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CO 255
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. ~~_ Conservation Order Category Identifier Organizing RESCAN [] Color items: [] Grayscale items: [3 Poor Quality Originals: [] Other: NOTES: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plotter/scanner) [] Maps: [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other BY: MARIA Scanning Preparation TOTAL PAGES 0 (.-.~ (--~ Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: ,¢ (f~ (/2 PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ~ YES __ NO /s/ ,. Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES ~ NO (SCANNING IS COMPL~'~-HIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 Re: THE APPLICATION OF CONOCO, ) INC. to establish pool ) rules for and define ) the Schrader Bluff Oil ) Pool. ) Conservation Order No. 255 Kuparuk River Field Milne Point Unit Schrader Bluff Oil Pool July 2, 1990 IT APPEARING THAT: . Conoco, Inc., by correspondence dated April 5, 1990, requested the Alaska Oil and Gas Conservation Commission (hereinafter the Commission) to issue an order defining the Schrader Bluff Oil Pool and establish pool rules for same. · Notice of public hearing was published in the Anchorage Daily News April 24, 1990. · A public hearing was held in the Commission office at 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 a.m. May 31, 1990. · Members of the staff of Conoco, Inc. presented testimony on behalf of the Milne Point Unit working interest owners. ARCO Alaska, Inc. and BP Exploration (Alaska) Inc. presented written statements. The hearing record was closed at 11:00 a.m., May 31, 1990 upon conclusion of the hearing. FINDINGS: Hydrocarbons are trapped in Tertiary and Upper Cretaceous shallow marine sands beneath large portions of the Milne Point, Kuparuk River, and Prudhoe Bay Units. . Formal geologic nomenclature uses the term Schrader Bluff Formation to define the Upper Cretaceous sands. Formal nomenclature uses the terms Prince Creek and Sagavanirktok Formations to define the unconformably overlying Tertiary sands. · The stratigraphic section corresponding to the Schrader Bluff Formation may be defined by the Conoco Milne Point A-1 well. Conservation Or~er No. 255 July 2, 1990 Page 2 · · · · · · The structure of the Schrader Bluff Formation is a homocline that dips to the east-northeast, extending from southwest of the Kuparuk River Field to beyond the barrier islands, and having a structural relief ranging from approximately 2200 feet to 4800 feet subsea depth. The average temperature of the Schrader Bluff oil accumulation is 90°F at 4000 feet subsea depth. The geothermal gradient below 3000 feet subsea is 3°F per one hundred feet of depth. Tertiary sands occurring within the Prince Creek and Sagavanirktok Formations are unconsolidated and extremely friable in comparison to the moderately cemented sands found within the Cretaceous Schrader Bluff Formation. Oil gravities found in the Prince Creek and Sagavanirktok Formations range from 10-13°API whereas oil gravities in the Schrader Bluff Formation range from 14-19.5° AP1. In the Milne Point Unit the Schrader Bluff Formation is densely faulted. Five separate oil-water contacts have been documented within a continuous sand member of the Schrader Bluff Formation in the Milne Point Unit, indicating that faulting has divided the reservoir into separate pressure compartments. 10. Current seismic and well control does not allow identifi- cation of faults that may be pressure barriers. 11. Average hydrostatic pressure of the Schrader Bluff Formation is 1750 psig at 4000 feet subsea depth. 12. Average crude oil gravity found in the Schrader Bluff Formation is 17° AP1 with a bubble point pressure of 1388 psig, a solution gas/oil ratio of 191 SCF/STB, and a formation volume factor of 1.06 RB/STB. 13. The area proposed for development by the operator is covered by the Milne Point Unit and Unit Operating Agreements, which are the controlling instruments to assure protection of correlative rights. 14. Studies have indicated that a full scale waterflood project started within two years after initial production will increase ultimate recovery and will not preclude the use of other enhanced recovery procedures. 15· The operator states the development of the Schrader Bluff hydrocarbon accumulation is contingent upon surface Conservation Order No. 255 July 2, 1990 Page 3 16. commingling of produced fluids in existing Kuparuk River Oil Pool facilities with production from the Kuparuk River Oil Pool. The operator will utilize 2-phase test separators on each pad to measure production from individual wells of the Schrader Bluff Formation. A microwave absorption meter (Texaco's patented Microwave Watercut Monitor) will be used during well testing to determine percent of water and oil. Appropriate meters will be used for measuring fluid and gas volumes. CONCLUSIONS: i · The hydrocarbon accumulation in the Schrader Bluff Formation occurring within the boundary of the Milne Point Unit is appropriately named the Schrader Bluff Oil Pool. e The vertical limits of the Schrader Bluff Oil Pool may be defined in Milne Point well A-1 between the measured depths of 4174 feet and 4800 feet. · Hydrocarbon bearing formations overlying the Schrader Bluff Oil Pool are not suitable for development by methods applicable to the Schrader Bluff Oil Pool due to lithologic and oil property variations. · Establishment of pool rules for that portion of the Schrader Bluff Formation hydrocarbon accumulation occurring within the Milne Point Unit is appropriate due to depth, tempera- ture and oil property variations. · Ten-acre drilling units and "horizontal drilling" provide the necessary flexibility to efficiently drain the structurally complex Milne Point Unit portion of the Schrader Bluff hydrocarbon accumulation. · Surface commingling of produced fluids from the Schrader Bluff Oil Pool with produced fluids from the Kuparuk River Oil Pool in the Milne Point production facilities is appropriate for development of the Schrader Bluff Oil Pool. · Full-scale waterflooding of the Schrader Bluff Oil Pool is appropriate to increase ultimate recovery. · An exception to the gas-oil-ratio limit set forth in 20 AAC 25.240(b) is appropriate providing that full scale water- flooding of the Schrader Bluff Oil Pool commences within eighteen months following regular production. Conservation Order No. 255 July 2, ]990 Page 4 NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth apply to those lands within the Milne Point Unit portion of the Kuparuk River Field and is the area referred to in this order as the affected area, described as follows: Umiat Meridian T13N R9E Sections 13, 14, 23 and 24. T13N RI 0E Ail Sections T13N RllE Sections 5, 6, 7, 8, 15, 16, 17, 18, 19, 20, 21, 22, 29, 30, 31 and 32. Rule 1 Pool Designation and Definition The Schrader Bluff Oil Pool is defined as that accumulation of oil and gas within the Milne Point Unit, the affected area, and found within stratigraphic sections which correlate with the stratigraphic section occurring in the Conoco Inc Milne Point A-1 well between the measured depths of 4,174 and 4,800 feet. Rule 2 Well Spacing Nominal 10-acre drilling units are established for the pool within the affected area. Each drilling unit shall conform to a quarter-quarter-quarter governmental section as projected. The pool shall not be opened in any well closer than 300 feet to'the exterior boundary of the affected area. Rule 3 Horizontal/High Angle Completions A horizontal or high angle wellbore through the pool may be completed in one or more drilling units so long as the wellbore remains 300 feet from the exterior boundary of the affected area. Rule 4 Casing and Cementing Requirements To provide proper anchorage for the blowout prevention equipment, surface casing shall be set at least 500 feet below the base of the permafrost, and the annulus shall be filled with cement. To withstand anticipated internal pressure and the potential forces generated by thaw subsidence and freeze back, the casing shall meet normal design criteria and have minimum axial strain properties of 0.5% in tension and 0.7% in compression. Rule 5 Automatic Shut-in Equipment Ail wells which are producing hydrocarbons must be equipped with a failsafe automatic surface safety valve shut-in system able to Conservation Order No. 255 July 2, 1990 Page 5 simultaneously shut in the wellhead and shut in the artificial lift equipment if present. Rule 6 Common Production Facilities and Surface Commingling Production from the Schrader Bluff Oil Pool may be com- mingled on the surface with production from the Kuparuk River Oil Pool, Milne Point Unit, prior to custody transfer. b · Each producing well shall be tested at least twice a month for a minimum of six hours each test. This requirement will be for producing wells in the Schrader Bluff and Kuparuk River Oil Pools of the Milne Point Unit. C · The Commission may require more frequent or longer well tests if the summation of the calculated monthly production volume for both pools is not within 10% of the actual LACT metered volume. d · The operator shall provide the Commission with a Well Test and Allocation Report after six months of commingled regular production, and annually thereafter. The report will consist of a thorough analysis of all surveillance data relative to the well test system and the resulting allocation factors. Rule 7 Reservoir Pressure Monitoring Prior to regular production a pressure survey shall be taken on each well to determine reservoir pressure. 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 datum for all surveys is 4000 feet subsea. de Pressure survey means a static bottom-hole pressure survey of sufficient duration, pressure buildup test, multiple flow rate test, repeat formation tester, drill stem test, or pressure fall-off test. e · Data from pressure surveys required in this rule shall be filed with the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412, but must be made available to the Commission upon request. Conservation Order No. 255 July 2, 1990 Page 6 f · Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted in accordance with part (e) of this rule. Rule 8 Pool-wide Waterflood Pro~ect a , A waterflood project to maintain reservoir pressure must be implemented within eighteen months after regular production from the Schrader Bluff Oil Pool has started. b · A waterflood plan must be submitted to the Commission for approval at least three months prior to actual water injection in accordance with 20 AAC 25.402. Rule 9 Gas-Oil Ratio Exemption Wells producing from the Schrader Bluff Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 10 Administrative Action On its own motion or upon written request, the Commission may administratively amend this order so long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. DONE at Anchorage, Alaska and dated July 2, 1990. V Chatker'td-nT~ ~aska Oil and Gas Conservation Commission ~~ .... ~~~~e C Smith, Commissioner \%k' ='" ~ f a 0 i 1 an d G as C o ns e r v a t i o n C o mm ism i o n Dali ~ -W J~.~n,'--Commz-i'ssioner Alaska Oil ~as Conservation Commission 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Re: The application of Conoco ) Inc. for a public hearin9 to ) present testimony in order to ) establish pool rules for the ) development of the Schrader ) Bluff Oil Pool in the Milne ) Point Unit. ) ) PUBLIC HEARING BEFORE THE COMMISSION APPEARANCES: AOGCC: C. V. (CHAT) CHATTERTON, CHAIRMAN LONNIE SMITH, MEMBER DAVE JOHNSTON, MEMBER OTHERS PRESENT: RICHARD L. STEWART, UNOCAL R. L. SKILLERN, BP EXPLORATION RANDAL M. BRUSH, ARCO ALASKA DANIEL G. RODGERS, ARCO ALASKA JIM SCHERR, M.M.S. PAUL BARON, BP EXPLORATION MARK MYERS, DNR TOM (WRITING ILLEGIBLE) JAN MACDONALD, BP EXPLORATION. FRANK MILLE, M.M.S BOB CRANDALL, AOGCC RUSS DOUGLASS, AOGCC MICHAEL KOTOWSKI, ADNR AL HASTINGS, CONOCO STEVE DAVIES, CONOCO STEVE ROSSBERG, CONOCO MAY 31, 1990 9:00 A.M. 3001 Porcupine Drive Anchorage, Alaska RECEIVED R & R COURT REPORTERS 8 ! 0 N STREET, SUITE 10 I 509 W. 3RD AVert U E 277-0572 - 277-0573 277-8543 ANChORAGe, ALASKA 99501 JUN 1 B 1990 Alaska Oil & Gas Cons. Commissiol Anchorage 1007 W. 3RD AVENUE 272-75 l 5 l0 l! 12 14 16 17 19 20 2! 22 23 24 25 PROCEEDINGS MR. CHATTERTON: Our location here is in the conference room of the Alaska Oil and Gas Conservation Commission at 3001 Porcupine Drive, Anchorage, Alaska. The time approximates 9:0?. The -- this hearing will be conducted in -- in accordance with regulation 20 AAC 25.540(c), and complying with that, why, Lonnie, may I ask you to read into the record why we're here? MR. SMITH: Yeah. My name is Lonnie SMith. Notice of public hearing, reference the application of Conoco Inc. for a public hearing to present testimony in order to establish pool rules for the development of the Schrader Bluff Oil Pool in the Milne Point Unit. "Notice is hereby given that Conoco Inc. has petitioned the Alaska Oil and Gas Conservation Commission to issue a conservation order setting forth pool rules for the development of the Schrader Bluff Oil Pool in the Milne Point Unit. "The hearing will be held at 9:00 a.m. May the 31st~ 1990, at the Commission offices, 3001 Porcupine Drive, Anchorage, Alaska. all interested persons and parties are invited to give testimony." Lonnie Smith, Commissioner. Published in the Anchorage Daily NeWs April the 24th, 1990. MR. CHATTERTON: And the date, of course, today is May the 31st, 1990. R & R COURT REPORTERS 81ON STREET, SUITE lO! 509W. 3RDAVENUE 277~O572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 007 W. 3RD AVENUE 272-7515 10 l! 12 16 17 2O 2! 22 23 24 25 Those wishing to testify, that know that wish to testify in this matter that's before us, why, if -- if they would stand and be sworn in, why we could do it a little bit faster. So who -- who plans to testify? AL HASTINGS STEVE DAVIES STEVE ROSSBERG having first been duly sworn under oath by Commissioner Smith, testified before the Commission: MR. SMITH: Thank you. Sit down. MR. CHATTERTON: The general procedure here is that we have the applicant present his testimony, and then if there are any questions that you do not wish to have -- testify on, why, you could write them down on a piece of paper and submit them to the Commission, and if we believe that those questions are germane to the matter at hand, why we shall cross examine -- or -- or ask those questions of those testifying. And without further adieu, why, Conoco, Al, proceed. MR. HASTINGS: director ..... MR. CHATTERTON: Okay. I'm A1 Hastings. I'm the Oh, excuse me. Let me interrupt. I think it would be appropriate if I introduced the people at the head table. To the far -- my -- my far left is Meredith -- Meredith Downing. She's with R & R Court Reporters, and will be recording these proceedings. As you already have R & R COURT REPORTERS 8iON STREEt, SUITE 10! 509W. 3RDaVENUE 277-0572 - 277-0573 277~8543 ANCHORAGE, ALASKA 995OI 1007 W. 3RD AVENUE 272-75 ! 5 10 12 13 14 16 17 19 20 21 22 23 24 25 found out, why, next to me on my left is Commissioner Lonnie Smith. To my right is Dave Johnston, Commissioner. And I am Chat Chatterton, Chairman of the -- a commissioner. Now, excuse me for interrupting, Al, but go ahead. MR. HASTINGS: Thank you. I'm A1 Hastings. I'm the Director of External Affairs for Conoco's Anchorage Division. I'm also a registered professional engineer in petroleum engineering. The purpose of this testimony is to provide support for the establishment of pool rules for the Milne Point Unit Upper Cretaceous resource. Conoco has prepared testimony in behalf of the majority working interest owners in the Milne Point Unit. It is requested that the new pool be named the Schrader Bluff Pool, and the vertical limits of this proposed -- proposed pool are from 4174 to 4800 feet measured vertical depth in well number A- l. The scope of this testimony includes a discussion of the geological and reservoir properties as they are currently understood, as well as Conoco's proposed plans for reservoir surveillance, well planning, facilities installation and project scheduling. This testimony will enable the commission to establish rules which will allow economical development of resources within the Schrader Bluff Pool. Confidential data and interpretation concerning the Schrader Bluff formation will also be furnished to the Commission as additional support for this testimony. R & R COURT REPORTERS 810 N STREET, SUITE 10! 