD. 9,950.0 (ft) Bkgrnd Gas Conn. Gas Materials I Consumption Usage On Hand I Item 2710 74601 Personnel Company ( Exhibit VI-4 b ( Operator: BP EXPLORATION Well: L-02 Field: PRUDHOE BAY Report: 13 Date: 12/11/2002 Formation SAG RIVER Lithology SANDSTONE (ppm) (ppm) Trip Gas Pore. Press (ppm) (ppg) Item Units GAL Units Usage On Hand DIESEL Company FAIRWEATHER SPERRY-SUN SPERRY-SUN No. Hours 2 DOYON 4 BAROID 2 No. Hours Company 26 DOYON 2 PETROTECHNICAL RESOUR No. Hours 5 1 Phase PRE SURF INT1 PROD1 TOTALS Prod % Total. 25.50 78.5% 65.00 100.0%' 168.00 91.6% 15.50 14.00 100.0% 272.50 92.4% 1 15.50 Cumulative Phase Breakdown Planned Change of Scope NPT % Total WOW % Total Prod % Total NPT % Total WOW % Total 7.00 21.5% 5.3%: 7.00 2.4% 0.00 0.0% : Remarks 0.00 0.0%1 0.00 Total Total Cost Hours USD 32.50 122,630.00 65.00 462,016.58 183.50' 1,054,539.9 14.00 295.00: 1,639,186.5 8.4%; 0.0% PJSM held for all Operations ( ( I Printed: 12/12/2002 5:36:13 AM /---. .~ ---., Exhibit VI-5: L-110 Welllntegffiy ReQort Original Completion Date: 9/15/2001 Schrader Bluff Penetration Hole Diameter: 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift ..-...., Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 256 sacks (612 ft3) of cement. Floats held and the plug bumped with 2850 psi. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2668'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 977'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-5 a Drilling Daily Reports (Cementing) - Exhibit VI-5 b ~.. TREE = ( ----_..--------- ---- ------ ----------------------- -----_.--- ---------- -------------- --- --- .-.--------- ------------------- ---- ---------------..-------------------_._---- ----'--'-------- \lOTES: 3-1/8" 5M CIW WELLHEA 0 - 11" FI'vC AClUA TOR = KB. 8...EV = 77.10' BF. 8...EV = 54.82' l/iJP = 1000' Angle = 52 @ 4634' I udtum tv[) = 8490' Datum 1\10= 6600' SS L-110 --f 1f!':\....". \iifJ 17-5/8" CSG, 29.7#, L-80, 10= 6.875" 2819' ST MD 4 4259 3 6969 2 8107 1 8226 Minimum 10 = 2.75" @ 2310' 3-1/2" HES SSSVN ( PERFORATION SUMMARY RE FLOG: ----- Af\K3LE ATTOP PERF: 11 @8467' I'bte: Refer to Production DB for historical perf data SIZE SPF INlERVAL Opn/Sqz DATE 2-1/2" 6 8467 - 8521 0 09115/01 8251' I 5-1/2" CSG, 15.5#, L-80, BTC, 10= 4.950" H 3-1/2" TBG, 9.2#, L-80, IBT-M, .0087 bpf, 10 = 2.992" 5-1/2"X 3-1/2" CSGXO,ID= 2.968" H ~ 8302' 8303' 8315' 8304' 8315' 8366' 8387' ~ 8428' 8821' 8893' 3-1/2" CSG, 9.2#, L-80, NSCT, 10 = 2.992" 8992' DATE REV BY CO tvfv1 EN T S DL\ lE REV BY COMIVENTS I "~/02/01 CI-VKAK ORGINAL COtvPLETION 15/01 JLIVVKK PERFS I ¿f30/02 DAC/KK GLV CORRECTIONS 04/08/03 DRS/lP TV [)IMD CORRECTIONS (, I SAF(' 1015' H7-5/8" TAM FORT COLLAR I 2310' 3-1/2" HES XDB BVN, 10= 2.75" GAS LIFT MANDRELS TVD DEV TYPE VL V LATCH PORT 3433 49 KBG-2 DOME B1M 16 5220 38 KBG-2 SO B1M 16 6219 14 KBG-2 DMY B1M 0 6335 8 KBG-2 DMY B1M 0 DATE 10/18/01 10/18/01 08102/01 08/02/01 -13-112" HES X NIP, 10 = 2.75" I I-iTOP OF BKR FBR, 10 = 4.00" I -13-112" BKRSEALASSY,ID=3.oo" -13-112" HESX NIP, 10 = 2.75" I -13-112" HES X NIP, 10 = 2.75" I -120' PUPJT WI RA TAG I -110' PUPJT WI RA TAG I BOREA LIS UNIT WELL: L-110 PERMIT No: 2011230 A F1 No: 50-029-23028-00 SEC 34, T12N; R11E 2365' NSL & 3772' WEL Exhibit VI-5 a BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,020.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 7,186.0 (ft) Casing (MD): 2,819.68 (ft) AFE No: 5M4022 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,380,000 Auth Depth: 9,099.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,386 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 180,961 DOLlDFSlTarget: 15.63/15.21/13.10 Liner (MD): Daily Well: 60,707 Geologist: Liner Top (MD): Cum. Well: 1,874,649 Engineer: Allen Sherritt Supervisor: Decker / Anthony ( Operator: BP EXPLORATION Well: L-110 Field: PRUDHOE BAY ~' Exhibit VI-5 b Report: 16 Date: 7/31/2001 Rig Accept: 13:30 7/15/2001 Rig Release: Spud Date: 7/15/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 30 Cost Ahead -200,000 USD, Days Ahead -4.0 Current Status: P/U 3 1/2" Seal Assy. & RIH 24hr Summary:Wiper trip to TD. POH & LID drill string. R/U & run prod csg. 24hr Forecast: R/U & run 3 1/2" production tubing. Run LOT & freeze protect Comments: No Accidents, No Incidents, & No Spills.. Weather = 35 Deg W/ wind E @ 3 mph. Days Since Last DAFWC: 985 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/29/2001 Next BOP Press. Test: 8/5/2001 Last Divertor Drill (D3): 7/16/2001 No. Stop Cards: Fire: 7/29/2001 ( LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 2,561.0 (ft) 13.70 (ppg) 412 (psi) 585 (psi) 10.60 (ppg) 26.3 (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: . . .. 4 CLEAN OUT Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND 18:00/PIT 9,020.0 (ft) (OF) 10.60 (ppg) 50 (s/qt) (ppg) 20 (cp) 26 (lb/100ft2) 7.6 ! ( Last Accum. Drill (D4): 7/20/2001 Last Spill Drill: 7/31/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/26/2001 Pump! Slow Pump Rates (Circ) 1 Slow Pump Rates (Choke) 1 ! Stroke Rate Pressure(psi): Stroke Rate Pressure(psi) ¡ I II . 28 I 508 . I 42 643 42 640 42 640 HSE & Well Control All Free Days: 15 Last Envir. Incident: 3/16/2001 1 1 2 2 0 erationaLParameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 97 (hr) Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) 10 sec gels: 10mingels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: Last Trip Drill (D1): Last Safety Meeting: 7/31/2001 7/31/2001 Non-compliance Issued: N Slow Pump Rates (Kill) Stroke Rate Pressure(psi) Pump Status - Drilling and Riser Pump ¡Type] Eff. Strokes Liner Size ¡tire. Rate ¡ I 0 0 0 i 0 I i I Description 40 (mg/L) (mg/L) (%) (%) 800 (mg/L) (%) 94.08 (ppb) 41.68 (ppb) /4.50 (mL/mL) : ES: ! Solids: Oil: Water: Oil/Water: . Daily Cuttings: I Cum. Cuttings: ! Lost Downhole: I Lost Surface: I (mV) 11.00 (%) 2.0 (%) 87.0 (%) / (bbl) (bbl) 41.0 (bbl) (bbl) Printed: 8/1/2001 6:14:32 AM Operator: BP EXPLORATION ( Well: L-11 0 Field: PRUDHOE BAY From-To Hrs Phase Task Activity hh:mm (hr) 00:00-01 :00 1.00 INT1 CASE BHALD 01 :00-02:30 1.50 INT1 CASE BHALD 02:30-08:30 6.00 INT1 CASE RUN 08:30-09:00 0.50 INT1 CASE RUN 09:00-13:00 4.00 INT1 CASE RUN 13:00-13:30 0.50 INT1 CASE CIR 13:30-19:00 : 5.50 INT1 . CASE I RUN 19:00-20:00 . 1.00 I INT1 i CASE CIR ! 20:00-21 :00 ¡ 1.00 I INT1 ¡CASE RUN , i I 21 :00-21 :30 . 0.50 i INT1 CASE RUN 21 :30-23:30 2.00 INT1 CASE i CIR 23:30-00:00 0.50 INT1 CASE CMT ( ~' BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT 0 erations Summa Code NPT Exhibit VI-5 b Report: 16 Date: 7/31/2001 Operation N DPRB N DPRB N DPRB P P P P P P P P P Con't - UD BHA. Clear floor, pull wear bushing, change out bails, & RIU to run csg. PJSM. RIU & re-run 3 1/2" production csg. Note - Cut shoe track & replace float equipment & centralizers Rig down 3 1/2" casing tools & rig up 5 1/2" casing tools. Con't RIH wi 5 1/2" 15.5#,L-80, BTC-M casing to 2880'. Rig up circulating head & circulate 150 % liner volume (4 1/2 BPM @ 373 psi). . . Con't RIH wi 5 1/2" casing to 8228'. Obstuction. Work pipe - no success. . P/U & M/U swedge & circulating line. Wash csg thru tight spot 8228' to 8298'. Pump rate = 3 BPM @ 680 psi & lost 10 Bbls mud. : Con't RIH w/5 1/2" casing to 8967'. M/U landing joint & land Hgr. in casing head. Production casing landed @ 8992'. R/U cement head & lines. Break circulation & circulate hole. Displace hole to 10.4 ppg mud. PJSM. Pump 5 Bbls & presure test pumps & lines to 4000 psi - OK. Pump 25 Bbl CW 100 & drop bottom plug. Pump 40 Bbl spacer (@ 111.20 ppg). ( 06:00 Update: Mix & pump cement job for 31/2" X 51/2" production casing. Full Ret Bumped plug & cmt in place @ 0200 hrs. Floats -OK RID cement svc's & UD landing joint. Set pack-off, RILDS, & pressure test - OK. Company BP AMOCO NABORS 4 AnchorinI Marine 5 6. i 7 Rig Heave: Rig Roll: Rig Pitch: No. I Hours 2 12.00 BAROID 24 12.00 No. Hours Company I 2 12.00 ANÄDRILI.. SCI-iLUMBERGËRI Anchor Tension Rig Heading: VOL: Swell Height: I Sea Height: Sea Dir.: Sea Period: Comments: ; i I - ! Riser Tension: Riser Angle/Dir.: Current: Current Direction: I Cumulative Phase Breakdown Planned Change of Scope Prod % Total NPt % Total: WOW % Total Prod % Total NPT % Total WOW % Total n11ioo 98.3% 2.00 1.7%' Phase SURF PRE INT1 TOTALS 103.50 69.9% 220.50 82.6% 44.50 30.1 % 46.50 17.4% ( 0.00 I 0.0%- Total, Hours I I 119.00 ¡ 0.00 ~ I 148.00 I 267.00 ¡ 0.00 Total Cost USD 0.0% 0.00 0.0% 0.00 0.00 0.0% Printed: 8/1/2001 6:14:32 AM BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,020.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 7,186.0 (ft) Casing (MD): 2,819.68 (ft) AFE No: 5M4022 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,380,000 Auth Depth: 9,099.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 182,101 DOUDFS/Target: 16.63/16.21/13.10 Liner (MD): Daily Well: 452,823 Geologist: Liner Top (MD): Cum. Well: 2,327,472 Engineer: Allen Sherritt Supervisor: Decker / Anthony ~' ( Operator: BP EXPLORATION Well: L-110 Field: PRUDHOE BAY f Exhibit VI-5 b Report: 17 Date: 8/1/2001 Rig Accept: 13: 30 7/15/2001 Rig Release: Spud Date: 7/15/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 30 Cost Ahead -150,000 USD, Days Ahead -4.0 . Slow Pump Rates (Choke)! Slow Pump Rates (Kill) ! Stroke Rate PressureO! Stroke Rate PressureO Can't - 3 1/2" X5 1/2" production casing cement job. Pump 25 Bbls CW 100, drop bottom plug, pump 40 Bbls Mud Push (@ 11.20 ppg), 109 Bbls liteCRETE cement (@ 12.0 ppg as per program), Drop top plug, swithch to rig pump & displace cement with 203 Bbls filtered sea ; water. Bump plug & pressure to 2850 psi. Plug down & cement in ! place @ 0200 Hrs. Bleed pressure & check float equipment - OK. : Rig down cement head, flush stack, break out & lay down landing :joint. Current Status: N/D BOPE 24hr Summary: Complete long string cement job. Run 3.5" Tbg 24hr Forecast: Land Tbg, test N/D - N/U tree, test Freeze protect RDMO Comments: No Accidents, No Incidents, & No Spills.. Weather = 35 Deg W/ wind E @ 3 mph. Days Since Last DAFWC: 986 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/29/2001 Next BOP Press. Test: 8/5/2001 Last Divertor Drill (D3): 7/16/2001 No. Stop Cards: Fire: HSE & Well Control All Free Days: 16 Last Envir. Incident: 3/16/2001 ( LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 8/1/2001 I I Last Accum. Drill (D4): 7/20/2001 Last Spill Drill: 7/31/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/26/2001 Pump: Slow Pump Rates (Circ) ! Stroke Rate PressureO I 2,561.0 (ft) 13.70 (ppg) 412 (psi) 585 (psi) (ppg) (bbl) 0 erationaLParameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 97 (hr) DriliinFluid (lb/100ft2) , Ca: (lb/100ft2) I K+: (cc/30min)! CaCI2: (OF) . NaCI: (cc/30min); CI-: (/32") , Sand: I (ppb) ¡ HGS: (ppb) I LGS: (mL) ! Pf/Mf: Ann. Vel. Riser: (ftlmin) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND 16:00/PIT 9,020.0 (ft) (OF) 8.60 (ppg) 28 (s/qt) (ppg) (cp) (lb/100ft2) 10 sec gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: 0 erations Summa Code: NPT From-To Hrs Phase II Task I hh:mm : (hr) 00:00-02:00 I 2.00 INT1 I CASE i I CMT P ( 02:00-03:00 : 1.00 CASE INT1 RD P Last Trip Drill (D1): Last Safety Meeting: 7/31/2001 8/1/2001 Non-compliance Issued: N I Pump Status - Drilling and Riser i Pump IType! Eff. Strokes~Liner Size I Circ. Rate :1 I ! 0 0 0 0 I I , I I I I I (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) / (mUmL) : ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (bbl) (bbl) 30.0 (bbl) (bbl) Operation Printed: 8/2/2001 6:19:56 AM ( Operator: BP EXPLORATION Well: L-110 Field: PRUDHOE BAY From-To Hrs Phase Task Activity hh:mm (hr) 03:00-04:00 1.00 INT1 CASE NU 04:00-05:30 1.50 COMP RUNCO RU 05:30-14:00 8.50 COMP RUNCO RUN 14:00-15:00 1.00 COMP CASE PRESS 15:00-21 :00 6.00 COMP 'RUNCO RUN I I 21 :00-22:30 1.50 COMP RUNCol¡ I I I ! 22:30-00:00 1.50 COMP ¡RUNCO CIR ( ¡" i BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summa Code NPT Exhibit VI-5 b Report: 17 Date: 8/1/2001 Operation P PJSM. Rig up & set pack-off. RILDS & torque to 450 ftllbs. FMC . pressure test ot 4000 psi - OK. Rig down FMC svc's. Clear floor & rig up 3 1/2" tbg equipment. Make up dummy run with tubing hanger. PJSM. Run 190Jts. 3 1/2' 9.2#, L-80, IBT-Mod tubing. P P P Test 5.5" X 3.5" Prod. Csg to 4000 psi for 30 minutes - OK. PJSM wI Cameo. Simultaneous Operations: 1. RIU Cameo dual control line reels, sheaves and eguipment. Hook contollines to SSSV and test to 5000 psi.Cont. RIH wI Tbg. "2. Perform LOT on 7 5/8" X 5 1/2" annulus with 10.4 ppg. mud. I Leak off pressure = 492 psi = 14.09 ppg EMW. Established injectivity: 1 BPM @ 850 psi. initial; down to 567 psi after pumping 3 Bbls. , 2 BPM @ 800 psi and 3 BPM @ 880 psi. Pumped 38 bbls 10.4 mud and 10 bbls seawater to clear lines. Hooked up Hot Oil and pumped 33 I bbls dead crude down annulus. Pumped at 1.5 Bpm. Initial pressure 1800 psi. Final pressure 1250 psi Bleed pressure, RD Hot Oil. Con't RIH wI 3 1/2" tbg. Space out 3 1/2' tbg. Operation Inc @ : midnight. , P/U 2 extra jts tbg. M/U circulating head, break circulation & sting into PBR. Shut down pumps immediately after seeing pressure increase. Con't RIH to No Go & mark tbg. - - POH & lay down excess tbg. PIU required pups & tbg hanger. Pressure test control lines to 5,000 - OK. M/U circulating head & landing joint on tbg hanger. P P P 06:00 Update: Space out 3 1/2" production tubing. Reverse circulate corr inhibitor. Land tubing. Pressure test Tubing & Casing to 4000 psi for 30 min. Shear RP.Pull Ldg. jt. Inst TWC & test N/D BOPE Anchor Tension , " , Rig Heading: VDL: Swell Height: I -- " Sea Height: Sea Dir.: Sea Period: Comments: tion , Item Units : Usage" On Hand i No'1 Hours" "Company I No. : 21 12.00 ANADRILL SCHLUMBERGER i 2 I i I Rig Heave: Rig Roll: Rig Pitch: 12 I , Riser Tension: Riser Angle/Dir.: Current: Current Direction: I Cumulative Phase Breakdown Change of Scope % Total Prod % Total: NPT % Total WOW % Total I I Prod % Total 117.00 98.3% Planned NÞ~, % Total[ WOW 2.00 1.7%1 I 44.50 29.3% i Total Hours 119.00 0.00 152.00 . 20.00 291.00 0.00 Phase SURF PRE INT1 COMP TOTALS 107.50 70.7% 20.00 100.0% , , , , 244.50 84.0% 46.50 16.0% ( Total Cost USD 0.00 0.0%: I I 0.0%, 0.0% 0.0% 0.00 0.00 0.00 Printed: 8/2/2001 6:1956 AM BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,020.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,186.0 (ft) Casing (MD): 8,991.45 (ft) AFE No: 5M4022 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,380,000 Auth Depth: 9,099.0 (ft) Next Casing (MD): (ft) Daily Mud: Hole Size: Next Casing (TVD): (ft) Cum. Mud: DOUDFSfTarget: 17.33/16.91/13.10 Liner (MD): Daily Well: Geologist: Liner Top (MD): Cum. Well: Engineer: Allen Sherritt Supervisor: Decker I Anthony ( Operator: BP EXPLORATION Well: L-110 Field: PRUDHOE BAY ( ( 182,101 190,093 2,517,565 Rig Accept: 13:307/15/2001 Rig Release: Spud Date: 7/15/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Exhibit VI-5 b Report: 18 Date: 8/2/2001 Program: Tot. Personnel: 30 Cost Ahead -137,600 USD, Days Ahead -4.5 Current Status: Mobilize Nabors Rig 9 ES to L-114 24hr Summary: Lnd tbg & PT tbg & csg. NID BOP stack, N/U X-mas tree, rei rig. 24hr Forecast: Comments: One Accident ( non-recordable, first aid only - see Remarks), No Incidents, & No Spills.. Weather = 35 Deg WI wind NW @ 9 mph. Days Since Last DAFWC: 987 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/29/2001 Next BOP Press. Test: 8/512001 Last Divertor Drill (03): 7/16/2001 No. Stop Cards: Fire: 8/212001 ( LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 2,561.0 (ft) 13.70 (ppg) 412 (psi) 585 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. oft Bottom: Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND 14:30/PIT 9,020.0 (ft) (OF) 8.60 (ppg) 28 (s/qt) (ppg) (cp) (lb/100ft2) HSE & Well Control All Free Days: 17 Last Envir. Incident: 3/16/2001 Last Trip Drill (01): Last Safety Meeting: Last Accum. Drill (D4): 7/20/2001 Last Spill Drill: 7/31/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/26/2001 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Non-compliance Issued: N 7/31/2001 8/2/2001 ! Slow Pump Rates (Choke) I Slow Pump Rates (Kill) Stroke Rate PressureO Stroke Rate PressureO 0 erationalParameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Pump Status - Drilling and Riser Pump ¡Type I' Eft. I Strokes Liner Size Circ. Rate I I 0; 0 0 0 I . I i Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ftImin) Ann. Vel. DP: (ftImin) 10 sec gels: 10 min gels: . Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) I (mUmL) From-To Hrs ¡Phase: Task ¡ Activity hh:mm I (hr) : ; ! 00:00-01 :00 . 1.00 I COMP IRUNCO: LANDTH ] I ES: Solids: Oil: Water: OillWater: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: Operation (bbl) (bbl) (bbl) (bbl) I 01 :00-02:00 1.00 1 COMP IRUNCo! LANDTH I ! : : I I 02:00-03:00' 1.00 1 COMP [RUNCO: LANDTH : I I 03:00-05:00 2.00! COMPRUNCO: LANDTH i I , . . Con't - Land 3 1/2" tbg & verify spaceout. (string wt = 106 k up & 76 k ¡ dn) , ¡ Pick up above PBR & reverse circulate corr inhibitor (3 BPM @ 480 ¡psi). , Land tubing & RILDS. Check control line pressure - OK. ( P P P P ! Pressure test surface equipment to 4000 psi - OK. Pressure test 3 : 1/2" tbg to 4,000 for 30 min - OK. Bleed tbg pressure to 2,000 psi. Printed: 8/3/2001 6:09:36 AM ~ ( Operator: BP EXPLORATION Well: L-110 Field: PRUDHOE BAY From-To Hrs Phase Task Activity hh:mm (hr) 03:00-05:00 2.00 COMP RUNCO LANDTH 05:00-06:00 1.00 COMP RUNCO ND 06:00-07:00 1.00 COMP RUNCO ND 07:00-11 :00 4.00 COMP' WHSU NU 11 :00-12:30 1.50 COMP. WHSU PRESS 12:30-13:30 1.00; COMP WHSU PLUG P ! 13:30-15:00 I 1.50 ¡ COMP [RUNCO FREEZE i P ! i I 1 15:00-16:00.1.00 COMP WHSU PRESS P I ! 16:00-17:0011.00 COMP WHSU RD P 06:00 Update: ( Company BP AMOCO NABORS Anchor I Tension, Rig Heading: VDL: Swell Height: 3 I I Sea Height: Sea Dir.: Sea Period: Comments: ~. BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summa Code NPT Exhibit VI-5 b Report: 18 Date: 8/2/2001 Operation P Pressure test anulus to 4,000 psi for 30 min- OK. Bleed down tbg pressure & shear RP @ 2900 psi. Note - all pressure's & times charted & chart is on file. Back out landing joint. install TWC & pressure test from below to 2800 psi-OK. . Rig down Camco svc's. Blow down all surface lines & drain BOP stack. Nipple down BOP stack & adaptor flange. Nipple up adaptor & production X-mas tree. Rig up FMC svc's. Install SBMS & control lines. Pressure test adaptor flange & control lines to 5,000 for 15 min - OK. Fill production X-mas ! tree with diesel. ; Rig up DSM & recover TWC. P P P P Rig up circulating lines on casing & tubing valves. Rig up Little Red services, pressue test pumps & lines to 3,000 psi - OK. Pump freeze . protect into annulus (45 bbls), shut valve & allow diesel to U-tube into tubing. Install BPV & pressure test same to 1,000 psi - OK. Rig down DSM. ! Secure productiorÏX-mas tree & cellar area. Release rig to move to I L-114 @ 1700 Hrs 8/02/2001. Units Usage! On Hand No. I Hours Company ¡ 21 12.00 ANADRILL SCHLUMBERGER i I I I Rig Heave: Rig Roll: Rig Pitch: i I i i I Riser Tension: Riser Angle/Dir.: Current: Current Direction: 11 12 / Cumulative Phase Breakdown Change of Scope % Total Prod' % Total I NPT o/~total ¡ WOW 1 I I 1 0.00 o.oJ 0.00 Phase SURF PRE INT1 COMP TOTALS . Prod"... %t~tall 117.00 98.3% I i 107.50 70.7%1 37.00 100.0% . ~. .. . 261.50 84.9% Planned NPT %Total] WOW 2.00 1.7%1 i 44.50 29.3% I Total 1 Hours I 119.00 I 0.00: 152.00 : I 37.00¡ 308.00 I 46.50 15.1%! ( .. . % Total 0.00 0.0% i ! i I 0.0%1 0.00 0.0% 0.00 Printed: 8/3/2001 6:09:36 AM ~ "-,,, "-"'. Exhibit VI-6: L-114 Well Integrity Report Original Completion Date: 9/13/2001 Schrader Bluff Penetration Hole Diameter: 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift ~, Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 239 sacks (571 ft3) of cement. Floats held and the plug bumped with 2100 psi. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2342'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 763'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-6 a Drilling Daily Reports (Cementing) - Exhibit VI-6 b -" lREE= ( ------------ ----- -------- - ------------------ - ------- -------- - --- - --------------- 3-1/8" 5M crw WELLHEAD = 11" FM: AC1UA TOR= KB- B..EV = 76.3' BF. B..EV = 49.4' "'ìP= 1591' . Angle = 55 @ 4052' ,....atum tv[) = 7780' D3tum lV 0 = 6600' SS 7-5/8" CSG, 29.7#, L-80, 10 = 6.875" 2637' Minimum ID = 2.75" @ 2193' 3-112" HES SSSVN ( PERFORATION SUMrv\A. RY REF LOG: ---------- ANGLEATTOP ÆRF: 15 @ 7704' I\bte: Refer to R-oductbn œ for historical perf data SIZE SPF INTERV AL Opn/Sqz DATE 2-1/2" 6 7704 - 7750 0 09113/01 1 5-1/2"CSG,15.5#,L-80, BTC, 10= 4.950" 1 13-112" TBG, 9.2#, L-80, IBT-M, .0087 bpf, 10 = 2.992" 1 15-1/2" X 3-1/2" CSG XC, 10 = 2.968" l-i 7425' 7431' 7438' 1 FBTO 1 8158' 13-1/2" CSG, 9.2#, L-80, NSCT, 10 = 2.992" 1 8253' -_.- ------- ------------------------------------------ L-114 I SAFE-rt J TES: e ~ ~ 981' 2193' ST MO 4 3695 3 6246 2 7234 1 7353 7379' 7425' 7442' 7489' 7509' 7551' 8146' DATE REV BY CO rvtv1 E NT S DAlE REV BY CO rvtv1 ENTS . "'17/01 CHIKAK ORIGINAL COMPLETION 13/01 CWS/KK ÆRFS 12.130102 OAC'KK GL V CORREC1l0NS 04/08/03 ORSlTP lV D'MO CORREC1l0NS 05/15/03 JCM'TLH GL V C/O 05/28/03 MH'TLP GL V C/O ( H7-5/8" TAM PORT COLLAR I -13-1/2" HES XOB BVN, 10 = 2.75" I GAS LlFf rv\A.NORELS lVO ŒV 1YÆ VLV LATCH FORT 3423 49 KBG-2 OOrvE BL 16 5226 37 KBG-2 SO BL 20 6084 24 KBG-2 OMY BL 6194 21 KBG-2 OMY BL -i3-1/2" HES X NP, 10 = 2.75" I-iTOPOF BKR PBR, 10 = 4.00" I -13-1/2" BKR SEAL ASSY, () = 3.00" I -13-1/2" HES X NP, 10 = 2.75" -i3-1/2" HESXNP, 10=2.75" -i20' AJPJT WI RA TAG I -110' AJPJT WI RA TAG I DATE OS/28/03 05/14/03 08/17101 10/11/01 BOREA LIS UNIT WELL: L-114 PERrv1IT No: 2011360 A A No: 50-029-23032 SEC 34, T12N R111; 2346' NSL & 3844' WEL Exhibit VI-6 a (' BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 8,270.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,155.0 (ft) Casing (MD): 8,252.06 (ft) AFE No: 5M4026 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,500,000 Auth Depth: 8,268.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 137,614 DOUDFS/Target: 12.75/11.80/13.70 Liner (MD): Daily Well: 197,107 Geologist: F.Redella/D.Stearns Liner Top (MD): Cum. Well: 1,595,533 Engineer: Neil Magee Supervisor: Anglen / Morris Exhibit VI-6 b Operator: BP EXPLORATION Well: L-114 Field: PRUDHOE BAY Report: 14 Date: 8/15/2001 (, Rig Accept: 06:008/3/2001 Rig Release: Spud Date: 8/4/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Tot. Personnel: 37 Cost Ahead 225,000 USD, Days Ahead 2.00 Program: Current Status: Rih 3 1/2 completion @ 4750'. 24hr Summary: Lay dn bha, run 3 1/2 X 51/2 csg, cmt, begin 3 1/2 completion 24hr Forecast: Run completion, test, nipple dn. Comments: No Accidents, No Incidents, & No Spills.. Weather = 36 Deg W/ wind NE @ 6 mph. CF= 29 deg - Rain HSE & Well Control All Free Days: 3/16/2001 Days Since Last DAFWC: 1000 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 8/12/2001 Next BOP Press. Test: 8/13/2001 Last Divertor Drill (03): 8/4/2001 No. Stop Cards: Fire: 13 . . Last Envir. Incident: Last Trip Drill (01): Last Safety Meeting: 8/13/2001 8/12/2001 Last Spill Drill: 8/15/2001 Regulatory Agency Insp: N Kick While Drill (02): 8/11/2001 Pump' Slow Pump Rates (Circ) Stroke Rate PressureO Non-compliance Issued: N Pit: 8/6/2001 : Slow Pump Rates (Choke); Slow Pump Rates (Kill) I Stroke Rate PressureO I Stroke Rate PressureO I [ , I I i I I 8/12/2001 LOT TVD: 3,567.0 (ft) LOT EMW: 12.02 (ppg) MAASSP: 264 (psi) Test Pressure: 301 (psi) Kick Tolerance: (ppg) Kick Volume: (bbl) ( 0 erational Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 85 (hr) Pump Status - Drilling and Riser Pump Typei Eff. Strokes: Liner Size:Circ. Rate ; (%) (spm). (in) ,(gpm) I I 0 i 96 "5.500' 0 ! 