509W. 3RDAVENUE 277~O572 - 277-0573 277-8543 ANCHORAGE, aLASKA 9950! 007 W. 3RD AVENUE 272-7515 10 l! 12 16 17 19 20 2! 22 23 24 25 5 Development drilling, roads, pipelines and facilities installation have commenced in early 1990, and initial production is scheduled to begin by year end. Conoco requests the Commission to approve several key concepts which are considered essential for the economic development of the Schrader Bluff Pool. These concepts are: Waterflood initiation within 18 months after primary production is commenced. Well spacing of 20 acres to allow flexibility in placement of wells for maximum recovery of reserves. Waiver of the gas/oil ratio limitation in 20 AAC 25.24(b) -- 240(b) for a period of time not exceeding 18 months from the date of initial sustained production. Should the gas/oil ratio increase above the current regulatory limits, the intent of this waiver is to allow for a period of primary production prior to waterflooding. Number four, surface commingling of production from the Schrader Bluff Pool and the Kuparuk River Pool. This testimony is intended to provide the Commission with sufficient information to formulate these rulings. At this point Steve Davies will discuss the geologic portion. MR. CHATTERTON: And do you wish to be recognized as an expert ..... MR. DAVIES: Yes, sir. R & r COURT REPORTERS 810 N STREET, SUITE IO1 509W. 3RD AVENUE 277-0572 - 277-0573 277~8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-7515 l0 12 14 16 17 20 2! 22 23 24 25 MR. CHATTERTON: ..... in this matter? MR. DAVIES: My name is ..... MR. CHATTERTON: All right. MR. DAVIES: ..... Steve Davies. I'm a staff geologist with Conoco. I graduated with a master's degree in 1980 from the University of Utah. With the exception of a single year, I have been associated with the Milne Point project in various capacities since 1981. MR. CHATTERTON: Any objection to ..... MR. JOHNSTON: No. MR. CHATTERTON: We will accept ..... MR. SMITH: No. MR. CHATTERTON: ..... you as an expert witness in the matter before us. MR. DAVIES: Geological discussion. Introduction. This portion of the testimony will provide geologic data to the Commission in support of Conoco's proposed Schrader Bluff Pool. Geologic justification will be presented for limiting vertical and areal extent of the pool. Stratigraphic nomenclature. At Milne Point, the Upper Cretaceous and Lower Tertiary sandstones that are potentially oil bearing are generically called the Shallow Oil Sands, SOS. The type log for this interval at Milne POint is the Conoco A-! well, which is located near the center of the unit. Reference figure one. R & r COURT REPORTERS 810 N STREET, SUITE ! O ! 509 W. 3RD AVENUe 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-75 ! 5 10 12 13 !4 !6 17 !8 !9 20 2! 22 23 24 Figure two compares informal Milne Point nomenclature with that used by ARCO in the Kuparuk River Unit. At Milne Point, the SOS are grouped into five intervals, which are named K, L, M, N and O, in descending order. The K and L intervals correspond to ARCO's Upper Ugnu, and the M interval corresponds to the Lower Ugnu. Reservoir sandstones within the N interval are equivalent to the mudstone and shale sequence that lies at the base of the Lower Ugnu in the Kuparuk River Unit. Reference Werner, 1984. Interval 0 corresponds to ARCO's West Sak Sands. Ma3or sandstone beds within each sequence are designated by the subordinate letters A, B, C, D, E and F. Thus, the two dominant sandstone beds in the Upper West Sak of ARCO are termed OA and OB within the Milne Point Unit. For this testimony, only the N and 0 sandstones will be discussed in detail. Stratigraphic description. O Interval. The 0 interval occurs between 4,362 and 4,800 feet measured depth in the A-1 well. It consists of fine-grained sandstone and silty sandstone interbedded with siltstone and mudstone. These sandstone beds are medium to dark brown, moderately sorted, friable and have trace amounts of glauconite scattered throughout. They are generally massive, but have scattered, faint, horizontal laminae. Evidence of bioturbation is common, and shell fragments are rare. The OA and OB sandstone beds each range in thickness from 20 to 50 feet. These two beds dominate the 0 interval and have a R & R COURT REPORTERS STREET, SUITE 10! 509W. 3rDAVENUE 277-O572 - 277-O573 277-8543 ANCHORAge, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 12 13 16 17 19 20 2! 22 23 24 25 8 high degree of lateral continuity. These sediments were deposited under shallow marine conditions in the distal portions of a delta. N interval. In the A-1 well, the N interval is located between 4174 and 4362 feet measured depth. The sandstone beds of this interval are medium gray to dark brow, very fine- to fine- grained, poorly to moderately sorted, friable and massive to interbedded. Trace amounts of glauconite occur within the N interval. Some portions of the beds are distinctly mottled in appearance, suggesting extensive bioturbation. Sandstone beds in this interval are typically quite thin, ranging from five to 20 feet in thickness. The NB sandstone is the thickest, reaching SS feet in the southwestern portion of the Milne Point Unit. The N interval was also deposited along the margins of a large delta complex. Age of sediments. Based no micropaleontology and palynology studies by ARCO, the N interval and the lowest portion of the M interval are thought to be Late Cretaceous, Maastrichtian, in age. The upper M interval and all of the K and L intervals are assigned to the Early Tertiary, Paleocene. Reference Werner, 1987. Proposed pool name. Formal North Slope nomenclature is shown in figure two. By definition, the Schrader Bluff Formation is the uppermost marine unit of the Cretaceous in central Alaska. Reference Detterman and others, 1975. The sediments in the N and R & R COURT REPORTERS 810 N STREET, SUITE 10! 509W. 3RDAVENUE 277-0572 - 277-0573 277~8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-75 ! 5 l0 12 16 17 19 2O 2! 22 23 24 25 0 intervals at Milne Point are Late Cretaceous,, shallow marine, deltaic deposits. They should collectively -- they should be collectively referred to as the Schrader Bluff Formation. The name Schrader Bluff Pool is proposed for oil accumulations within the N and O sandstones at Milne Point. Proposed vertical pool boundaries. The lower boundary of the Schrader Bluff Pool is placed at 4800 feet measured depth in the Milne Point A-1 well. This depth marks the point of transition between the Schrader Bluff Formation and the thick shale section of the underlying Seabee Formation. The upper boundary of the pool is placed at a measured depth of 4174 feet in the A-1 well. Detailed correlations of well logs place an unconformity at this point. A proprietary apatite fission track stuck commissioned by Conoco confirms the loss of section at this erosional surface. The unconformity is an'important dividing line. Below it, the SOS reservoirs contain oil that ranges in gravity from 14 to 19.5 degrees API. Above it, the SOS contain thick, viscous oil ranging in gravity from ten to 13 degrees API. The unconformity is also an important economic dividing line: oil trapped within the underlying N and O intervals is the target of current interest, while the more viscous oil in the overlying K, L, and M intervals is a resource that will require additional cost and technology to recover. Structure. The structure of the Schrader Bluff Formation r & R cOUrt REPORTERS 810 n STREET, SUITE IO1 509W. 3RD AVENUE 277-0572 - 277-0573 277~8543 aNCHORAGE~ ALASKa 99501 1007 W. 3RD AVENUE 272-75 ! 5 10 12 14 16 17 19 20 2! 22 23 24 25 10 is a homocline that dips one to two degrees to the east- northeast. Reference figure three. This homocline is a regional feature that extends from southwest of the Kuparuk River Field to the offshore area beyond the barrier islands. Figure four is a generalized structure map in the Milne Point area for the top of the NA sandstone. It shows the two sets of faults -- it shows the two sets of localized faults that cut the regional homocline. The first, which is dominant, trends north-south and has displacements ranging from wp to 150 feet. Two-thirds of these faults are downthrown to the east, and the remainder are downthrown to the west. The second fault set trends northwest and has an average displacement of 40 feet. Three-quarters of these are downthrown to the northeast, with the rest being downthrown to the southwest. The current northeastern dip is the result of regional tilting in response to sediment loading as a massive system of deltas advanced from the Brooks Range toward the northeast during the Tertiary. Reference Carmen and Hardwick, 1983. The faults that cut the Schrader Bluff are thought to have formed in response to this loading, because of their dominant down-to-the- basin, east and northeast, geometry. Reference Werner, 1987. Conventional seismic data is not capable of defining all of the faults within the Schrader Bluff, and refined structural interpretations will be developed as additional well data become available. R & r COURT rEPORTeRS 8 ! 0 N STREET, SUITE ! 01 509 W. 3RD AVEN U E 277-0572 ~ 277-O573 277-8543 aNCHORAGE, aLASKA 9950! ! 007 W. 3RD AVENUE 272-7515 l0 16 17 19 2O 2! 22 23 24 11 Oil accumulations. The Schrader Bluff Formation contains tremendous quantities of oil. Combined oil-in-place estimates for the reservoirs within the Milne Point and Kuparuk River Units range from 15 to 25 billion barrels. Reference Werner, 1987. Trappin9 mechanisms. The sandstones of the O interval are noted for their continuity throughout the Milne Point and Kuparuk River Units. Oil accumulated in these sandstone beds up- structure to the south and west where faulting provides the primary trapping mechanism. Reference Werner, 1987. As with all of the Schrader Bluff sandstones, structural dip controls oil distribution to the east -- to the north and east. Both structure and stratigraphy control distribution of oil within the N interval. The NA, NC and ND sandstone beds pinch-out up-structure to the southwest of the Milne Point Unit. The ultimate control over oil in these reservoirs is the up-dip sand limit. NB and NE are much more continuous, and faulting apparently controls the up-dip limit of their oil accumulations to the south and west in the Kuparuk River Unit. Reference Werner, 1987, figure seven. Controls over oil -- oil distribution. The faults shown on figure four do not represent continuous individual faults. Rather, they depict fault zones that appear to control the Schrader Bluff oil accumulations. Current seismic control does not allow us to identify individual faults that are impermeable boundaries. However, different oil/water contacts in five of the R & R COURT REPORTERS 810N STREET, SUITE IOI 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGe, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 12 16 17 19 2O 2! 22 23 24 25 12 six large blocks labeled on the map indicate that one or more faults within these zones separate the Schrader Bluff into isolated reservoir compartments. The north-south trending zone highlighted along the left -- along the left margin of the map forms the western boundary of the Schrader Bluff Pool. It is composed of faults having 40 to 120 feet of displacement. This zone effectively separates reservoir compartment number six from the Oliktok Point wells that lie to the west. These wells have very little pay in the N interval. North-south trending faults of similar magnitude form the zones that separate the six large reservoir compartments within the Milne Point Unit. Varying oil/water contacts demonstrate the sealing capability of these fault zones. The northwest-trending fault zone highlighted along the lower margin of the map comprises several faults. Displacement along these faults is not great, ranging from 30 to 140 feet. However, by analogy with the north-south trending fault system, these faults have sufficient displacement to separate and seal oil in the Schrader Bluff Pool from West Sak and Ugnu oil in ARCO's Kuparuk River Unit. The largest and most continuous of these faults forms the southern boundary of the Schrader Bluff Pool. Summary. The schrader Bluff Formation in the vicinity of the Milne Point and Kuparuk River Units was deposited by a delta complex during the late Cretaceous. The structure of the R & R COURT REPORTERS 8 ! O N STREET, SUITE 10 I 509 W. 3RD AVEN U E 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-75 ! 5 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 13 Schrader Bluff sandstones is a northeast-dipping homocline that is cut by north and northwest-trending faults. These faults divide the sandstones into six main reservoir compartments that are sealed from one another and from the West Sak and Ugnu oil that lies up-dip to the southwest. The name Schrader Bluff Pool is proposed for oil accumulated in these reservoirs at Milne Point. This name is in agreement with formal North Slope stratigraphic nomenclature. MR. CHATTERTON: Thank you. Any questions? MR. SMITH: Yes. Steve, did you have formal exhibits, individual maps or are they to be the attachments on ..... MR. DAVIES: They are the attachments. MR. SMITH: Okay. Is this extra copies here? MR. DAVIES: Yes. MR. SMITH: Could I have two of those? MR. DAVIES: Certainly. MR. SMITH: Thank you. MR~ CHATTERTON: Yeah. Meredith has got one copy. exhibit copy. MRo SMITH: Okay. Well, I'll use one for an MR. CHATTERTON: Yeah. Okay. I'll ..... MR. SMITH: With all the attachments. So you referenced Exhibits One through Four, correct? R & R COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-7515 l0 12 13 14 16 17 20 2! 23 24 25 handle this? 14 MR. DAVIES: Correct. MR. CHATTERTON: Let's see, how are we going to MR. SMITH: I'll 3ust list this whole thing'as the exhibit, it was the testimony and ..... MR. CHATTERTON: As one exhibit? MR. SMITH: And -- and has the ex- -- attached exhibits. Okay. How will this be: The -- probably should list each one of these as Exhibit One. As figure one through ..... MR. CHATTERTON: Off the record for a moment, please, Meredith? MR. SMITH: As figure one through four as Exhibit Would that be all right? One through Four. (Off record) (On record) (Exhibit One marked) MR. CHATTERTON: While we were off the record, why, the Commission was considering the presentation here, and we have been presented with a packet that we will identify here as Exhibit One, which is identified as -- as "the Milne Point Unit testimony for Schrader Bluff Pool rules." Many of the -- which includes many exhibits. There are a couple of copies right here available I see that -- that people can -- may borrow if they like right now or take a look at. So that -- we will enter this into the record as Exhibit ..... r & r COURT REPORTERS 810 N STREET, SUITE IO! 509W. 3RD aVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 007 W. 3RD AVENUE 272-7515 l0 14 16 17 19 20 2! 