96 : 5.500 ! I ' ! 1 2 Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) BHA . , - -. . . . . HOLE OPENER, BIT SUB, DRILL COLLAR, STRING STAB, 2 x DRILL COLLAR, HWDP, JAR, 20 x HWDP, Dtnlin Fluid 4 (lb/100ft2) Ca: 6 (lb/100ft2) K+: 3.0 (cc/30min) CaCI2: 200 (OF) NaCI: 6.8 (cc/30min) CI-: 1 (/32") Sand: 17.50 (ppb) HGS: (ppb) LGS: 0.20 (mL) Pf/Mf: Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: 10 sec gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: 20 (mg/L) (mg/L) (%) (%) 300 (mg/L) 0.10 (%) 82.32 (ppb) 44.77 (ppb) 0.20/4.0 (mUmL) ES: I Solids: ¡Oil: : Water: , Oil/Water: : Daily Cuttings: I Cum. Cuttings: ~ Lost Downhole: , Lost Surface: I I (mV) 10.50 (%) (%) (%) / (bbl) (bbl) (bbl) (bbl) (ft) (OF) 10.40 (ppg) 46 (s/qt) (ppg) 13 (cp) 18 (lb/100ft2) 9.1 ( Printed: 8/16/2001 5:56:32 AM '~l BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT 0 erations Summa Code NPT ~l Exhibit VI-6 b { Operator: BP EXPLORATION Well: L-114 Field: PRUDHOE BAY Report: 14 Date: 8/15/2001 From-To Hrs Phase Task hh:mm (hr) 00:00-00:30 0.50 PROD1 CASE Activity Operation PTOH P Cont lay dn bha, clear rig floor. , , I I': . I 19:00-20:00 i 1.òoi PROD1: CASE 'I , I : 20:00-22:30 ' 2.50 PROD1 CASE I PRESS , , , 1 I i 22:30-00:00 ! 1.50 . CaMP !RUNCoj CMPSTG : I I 1 06:00 Update: Rih 3 1/2 comp assy. 150 its tbg in hole CMT P Flow check, pull wear bshng, make dummy run csg hgr, record spaceout. Lay dn hgr /Idng it. Flow check, commence run 5 1/2 X 3 1/2 csg as per program. Float check, fill all its, circ at 7 5/8 shoe. Csg = 31/2,9.2#, IBT, L80 51/2, 15.5#, BTC M, L80 Circ with hgr landed. Can not recip csg. Note 100% returns. Circ 5 bpm @ 1100 psi. Make up cmt hd, test lines, commence cmt csg as follows: Pump 10 bbl CW 100, test lines 4000 psi, pump addtnl1 0 bbls CW 100. DRop btm plug, pump 40 bbls Mud Push XL 11.2 ppg. Pump 102 bbls 12 ppg Lite Crete slurry @ 5 bpm. Drop top plug, flush , lines 10 bbls H2o. Displace with rig pumps 183 bbls sea water. 2629 ,strokes. Bump plug 2 bpm at 2100 psi and holding. : Final circ press 1700 psi. 2 bpm. Plug bumped at 1900 hrs. i Bleed press, floats holding. rig dn all related cmt equip. Release cmt unit. Install packoff / test to 4000 psi /15 min. Will not hold press. Pull, re-run, re-test. Test successful. 00:30-02:00 1.50 PROD1 CASE RUN P " . 02:00-15:00 13.00 PROO1 CASE RUN P 15:00-16:30 1.50 PROD1 CASE CIR P 16:30-19:00 2.50PROD1 CASE CMT P P P Flow test, PJSM, rig up and rih 3 1/2 comp string as per program. Comp assy = seal assy, GLMs, X nipples, 3 1/2, 9.2#, L80, IBT ( Item On Hand No. Hours .. . .. 24 12.00 21 12.00 Anchor Tension Rig Heading: VOL: Swell Height: ! I I . , Sea Height: Sea Dir.: Sea Period: I Rig Heave: Rig Roll: Rig Pitch: I I I . [ Riser Tension: Riser Angle/Dir.: Current: Current Direction: / Comments: Phase PRE SURF PROD1 COMP . . . .. . TOTALS Prod % Total 33.00 100.0% 21.50 100.0% 39.50 84.9% 1.50 100.0% . . 95.50 93.2% Cumulative Phase Breakdown Change of Scope WOW % Total Prod % Total] NPT % Total WOW % Total I I 0.00 Total: Total Cost Hours i USD 33.00: 21.501 46.501 1.50; 102.50 I 0.00 7.00 15.1% 7.00 6.8% 0.00 0.0% 0.00 0.0% . Remarks 0.00 i 0.0%1 0.0% ( Printed: 8/16/2001 5:56:32 AM BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 8,270.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,155.0 (ft) Casing (MD): 8,252.06 (ft) AFE No: 5M4026 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,500,000 Auth Depth: 8,268.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 138,754 DOUDFSfTarget: 13.75/12.80/13.70 Liner (MD): Daily Well: 204,871 Geologist: Liner Top (MD): Cum. Well: 1,811,670 Engineer: Neil Magee Supervisor: Anglen / Morris ( Operator: BP EXPLORATION Well: L-114 Field: PRUDHOE BAY ( (' Exhibit VI-6 b Report: 15 Date: 8/16/2001 Rig Accept: 06:008/3/2001 Rig Release: Spud Date: 8/4/2001 Elev Ref: SEA LEVEL KB Elev: 77.10 (ft) Program: Tot. Personnel: 37 Cost Ahead 150,000 USD, Days Ahead 2.00 Current Status: Freeze protecting well 24hr Summary: Rih tbg, LOT, test csg, rih, Ind tbg, test, NU tree, test, frz protect 24hr Forecast: Freeze protect, set BPV, release rig, move L-107 Comments: No Accidents, No Incidents, & No Spills.. Weather = 34 Deg W/ wind NE @ 11 mph. CF= 23 deg HSE & Well Control All Free Days: 3/16/2001 Days Since Last DAFWC: 1001 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 8/12/2001 Next BOP Press. Test: 8/13/2001 Last Divertor Drill (D3): 8/4/2001 No. Stop Cards: Fire: 8/15/2001 ( LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 3,567.0 (ft) 12.02 (ppg) 264 (psi) 301 (psi) (ppg) (bbl) Rap Daily: Rap Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: Type: Time/Loc: Depth: Temp: Density: Funnel Vise.: ECD: PV: YP: pH: (ft) (OF) 8.80 (ppg) 28 (s/qt) (ppg) (cp) (lb/100W) 9.1 ( From-To I Hrs ; Phase I Task hh:mm ! (hr): . I , 00:00-04:00 i 4.00 : CaMP tRuNCal r I , i I 04:00-05:00 1.00: CaMP tRUNCal : : I 05:00-07:00 2.00: CaMP [RUNCo! I I I : ! , ' I I , I , : 07:00-09:00 I 2.00 : CaMP HUNCO! , ¡ : I , ! Last Envir. Incident: Last Spill Drill: 8/15/2001 Regulatory Agency Insp: N Kick While Drill (D2): 8/11/2001 Pump Slow Pump Rates (Circ) Stroke Rate PressureO 14 Last Trip Drill (D1): Last Safety Meeting: 8/13/2001 8/12/2001 Non-compliance Issued: N Pit: 8/6/2001 Slow Pump Rates (Choke) Slow Pump Rates (Kill) Stroke Rate PressureO Stroke Rate PressureO Operations Summa Code I NPT I , I I I Cont rih 31/2 tbg to 2700 ft. Receive cmt compressive strengh test 'I results. Perform LOT 5 1/2 X 7 5/8 annulus. Results = 12.02 EMW, 301 psi, I 3800 ft. I Resume rih 3 1/2 tbg. while bullhead 67 bbls1 0.4 mud dn 15 1/2 X 7 5/8 annulus. Inj rate = 127 gpm @ 770 psi 1 Follow with 34 bs dead crude. Identical injection rate. Place Control line equip on floor, rig up same, test lines 5000 psi. 0 erational Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 85 (hr) Ddllin (lb/100W) (lb/100W) (cc/30min) (OF) (cc/30min) 1 (/32") (ppb) (ppb) (mL) Ann. Vel. Riser: (ftImin) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ftImin) 10 sec gels: ! 10 min gels: I Fluid Loss: : HTHP Temp: : HTHP WL: I Cake: MBT: Lime: PM: Activity CMPSTG I I P LOT P CMPSTG ¡ P SSSV P 'I Pump Status - Drilling and Riser Pump IType! Eff. !Strokes Liner Size tire. Rate I . I (%) (spm) , . (in) (gpm) 1 I D 96 5.500 2 D I 96 5.500 I (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) / (mUmL) ES: Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (bbl) (bbl) (bbl) (bbl) Operation Printed: 8/17/2001 5:47:24 AM From-To Hrs Phase Task Activity hh:mm (hr) 09:00-09:30 0.50 COMP RUNCO TSTPRS 09:30-13:30 4.00 COMP RUNCO CMPSTG 13:30-16:00 2.50 COMP RUNCO CMPSTG BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT 0 erations Summa Code NPT ( Exhibit VI-6 b ( Operator: BP EXPLORATION Well: L-114 Field: PRUDHOE BAY Report: 15 Date: 8/1612001 Operation P Test csg to 4000 psi / 30 min. test good. P Resume rih 3 1/2 tbg. Slow going with control lines. P Circ 20 spm while stab into PBR. Note 200 psi press increase. Stop pump and bleed. Note 10.5 ft seal stab in. Space out, record measurements, make up pups / tbg hgr. Attach control lines, test to 5000 psi. 16:00-17:00 1.00 COMP RUNCO SSSV P 17:00-19:30 2.50 COMP RUNCO CMPSTG P 19:30-21 :00 1.50 COMP ¡RUNCO TSTPRS P Take up / dn wts, Up 100, Dn 90. Reverse circ btms up, displace annulus with inhibited seawater. . Land tbg, lock down hgr. Test tbg to 4000 psi / 30 min. Bleed tbg to 2000 psi. Test 3 1/2 X 5 1/2 annulus to 4000 psi /30 min. , Bleed tbg slowly, RP shears at 2700 differential. 21 :00-22:30 ! 1.50 I COMP ¡RUNCO' TSTPRS i P Install TWC, test below check to 2800 psi. Bleed all pressures. All tests successful. No re-rest. : Prepare and nipple dn bope. Set back bop. i 1 22:30-00:00 1.50: COMP ¡RUNCO]: , 1 I I i 06:00 Update: Install control lines, nipple up tree, test, pull two way check, freeze protect well ND P BP BAROID BP Item Units I Usage I Hou rs 12.00 12.00 ( No. 2 2 1 Anchor Tension Rig Heading: VDL: Swell Height: i I 1 i Sea Height: Sea Dir.: Sea Period: 4 Rig Heave: Rig Roll: Rig Pitch: i 1 1 I Riser Tension: Riser Angle/Dir.: Current: Current Direction: / Comments: Phase PRE SURF PROD1 COMP TOTALS . . Prod % Total . ... . 33.00 100.0% 21.50 100.0% 39.50 84.9% 25.50 100.0% 119.50 94.5%: C umulâtiveP h aseBreakdown . . .. Change of Scope WOW % Total Prod % Total NPT % Total WOW % Total Total Hours 33.00 21.50 46.50, 25.501 I 126,50 ! 0.00 7.00 15.1% 7.00 5.5% 0.00 . ! 0.0% 0.00 0.0% ! Remarks 0.00 0.0% 0.00 0.0% ( Printed 8/17/2001 5:47:24 AM ,,-"" ,.-., .-..~ Exhibit VI- 7: L-116 Well Integrity Report Original Completion Date: 9/14/2001 Schrader Bluff Penetration Hole Diameter: 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift '-'" Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 217 sacks (516 ft3) of cement. Floats held and the plug bumped with 3200 psi. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2494'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 1067'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-7 a Drilling Daily Reports (Cementing) - Exhibit VI-7 b "-', ------------------------- ----.----------- -----,----- '------ TREE = 3-1/8"5MCIW WELLHEAD = 11" FMC ACfUA TOR = KB- ELEV = BF. ELEV = It L-116 SAFE~' OTES: '0 = 76.7' 52.5' 1218' 25 @ 2431' 6884' 6600' SS --1 Angle = Datum MD = DatumTVD = 1014' H7-5/8" TAM PORT COLLAR I @ 2208' 3-1/2" HES XDB BVN,ID = 2.75" 7-5/8"CSG,29.7#, L-80, ID=6.875" I 2653' Minimum 10 = 2.75" @ 2208' 3-1/2" HES SSSVN ST MD 4 3640 3 5491 2 6224 1 6342 GAS LIFT MA I'DRELS TVD DEV TYÆ VLV LATQ1 PORT 3425 17 KBG-2 DOME INT 16 5215 12 KBG-2 DOME INT 16 5941 5 KBG-2 DMY INT 0 6059 5 KBG-2 SO INT 24 DATE 01/29/02 04/17/03 07/16/01 04/17/03 PERFORAllON SUMMARY REF LOG: ---- ANGLE AT TOP PERF: 4 @ 6675' Note: Refer to Production œ for historical perf data SIZE SPF INTERVAL OpnlSqz DAlE 2-1/2" 6 6675 - 6720 0 09/14/01 2-1/2" 6 6734 - 6740 0 09114/01 ( 3-1/2"TBG, 9.2#, L-80, IBT-M, .0087 bpf, 10 =2.992" 1 I 5-1/2" CSG, 15.5#, L-80, BTC, ID = 4.950" I 15-1/2" X 3-112" CSG XO, ID = 2.968" 1-1 6419' 6421' 6368' -13-112" HESX NIP, ID =2.75" I 6433' ~ 6422' 6432' I-ITOPOF BKR FBR, 10= 4.00" I -i3-1/2" BKR SEAL ASSY, ID= 3.00" I 6662' 1-120' PUP JT WI RA TAG 6981' l-i 10' PUP JT WI RA TA G I I PBTD I 7062' 13-1/2" CSG, 9.2#, L-80, NSCT, D = 2.992" I 7172' 1 DA TE REV BY COMrvENTS DATE REV BY CO tvfv1 E NT S -'/16/01 CH/KAK ORIGNA L COMR...EllON 14/01 ONSiKK PERFS 11/17101 GC/KAK PERF CORRECTON 12/30/02 DAC'KK GLV CORRECTIONS 04108103 DRSlTP TVD/IvD CORRECTIONS 04/17/03 JCMfTLH GLV UPDATE BOREALIS UNIT WI3...L: L-116 ÆRMT I\b: 2011160 API I\b: 50-029-23025 SEC 34, T12N, R11 E, 2372' NSL & 3743' WEL Exhibit VI-7 a BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: Current Well Status Depth MD: 7,190.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 6,983.0 (ft) Casing (MD): 2,652.77 (ft) AFE No: 5M4028 Progress: (ft) Next Casing Size: (in) AFE Cost: 2.426,000 Auth Depth: 7,209.0 (ft) Next Casing (MD): (ft) Daily Mud: 14,522 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 156.437 DOUDFSfTarget: 13.33/12.66/12.70 Liner (MD): 7,172.65 (ft) Daily Well: 377,650 Geologist: Liner Top (MD): (ft) Cum. Well: 1,813,209 Engineer: Neil Magee Supervisor: Decker / Morris ( Operator: BP EXPLORATION Well: L-116 Field: PRUDHOE BAY Days Since Last DAFWC: 968 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/6/2001 Next BOP Press. Test: 7/13/2001 Last Divertor Drill (03): 7/3/2001 No. Stop Cards: 3 Fire: 7/14/2001 Well Kill (05): 6/12/2001 ( \ LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 2,583.0 (ft) 15.46 (ppg) 625 (psi) 813 (psi) 10.80 (ppg) 36.9 (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. oft Bottom: ( Pump Type: Time/Lac: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND i 10 sec gels: 11 :OO/PIT 10 min gels: 7,190.0 (ft) Fluid Loss: 68 (OF) HTHP Temp: 10.60 (ppg) HTHP WL: 45 (s/qt) Cake: (ppg) I MBT: 11 (cp) . Lime: 18 (lb/1 00ft2) ~ PM: 9.0 : ( I I ' I ... , .. I 03:00-12:00 I 9.00 I COMP CEMT I I I I, ! Activity RUN CIR ( Exhibit VI-7 b Report: 14 Date: 7/14/2001 Rig Accept: 10:297/1/2001 Rig Release: Spud Date: 7/1/2001 Elev Ref: SEA LEVEL KB Elev: 76.70 (ft) Program: Tot. Personnel: 30 Cost Ahead 25,000 USD, Days Ahead -1.00 13 Last Envir. Incident: Last Accum. Drill (04): 7/6/2001 Last Spill Drill: 7/14/2001 Regulatory Agency Insp: N Kick While Drill (02): 7/8/2001 Last Trip Drill (01): Last Safety Meeting: 7/14/2001 7/14/2001 Current Status: Rih 3 1/2 tbg, 24hr Summary: Ru 5 1/2 csg, circ, cmt, set / test pkf, rih 3 1/2 prod string. 24hr Forecast: Rih 3 1/2 tbg, Ind hgr, test, nipple dn bope. Comments: No Accidents*No Incidents*No Spills Temp: 37 deg. Wind: 14 mph NE CF: 20 deg. HSE & Well Control All Free Days: 3/16/2001 Non-compliance Issued: N Stripping: 7/7/2001 Slow Pump Rates (Circ) i Slow Pump Rates (Choke) Stroke Rate PressureO I Stroke Rate PressureO 0 erationalParameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ft/min) Slow Pump Rates (Kill) Stroke Rate PressureO Pump Status - Drilling and Riser Pump :Typei Eft. Strôkesl Liner Size Cire. Rate : ! (%) (spm) ¡ (in) (gpm) 1 I 0 ¡ 96 5.500 . 2 0: 96 5.500 i ! i 20 (mg/L) (mg/L) (%) (%) 300 (mg/L) 0.10 (%) 101.43 (ppb) 36.95 (ppb) 0.05/0.3 (mUmL) 0 I Code: Rotating Weight: Pick Up Wt.: Slack Oft Wt.: Cire. Rate Riser: Cire. Rate Hole: Circ. Oft Bottom: Circ. On Bottom: Jar Hrs since Inspect: 146 (hr) DriUinFluid 6 (lb/100ft2) I Ca: 8 (lb/100ft2) : K+: 3.5 (cc/30min) i CaCI2: 200 (OF) NaCI: 9.5 (ce/30min) CI-: 1 (/32") Sand: 10.00 (ppb) ¡ HGS: (ppb) i LGS: 0.10 (mL) : Pf/Mf: : ES: . Solids: Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: I Lost Surface: (bbl) (bbl) (bbl) (bbl) (mV) 11.00 (%) 1.0 (%) 88.0 (%) 1 Operation ¡Run 3.5" X 5.5" Production String. 22 Jts 3.5': & 156 Jts 5.5". Shoe set at 7172'. Plug receptacle at 7064'. Top of PBR @ 6422'. Attempted circ. 1 Jt. prior to landing. Rèciprocating pipe. No returns ,for 1 st 95 bbls pumped then partial rtns with losses of 80 bbls/Hr. ; i improving steadily to 20 bbls 1 Hr. by 08:30. Adding Barofibre and I thinning mud. Mud thinned and wt at 10.7 ppg with 5 Ib / bbl barofibre ¡at 12:00 Hrs. Losses < 12 bbl / Hr. P P Printed: 7/15/2001 6:0920 AM ( BP EXPLORATION Daily Operations Report R~: NABORS9ES Event: DRILL +COMPLETE Well Type: Operations Summa Code NPT (' Exhibit VI-7 b ( Operator: BP EXPLORATION Well: L-116 Field: PRUDHOE BAY Report: 14 Date: 7/14/2001 From-To Hrs Phase Task hh:mm (hr) 12:00-14:30 2.50 COMP CEMT Activity Operation CMT P R/U Dowell Pump 5 bbl CW100. Test lines to 4000 psi. Pump 5 bbls CW100 followed by 50 bbls 11.3 ppg. Mud Push XL Spacer. Drop wiper dart and pump 90 bbls 12.0 ppg LiteCrete Cement. Drop Plug dart and displace with 159 bbls filtered seawater. Bump plug with 3200 psi. Hold for 5 min, bleed off & check floats - OK. RD Cmt equip. & Landing jt. M/U packoff running tool and install Packoff. RILDS. LID running tool. Test Packoff to 5000 psi. Clear rig floor, rig up, make ready to run comp assy. 14:30-16:30 2.00 PROD1 WHSU PRESS P 16:30-17:30 1.00 COMP RUNCO RTIH P 17:30-22:30 5.00 COMP RUNCO RTIH P , 1.00 : COMP ¡RUNCO 22:30-23:30' RTIH P ! I 23:30-00:00 0.50 COMP ¡RUNCO: RTIH P i PJSM, MU seal assy / shoe, rih same, follow with 3 1/2, 9.3#, . L80 BTC-M, prod tbg. . Place Cameo control line equip on rig floor, prepare test csg. PJSM, test lines for csg test. 06:00 Update: Test csg to 4000 psi, LOT 5 1/2 X 7 5/8 Annulus, inject mud / crude oil for freeze protection, install sssv, rih 3 1/2 tbg Formation S Lithology SHALE Mud Lo i Form. Top MD. I (ppm) i Trip Gas (ppm) I Pore. Press (ppm) (ppg) ¡ Units :GAL i On Hand I ( DIESEL Company . . . BP AMOCO NABORS Hours 21 12.00 BAROID 241 12.00 I No. ,Hours Company I No. Hours 2112.00 ANÂDRILL SCHLUIV1BERGER: 2 12.00 ~ I 11 12 Anchor Tension Rig Heading: VDL: Swell Height: 3 4 Anchorin IMarine 5 . 