22 23 24 25 15 MR. SMITH: Number One. MR. CHATTERTON: Okay. Your turn. MR. ROSSBERG: ..... Exhibit Number One. My name is Steve Rossberg. I'll be presenting the engineering portion of this testimony. My qualifications are I have a bachelor of science degree in engineering from Montana State University. I've worked for Conoco for approximately eight and a half years in various drilling and production engineering assignments in the Rocky Mountains and Alaska. MR. CHATTERTON: Okay. We find you qualified as an expert witness in the matters before us. You may proceed, Steve. MR. ROSSBERG: Reservoir Description. This portion of the testimony will summarize various reservoir properties necessary to perform volumetric calculations for determination of original oil in place. Discussions of permeability, fluid properties, primary recovery mechanisms and recovery estimates are also included. Documentation for this summary is included in Conoco's reservoir engineering task group study which was submitted as a confidential portion of this testimony. Discussion will be limited to the Schrader Bluff Reservoir N and 0 series sands, which have tested oil of 14 degree API or higher. The upper series sands, K, L and M, have large quantities of oil in place. With high in-situ viscosity R & R COURT REPORTERS 810 N STREET, SUITE 10 I 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-7515 13 17 2! 16 and low AP1 gravity, development of these sands will require additional study and the application of a completely different recovery technique. Conoco requests 20-acre well spacing to allow flexibility in placement of wells to maxim- -- maximize recovery from the N and O series sands within the Schrader Bluff reservoir. Since projected recovery and flow rates are based on anticipated waterflood response, approval for implementation of a waterflood is also requested. Information contained in this section is intended to provide the Commission with sufficient justification to formulate these rulings. Porosity. A detailed analysis including data from 26 wells, reference Table One, was conducted to determined effective porosity from well logs. This data base is considerably larger than the available core data base; therefore, logs were selected as the basis for determining porosity. Areal distribution of this data extends across the Milne Point Unit. The results were used in volumetric estimates of original oil in place, determination of effective permeability, irreducible water saturation and oil saturation. A shale ..... MR. CHATTERTON: May I interrupt for a moment here? The Table One you're referring to is Table One of Exhibit One, is that correct? MR. ROSSBERG: Yes, sir, that's correct. r & R COURT REPORTERS 810 n STREET, SUITE 10 I 509 W. 3RD AVEN U E 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AVENUE 272-7515 l0 13 14 16 17 19 2O 2! 22 23 24 MR. CHATTERTON: Thank you. MR. ROSSBERG: A shale corrected neutron-density crossplot technique was used to calculate poros- -- porosities. Crossplotting corrects for the effects of solid clay particles on the log readings. Shale correction eliminates that portion of the porosity filled with clay-bound water. In addition, logs were normalized to correct for systematic errors, such as tool miscalibrations or hole washouts. The resulting effective porosity values were used in determination of reservoir storage capacity and development of hydrocarbon-feet maps. Figure five of Exhibit A-one is a plot of calculated log porosity versus core porosity utilizing data from well B-2, indicating a very good correlation between log-derived porosity and core porosity. Water saturation. Well logs were also used to calculate water saturations for the wells listed in Table One. Core data is available from four wells within the Unit, and capillary pressure derived water sat- -- saturations from well B-2 were used to chose the most appropriate log analysis technique. The modified Simandoux technique provided the best match with capillary pressure derived saturations, and this technique was applied to the well data base shown in Table One to determine water saturation. This log technique accounts for clay-bound water, which is sus- -- which is suspected to be present in some of the sands, and is considered to be a more accurate determination of water R & r COURT REPORTERS 8 ! 0 N STREET, SUItE 10 ! 509 W. 3RD AVENUE 277-O572 - 277-O573 277-8543 ANCHORAGE, AlaSka 99501 1007 W. 3RD AVENUE 272-75 I 5 l0 1! 12 14 16 17 20 2! 22 23 24 25 18 saturation than the core-derived data. Ail of the wells in Table One have electric logs that were corrected for hold diameter and standoff. True -- true resistivity was calculated using standard popula- -- published log correlation charts. A water resistivity of 0.178 ohm-meters at 100 degree fahrenheit was calculated using 100~ water saturated sands. This value was used as a formation water resistivity in the log analysis. Reservoir fluids and PVT properties. Reservoir pressure, oil gravity and temperature in the Schrader Bluff Pool vary widely within the unit. Fluid properties were calculated at various structural elevations using equations derived from published correlations. Based on this methodology, average values for fluid properties are as follows: Average reservoir pressure, 1~750 psig; average reservoir temperature, 90 degrees fahrenheit; average crude oil gravity, 17 degrees API; bubble point pressure, 1,388 psig; solution gas/oil ratio, 191 standard cubic feet per stock tank barrel of oil; oil formation volume factor, above bubble point, 1.06 barrel per stock tank barrel of oil; oil viscosity at reservoir temperature, $00 centipoise. Net pay determination. For the purpose of the N and O series sands, net pay is defined as pay with a mobile oil saturation and a permeability above one millidarcy. The oil/water contact is defined as the limit of mobile oil; therefore, the oil/water contact coin- -- coincides with the zero r & R COURT REPORTERS 8ION STREET, SUITE IO1 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAge, ALASKA 9950! 007 W. 3RD AVENUE 272-75 ! 5 l0 12 13 14 16 17 19 20 21 22 23 24 25 19 net effective pay line. Figure 6 of Exhibit A-one is a plot of core air permeability versus porosity from Milne Point Unit Well B-2, indicating that a permeability cut off of one millidarc¥ results in a porosity cutoff of -- of approximately 16%. Two distinct data groupings around the 16% porosity suggests that sands and shales tend to segregate at this point. THe water saturation cutoff of 62.5% was arbitrar- -- arbitrarily set to approximate the condition of residual oil saturation. Original oil-in-place. Based on well control, areas of oil accumulation were divided into six ma3or fault blocks. Reference figure four of Exhibit A-one. Table two lists the oil/ water contact levels by sand in each fault block, indicating varying oil/water contacts in the different fault blocks across the structure. Appendix one of Exhibit A-one contains correlations for each sand in each well. The pay zones within each well were identified using the net pay criteria discussed above. Within each pay zone, the values of net pay, effective porosity, effective water saturation and hydrocarbon-feet were calculated in each well according to the pre- -- previously discussed methodology. The net pay values were entered into Conoco's computer mapping program and digitized on a 500-foot by 500-foot grid, and contoured on a sand by sand basis. The net effective pay contour maps treated the fault blocks as separate areas. The program R & R COURT REPORTERS StreeT, suite 10! 509w. 3RDaVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 007 W. 3RD AVENUE 272-75 ! 5 10 12 14 16 17 19 20 2! 22 23 24 25 20 forced the oil/water contact to the zero net effective pay contour and modified net effective pay trends in those locations accordingly. The result was that net effective pay trends near wells reflected the log analysis; while the contours between wells reflected regional trends. Contours approaching oil/water contacts were closely gathered together, reflec- -- reflecting rapidly changing net effective pay values in the transition zone. The effective porosity maps were generated in the same manner, with the exception that trends were not truncated at the oil/water contact or by faults. Therefore, the effective porosity maps reflected more broad regional trends which are implied by the well data. The initial effective water saturations were also computer generated on 500 by 500 grids directly from the porosity maps. Each porosity value was converted to effective water saturation by applying the initial water saturation equation previously discussed. As a control, the computer-derived saturations were checked with individual well locations and found to be in close agreement. The net effective pay, porosity and saturation maps were combined mathematically on 500 by 500-foot grids to produce hydrocarbon-foot maps on the individual sands. The contours were planimetered within each four section tract. Reference, figure four of -- of Exhibit A-one. Within each tract, the contours were planimetered separately within each fault block. R & r COURT REPORTERS 810N STREET, SUITE 10! 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, aLaSKA 99501 007 W. 3RD AVENUe 272-7515 l0 12 14 15 16 17 19 20 21 22 23 24 25 21 Hydrocarbon feet volumes were converted to original oil in place by applying the factor ??58 divided by the oil formation volume factor. Permeability. Permeability ranges from 27 millidarcies to 5,896 millidarcies inn the N sand and from 21.2 millidarcies to 143 millidarcies in the 0 sand. Since 1980 12 production tests conducted in the N and O series sands have produced reliable permeability values. The results of the -- the results of seven of these tests are summarized in Table Three, indicating an average flow capacity of 6,410 millidarcy feet. A recent production test on Milne Point Unit Well G-1 located in tract 14 of the Milne Point Unit indicated a flow capacity of approximately 82,000 millidarcy feet and a permeability of 2,000 millidarcies. In cores taken from G- one, air permeability ranged from 5,000 millidarcies to then -- to 10,000 millidarcies, and from 200 millidarcies to ?00 millidarcies for the N and 0 series sands respectively. Primary recovery mechanisms. Primary recovery from the MPU Schrader Bluff reservoir will predominantly result from pore volume compress- -- compressibility with a minimum amount of solution gas drive. Laboratory analysis indicates sufficient pore -- core compressibility to contribute to primary recovery. Recovery predictions. The MPU Schrader Bluff reservoir was modeled using the Todd, Dietrich and Chase Volatile Oil Steamflood Simulator in an isothermal mode. The TDC model is a R & R COURT rEPORTERS 810N STREET, SUITE 10! 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 007 W. 3RD AVENUE 272-75 ! 5 10 12 13 14 16 17 19 20 2! 22 23 24 25 22 -- is three-dimensional and able to handle multiple, non- communicating layers, as well as simultaneous flow of oil, gas and water. In addition, the TDC model will handle -- handle pressure dependent pore volume and permeability. MPU wells A-three and N-lB were selected to represent average well in two distinctly -- distinctively different areas of the reservoir. These wells provided porosity, permeability and oil gravity data for the respective areas. Each of the N and 0 sands were treated as separate homogeneous layers. Porosity and water saturation data were read directly' from well logs using techniques discussed in the determination of original oil in place. PVT properties were calculated, reference reservoir fluid section of Exhibit A-one, and assigned to the various sands in different areas of the field based on observed oil gravities. Permeability and relative permeability characteristics, reference permeability section, were generated and entered into the model. The wells were pressure constrained to a producing bottom-hole pressure of 800 psig. In3ection well pressures constrained to minimum fracture gradient of 0.? psi per foot. The wells were not water-cut constrained. The model was set up on a seven by seven grid, which results in five grid -- grid blocks between wells on opposite corners. Well spacing was changed by increasing or decreasing horizontal dimensions of the grid blocks. In3ection pattern R & R COURT REPORTERS 810 N STREET, SUITE 101 509W. 3RD AVENUE 277-O572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 12 16 17 19 20 2! 22 23 24 23 patterns were simulated by placing wells at the appropriate positions and ad3usting grid block sizes. Various well spacing and injection well patterns were modeled. The results clearly illustrate that waterflooding on 890-acre five-spot or inverted nine-spot patterns will result in increased recovery over primary, on any spacing to 40 acres, or a regular 80-acre nine-spot pattern. Primary recovery cases show high initial rates approaching those of waterflooding, indicating that injection can be delayed for a period of primary -- primary production. Oases run on delayed in3ection indicate that reservoir pressure will be maintained -- maintained with in3ection delays of up to two years. MOdel results indicate delayed in3ection to have negligible impact on ultimate recovery. Faulting and stratigraphy will ultimately play a important role in determination of optimum spacing and pattern placement. Increasing well density to 20 acres may become necessary to achieve the necessary communication between in3ectors and producers in some areas of the field. THe following is a summary of ma3or conclusions presented in the reservoir description portion of this testimony: 1. Based on well control, areas of oil accumulation were divided into six ma3or fault blocks. Ref- -- reference figure four of Exhibit A-one. 2. Primary recovery from the MPU Schrader Bluff reservoir will predominantly result from pore volume R & R COURT REPORTERS 81ON STREET, SUITE lO! 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, aLASKA 99501 1007 W. 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 24 compressibility with a limited amount of solution gas drive. 3. Computer model results clearly illustrate that waterflooding on 80- acre five-spot or inverted nine-spot patterns will result in increased recovery over primary. 4. Cases run on delayed injection indicate that pressure will be maintained with injection delays up to two years. Model results indicate delayed injection will have negligible impact on ultimate recovery. A period of primary production will provide additional production data for use in design of a waterflood pattern, which may result in a more efficient waterflood and increased recovery. 5. Faulting and stratigraphy will ultimately play an important role in determination of optimum spacing and waterflood pattern. Increasing well density to 20 acres may become necessary to achieve necessary communication between injectors and producers in some areas of the field. Reservoir surveillance. To monitor depletion and optimize recovery from the Schrader Bluff reservoir, an active program of reservoir surveillance will be initiated in the early stages of development dril- -- of development. This portion of the testimony will discuss a proposed reservoir surveillance program, which will include careful monitoring of reservoir pressure, gas/oil ratio, produced volumes, injected volumes, injection well surveillance and well surveys. Reservoir pressure. In the Schradervoir (sic) -- in the R & R COURt REPORTERS 81ON STREET, SUITE 101 509W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGe, ALASKA 9950! I O07 W. 3RD AVENUE 272-75 ! 5 l0 12 13 14 16 17 19 2O 21 22 23 24 25 25 Schrader Bluff reservoir, both permeability and pore volume are thought to be pressure dependent; therefore, careful monitoring of reservoir pressure and pressure maintenance are considered to be very important aspects of the depletion program. Monitoring of reservoir pressure will commence with the initial drilling phase. The static bottom-hole pressure will be measured in each well prior to initiating sus- -- sustained production, these pressure measurements will be obtained either by drill stem testing or repeat formation testing during the drilling and logging phase. If a DST or RFT is not conducted, the static reservoir pressure will be measured after completion using mechanical or electric gauges run on wireline. These static pressure surveys will be conducted for at least eight hours to insure that adequate information is obtained. After six months of sus- -- sustained production, the reservoir pressure will be measured in one well per 640-acre section. In areas of the reservoir producing on primary production, these measurements will be conducted every six months until waterflooding is initiated. In areas of the reservoir under active waterflood, the pressure will be measured in one well per 640-acre section after six months of sustained production and again after 18 months of production. In addition, one well per 640-acre section will be designated a key well. The static reservoir pressure will be measured after 30 months of sustained production and annually thereafter for the life of the R & R COURT REPORTERS 810N STREET, SUITe 10! 509W. 3rDAVENUE 277-O572 - 277~0573 277-8543 ANCHORAGe, ALASKA 9950! 1007 W. 3RD AVENUE 272-75 ! 5 l0 12 16 17 20 2! 22 23 24 26 well. Bottom-hole pressures will be obtained by 24-hour static tests, pressure buildup surveys, multiple flow rate tests or in injection wells by pressure falloff. For consistency, the pressure datum plane in the MPU Schrader Bluff reservoir shall be 4,000 feet subsea. All necessary data and well conditions to perform a complete engineering analysis, including rates, pressures, depths, temperature and times will be recorded and forwarded to the Commission by the last day of the month following the month in which the survey was conducted. Reservoir Report Form 10-412, complete with any necessary attachments will be utilized to report the data. Due to complicated faulting and stratigraphy in the Schrader Bluff reservoir, it may be necessary to implement a pressure-transient, introduce -- interference testing program to intersure (ph) -- to insure proper pattern arrangement and communication between injectors and producers. The purposes of -- the purpose of this testing program will be to identify reservoir boundaries, such as faults, facies changes or other permeability barriers that may adversely influence the waterflood project. Information gathered from interference testing will be forwarded to the Commission upon request. In addition to the static pressure monitoring program, the producing bottom-hole pressures will be routinely monitored in all producing wells. Injection wells -- in injection wells R & R COURT REPORTERS 810N STREET, SUITE IO! 509W. 3RDAVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 272-75 ! 5 ANCHORAGE, ALASKA 99501 l0 12 16 17 20 2! 22 23 24 27 the surface in3ection pressure will be continuously monitored. Gas/oil ratio testing. With an initial solution gas/oil ratio of 191 standard cubic feet per stock tank barrel of oil, an initial oil formation -- and an initial oil formation volume factor of 1.06, the MPU Schrader Bluff reservoir is considered highly under-saturated. As previously discussed, primary recovery from solution gas drive will be negligible compared to pore volume compressibility, which is considered to be the most significant drive mechanism for primary recovery. Current plans are produced -- are to produce the reservoir under primary means for a period of one year and then implement a full scale waterflood pro3ect. Due to the under-saturated nature of the reservoir, water channelling problems or extremely large fill-up volumes resulting from build up of gas saturation in the reservoir are not anticipated. In addition, sufficient structural relief -- relief to form a secondary gas cap is not thought to be resent in the MPU Schrader Bluff reservoir. Based on these assumptions, it is concluded that pressure depletion resulting from primary production, and the anticipated increase in GOR, will have negligible impact on ultimate recovery from the Schrader Bluff reservoir. Computer model runs on cases delaying production to two years confirm this conclusion. Between 90 and 120 days after continuous production, a gas/oil ratio test will be taken on each producing well. To ensure accuracy, the test will be for a minimum of 12 hours in R & r COURT REPORTERS 81ON STREET, SUITE 101 509W. 3rDAVeNUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AVENUE 272-7515 14 l? 2! 24 28 duration and conducted at normal producing rate and pressure of the well. All tests will be reported on the oil -- on the Gas/Oil Ratio Form 10-409 by the 15th day of the month following the month that the test was conducted. Subsequent gas/oil ratio tests will be performed every six months on wells producing on primary production, prior to implemen- -- implementation of the waterflood or on wells isolated from injectors. Based on this testimony, Conoco requests that the Gas/oil ratio limitation in 20 AAC 25.240(b) be waived for a period of time not exceeding 18 months from the date of initial sustained production from the Schrader Bluff reservoir. SHould the GOR increase above current regulatory limits, this waiver will allow for a period of primary production prior to initiating the waterflood. Data collected during the primary production phase will be used in waterflood design. This should ultimately result in more efficient secondary recovery and increased reserves. Produced volumes. It is proposed that surface commingling of production from the Schrader Bluff Pool with production from the Kuparuk River Pool be allowed at any point downstream of the well test system for final separation and sales at the Milne Point Unit Central Facilities Pad. The current Kuparuk River Pool has an estimated economic life of approximately seven years without commingled Schrader Bluff production. Commingling of production will prevent both economic waste from and under-utilization of the existing facilities in R & R COURT reporters 81ON STREET, SUITE 101 509W. 3RDAVENUE 277-0572 - 277-O573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD aVENUE 272-75 ! 5 14 l? 24 29 the field and loss of reserves from the Kuparuk River reservoir. Prior to commingling, the Commission may approve -- Prior to commingling, the Commission may approve the proposed method of testing and allocation; and also approve the proposed design and operating procedure for the test equipment. The following is Conoco's proposed methodology for well testing and allocation between the pools. Produced volumes of oil, water and gas from the MPU Schrader Bluff Pool and Kuparuk River Pool will be monitored with individual well tests. Well tests will be the basis for allocating monthly production volumes, oil, water and gas, for the individual wells. THe individual well tests will be of at least six hours in duration and performed a minimum of twice monthly. Schrader Bluff wells will be produced with artificial lift equipment. The producing bottom pressure will be routinely monitored with surface read-out of bottom-hole pressure gauges or by shooting fluid levels. The producing bottom-hole pressure will be recorded at the beginning of each test cycle. The test equipment will be discussed in detail later in the facilities and scheduling portion of this testimony. Bi-monthly well tests will be in agreement within 10~ plus or minus error to be validated for allocation usage. Wells tests out -- testing outside of this tolerance will be retested a third time. INdividual pad production will be summed to determine total production from the individual pools. R & R COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 007 W. 3RD AVENUE 272-75 ! 5 l0 l! 12 13 14 16 17 19 20 2! 22 23 24 30 It is also proposed to commingle gas from the Schrader Bluff Pool with gas from the Kuparuk River Pool. This gas will be reinjected into the Lower Kuparuk River gas displacement project in Milne Point unit well E-three. Under no circumstances will gas be transported out of the Milne Point Unit. All gas produced from the Schrader Bluff Pool will be allocated based on individual well tests and utilized in accordance with Rule 20 AAC 25.235. Injected volumes and waterflood surveillance. A daily record of in3ection rate and surface pressure will be maintained for each injection well in the Schrader Bluff Pool. In addition, a record of cumulative injection and pressure will be maintained per well and per pad. This data will be measured and totalized on an individual well basis. Initial surface injection pressure will not exceed 1,O00 psig, which is below the estimated parting pressure, based on an estimated frac gradient of .? psi per foot. After six months of continuous stabilized injection, step-rate tests will be conducted in one well per ADL tract to determine actual parting pressure and fracture length at various rates and pressures. In3ection pressure may be increased based on the results of the step-rate tests. In3ection wells will be pressure parted only if it can be clearly demonstrated, using industry accepted reservoir engineering analysis, that the waterbank extends beyond the fracture half-length. A second round of step-rate tests will be R & R COURT REPORTERS 81ON STREET, SUiTe 101 509W. 3RD AVENUe 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 12 13 14 16 17 19 20 2! 22 23 24 25 conducted after 36 months of continuous injection. In conjunction with the step-rate testing program, pressure fall-off tests may be conducted in one well per pad to determine average reservoir pressure. The results of step-rate and pressure fall- off tests will be reported to the Commission upon request. Injection surveys using wireline conveyed temperature logs, radio-active logs, mechanical flow measuring tools, or a combination of these devices will be run in each injection well after 12 months of continuous injection. Following the initial surveys, each injection well will be routinely surveyed every third year. Surveys will be conducted in any well exhibiting major changes in either injection rate or pressure. Completed surveys will be filed with the Commission within 90 days after performing of the survey. As Unit Operator of the Milne Point Unit Schrader Bluff Pool Unit Waterflood, Conoco, Incorporated, will submit an annual report to the Commission on the Schrader Bluff Pool Waterflood. The report will be submitted by April 1 of each year for the period ending December 31st and will contain the following information: (a) A tabulation by month, and on a cumulative basis, of produced volumes, oil, water and gas, and injected volumes and pressures; (b) A summary of all injection surveys, injection well testing and injection well performance for the period; and R & r COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RDAVENUE 277-O572 - 277-O573 277-8543 ANCHORAGe, aLASKA 99501 1007 W. 3RD AVENUE 272-75 ! 5 l0 12 13 14 16 17 19 20 2! 22 23 24 32 (c) A summary of pressure surveys conducted on either producers or in3ectors during the period. Well planning. Casing and cementing. The Schrader Bluff Pool casing and cementing requirements are generally consistent with AOSCC Regulation 20 ACC 25.030, requiring that casing and cementing programs meet the following criterion: 1. Provide adequate protection of all fresh water zones; 2. Prevent fluid migration between strata; 3. Provide protection from pressures that may be encountered, including pressure due to thaw subsidence and freezeback within the per- -- permafrost interval. The proposed standard casing design for a typical Schrader Bluff well is very similar to that currently used in Milne Point Unit Kuparuk River wells. It consists of 13 and three-eighths inch conductor set a minimum of 80 feet and cemented to surface; nine and five-eighths inch surface casing set at least 500 feet below the base of the permafrost and cemented to surface utilizing an arctic set cement; seven inch production casing from surface to approximately 5,000 feet true vertical depth, cemented from TD to 500 feet above the top of the Prince Creek K sand. An alternative -- an alternative design currently under consideration is to substitute the above design with 16-inch conductor, 13 and three-eighths inch surface casing and nine and five-eighths inch production casing, which may better facilitate r & R COURT rEPORTErS 81ON STREET, SUITE lO! 509W. 3RD AVENUE ' 1007 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 272-75 ! 5 ANCHORAGE, ALASKA 99501 14 l? 24 33 running wire-wrapped screen liners for gravel packing. A typical open-hole completion currently under consideration is as follows: iS and three-eighths inch conductor set at a minimum of 80 feet, and cemented to surface; nine and five-eighths inch surface casing set 500 feet below the base of the permafrost; seven-inch production casing set approximately 50 feet above the top of the Schrader Bluff N sand, cemented to TD - - or excuse me, cemented from TD to 500 feet above the top of the K sand; the open hole will be un- -- under-reamed to 12 and a quarter inches from the seven inch casing point to 150 feet below the base of the O stand. The open hole section may be 9ravel packed with either slotted or wire wrapped liner. Correction. The open hole section may be completed with either slotted or wire wrapped liner and possibly gravel packed. To provide insulation, the surface casing/production casing annulus will be arctic packed in all wells. It is proposed that the Schrader Bluff casing and cementing rules be written as specified in 20 AAC 25.030 and in accordance with the current Kuparuk River Field rules as follows: 1. For proper anchorage and divert -- and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and sufficient cement will be used to fill the annulus behind the pipe to surface. 2. For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost R & R COURT REPORTERS 8 ! O N STREet, SUITE ! 01 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AVENUE 272-75 ! 5 l0 12 13 16 17 19 2O 2! 22 23 24 25 34 thaw-subsidence and freeze back, a string of surface casing will be set at least 500 feet measured depth below the base of the permafrost section. Sufficient cement will be used to fill the annulus behind the casing to the surface. 3. To prevent well -- well failure due to permafrost action, Conoco as operator shall install surface casing including connections with sufficient strength and flexibility to prevent failure. To be approved for use as surface casing, the Commission shall require evidence that the proposed casing and connections meet the above requirements. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back, based on sound engineering principles~ may be approved by the Commission upon application. 4. It is proposed that the Commission approve a ruling that intermediate casing not be required. 5. It is proposed that the Commission approve a ruling allowing the following alternative completion methods: a) slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hold and which may be gravel packed; b) open hole completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may be subsequent- -- may subsequently be completed with slotted liners, wire-wrapped R & R COURT REPORTERS 810N STREET, SUITE I01 509W. 3RDAVENUE 277-O572 - 277-0573 277~8543 ANCHORAGe, ALASKA 99501 007 W. 3RD AVENUE 272-75 ! 5 (i l0 12 14 16 17 19 20 21 22 23 24 25 35 screen liners, or combinations thereof, and may be gravel packed; c) horizontal completions with liners, prepacked liners, slotted liners, wire-wrapped screens, or a combination thereof, landed inside the horizontal extension and possibly gravel packed. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engineering principles. Blowout prevention. It is proposed that the rule for blowout prevention in the Schrader Bluff Pool be written identically to the provisions established in Regulation 20 .AAC 25.035, secondary well control: blowout prevention equipment requirements, of the AOGCC regulations. Except -- except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance wit API Recommended Practice 53 for blowout prevention systems. Automatic shut-in equipment. It is recommended that it be mandatory to install a Commission-approved, failsafe, automatic surface safety systems on all producing wells. The system may be hydraulically, pneumatically or electrically controlled and must be able to simultaneously shut in the well head and shut in the artificial lift equip- -- equipment, if present, to prevent uncontrolled flow of liquid hydrocarbons. To insure that the surface safety system is functioning properly, a Commission representative may witness operation and performance R & R COURT REPORTERS 810 N STREET, SUITE lO! 509W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-75 ! 