6 7 I I I Sea Height: Sea Dir.: Sea Period: I Rig Heave: Rig Roll: Rig Pitch: Riser Tension: Riser Angle/Dir.: Current: Current Direction:' / Comments: Phase PRE SURF PROD1 COMP TOTALS Cum u lative PhaseB reakd own Planned Change of Scope Prod % Total NPT % Total WOW % Total Prod % Total i NPT % Total ¡ I I I I WOW % Total 40.00 56.3% 31.00 43.7% 172.00 95.8% 7.50 4.2% I 39.50 100.0%. 251.50 86.7%: 0.0% 0.00 Total Hours 0.00 71.00 179.50 39.50 290.00 0.00 0.0% Window Top: (ft) Mud Sys Ftg: (ft) Window Desc: CTOD: CTID: CT Strength: (psi) CT Length: (ft) ( Printed: 7/15/2001 6:09:20 AM BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: Current Well Status DepthMD: 7,190.0(ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 6,983.0 (ft) Casing (MD): 2,652.77 (ft) AFE No: 5M4028 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,426,000 Auth Depth: 7,209.0 (ft) Next Casing (MD): (ft) Daily Mud: 1,140 Hole Size: Next Casing (TVD): (ft) Cum. Mud: 157,577 DOUDFS/Target: 14.33/13.66/12.70 Liner (MD): 7,172.65(ft) Daily Well: 210,390 Geologist: Liner Top (MD): (ft) Cum. Well: 2,023,599 Engineer: Neil Magee Supervisor: Decker I Morris ( Operator: BP EXPLORATION Well: L-116 Field: PRUDHOE BAY Days Since Last DAFWC: 969 Last Csg Test Press.: 4,000 (psi) Last BOP Press. Test: 7/6/2001 Next BOP Press. Test: 7/13/2001 Last Divertor Drill (D3): 7/3/2001 No. Stop Cards: Fire: Well Kill (D5): 7/14/2001 6/12/2001 , I ( LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 2,583.0 (ft) 15.46 (ppg) 625 (psi) 813 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: T orq. off Bottom: Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: (ft) (OF) (ppg) (s/qt) (ppg) (cp) (lb/100ft2) ( From-To! Hrs . Phase i Task I hh:mm '(hr): i I 00:00-01 :00 1.00' COMP !RUNCO 01:00-02:00 , 1.00 : COMP ¡RUNCo! , ' I ¡'I I 02:00-03:30 : 1.50 'COMP IRUNCdl I , I I ' , , I . I ' I i , " f Exhibit VI- 7 b Report: 15 Date: 7/15/2001 Rig Accept: 10:297/1/2001 Rig Release: Spud Date: 7/1/2001 Elev Ref: SEA LEVEL KB Elev: 76.70 (ft) Program: Tot. Personnel: 30 Cost Ahead 0 USD, Days Ahead -2.00 14 Last Envir. Incident: Last Accum. Drill (D4): 7/6/2001 Last Spill Drill: 7/15/2001 Regulatory Agency Insp: N Kick While Drill (D2): 7/812001 Pump Slow Pump Rates (Circ) Stroke Rate PressureO Slow Pump Rates (Choke): Slow Pump Rates (Kill) Stroke Rate PressureO! Stroke Rate PressureO I I ! 0 erationalParal11eters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ft/min) Ann. Vel. DP: (ftlmin) 10 see gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: erations Summa NPT Last Trip Drill (D1): Last Safety Meeting: 7/14/2001 7/15/2001 Current Status: Moving to L-11 0 24hr Summary:Test csg, LOT, inject, rih tbg, land, test, nd bop, nu tree, test. 24hr Forecast: Freeze protect, set bpv, test, release rig, move to L-11 0 Comments: No Accidents*No Incidents*No Spills Temp: 44 deg. Wind: 10 mph NE CF: 20 deg. HSE & Well Control All Free Days: 3/16/2001 Non-compliance Issued: N Stripping: 7/712001 Pump Status - Drilling and Riser Pump Typei Eff. ¡Strokes Liner Size: Circ. Rate (%) I (spm) (in) ¡ (gpm) I I, D 96! 5.500 I D 96 i 5.500 I I I 1 2 (mg/L) (mg/L) (%) (%) (mg/L) (%) (ppb) (ppb) I (mUmL) : ES: : Solids: ! Oil: Water: Oil/Water: Daily Cuttings: Cum. Cuttings: Lost Downhole: Lost Surface: (bbl) (bbl) (bbJ) (bbl) TSTPRS P : Test 5 1/2 X 3 1/2 tbg I csg to 4000 psi I 30 min. Test successful. Operation TSTPRS P LOT P : Manifold in hot oil I kill line, test same to 3000 psi, in preparation for LOT. I Perform LOT dn 5 1/2 X 7 5/8 annulus. 1 bpm, 5 stroke intervals. , Leak off press at 404 psi ( EMW 13.61 ). Test interval 2652 - 3770 ft ( TOC ). Hold press, bleed to 264 psi and holding. Printed: 7/16/2001 6:10:39AM \{ BP EXPLORATION Daily Operations Report Rig: NABORS 9ES Event: DRILL +COMPLETE Well Type: 0 erations Summa Code NPT ( Exhibit VI-7 b (' Operator: BP EXPLORATION Well: L-116 Field: PRUDHOE BAY Report: 15 Date: 7/15/2001 From-To Hrs Phase Task hh:mm (hr) 02:00-03:30 1.50 COMP RUNCO Activity Operation LOT P Cont inject 47 bbls 10.6 ppg mud, follow with 33 bbls hot oil. 650 psi - 3 bpm. Rig dn injection equip. Release unit. Mu sssv, test control lines to 5000 psi 03:30-04:00 0.50 COMP RUNCO MUSLIN P 04:00-09:00 5.00 COMP RUNCO RUN P Cont rih 3 1/2 tbg, installing control lines. 09:00-14:00 5.00 COMP RUNCO RUN P Sting in to pbr with slow pump, note sting in with press build. Space out for tg hgr, make up pups, connect control lines to hgr, test lines to 5000 psi. Test successful. Verify space out. Reverse circ Corexit 3 bpm at 440 psi. 14:00-15:00 1.00 COMP RUNCO CIRREV P 15:00-16:00 1.00 COMP RUNCO LANDTH P : 2.50 I COMP ¡RUNCO 16:00-18:30. TSTPRS P I Land tbg hgr, run in Ids. Rig up for test. 18:30-20:30 WHSU ND P I I 20:30-00:00 WHSUi NU P I iTest tbg 4000 psi /30 min., bleed to 2000 psi. Test 31/2 X 51/2 annulus to 4000 psi /30 min. Bleed tbg and shear RP at 2900 psi. : differential. Set TWC, test below check to 2800 psi. All tests : successful. No re-tests. ! Nipple dn bope. : Connect control lines to ports, nipple up tree, test control lines, , all hgr / tree seals to 5000 psi. Test succesful. 06:00 Update: Complete tree test, freeze protect, set bpv, release rig, begin move to L-110 ( Formation S Lithology SHALE MudLo Form. Top MD. (ppm) ¡ Trip Gas (ppm) Pore. Press Item Units (ppm) (ppg) DIESEL Company BP AMOCO NABORS No. ! Hours Company I No. 21 12.00 ANADRILL SCHLUMBERGER 2 Anchor Tension Rig Heading: VDL: Swell Height: I Sea Height: Sea Dir.: Sea Period: . I Rig Heave: Rig Roll: Rig Pitch: 8 9 I . ! Riser Tension: Riser Angle/Dir.: Current: Current Direction: / Comments: Phase PRE SURF PROD1 COMP TOTALS Prod % Total Cumulative Phase Breakdown Change of Scope WOW % Total Prod % Total i NPT % Total. WOW % Total i Total Cost USD 38.50 12.3% 0.00 0.0% 0.00 0.0%: 0.00 0.0%: 0.00 Total Hours I 0.00 71.00 179.50 63.50 314.00; 0.00 40.00 56.3% 172.00 95.8% 63.50 100.0% 275.50 87.7% 31.00 43.7% 7.50 4.2% 0.0% ( Printed: 7/16/2001 6:10:39 AM .----. ~, .--." Exhibit VI-8: L-120 Well Integrity Report Original Completion Date: 3/17/2002 Schrader Bluff Penetration Hole Diameter: 6-3/4" Schrader Bluff Penetration Casing Diameter: 5-1/2" Well Status as of 8/2003: Oil Producer Gas Lift -~- Cement Logs Across Schrader Bluff: None Comments: The 5-1/2" primary cement job consisted of 327 sacks (579 ft3) of cement. Cement returns to surface were noted during the 5-1/2" cement job and the casing tested to 2500 psi for 10 minutes. The 5-1/2" cement job was designed to cover the Schrader Bluff sands. With a gauge hole, 2177'MD of cement is calculated to be above the top of the Schrader Bluff Na sand. Calculations using 30% excess hole size indicate 589'MD of cement above the top of the Na sand. Additional Information: Well Diagram - Exhibit VI-8 a Drilling Daily Reports (Cementing) - Exhibit VI-8 b '-'. -------------- -------- ----------------------.-. 