5 10 12 13 14 16 17 19 20 2! 22 23 24 25 36 tests at intervals and times specified by the Commission. Facilities description and project schedule. There are approximately 16,800 developable acres in the Milne Point Unit Schrader Bluff Pool. Due to directional drilling limitations on these 4800 foot TVD wells, the largest area developable by a drill pad is approximately one section, 640 acres. This implies that a potential for a total of 26 pads (sic). The major constraint on development in the Schrader -- Schrader Bluff reservoir will be available processing capacity at the Milne Point Unit Central Facilities Pad. Without ma3or modifications, CFP handling capacity is estimated at 40,000 barrels of oil per day. Total capacity of the Kuparuk is currently estimated at 30,000 barrels of oil per day, requiring in3ection of 40,000 barrels per day. CFP in3ection capacity is currently 50,000 barrels per day, leaving approximately 10,000 barrel per day excess for Schrader Bluff in3ection. THerefore, total excess facility capacity, crude processing and in3ection, in 1990 is estimated at 10,000 barrels per day. The available capacity will increase substantially as Kuparuk production declines. It will become necessary to increase in3ection capacity of the facility as the Schrader Bluff development proceeds to fully implement the waterflood pro3ect. However, this expansion should not be necessary in the early development stages. Due to the close proximity to the CFP, development of the Schrader Bluff reservoir will begin in tract R & r COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RD AVENUE 277-O572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 l0 l! 12 14 16 17 19 20 2! 22 23 24 25 37 14 of the Milne Point Unit. Shorter roads and pipelines result in the most economical development scenario in this tract. Plans are to drill 12 additional Schrader Bluff wells and complete 160-acre primary development in tract 14 on H, I and J pads during 1990. Reference Figure Seven of Exhibit A-one. Installation of pad facilities and pipeline hookup are planned for the third quarter of 1990, with initial production scheduled to commence by year-end. Infill drilling to 80 acres and implementation of a waterflood is planned for 1991. Development will continue at a pace set to maintain facilities at full capacity as the Kuparuk reservoir declines. Reference Figure Eight of Appendix -- or, excuse, of Exhibit A-one. Economical development of the Schrader Bluff Pool is contingent upon utilizing the existing Kuparuk facilities. As previously stated, it will be necessary to surface commingle Schrader Bluff crude with Kuparuk River crude. Plans are to install test facilities at each pad consisting of a two-phase separator and the -- and an emulsion meter. Microwave absorption meters have been extensive- -- extensively tested in other Conoco operations and by other major oil companies. The available test data indicates that these meters Will be applicable for use in the Schrader Bluff test systems. Unlike other emulsion meters, microwave absorption meters are relatively unaffected by phase percentages and specific gravity. Test systems utilizing these meters are approved by the Texas Railroad Commission for R & r COURT REPORTERS 810 N STREET, SUITE 101 509W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 14 2! 24 38 allocating commingled production. Additional data concerning the design, installation, and testing of these meters has been previously furnished to the Commission. The current Kuparuk River test system on B and C pads utilizes three-phase test separators. Kuparuk tests, as an aggregate, are generally within lO~ of the sales volume. The Kuparuk test system operates at essentially the same working pressure as normal manifold pressures, resulting in reliable test data. Based on test data gathered for the microwave absorption meters, it is anticipated that the proposed Schrader Bluff system will be within this accuracy range. This system will also be designed to operate as closely as possible to normal producing pressure -- pressures, which should enhance performance of the system. Conclusion. Through. This testimony has been based on Conoco's present knowledge of the Schrader Bluff reservoir and contains results from theoretical analysis, laboratory analysis, model studies, reservoir management considerations and operational requirements. Conoco is confident that present knowledge of the reservoir is adequate to devise a prudent and economic course of action for development of the Schrader Bluff Pool, and trusts that this data is sufficient for the Commission to formulate Pool Rules consistent with the plan of development as currently envisioned. MR. CHATTERTON: Thank you very much. Any R & R COURT REPORTERS 810 N STReet, SUITE IO1 509W. 3RD aVEnUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. SRD AVENUE 272~7515 10 12 14 16 17 19 20 2! 22 23 24 39 questions of either of these gentlemen? MR. JOHNSTON: The -- the sands that you described earlier, how areal extensive are they? MR. DAVIES: The OA and OB sands are wide spread throughout the Milne Point Unit. They continue down through at least the northern one-third of the Kuparuk River unit to the south. The N sands themselves, although they're quite thing, they're also very extensive areally. They occur through the bulk of the Milne Point Unit, and they also extend to the south into the Kuparuk River Unit. MR. JOHNSTON: So do the sands come and go or are they fairly continuous throughout this area? MR. DAVIES: With present well control, they appear to be fairly continuous. However, in-fill drilling might show that they are indeed sands packages that are in the same stratigraphic location but not necessarily continuous. MR. JOHNSTON: All right. I suppose that would be even more complicated by the tremendous number of faulting that you have down in this area? MR. DAVIES: That's true. MR. JOHNSTON: On the metering, how -- how do you propose to test the actual microwave emulsion meter to make sure that it is accurate? Do you have a check on that? MR. ROSSBERG: Yeah, we've got -- in our R & r COURT RePOrTERS 810 N STREET, SUITE IO1 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANChORAGe, ALASKA 99501 007 W. 3RD AVENUE 272-75 ! 5 l0 14 16 17 19 20 2! 22 23 24 40 facilities design, we have incorporated provisions for manual testing actual fluid grind-outs to check the meters. MR. JOHNSTON: Okay. And do you pull -- or does the microwave emulsion meter record the data from the entire test stream, or do you pull samples of that? MR. ROSSBERG: No. How -- how the system will work is from the wellhead we will have a three-way valve, which will put a well either into test or normal production. So when a well is in test, the entire flow stream will enter the test system, go through the two-phase separator where the gas will go out the top, we'll meter it with a turbine meter, and the emulsion will go out the bottom. It'll -- it'll go through a PD pump and then through the -- the microwave meter, and then once the phase percentages are calculated by the meter, the total flow stream will go through either a turbine or a PD meter and then through a net oil computer. So we're measuring the actual production on the total flow stream of the well. MR. JOHNSTON: Right. Okay. And do you have a problem with insuring that you have proper mixing of the test stream of these meters? MR. ROSSBERS: No, we don't think we've got a problem there. Presently we plan to complete the initial wells with submersible electric pumps, down-hole centrificals and they create a very good emulsion. MR. JOHNSTON: All right. Have you used the -- R & r COURT REPORTERS 81ON STREET, SUITe IOI 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! ! 007 W. 3RD AVENUE 272-7515 l0 l! 12 14 16 17 2O 2! 22 23 24 25 41 the meters elsewhere for protection purposes? MR. ROSSBERG: We've -- we've currently got these meters in service in -- on a producing property in the Gulf of Mexico. Our production engineering research group has also done extensive testing of these meters in -- in actual field operations, and we submitted the results of this testing program to the Commission. MR. JOHNSTON: Okay. Perhaps we should enter that, the -- the results of that study as Exhibit Two? MR. SMITH: Exhibit Two? Would there be any ob3ection to that? MR. ROSSBERG: No. (Exhibit 2 marked) MR. SMITH: Is -- I might ask another question there. Is there anything about that that's confidential from the standpoint of -- I noticed it's a Texaco patented process? MR. ROSSBERG: Yeah. We checked that out with our research people in Houston, and Texaco probably considers it good advertising. MR. SMITH: We/iv -- okay. If -- if you could give me a copy of that for the exhibit, that's -- we have pages missing in the one we received, there are two or three pages missing. It seems -- I -- I can tell you which ones. I think page four -- am I -- no, that's not. Well, 11 and 12 for sure, but it seemed like there was another one. r & r COURT REPORTERS 8 ! 0 N STREET, SUITE 10 i 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGe, ALASKA 99501 | 007 W. 3RD AVENUE 272-75 ! 5 l0 16 17 20 2] 22 23 24 25 42 MR. ROSSBERG: I'll -- I'll get you a ..... MR. SMITH: Okay. MR. ROSSBERG: ..... complete copy of it. MR. SMITH: Okay. MR. JOHNSTON: What -- have -- have you been able to determine what the likely draining -- drainage radius of these wells will be? MR. ROSSBERG: Right now for our -- for our reserve -- reserve estimates, we're assuming that the wells will drain 160 acres. We really won't know any different until we in- fill drill and -- and get a better handle on the -- you know, the faulting picture out there. Most of the -- generally the faults we're seeing are -- have throws of '- in the neighborhood of 30 to 50 feet, which we feel may or may not be barriers to flow ...... MR. JOHNSTON: Right. MR. ROSSBERG: ..... We're certainly seeing in the Kuparuk that these minor faults do not seem to interfere with the waterflood all that much. MR. JOHNSTON: Do -- do you see the drainage radius being affected by the depth that you're extracting the -- the hydrocarbons from? For example, if it's a deeper well, do you -- do you feel that it would be a larger drainage radius giVen the thermal nature of the ..... ? MR. ROSSBERG: No, I don't think that that would r & R COURT REPORTERS 8 ! 0 N STREET, SUITE 1 O! 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3rD AVENUE 272-75 ! 5 10 l! 12 14 16 17 19 20 2! 22 23 24 43 influence the drainage radius. If anything, it may -- it may influence the rate. The deeper wells probably would be a little higher rate. MR. JOHNSTON: What kind of sanding problems do you expect? MR. ROSSBERG: We have tested two wells this year at G pad to sand failure in the N series sand, and have successfully gravel packed and retested the wells at commercial rates. The 0 series sand has not produced significant sand volumes that would be considered a problem on any of our tests. So at this point, our plans are to install sand control type completions on our N sand wells, and produce our 0 sand wells without sand control initially. MR. JOHNSTON: Okay. Do you -- do you see the -- any problems with the submersible pumps contributing to the sanding problems? MR. ROSSBERG: No. Basically this -- the -- a well's tendency to produce sand is dictated by the amount of draw down you put on the reservoir. We feel that with the ESPs we actually have better control of draw down than we would by, you know, alternative lift means. We've set our in- -- our installations will be set up for continuous monitoring of the producing bottom-hole pressure, and through the use of variable speed controllers we'll be able to produce our wells based on bottom hole pressure. R 8:r COURT REPORTERS 81ON STREET, SUITE lo! 509W. 3RDAVENUE 277-O572 - 277-0573 277-8543 ANCHORAGe, ALASKA 99501 007 W. 3rD AVENUE 272-7515 l0 ll 12 14 16 17 20 2! 22 23 24 25 iI iI 44 MR. JOHNSTON: And in the production testing that you've done to date, have you witnessed any of the wells capable of unassisted flow to the surface? MR. ROSSBERG: Yes, we have. MR. JOHNSTON: That's all the questions I have for right now. MR. CHATTERTON: Lonnie? MR. SMITH: Yes. On the well test system again, you mentioned you're proposing a minimum six-hour well test twice monthly. That -- I -- I presume then your -- your capacity, if you had to increase them to 12-hour tests or something like that, well, you'd be once monthly. Is it that kind of limitations on it, or ..... ? MR. ROSSBERG: No. We've -- we've got -- based on this six -- six-hour twice monthly scenario, we have designed our initial test systems to handle in-fill drilling at the pads to -- all the way down to 80 acres. In other words, six producers, two in3ectors per pad on an inverted nine-spot, and the test system will -- will handle that increased development without changing the duration of the test. We've -- we've incorporated that ..... MR. SMITH: Okay. MR. ROSSBERG: ..... into the design. MR. SMITH: So ..... MR. ROSSBERG: So the -- the -- I -- to answer R & R COURT RePORTers 81ON STREET, SUITE I01 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 aNCHORAGE, ALASKA 99501 ! 007 W. 3RD AVENUE 272-7515 l0 13 14 16 17 19 20 2! 22 23 24 25 45 your question, the -- the piping and -- and test facilities itself are -- are designed to handle that test frequency at what we see now as our optimum development. MR. SMITH: Okay. So initially you'd have much more latitude? MR. ROSSBERG: Right. MR. SMITH: Now, you mentioned about the test being -- the acceptable test, I guess the bimonthly test would be in agreement within 10% plus or minus to be validated -- ten -- 10% of the previous acceptable tests, is that what you mean? MR, ROSSBERG: Yes, sir. MR. SMITH: Yeah. And -- that -- back to that microwave water cut analysis equipment again. You're .-- you'll be metering the total stream to get the volume, and then you have to -- this microwave absorption technique will determine what -- what the cut is of that, and you'll be checking that then against manual readings., grind-outs (ph), at least -- well, how frequently or when or -- all the time or occasionally or just initially? MR. ROSSBERG: We would -- we would do that initially upon commissioning a test facility until we're satisfied that the tests we're getting are indeed within the requirements ..... MR. SMITH: Yeah. I ..... MR. ROSSBERG: ..... set up of ..... R & R COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277.0573 277~8543 272-7515 ANCHORAGe, ALASKA 99501 l0 12 13 14 16 17 19 20 2! 22 23 24 25 MR. SMITH: ..... think we'd ..... MR. ROSSBERG: ..... our testing program. MR. SMITH: We'd -- we'd like to see something like that I think to see -- to validate the system since it is pretty new. It's a new approach to -- to handling that. It appears to be -- have all the answers, but the -- I -- I know operationally you -- there's bound to be some snags in there somewhere. For -- just for instance, if -- if it didn't work, then -- then you're back to a manual system, right? MR. ROSSBERG: Well ...... 46 MR. SMITH: If there was something wrong -- ma3or with it? MR. ROSSBERG: We're -- yeah, we're back -- with our facility set up the way it is, I guess our -- our fall back position is manual testing, but we wouldn't, you know, -- we've got other options. The three-phase separation, other meters. MR. SMITH: Okay. MR. ROSSBERG: There are several different approaches that we could take. MR. CHATTERTON: May I interrupt right there, Lonnie, please? MR. SMITH: Okay. MR. CHATTERTON: You say three-phase separation. I think I remember you testifying some place that you might form R & r cOUrt REPORTERS 81ON STREET, SUITE IO1 509W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AVENUE 272-75 ! 5 10 12 16 17 2O 2! 22 23 24 25 quite an emulsion. How do you three-phase ..... MR. ROSSBERG: You need heat. 47 MR. CHATTERTON: ..... a highly emulsified ..... ? MR. ROSSBERG: We'd need to have a lot more retention time and -- and the addition of heat and ..... MR. CHATTERTON: You sure ..... MR. ROSSBERG: ..... probably a ..... MR. CHATTERTON: ..... would, ..... MR. ROSSBERG: ..... chemical breaker. MR. CHATTERTON: ..... wouldn't you? MR. ROSSBERG: Yeah. MR. CHATTERTON: You bet. Yeah. MR. ROSSBERG: That's what we see as one of the advantages to this system is that we don't have to worry about breaking this emulsion at the pads. MR. CHATTERTON: Right. Okay. Thank you. Go ahead, Lonnie. MR. SMITH: Well, the -- the accuracy here of determining your -- your volume on the well test, and your water cut, it -- it appears to be quite -- quite high on reading this material. How will that compare with what you're now doing in the Kuparuk that you're co- -- going to commingle this with? MR. ROSSBERG: Our Kuparuk test system is generally within plus or minus 10~ ..... MR. SMITH: Okay. r & R COURT REPORTERS 81ON STREET, SUITE IO1 509W. 3RD AVENUE 277-0572 - 277-O573 277-8543 aNChORaGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-75 ! 5 l0 12 13 16 17 19 20 2! 22 23 24 25 48 MR. ROSSBERG: ..... of total sales volume. When you sum the tests, it's -- it's within plus or minus 10~, which is the same tolerance that we're allowing in the Trader Bluff pool. MR. HASTINGS: Lonnie, we just went through and looked at the last 11 months of data on our Kuparuk system, and the average over that 11 months was something like 95.6, in comparison of the well test total to the flag meter (ph). And there's a copy of that in -- in that letter there. MR. SMITH: In -- Okay. So is that to be an exhibit or a submission or what? That's just a ..... MR. HASTINGS: We -- we submitted it separately. MR. SMITH: Okay. MR. CHATTERTON: And that is what you've chosen -- wish to ..... MR. SMITH: (indiscernibler simultaneous speech) MR. CHATTERTON: ..... be held as confidential? MR. HASTINGS: No, that information is publicly available. There's just a sheet in there (indiscernible), yes. MR. CHATTERTON: Do you have any objection to entering that into the record? MR. HASTINGS: No. MR. SMITH: Make it Exhibit Three. MR. CHATTERTON: We -- if I could interrupt you. Al, would you mind explaining what this is and -- and we'll enter r & r court REPORTERS 8 ! 0 N STREET, SUITE 10 l 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AVENUE 272-75 ! 5 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 49 it in -- whatever it is, we'll enter it into the record as an Exhibit Number Two I guess? MR. SMITH: Three. MR. CHATTERTON: Three. Exhibit Number Three. (Exhibit 3 marked) MR. HASTINGS: And it's -- it's a summary of totalling the individual well tests times the days they produced per month and compared that to the flag metered volume that entered the pipeline, and we did it for the last 11 months that we've been on production, and the average over that 11 months of well test to black (ph) metered value was 95.6~ I believe. I don't have a copy of it in front of me. MR. CHATTERTON: Tom (ph), you have -- 'there you are. And if anyone has any questions, please contact A1 Hastings at 564-7650 ...... MR. HASTINGS: That's the (indiscernible, simultaneous speech) MR. CHATTERTON: ..... Okay. Thanks, Al. We will enter this into the record as Exhibit Three. And it is a letter with attachments from David L. Bowler, Division Manager for Conoco, and addressed to Chatterton with the Oil and Gas Conservation Commission. So done. Lonnie, any ..... MR. SMITH: Yes. Steve, I have another question here. On the -- this surface safety shut down proposal to R & R COURT REPORTERS 810 N STREet, SUITE ! 01 509 W. 3RD AVENUE 277-O572 - 277-O573 277-8543 ANCHORAGe, ALASKa 99501 007 W, 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 50 prevent uncontrolled flow of hydrocarbons. Is that -- does that work off of a pressure system on the flow line itself, or ..... MR. ROSSBERG: What -- what we're currently what our -- what our plan is, or most recent plan, is to have two master valves, a three-wave valve and then an actuated win9 valve, which you'd have two -- basically two safety backups. You'd have your -- you know, your secondary master valve, and the actuated valve on the wing downstream of the three-way valve. MR. SMITH: Okay. But what -- how do you actuate them? MR. ROSSBERG: We -- we basically want to leave that open to our discretion, either pneumatically or hydraulically or possibly electrically. MR. SMITH: Well, that's -- you mentioned that. That's the -- the -- mechanically the way you did, but what does it operate off of? I mean, ..... MR. ROSSBERG: Oh. MR. SMITH: ..... manual, throwing a switch somewhere, or a pressure monitoring of a ..... MR. ROSSBERG: It would be ...... MR. SMITH: ..... certain line? MR. ROSSBERG: ..... pressure monitoring on the ..... MR. SMITH: On the flow line? MR. ROSSBERG: On the flow line. r & R COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANChORAGe, ALASKA 99501 007 W. 3RD AVENUE 272-75 ! 5 10 12 14 16 17 19 20 2! 22 23 24 25 51 MR. SMITH: Of each well? MR. ROSSBERG: Right. MR. SMITH: Okay. Thank you. I think that covers it for me, Chat. Do you have some? MR. CHATTERTON: All right. I proposed that we take about a ten-minute break, and you two gentlemen, please, if you -- at the end of break, if you'd return here and see if we have any more questions that we catch you while you're here? MR. ROSSBERG: All right. MR. CHATTERTON: Give your voice a chance to rest. Okay. Meredith, I guess we're off the record, or however you do it. (Off record) (On record) MR. CHATTERTON: All right. We're all gathered -- gathered back, aren't we? Okay. Let's go back on the record, Meredith. COURT REPORTER: On record. MR. CHATTERTON: After taking a ten-minute b~eak, why, we're back on the record with this, and we have Conoco representatives before us, and again, Lonnie, do you have any questions of them? MR. SMITH: No further questions. MR. JOHNSTON: The -- on page 15 you indicated with reference to your casing design that you were going to R & R COURT REPORTERS 810 N STREET, SUITE l O 1 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AVENUE 272-75 ! 5 l0 12 14 16 17 19 20 2! 22 23 24 25 52 cement 500 feet above the Prince Creek K sand. Is that your shallowest known zone of hydrocarbons? MR. ROSSBERG: It's water bearing sand. MR. JOHNSTON: Yeah. MR. CHATTERTON: Well, -- do you ..... MR. JOHNSTON: Yeah. MR. CHATTERTON: That -- that does it? Well, why -- why we were on a break, why, we were furnished questions that we'll address following the release of you two people by the Commission for testifying or answering our questions I guess. And if anybody else wants to put -- and whether or not anybody else wants to put something into the record or not, why, we'll then catch your questions. I would appreciate -- I have two sheets of paper here with questions on them. I know who submitted the one, but would the other person identify theirselves, please? And you could proceed to come up and do it, if you'd like? UNIDENTIFIED: Okay. MR. CHATTERTON: Ali. right. UNIDENTIFIED: Do you want me to read the questions? MR. CHATTERTON: We don't need to do it right now, but so we can address those questions. Gentlemen, I'd like to have you flesh out my current understanding of what the Schrader Bluff Oil Pool consists of. R & R COURT REPORTERS 81ON STREET, SUITE 101 509W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORaGe, ALaSka 99501 007 W. 3RD AVENUE 272-7515 l0 12 13 14 16 17 19 20 2! 22 23 24 25 53 As I remember from the testimony here, why, you have defined it as far as the vertical limits, top and bottom of the zone, and -- but -- and as I understand that, those depths that you have put forth there, they are basically what are depicted on Figure Two of Exhibit One, ..... MR. DAVIES: Um-hm. MR. CHATTERTON: ..... and labelled as sands within the cretaceous, and you have -- and your designation of them, are the N sand and the 0 sand. The two sands immediately occurring beneath an unconformity. And I understand further that the oil-bearing sands beneath the unconformity basically contain 14 to 20 gravity -- API gravity oil, and above that unconformity, the -- from 10 to 13 API gravity oil. Now, these N sands as you depict them here on Figure Two of Exhibit One, with subdivisions of Al~ B, D, D, and E and F, do they extend, the stratigraphic equivalent of those sands extend over a vast area of -- of the Slope up there, of the Milne Point Unit~ the Kuparuk River Unit, the Prudhoe Bay Unit? MR. DAVIES: The N series sands themselves are well developed within the Milne Point Unit, but they are quite thin. They do, based upon current well control, appear to have great degree of lateral continuity. The extend, based on correlations that I have done at least into the northern portion of the Kuparuk River Unit. I have not personally tried to tract them down towards the central and southern portion of the Kuparuk R & R COURT REPORTERS 810N STREET, SUITE lO! 509W. 3RD AVENUE 27740572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-7515 l0 12 13 14 16 17 19 20 2! 22 23 24 25 54 River Unit, however, I do know that on -- based on published data by an ARCO geologist, Werner, in 1984 -- 1987, what I understand is there is some sort of facies change that occurs, and these sands do fade out towards the south and become a mudstone, shale sequence. So they do seem to be areally limited towards the south, and probably the southwest. Now, towards the north as far as our well control extends, they continue on in that direction. The same thing towards the east. MR. CHATTERTON: And the O sands as depicted in your figure two of Exhibit One, how far can you -- do they extend areally? MR. DAVIES: They extend throughout the Milne Point Unit. They are developed, again, in at least the northern portion of the Kuparuk River Unit. I do believe that they extend southward through the central portion of the Unit, but that's the extend of my knowledge. MR. CHATTERTON: Yes. MR. DAVIES: They are, however, well developed within the Milne Point Unit area. MR. CHATTERTON: Right. You generally accept Werner's depiction of the extent of what I think are these sands that he depicts on ..... MR. SMITH: Figure Three? MR. CHATTERTON: ..... Figure Three of -- of Exhibit One? Do you have that? R & R COURT REPORTERS 810N STREET, SUITE 101 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD Avenue 272-7515 10 12 13 14 16 17 18 19 20 2! 22 23 24 25 55 with that ..... MR. DAVIES: Yes. MR. CHATTERTON: You -- you concur fairly well MR. DAVIES: Yes. MR. CHATTERTON: ..... picture? MR. DAVIES: Yes. The sands themselves probably extend a little further than this. This -- what's outside here in the stippled pattern is the actual oil accumulation. MR. CHATTERTON: Right. MR. DAVIES: So that does not necessarily equate to the depositional edge of the sands themselves. MR. CHATTERTON: Now, looking at Figure Three of Exhibit One, it indicates that the oil/water contact is in -- in this West Sak oil accumulation, quote/unquote, occurs around 4500 sub- -- vertical subsea. I think you testified that it may go down to 4800 feet vertical subsea? MR. DAVIES: No, 4800 feet vertical subsea is what we pick as the lower limit of the O interval on the A-one type ..... MR. CHATTERTON: Okay. MR. DAVIES: ..... log presented ..... MR. CHATTERTON: And not necessarily oil/water contact? MR. DAVIES: That's correct. That's correct. MR. CHATTERTON: That indicates that the portions R & r COURT REPORTERS 810 N STREet, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 ! 007 W. 3RD AVENUE 272-75 ! 5 l0 12 14 16 17 19 20 21 22 23 24 25 56 of the pool lying beneath the Milne Point within the confines of the Milne Point Unit actually range from a depth, vertical to vertical depth, indicated here of 4500 to 3500. About 1,000 feet difference in vertical depth. And even up to -- extending beyond the Milne Point Unit, even up to vertical subsea depths of 2200 feet? MR. DAVIES: Yes. MR. CHATTERTON: Now, roughly -- roughly what is the temperature gradient, geothermal gradient in -- in this area? Do you happen to know off hand? MR. DAVIES: No, I don't happen to know. MR. CHATTERTON: All right. You have testified that -- your portion of the -- or one of you gentlemen have, occurs -- the temperature of -- of this -- this interval is around 90 degrees, did I remember that ..... ? MR. ROSSBERG: That -- that's correct. MR. CHATTERTON: That's correct. Do you happen to know what the temperature -- reservoir temperature would be of the -- those equivalent sands up in the Kuparuk River Unit? MR. ROSSBERG: I --well, I do know that as you can see that as the reservoir -- going from the Kuparuk River Unit to Milne Point is -- is sloping down dip, and we're con- -- we're picking up considerable depth, and based on that, we assume that the temperature at Milne Point is considerably warmer than what it is further up dip in the Kuparuk River Unit, which would R & R COURT REPORTERS 8 ! 0 N STREET, SUITE ! O1 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGe, ALASKA 9950! 1007 W. 3RD AVENUE 272-75 ! 5 10 12 14 16 19 20 2! 22 123 24 25 57 further indicate that the viscosity of the oil contained within the N and 0 series sands at Milne Point is of probably less viscosity than what we're seeing -- than what is seen further up dip in the reservoir, which would indicate essentially that there could be completely different recovery mechanisms employed in the two areas. MR. CHATTERTON: Basically because of the temperature difference? MR. ROSSBERG: The temperature and corresponding viscosity, differences. MR. CHATTERTON: Okay. And the -- which affects the mobility? MR. ROSSBERG: That's right. MR. CHATTERTON: In other words, you -- you might wish to use one form of depletion, of reservoir depletion, in -- in the warmer area as compared to a colder area? MR. ROSSBERG: That's correct. That would dictate probably well spacing, waterflood patterns, total number of wells needed to drain -- economically drain an area. In essence it is a -- it is the -- the same sands, but essentially different reservoirs. And that's -- that's our interpretation. MR. CHATTERTON: Although that being separate pools, synonymous with being separate reservoirs, it's not apparently a proved fact yet. Maybe or it may not be widely accepted. I guess if there -- there is a pressure differ- -- is R & r COURT REPORTERS 810N STREET, SUITE IOI 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-7515 l0 12 14 16 17 19 20 2! 22 23 24 58 there communications between the sands in the Milne Point Unit and the sands in the Kuparuk River Unit, for instance? Or even the sands within the Prudhoe Bay Unit? Is it a closed -- are we definitely sure that -- that they're not pressure connected? MR. ROSSBERG: I -- I would hypothesize that due to the faulted nature and that fault system running from -- essentially from west to east,across the -- the base of the Milne Point Unit, would in all probabilities be a barrier to pressure communication. MR. CHATTERTON: Okay. MR. ROSSBERG: But we -- we don't have any pressure data that -- that tells us otherwise. MR. CHATTERTON: Okay. MR. ROSSBERG: We haven't seen any depletion. Our wells are basically at normal pressure, but we don't necessarily have the data to confirm that either. But ..... MR. CHATTERTON: Okay. MR. HASTINGS: We know that -- we know that some of the faults are -- are barriers to fluid migration because of different oil/water contacts. We don't know yet which of those faults are, or where they're necessarily located. We do know that some are and that some are not. So we cannot absolutely say at this point in time which faults will be barriers ..... MR. CHATTERTON: Right. MR. HASTINGS: ..... and which will not. r & R COURT REPORTERS 810N STREET, SUITE 10! 