1REE = 3-1/8" 5M crw (" WELLHEA 0 = 11" Ftv'C ACnJA TOR = NA. KB. ELEV = 79.10' BF. B...EV = 55.40' }(np= 950' ( A.ngle = 55 @ 4615' ,--"urn rvÐ = 8994' caturn lV 0 = 6600' SS 7-5/8" CSG, 29.7#, L-80, 10 = 6.875" 3042' Minimum 10 = 2.812" @ 2220' 3-1/2" CAMCO SSSVN PERFORAllON SUMMARY REF LOG: ANGLE AT TOP PERF: 8 @ 8870' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DA1E 2-1/2" 6 8870 - 8904 0 03117/02 2-1/2" 6 8914 - 8920 0 03/17/02 ( 13-112" TBG, 9.2#, L-80, IBT-M, .0087 bpf, 10= 2.992" 1 1 5-1/2" CSG, 15.5#, L-80, BTC, D = 4.950" 1 14-3/4" X 3-1/2" CSG XO, 10 = 3.000" H 8656' 8657' 8675' FBTD 9358' 13-1/2" CSG, 9.2#, L-80, 10 = 2.992" 1-1 9459' ( ----- . ------ --------- ------------------ ')TES: L-120 41',. ~ I I ~ -i' 986' 2220' ST rvÐ 3 4444 2 7394 1 8577 8633' ~ SAFE"J( 1'l7-5/8" TAM PORT COLLAR I 3-1/2" CAMCO BP-6i SSSVN, D = 2.812" GAS LFT rvtA.NDRELS TVD DEV lYPE VLV LATCH FORT 3417 54 KBG2-9 DOME BTM 16 5217 47 KBG2-9 DOME BTM 16 6190 17 KBG2-9 S/O BTM 20 DATE 03124/02 03124/02 03124/02 DA1E REV BY C 0 fvfv EN 1$ DATE REV BY COMNENTS , "')/15/02 ORlGINA. L COMPLETON )2/02 CH/TP CORRECllONS v,j/17/02 CWS/tlh A 00 ÆRF 03/24/02 JB/KAK GLV CHANGEOUT 04/08/03 DRS/TP TVD/rvÐ CORRECTIONS -13-112" BKR CMD SLIDING SLV, 10 = 2.813" I 8656' 8658' 8674' 8695' BKR LOC SEAL ASSY, 10 = 2.990" TOP OF BKR PBR, 10 = 4.00" B1M OF 3-1/2" BKRSEAL ASSY, D = 2.990" 8716' -3-1/2" HES X NIP, 10 = 2.813" I -3-1/2" HES X NIP, 10= 2.813" I 8790' - 16' PUP JT WI RA TAG I 9215' 1--115' PUP JT WI RA TA G I BOREAL IS UNrr WELL: L-120 PERMT f\b: 2020060 API f\b: 50-029-23064-00 SEC 34, T12N, R11E 2608' NSL & 3545' WB... Exhibit VI-8 a BP EXPLORATION Daily Operations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,474.0 (ft) Casing Size: 7.625 (in.) Costs in: USD Est. TVD: 7,157.0 (ft) Casing (MD): 3,042.1 (ft) AFE No: 5M4032 Progress: (ft) Next Casing Size: 5.500 (in) AFE Cost: 2,826,000 Auth Depth: 9,526.0 (ft) Next Casing (MD): 9,474.0 (ft) Daily Mud: Hole Size: Next Casing (TVD):7,157.0 (ft) Cum. Mud: DOUDFSlTarget: 14.50/13.75/18.90 Liner (MD): Daily Well: Geologist: Liner Top (MD): Cum. Well: Engineer: ODENTHAL Supervisor: MASKELL ( Operator: BP EXPLORATION Well: L-120 Field: PRUDHOE BAY Days Since Last DAFWC: 1182 Last Csg Test Press.: (psi) Last BOP Press. Test: 2/12/2002 Next BOP Press. Test: 2/19/2002 No. Stop Cards: Fire: 2/12/2002 ( LOT TVD: LOT EMW: MAASSP: Test Pressure: Kick Tolerance: Kick Volume: 2,658.0 (ft) 13.81 (ppg) 485 (psi) 623 (psi) (ppg) (bbl) ROP Daily: ROP Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: No Type Weight '6 HOLE OPENIN Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: LSND 21 :OO/SUC 9,474.0 (ft) (OF) 10.30 (ppg) 42 (s/qt) (ppg) 15 (cp) 15 (lb/100ft2) 8.9 ( \, ,( 10 sec gels: : 10 min gels: Fluid Loss: I , HTHP Temp: : HTHP WL: . Cake: I : MBT I . Lime: PM: 146,266 66,051 1,946,068 ( Exhibit VI-8 b Report: 15 Date: 2/13/2002 Rig Accept: 17:001/30/2002 Rig Release: Spud Date: 1/31/2002 Elev Ref: SEA LEVEL KB Elev: 79.10 (ft) Program: Tot. Personnel: 28 Cost Ahead 225,000 USD, Days Ahead 3.00 14 Last Trip Drill (01): Last Safety Meeting: 2/12/2002 2/13/2002 Current Status: 24hr Summary: Fin cleanout run. RU & run 3.5/5.5" casing. 24hr Forecast: Finish run casing. Cement same. Freeze prot OA. Run tubing. Comments: No Incidents. No Injuries. No Spills. WX: Temp: -15 Deg. Wind: 14 mph E. CF: -44 Deg. Daily mud cost = $8017. Cum Cost = $150,480. HSE & Well Control All Free Days: Last Envir. Incident: 3/16/2001 Last Abandonment Drill: 1/28/2002 Last Accum. Drill (04): 2/12/2002 Last Spill Drill: 2/13/2002 Regulatory Agency Insp: N Kick While Drill (02): 2/8/2002 Pump Slow Pump Rates (Circ) : Stroke Rate PressureO Non-compliance Issued: N ; Slow Pump Rates (Choke): Slow Pump Rates (Kill) Stroke Rate PressureO ¡ Stroke Rate PressureO I I " I I Operational parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 46 (hr) " " BHA " Wt Below I Depth Out i Description Jar (ft) I i 9,474.() HoLEÓÞENER,FLOATSÛI3, DFÜLLCOLLAR, NM STABILIZER, DRILL COLLAR, XO, I ! 3 x HWDP, JAR, 18 x HWDP Drillinq Fluid 7 (lb/100ft2) Ca: 9 (lb/100ft2) K+: 3.0 (cc/30min) : CaCI2: 200 (OF) ¡ NaCI: 8.8 (cc/30min) I CI-: I 1 (/32") . Sand: 16.00 (ppb) : HGS: (ppb) : LGS: 0.15 (mL) . Pf/Mf: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ftlmin) Ann. Vel. DP: (ft/min) 92.77 22.51 0.05/0.4 " I Pump Status - Drilling and Riser Pump ¡Type' Eff. Strokes I Liner Size I Circ. Rate , I I 0 0 I 0 0 I I I 40 (mg/L) (mg/L) (%) (%) 400 (mg/L) (%) (ppb) (ppb) (mUmL) . ES: Solids: ; Oil: I Water: ¡ Oil/Water: , Daily Cuttings: ; Cum. Cuttings: I Lost Downhole: . Lost Surface: (mV) (%) 3.0 (%) 88.0 (%) / (bbl) (bbl) (bbl) (bbl) Printed: 2/14/2002 5:49:33 AM r BP EXPLORATION Daily Operations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT 0 erations Summa Code NPT ( Exhibit VI-8 b ( Operator: BP EXPLORATION Well: L-120 Field: PRUDHOE BAY Report: 15 Date: 2/13/2002 From-To Hrs Phase Task Activity hh:mm (hr) 00:00-02:00 2.00 PROD1 DRILL CIR 02:00-07:30 5.50 PROD1 DRILL PTOH Operation P Fin pump sweep around to clean hole. Spot liner running pill. Monitor well. POH for casing. POH for casing. Work tight spots 9100, 8975-8879, 8570-8500. Cont POH LDDP leaving 40 stands in derrick. Monitor well @ 7 5/8" shoe - OK. LD cleanout BHA. P 07:30-08:30 1.00 PROD1 DRILL BHALD P 08:30-09:00 0.50 CaMP CASE PUL P 09:00-10:30 1.50 CaMP CASE RU P 10:30-10:45 0.25' CaMP CASE. SAFETY P 10:45-16:00 5.25 .COMpiCASE. RUN P i . 16:00-16:30 : 0.50 ; CaMP : CASE ì crR P ¡ I ' 16:30-21 :30 . 5.00 COMP;CASE: RUN P I I I 21 :30-22:00 . 0.50 CaMP CASE' CIR P ... ... . I CaMP CASE I RUN P 22:00-00:00 . 2.00 I I Pull wear ring & make dummy run with casing hanger. RU to run 3.5" & 5.5" casing. . PJSM for running casing. , MU shoe track. Run 22 its 3.5" casing followed by 5.5" casing to 3040'. , Circ 1.5 csg vol to cond mud prior to run in OH. , Run casing to 6000'. ( 06:00 Update: Cont run casing. Circ at 8000'. Mud pretty thick (100+ FV) and fair amt of sand coming back. Stage up pumps to 4 bpm. Est lost 10-12 bbl. Cont circ to clean up hole & cond mud. Run casing to bottom. Mud Lo Form. Top MD. I I Break circ and clear 1.5x pipe vol to cond mud & break gels. ! Cont running casing. No losses to this point. Fill pipe every jt. Break ¡ circ every 10 joints while running. Company No. 1 2 Information I Bkgrnd Gas Conn. Gas Materials rConsum tion ¡ Usage; On Hand Item : 0: 5976 Person nel Hours ...... Company... . .. No.¡ Hours 12.00 PETROTECHNICAL RESOUR I Ö¡ BAROID 12.00 NABORS Crew 23] 12.00 Anchorin IMarine 5 I 6 7 I I (ppm) i Trip Gas (ppm) I Pore. Press Formation COLEVILLE Lithology (ppm) (ppg) DIESEL BP NABORS Supv Company ¡NO. ,Hours 2: 12.00 I I Anchor I Tension, Rig Heading: VDL: Swell Height: 3 4 8 9 10 11 12 Sea Height Sea Dir.: Sea Period: Rig Heave: Rig Roll: Rig Pitch: Riser Tension: Riser Angle/Dir.: Current Current Direction: / Comments: Phase SURF PRE PROD1 CaMP TOTALS Prod % Total 107.50 77.9% 5.00 100.0% 189.50 100.0%: 15.50 100.0%1 317.50 91.2%1 Cumulative Phase Breakdown Planned Change of Scope NPT %Total: WOW % Total Prod % Total NPT % Total ¡ WOW % Total 1.50 1.1%1 29.00 21.0% Total Cost USD 1.50 0.4%' 29.00 8.3% 0.00 I 0.0%1 0.00 I 0.0%: 0.00 Total Hours; . I 138.00 . 5.00: 189.50 : 15.50: 348.00 : 0.00 0.0% ( Printed: 2/14/2002 5:49:33 AM BP EXPLORATION Daily Operations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Current Well Status Depth MD: 9,474.0 (ft) Casing Size: 5.500 (in.) Costs in: USD Est. TVD: 7,157.0 (ft) Casing (MD): 9,459.2 (ft) AFE No: 5M4032 Progress: (ft) Next Casing Size: (in) AFE Cost: 2,826,000 Auth Depth: 9,526.0 (ft) Next Casing (MD): 9,474.0 (ft) Daily Mud: Hole Size: Next Casing (TVD): 7, 157.0 (ft) Cum. Mud: DOUDFS/Target: 15.50/14.75/18.90 Liner (MD): Daily Well: Geologist: Liner Top (MD): Cum. Well: Engineer: ODENTHAL Supervisor: MASKELL ( Operator: BP EXPLORATION Well: L-120 Field: PRUDHOE BAY Days Since Last DAFWC: 1183 Last Csg Test Press.: (psi) Last BOP Press. Test: 2/12/2002 Next BOP Press. Test: 2/19/2002 No. Stop Cards: Fire: 2/12/2002 ( LOT TVD: 2,658.0 (ft) LOT EMW: 13.74 (ppg) MAASSP: 475 (psi) Test Pressure: 475 (psi) Kick Tolerance: (ppg) Kick Volume: (bbl) .'