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, aLASKA 9950! ! 007 W. 3RD AVENUE 272-75 ! 5 10 12 14 16 17 20 2! 22 23 24 59 MR. CHATTERTON: Regardless, why, devel- -- development of pool rules for one area of this accumulation that is show on Figure Three of Exhibit One and the source is Werner in a 1987 rendition, again as fair as reservoir management in those two areas, because of the temperature difference and the -- affecting the mobility, you may want to use different methods for -- for depleting those sands. Is that what I hear you gentlemen saying? MR. HASTINGS: I 3ust checked in this other source and the geothermal gradient out there below 3,000 is about three degrees per hundred. MR. CHATTERTON: Three degrees per hundred? MR. HASTINGS: So it's a fairly significant geothermal gradient. MR. CHATTERTON: Yeah. So that's 30 -- 30 degrees per thousand ..... MR. HASTINGS: Yes. MR. CHATTERTON: ..... feet. And we see depicted here a difference here a difference of almost two- -- 2,000 feet. MR. HASTINGS: What -- what we can do at the low end of the reservoir may be considerably different than what can be done ..... MR. CHATTERTON: yeah. MR. HASTINGS: ..... at the higher elevation R & R COURT REPORTERS 8 lO N STREET, SUITE 10! 509W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 9950! 1007 W. 3RD AveNue 272-75 ! 5 l0 12 16 17 19 20 21 22 23 24 25 6O portion of the reservoir. MR. CHATTERTON: Is -- is it much more difficult to control production as the viscosity of the crude oil increases? MR. ROSSBERG: Yeah. We -- we see that as a significant advantage of having the less viscous -- viscous fluid, should be less of a problem in sand control, and that's I think demonstrated by the fact we -- we haven't seen any significant sand production in the 0 sands, which are less viscous than the higher N sands where we do have a sand control problem, ..... MR. CHATTERTON: Okay. MR. ROSSBERG: ..... which is probably tied directly to the viscosity of the crude, which MR. CHATTERTON: Very good. Thank you. The -- I read some testimony that was given to the -- before the Legislature back in the middle ?Os regarding grass roots units and their purpose. Any of you gentle- -- gentlemen ever happen to check that? MR. HASTINGS: No, I haven't. MR. CHATTERTON: It -- and -- and I guess, is the Milne Point Unit a grass roots unit? MR. DAVIES: I'm ..... MR. HASTINGS: As far as ..... MR. DAVIES: ..... not sure. R & R COURT REPORTERS 8 ! 0 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 ].2 14 16 17 20 2! 22 23 24 surface ..... MR. HASTINGS- . .... I know it is. MR. CHATTERTON: Okay. MR. HASTINGS: I think the leases run from 61 MR. CHATTERTON: Right. MR. HASTINGS: ..... down. MR. CHATTERTON: The testimony that I read as I recall it, of what I read, I guess, indicated that the State of Alaska strongly favored grass roots units, and basically for the sharing of common production facility, regardless of where -- where the fluid came from. With these large extensive -- or areally large areal extensive units that we have, being a grass roots unit, why, it means that you're going to have a good chance of different pools occurring that are not superimposed upon one another. And, of course, carrying that thought forward, why, the -- your concept of commingling, why, would be consistent with that earlier interpretation of grass roots units. I 3ust toss that into it, to the -- to our testimony here. Anybody wishing to further -- I --I -- you might as well sit there, but technically -- is there anybody wishing to present any testimony or written testimony, or anyone else that wishes to test- -- to testify? Lacking any indication, are there any persons out there that wish to make an oral statement at this time? Did I see a hand? No? Okay. R & r cOUrt RePOrTERS 8 ! 0 N STREET, SUITE 101 509 W. 3RD AVENUE 277-0572 - 277-O573 277-8543 ANCHORAGE, aLASKA 99501 1007 W. 3RD AveNuE 272-75 I 5 10 !2 !3 !4 !5 !6 !7 !9 20 2! 22 23 24 62 MR. BRUSH: The next level you get to. MR. CHATTERTON: Ail right. Then I guess the next thing is that we do have some questions from the ..... MR. BRUSH: We have ..... MR. SMITH- He -- he has a ..... MR. BRUSH: ..... a written statement. MR. SMITH: ..... he has a statement ..... MR. BRUSH: A written ..... MR. SMITH: ..... to enter, but no ..... MR. BRUSH: ..... statement, not ..... MR. SMITH: ..... he doesn't want to ..... MR. BRUSH: ..... testimony. Not -- not -- it will not be entered orally, but just submitted as a written statement regarding this. MR. CHATTERTON: Okay. Do you want the statement entered into the record, hopefully? MR. BRUSH: Yes. MR. CHATTERTON: Yeah. Okay. Let's excuse you two gentlemen for a minute, and then come on up, please, and so do. ~ MR. BARON: The -- the same goes for BP. We'd like to submit a written statement. MR. CHATTERTON: All right. Excellent. Would you identify yourself? MR. BRUSH: My name is Randy Brush. I'm an R & r cOUrt rEPOrTERS 8ION STREET, SUITE 101 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 !2 !3 !4 !6 !7 !8 !9 20 2! 22 23 24 25 engineer with ARCO Oil and Gas Company. And I have some written statement to be entered into these proceedings. MR. CHATTERTON: Okay. Would you be willing to read -- read that into the record? MR. BRUSH: Sure. MR. CHATTERTON: Okay. Please sit down and -- and so do. MR. BRUSH: Okay. This is a letter to Mr. Chatterton from Jerry Pollock -- Pollock, manager of Kuparuk Engineering. "Dear Mr. Chatterton: Listed below are ARCO Alaska's comments regarding Conoco's Schrader Bluff Pool Schrader Bluff Pool Rules submission. We are submitting this letter as a written statement at today's public hearing. ARCO Alaska, Inc., is not making an oral -- oral statement because the rules, as drafted by Conoco, are acceptable if applied to the Schrader Bluff Pool contained within the Milne Point Unit. ARCO would like to point out the differences between the pool rules Conoco has proposed to apply to the Schrader Bluff Pool, which according to their draft submission incorporates the Ugnu K-13 and Upper West Sak sands, using ARCO's nomenclature, within the Milne Point Unit, and the pool rules ARCO expects to propose for development of the West Sak sands, which would include the Upper and Lower West Sak sands, in the Kuparuk River Unit. Because the West Sak sands in the Kuparuk River Unit r & r COURT REPORTERS 810N STREET, SUITE IO1 509W. 3RDAVENUE 277-O572 - 277-O573 277-8543 ANCHORAGE, ALASKA 99501 ! OO7 W. 3RD AVENUE 272-7515 l0 14 16 17 20 2! 22 23 24 64 differ substantially from the Schrader Bluff resource, different rules will be required to govern the KRU West Sak development. We understand that the AOGCC will allow different pool rules to be applied to the KRU West Salk development if 3ustified by the ARCO's submissions to the AOGCC at that time. ARCO's comments on Conoco's Schrader Bluff Pool rules · submission is -- are as follows: ARCO anticipates proposing a well spacing value in the KRU that is less, potentially much less, than the 40-acre value contained in ARCO's (sic) submission. This was the draft submission. This is because of the markedly different reservoir character of the West Sak sands in the KRU, with lower reservoir continuity and higher oil viscosities requiring tighter well spacing. What that spacing might be is under evaluation. ARCO supports the adoption of rules allowing for the allocation of oil production between reservoirs producing through common facilities. ARCO anticipates that the specific allocation procedures that it will propose for the KRU West Sak development will differ in detail, such as testing frequency, from those submitted by Conoco. ARCO understands that the AOGCC will determine these procedures on a case-by-case basis. Finally, ARCO anticipates proposing less elaborate automatic well shut-in equipment than has Conoco. The KRU West Sak wells will likely be unable to flow to the surface unassisted. R & R COURT REPORTERS 810N STREET, SUITE lO! 509W. 3RDAVENUE 277-0572 - 277-O573 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD aVENUE 272-75 ! 5 l0 14 16 17 19 20 2! 22 23 24 65 Please contact Kevin Meyers, 265-6156) if there are any questions regarding these comments. Very truly yours, J. R. Pollock. MR. CHATTERTON: Thank you very much. We shall enter that into the record as Exhibit Four. (Exhibit 4 marked) MR. CHATTERTON: Thank you very much. Next? MR. BARON: My name is Paul Baron. I'm a senior reservoir engineer with BP Exploration here in Anchorage. This letter to be entered as -- as an exhibit is from BP Exploration to Mr. Chatterton. It's from Allen Leske, Manager of Kuparuk and Shallow Sands in BP Exploration. "Dear Mr. Chatterton: BP Exploration Alaska, Inc., is submitting this letter as a written statement at today's public hearing. We are not making an oral statement because the rules as drafted by Conoco are acceptable if applied to the Schrader Bluff Pool contained within the Milne Point Unit. We would like to point out that there will be differences between Conoco's proposed Schrader Bluff Pool Rules and any future -- future pool rules proposed by ARCO for development of the West Sak sands in the Kuparuk River Unit, KRU, since the West Sak sands in the KRU differ substantially from the Schrader Bluff resource. We understand that the AOGCC will allow different pool rules to be applied to the KRU West Sak development, if 3ustified by submissions to the AOGCC at that time. R & R COURT REPORTERS 81ON STREET, SUITE lO! 509W. 3RD AVENUE 277-O572 ~ 277-0573 277-8543 ANCHORAGe, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 l0 12 13 14 16 17 20 2! 22 23 24 25 66 Please contact Allen Garon, 564-4077, if there are any questions regarding these comments. A.E. Leske, Manager, Kuparuk/Shallow sands." MR. CHATTERTON: Thank you very much. And we'll accept that and put it into the record as Exhibit Five. (Exhibit 5 marked) MR. CHATTERTON: All right. I believe that comes -- you -- you two gentlemen, Steve, you -- you all may want to come back here, 'cause we'll -- we'll see if we can get to these questions here. Okay. We have a question here, and -- well, asking this: And it is directed to us from Mike Kotow- -- Kotowski. And the question, why is plus or minus 10~ acceptable and not three to 5% ever? Why not a more strict error band requirement? MR. ROSSBERG: Conoco as -- as an operator and generally within the industry, plus or minus 10~ is accepted as a reasonable value for test systems when compared to actual lact (ph) sales meters. As was entered into the record by Mr. Hastings, our actual factors in the Kuparuk are much tighter than that. We've got an error of plus or minus 4~, indicating that our -- our systems actually function better than the -- the band that we're proposing in the pool rules. However, we believe for reservoir management purposes and general monitoring of production and allocation that the plus or minus 10~ is a -- is a reasonable factor. R & r COURT REPORTERS 810 N STREET, SUITE I0! 509 W. 3RDAVENUE 277-O572 - 277-O573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVENUE 272-75 ! 5 l0 13 14 16 17 19 20 21 22 23 24 25 MR. CHATTERTON: You don't need any more -- any closer tolerance for reservoir management purposes in other words? MR. ROSSBERG: That is correct. We feel that that is sufficient. MR. CHATTERTON: Okay. MR. HASTINGS: Chat, I believe this plus or minus 10% was a comparison of one test to the second test that we get in a month, and I think if -- if you would do the statistics on what a plus or minus 10% does on a whole series of well tests compared to what the -- the ultimate answer is, I -- when you combine all these, you'd find that a plus or minus 10% when you do the combination of all that, you're -- you're getting to the -- to the 5% range or so, if you -- if you do the statistical analysis of that. A 10% variation on any one variable if you combine a whole series of variables that were within 10%, when you get to the end of that, you've got something less than 10% if you do 'the statistics. MR. CHATTERTON: Do you think it's even possible to get, other than rare exceptions, to get down to this three to 5~ error? MR. ROSSBERG: It -- to consistently be at 3% would be difficult just by the fact that no matter how hard you try to size your lines accordingly to maintain the same pressure on your test system that you're operating at, it's -- it's very r & R court REPORTERS 81ON STREET, SUITE IO1 509W. 3RDAVENUe 277-0572 - 277-0573 277-8543 ANCHORAge, ALASKA 9950! 1007 W. 3RD AVENUE 272-7515 l0 13 14 16 17 19 20 2! 22 23 24 68 difficult to achieve that within the limits that would give you a 3% accuracy versus your sales volumes. I think to be within 5% of two tests on a given well during a month is well within reason. We expect that. MR. CHATTERTON: Okay. The next question from Mike is if the well test allocation volumes for any -- any given 24-hour period are plus or minus 10% different from the sales meter, how does Conoco propose to resolve the volumes between the Kuparuk pool and the Schrader Bluffs pool? MR. ROSSBERG: Let me ..... MR. HASTINGS: I can ..... MR. ROSSBERG: Go ahead, Al. MR. HASTINGS: ..... I can answer it. The way the system will work, we'll have the individual well tests from the Kuparuk River wells, we'll have the individual well tests from the Schrader Bluff pool. All these will total -- totalled for the whole month based on hours produced in the average , individual well test. This total will add up to some volume of amount of oil that goes through the black (ph) meter will have -- be some volume. The ratio of that will be applied to all the wells, and then whatever the difference is, that four or 5% will be applied equally back to the wells. MR. KOTOWSKI: Am I allowed to speak? MR. CHATTERTON: You may direct another question to the Commission, and if we think it's germane, we'll ask it, R & R COURT REPORTERS 8 ! O N STREET, SUITE 10 ! 509 W. 3RD AVeNUE 277-O572 - 277-0573 277-8543 ANCHORAGe, ALASKA 9950! 1007 W. 3RD AVENUE 272-7515 10 !2 !3 !4 !6 !7 !8 20 2! 22 23 24 25 69 following the regulation here. So you can write it out and ..... MR. KOTOWSKI: No, that's fine. I -- I think -- I think we'll have an opportunity to address this issue in another forum, so -- so that's ..... MR. CHATTERTON: All right. Fine. We have some questions from Mike -- Mark Myers with the -- the OG's staff geologist, and let's see if we can run down through these. There's three questions in all. What data do you have to support your conclusion that the O sands are separated by ceiling faults from the West Sak sands in the Kuparuk River oil field? I think we -- that's been answered, hasn't it? MR. MEYERS: (Nods affirmative) MR. CHATTERTON: I get an affirmative from Mark. Do age dating techniques have -- I can't even pronounce this stuff. MR. MEYERS: Palynology, paleontology. MR. CHATTERTON: Palynology and -- and -- okay. Dating of glauconite ETC support putting a significant unconformity between the N and the M sands? I'll direct that to you. MR. DAVIES: Dating of the glauconite? That's ..... MR. CHATTERTON: Yeah. MR. DAVIES: ..... question two? What the R & R COURT REPORTERS 810 N STREET, SUITE 10! 509W. 3RDAVENUE 277-0572 - 277-0573 277-8543 ANCHORAGE, ALASKA 99501 007 W. 3RD AVeNUe 272-75 ! 