. Rap Daily: Rap Cum.: WOB (min): WOB (max): RPM at Surface: RPM at Bottom: Torq. on Bottom: Torq. off Bottom: .. ". Type: Time/Loc: Depth: Temp: Density: Funnel Visc.: ECD: PV: YP: pH: SEA WATER 12:00/SUC 9,474.0 (ft) 100 (OF) 8.50 (ppg) 28 (s/qt) (ppg) 15 (cp) 15 (lb/100ft2) From-To: Hrs I Phase Task i hh:mm ; (hr) ! I 00:00-01 :30 1.50 I CaMP CASE; I I ! I 01 :30-03:30 2.00 I CaMP CASE I ( ¡ i 03:30-05:00 1.50: CaMP 1 CASE; : I , I ' ( 10 sec gels: 10 min gels: Fluid Loss: HTHP Temp: HTHP WL: Cake: MBT: Lime: PM: 146,266 229,916 2,175,474 f Exhibit VI-8 b Report: 16 Date: 2/14/2002 Rig Accept: 17:001/30/2002 Rig Release: Spud Date: 1/31/2002 Elev Ref: SEA LEVEL KB Elev: 79.10 (ft) Program: Tot. Personnel: 28 Cost Ahead 250,000 USD, Days Ahead 3.00 Last H2S Drill: Last Trip Drill (D1): Last Safety Meeting: 2/14/2002 2/14/2002 2/14/2002 Current Status: MU tubing hanger. 24hr Summary: Cmt casing - OK. Bump plug. Set packoff. Run Tubing. 24hr Forecast: Space out tbg. Circ clean SW. Land tbg. ND. NU. FP. ReI. Comments: No Incidents. No Injuries. No Spills. WX: Temp: -14 Deg. Wind: 11 mph E. CF: -40 Deg. Daily mud cost = $1657. Cum Cost = $152,137. HSE & Well Control All Free Days: 15 Last Envir. Incident: 3/16/2001 Last Abandonment Drill: 1/28/2002 Last Accum. Drill (04): 2/12/2002 Last Spill Drill: 2/13/2002 Regulatory Agency Insp: N Kick While Drill (02): 2/8/2002 Pump Slow Pump Rates (Circ) : Slow Pump Rates (Choke) Stroke Rate PressureO ~ Stroke Rate PressureO .. Rotating Weight: Pick Up Wt.: Slack Off Wt.: Circ. Rate Riser: Circ. Rate Hole: Circ. Off Bottom: Circ. On Bottom: Jar Hrs since Inspect: 46 (hr) ',' Drillinq Fluid 7 (lb/100W) Ca: 9 (lb/100ft2) K+: (cc/30min) CaCI2: 200 (OF) NaCI: (cc/30min) CI-: (/32") Sand: (ppb) HGS: (ppb) LGS: (mL) Pf/Mf: I I ! Operational Parameters Daily Bit Hrs: (hr) Daily Sliding Hrs:O.OO (hr) Cum. Bit Hrs: Ann. Vel. Riser: (ft/min) Ann. Vel. DC: (ftlmin) Ann. Vel. DP: (ftlmin) Non-compliance Issued: N Slow Pump Rates (Kill) Stroke Rate PressureO Pump Status - Drilling and Riser Pump ¡Type! Eff. Strokes Liner Size ¡Cire. Rate I i 0 0 O! 0 I (mg/L) (mg/L) (%) (%) 20,000 (mg/L) (%) (ppb) (ppb) / (mUmL) ES: Solids: Oil: Water: OillWater: Daily Cuttings: Cum. Cuttings: Lost Downhole: , Lost Surface: I (mV) (%) (%) 99.0 (%) / (bbl) (bbl) (bbl) (bbl) Activity Operations Summary Code I NPT Operation ¡ , I P I Continue running casing to 8000' - no problems, no losses. RUN CIR RUN I I Circ & cond mud. Stage pump slowly up to 4.5 BPM monitoring : losses. Lost approx 10 bbl mud while breaking circ slowly. Circ out ¡ barafiber and some sand plus viscous mud (100+ FV). ¡ Run casing to bottom. No further losses when RIH. MU casing hanger : and landing jt. Land casing with shoe at 9459' MD. P P Printed: 2/15/2002 6:42:35 AM ( Operator: BP EXPLORATION Well: L-120 Field: PRUDHOE BAY From-To Hrs Phase Task hh:mm (hr) 05:00-05:30 0.50 CaMP CEMT ( Activity BP EXPLORATION Daily Operations Report Rig: NABORS 9ES 9-ES Event: DRILL +COMPLETE Well Type: DEVELOPMENT Operations Summa Code NPT Report: 16 Date: 2/14/2002 Exhibit VI-8 b Operation RU P RU cement head and lines. Break circ and work pipe up to 240 klbs to break free. Reciprocate and circ at 180k up and 80k down. Circ at 4.5 BPM. . Circ and cond hole for cement. Stage pump up to 5.5 BPM while continue reciprocate pipe - OK. PJSM for cement job. BP, NAD, DS, Baroid, Peak. 05:30-06:45 1.25 CaMP CEMT CIR P 06:45-07:00 0.25 CaMP CEMT SAFETY P 07:00-08: 15 1.25 CaMP CEMT CIR P 08: 15-08:45 0.50 CaMP CEMT CMT P 08:45-09: 15 0.50 CaMP CEMT CMT P 09:15-09:30 0.25 CaMP CEMT CIR P ¡I. i 09:30-10:30 1.00.COMP:CEMT, : ' ( , I , 10:30-11 :00 . 0.50 CaMP iCEIV1T I 11 :00-12:00 : 1.001 CaMP iWHSU I . . I j 12:00-13:00 1.00 i CaMP [RUNCO: , , I 13:00-13:30 0.50 COMPRUNcol 13:30-23:00 9.50 CÒf\i1ÞjRUNCO I , 23:00-23:30 0.50 CaMP IRUNCO i i , 23:30-00:00 0.50 CaMP ¡RUNCo' I DISPL Cont circ 4.5-5 BPM and recip pipe while batch up spacer and tail . slurry. Pump 5 bbl CW100. Test lines to 4500 psi. Pump 20 bbl CW100 followed by 40 bbl Mudpush XL at 11.0 ppg. . Mix & pump 70 bbl LiteCrete lead slurry at 11.9 ppg 3 bpm 580 psi followed by 33 bbl Class G at 15.8 ppg - 3 bpm 500 psi. . SD pumping. Knock cap off cmt head. Install latched btm/top plug . combo in head and push down inside casing - OK. Replace cap- . Attempt to reciprocate up to 80% tensile for 5.5" casing - no success. Pipe appears differentially stuck. Full circ & no losses. Displace cement with seawater at 4.5-5 bpm: Lead slurry at shoe 1600 stks @ 705 psi, 5 bpm Tail slurry at shoe 2600 stks @ 1740 psi, 5 bpm. Final circ pressure at 3050 stks @ 1950 psi, 2 bpm. No losses noted during displacement. Bump plug with 2500 psi. CIP I at 10:20 hrs. Bleed off pressure. Floats holding - OK. I.. . . . .... ...... . ! RD cement head, lines. LD landing jt, elevators. P RD P SETOTR I .. ... . i Drain stack. Install packoff. RILDS. , I I Clear floor. RU to run tubing. I I I I Dummy run with tbg hanger on LJ to verify spaceout. . . . . MU seal assembly, sliding sleeve, i jt, #1 GLM with DCK-3 shear valve. Run 3 1/2" tubing. . . ... . ¡Install head pin. Test casing to 3500 psi - 10 min. Good test. P RU P RU P RUN P TSTFN P RU . ... . . . . RU control line spooling unit. attach control line to SSSVLN. Freeze protect OA - off critical path. See remarks for details. P 06:00 Update: Cont run tbg and control line. Get space out in to top of Baker casing seal receptacle. MU tubing hanger & control line. Formation COLEVILLE Lithology Item DIESEL Company BP NABORS Supv ( Mud La Form. Top MD. (ppm) Trip Gas (ppm) I Pore. Press I Units !GAL Units i N°'1 Hours Company O[ BAROID 231 12.00 Printed: 2/15/2002 6:42:35 AM bp I ~' , ( September 15, 2003 RECEtV'ED SEP 1 6 2003 ~aska Oil & Gas Cons. CommistkM1 Anchorage BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O, Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West ih Avenue, Suite 800 Anchorage, AK 99501 Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 RE: Orion Participating Area Application Orion Pool Rules and Area Injection Order Application Prudhoe Bay Unit Dear Dr. Myers and Chair Palin: BP Exploration (Alaska) Inc. (BPXA) is Operator of the Milne Point Unit (MPU) located immediately adjacent to, and northeast of, the proposed Orion Participating Area (OP A) and proposed Orion Pool Rules and Area Injection Order (OPR) within the Prudhoe Bay Unit (PBU). In this context, BPXA gives notice to the Department of Natural Resources and Alaska Oil and Gas Conservation Commission that MPU has no objection to the pending application of the PBU Owners to form the OP A and OPR. MPU has worked with PBU during the proposed OPA and OPR application processes and respectfully submits that these applications as proposed will not conflict with the MPU. Indeed, we believe the proposed OPA and OPR fully comply with 11 AAC 83.303, AS 31.05.080, and other applicable state statutes and regulations. Should you have any questions pertaining to MPU, please don't hesitate to contact Chris West at 564-4626. Best Regards, /~ ç;¡;: ß. ;Z ~ Edward D. laFehr MPU Asset Delivery Manager cc: M. Vela, Exxon Mobil Corp. K. Griffin, Forest Oil Corp. D. Kruse, CPAI G.M. Forsthoff, Chevron U.S.A. Inc. G. Gustafson, BPXA C. West, BPXA #1 I \ (' September 11 , 2003 Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Pre-read Materials Orion Participating Area/Pool Rules/Area Injection Order Pre-application Meeting Dear Dr. Myers and Chair Palin: Attached for your review are materials that will be presented on Tuesday September 16 at the Orion Participating Area/Pool Rules/Area Injection Order Pre-application Meeting. Any questions can be directed to Jonathan Williams at 564-5854 or Gary Gustafson at 564-5304. Best Regards, I ""1 fl.! 1l1j -j - J. /; ;I! Brian D. Huff GPB Polaris/Orion Subsurlace Team leader Cc: M. Vela, Exxon Mobil Corp. K. Griffin, Forest Oil Corp. D. Kruse, CPAI G.M. Forsthoff, Chevron U.S.A. Inc. G. Gustafson, BPXA """ -- ..--: ]