5 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 70 question is asking is whether or not we have substantial data to support putting an unconformity at the top of the N sands. What we have is limited at this point. Conoco has not done any direct micropaleontology or palynology studies itself. We have to rely on published data, primarily by ARCO as referenced in the papers by Werner, 1984 and 1987. Log correlations of the well control that we do have at Milne Point suggest that there is some sort of surface at that point. It appears to change a bit in terms of character, so we think it is an erosional surface. We did commission an apatite fission (ph) tract study, which is a technique like vitronite (ph) reflectants, which gives you a geothermal profile, a geothermal history for an area. Based on the outcome of that study, we see a significant shift in the relict (ph) geothermal profile at that point. We feel that's enough to substantiate the occurrence of an unconformity at the top of those sands. MR. CHATTERTON: Okay. Would you like to read question three? MR. DAVIES: Question number three is are there diogenatic complications which decrease reservoir continuity, calcite, cement, et cetera? There are some thin calcite cemented layers within the O sands, OA and OB. Their exact continuity is unknown at this point. Their lateral persistence is also unknown. That's something that will be checked as we get more R & R COURT REPORTERS 810 n STREET, SUITe i01 509W. 3Rd AVENUE 277-0572 - 277-0573 277-8543 ANCHORAGe, aLASKA 99501 1007 W. 3RD AVENUE 272-75 ! 5 10 12 14 16 17 20 2! 22 23 24 detailed well information. As far as other complications, I know of none at this point. 71 MR. CHATTERTON: The fact that there seems to be a vast difference if gravity of the crude oil found in the M sands versus the N sands, would it further support a concept of a nonconformity occurring there? MR. DAVIES: To me it does. It indicates that there is some sort of physical boundary at that point. Whether it's a boundary to the percolation of ground waters and the support of bacteria to biodegrade the oils which stops at that surface, I'm not sure. But it does appear just based on oil gravity itself that there is some sort of boundary at the top of the N sands. MR. CHATTERTON: Okay. Thankyou. Are there any other questions from anyone that you'd like to direct to the -- have the Commission direct to these people? Well, is there anything else to come before in -- in this gathering that anyone likes -- would like to volunteer? Very good. I guess the time is about 11 -- 11:10 on this day, and we will -- a.m. I might add, and I guess we'll just call this hearing to a close. And thank you all. for attending and testifying. Appreciate it. (END OF PROCEEDINGS) r & R COURT REPORTERS 810N STREET, SUITE lO! 509W. 3RD aVENUE 277-0572 - 277~0573 277-8543 ANCHORAGE, ALASKA 9~501 1007 W. 3RD AVENUE 272-7515 10 ]! 12 13 14 15 16 17 18 19 20 2] 22 23 24 25 ?2 C E R T I F I C A T E UNITED STATES OF AMERICA ) ) ss STATE OF ALASKA ) I, Meredith L. Downing, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Electronic Reporter for R & R Court Reporters, Inc., do hereby certify: THAT the annexed and foregoing Public Hearing was taken before me on the 31st day of May, 1990, commencing at the hour of 9:00 o'clock a.m., at the offices of the Alaska Oil and Gas Commission, 3001 Porcupine Drive, Anchorage, Alaska, pursuant to Notice. THAT the witnesses, before examination, were duly sworn to testify to the truth, the whole truth, and nothing but the truth; THAT this Transcript, as heretofore annexed, is a true and correct transcription of the testimony given at said Public Hearing, taken by me and thereafter transcribed by me; THAT the original of the Transcript has been lodged as required with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska. THAT I am not a relative, employee or attorney of any of the parties, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 18th day of June, 1990. My Commission Expires: SEAL RECEIVED JUN 1 8 1990 Alaska Oil .& Gas Cons. Gommis$ion Anchorage R & r COURT REPORTERS 81ON STREET, SUITE 101 509W. 3rDAVENUe 1007 W. 3RDAVeNUE 277-0572 - 277-O573 277-8543 272-7515 ANCHORAGE, ALASKA 99501 R E C [.:,'.IV E, b' j RECEIVE:> iV~'iAy 5~ !. 1990 ,:kf~ska Oil & fias Oonso gommissior~' iONOCO/AOGCC PUBLIC HEARING MAY 31, 1990 ATTENDANCE SHEET NAME COMPANY CONSERVATION ORDER 255 MILNE POINT UNIT TESTIMONY FOR SCHRADER BLUFF POOL RULES MAY 31, 1990 · .::!'i~J~ka .0~1 ~& [las Cons. Commi$~io~, '~'.~ gnchora~ INTRODUCTION GEOLOGICAL DISCUSSION RESERVOIR DESCRIPTION RESERVOIR SURVEILLANCE WELL PLANNING FACILITIES DESCRIPTION CONCLUSION REFERENCES TABLE OF CONTENTS AND PROJECT SCHEDULE Paq.e 1 2 6 11 15 17 18 19 LIST OF TABLES Table No. 1. Log Analysis Data Base 2. Oil/Water Contact Depths by Sand 3. Well Test Summary ii Figure No. 1. 2. 3. 4. 5. 6. 7. 8. LIST OF FIGURES Index Map SOS Nomenclature SOS Regional Structure Map SOS Milne Point Structure Log Porosity vs. Core Porosity Core Permeability vs. Core Porosity Tract 14 Map Anticipated Production Schedule iii APPENDICES I. sos Correlation Sheets INTRODUCTION The purpose of this testimony is to provide support for establishment of pool rules for the Milne Point Unit Upper Cretaceous resource. Conoco has prepared testimony in behalf of the majority Working Interest Owners in the Milne Point Unit. It is requested that the new pool be named the Schrader Bluff Pool, and the vertical limits of this proposed Pool are from 4174 feet to 4800 feet measured depth in Well No. A-1. The scope of this testimony includes a discussion of geological and reservoir properties as they are currently understood, as well as Conoco's proposed plans for reservoir surveillance, well planning, facilities installation and project scheduling. This testimony will enable the Commission to establish rules which will allow economical development of resources within the Schrader Bluff Pool. Confidential data and interpretation concerning the Schrader Bluff formation will also be furnished to the Commission as additional support for this testimony. Development drilling, roads, pipelines and facilities installation are scheduled to commence in early 1990, with initial production beginning by year end. Conoco requests the Commission to approve several key concepts which are considered essential for economic development of the Schrader Bluff Pool. These concepts are: 1) Waterflood initiation within 18 months after primary production is commenced. 2) Well spacing of 20 acres to allow flexibility in placement of wells for maximum recovery of reserves. 3) Waiver of the gas-oil ratio limitation 20 ACC 25.240(b) for a period of time not exceeding eighteen months from the date of initial sustained production. Should the gas-oil ratio increase above the current regula- tory limits, the intent of this waiver is to allow for a period of primary production prior to waterflooding. 4) Surface commingling of production from the Schrader Bluff Pool and Kuparuk River Pool. This testimony is intended to provide the Commission with sufficient information to formulate these rulings. The geologic portion of this testimony was prepared by Steve Davies, Staff Geologist, responsible for exploration and development geology in the Milne Point Unit area. Engineering testimony was prepared by Steve Rossberg, Senior Production Engineer, responsible for area engineering in the Milne Point Unit. GEOLOGICAL DISCUSSION Introduction This portion of the testimony will provide geologic data to the Commission in support of Conoco's proposed Schrader Bluff Pool. Geologic justification will be presented for limiting the vertical and areal extent of the pool. Stratiqraphic Nomenclature At Milne Point, the Upper Cretaceous and Lower Tertiary sandstones that are potentially oil bearing are generically called the Shallow Oil Sands (SOS). The type log for this interval at Milne Point is the Conoco A-1 well, which is located near the center of the unit (Figure 1). Figure 2 compares informal Milne Point nomenclature with that used by Arco in the Kuparuk River Unit. At Milne Point, the SOS are grouped into five intervals, which are named K, L, M, N and O, in descending order. The K and L intervals correspond to Arco's "upper Ugnu," and the M interval corresponds to the "lower Ugnu". Reservoir sandstones within the N interval are equivalent to the mudstone and shale sequence that lies at the base of the lower Ugnu in the Kuparuk River Unit (Werner, 1984). Interval "0" corresponds to Arco's "West Sak Sands". Major sandstone beds within each sequence are designated by the subordinate letters A, B, C, D, E and F. Thus, the two dominant sandstone beds in the upper "West Sak" of Arco are termed OA and OB within the Milne Point Unit. For this testimony, only the N and 0 sandstones will be discussed in detail. Stratigraphic Description 0 Interval The 0 interval occurs between 4,362 and 4,800 feet measured depth in the A-1 well. It consists of fine-grained sandstone and silty sandstone interbeddedwith siltstone and mudstone. These sandstone beds are medium to dark brown, moderately sorted,, friable, and have trace amounts of glauconite scattered throughout. They are generally massive, but have scattered, faint, horizontal laminae. Evidence of bioturbation is common, and shell fragments are rare. The OA and OB sandstone beds each range in thickness from 20 to 50 feet. These two beds dominate the 0 interval and have a high degree of lateral continuity. These sediments were deposited under shallow marine conditions in the distal portions of a delta. 2 N Interval In the A-1 well, the N interval is located between 4,174 and 4,362 feet measured depth. The sandstone beds of this interval are medium gray to dark brown, very fine- to fine-grained, poorly to moderately sorted, friable, and massive to interbedded. Trace amounts of glauconite occur within the N interval. Some portions of the beds are distinctly mottled in appearance, suggesting extensive bioturbation. Sandstone beds in this interval are typically quite thin, ranging from 5 to 20 feet in thickness. The NB sandstone is the thickest, reaching 33 feet in the southwestern portion of the Milne Point Unit. The N interval was also deposited along the margins of a large delta complex. Age of Sediments Based on micropaleontology and palynology studies by Arco, the N interval and the lowest portion of the M interval are thought to be Late Cretaceous (Maastrichtian) in age. The upper M interval and all of the K and L intervals are assigned to the Early Tertiary (Paleocene; Werner, 1987). Proposed Pool Name Formal North Slope nomenclature is shown in figure 2. By definition, the Schrader Bluff Formation is the uppermost marine unit of the Cretaceous in central Alaska (Detterman and' others, 1975). The sediments in the N and 0 intervals at Milne Point are Late Cretaceous, shallow marine, deltaic deposits. They should be collectively referred to as the Schrader Bluff Formation. The name Schrader Bluff Pool is proposed for oil accumulations within the N and 0 sandstones at Milne Point. Proposed Vertical Pool Boundaries The lower boundary of the Schrader Bluff Pool is placed at 4,800 feet measured depth in the Milne Point A-1 well. This depth marks the point of transition between the Schrader Bluff Formation and the thick shale section of the underlying Seabee Formation. The upper boundary of the pool is placed at a measured depth of 4,174 feet in the A-1 well. Detailed correlations of well logs place an unconformity at this point. A proprietary apatite fission track study commissioned by Conoco confirms the loss of section at this erosional surface. The unconformity is an important dividing line. Below it, the SOS reservoirs contain oil that ranges in gravity from 14 to 19.5 degrees API. Above it, the SOS contain thick, viscous oil ranging in gravity from 10 to 13 degrees API. The unconformity is also an important economic dividing line: oil trapped within the underlying N and 0 intervals is the target of current interest, while the more viscous oil in the overlying K, L and M intervals is a resource that will require additional cost and technology to recover. Structure The structure of the Schrader Bluff Formation is a homocline that dips 1 to 2 degrees to the east-northeast (figure 3). This homocline is a regional feature that extends from southwest of the Kuparuk River Field to the offshore area beyond the barrier islands. Figure 4 is a generalized structure map in the Milne Point area for the top of the NA sandstone. It shows the two sets of localized faults that cut the regional homocline. The first, which is dominant, trends north-south and has displacements ranging from 20 to 150 feet. Two-thirds of these faults are downthrown to the east, and the remainder are downthrown to the west. The second fault set trends northwest and has an average displacement of 40 feet. Three- quarters of these are downthrown to the northeast, with the rest being downthrown to the southwest. The current northeastern dip is the result of regional tilting in response to sediment loading as a massive system of deltas advanced from the Brooks Range toward the northeast during the Tertiary (Carmen and Hardwick, 1983). The faults that cut the Schrader Bluff are thought to have formed in response to this loading because of their dominant down-to-the-basin (east and northeast) geometry (Werner, 1987). Conventional seismic data is not capable of defining all of the faults within the Schrader Bluff, and refined structural interpretations will be developed as additional well data become available. Oil Accumulations The Schrader Bluff Formation contains tremendous quantities of oil. Combined oil-in-place estimates for the reservoirs within the Milne Point and Kuparuk River Units range from 15 to 25 billion barrels (Werner, 1987). Trapping Mechan isms The sandstones of the 0 interval are noted for their continuity throughout the Milne Point and Kuparuk River Units. Oil accumulated in these sandstone beds up- structure to the south and west where faulting provides the primary trapping mechanism (Werner, 1987). As with all of the Schrader Bluff sandstones, structural dip controls oil distribution to the north and east. Both structure and stratigraphy control distribution of oil within the N interval. The NA, NC and ND sandstone beds pinch-out up-structure to the southwest of the Milne Point Unit. The ultimate control over oil in these reservoirs is the up-dip sand limit. NB and NE are much more continuous, and faulting apparently controls the up-dip limit of their oil accumulations to the south and west in the Kuparuk River Unit (Werner, 1987, figure 7). ( 4 Controls over Oil Distribution The faults shown on figure 4 do not represent continuous individual faults. Rather, they depict fault zones that appear to control the Schrader Bluff oil accumulations. Current seismic control does not allow us to identify individual faults that are impermeable boundaries. However, different oil-water contacts in five of the six large blocks labeled on the map indicate that one or more faults within these zones separate the Schrader Bluff into isolated reservoir compartments. The north-south trending zone highlighted along the left margin of the map forms the western boundary of the Schrader Bluff Pool. It is composed of faults having 40 to 120 feet of displacement. This zone effectively separates reservoir compartment #6 from the Oliktok Point wells that lie to the west. These wells have very little pay in the N interval. North-south trending faults of similar magnitude form the zones that separate the six large reservoir compartments within the Milne Point Unit. Varying oil-water contacts demonstrate the sealing capability of these fault zones. The northwest-trending fault zone highlighted along the lower margin of the map comprises several faults. Displacement along these faults is not great, ranging from 30 to 140 feet. However, by analogy with the north-south trending fault system, these faults have sufficient displacement to separate and seal oil in the Schrader Bluff Pool from West Sak and Ugnu oil in Arco's Kuparuk River Unit. The largest and most continuous of these faults forms the southern boundary of the Schrader Bluff Pool. Summary The Schrader Bluff Formation in the vicinity of the Milne Point and Kuparuk River Units was deposited by a delta complex during the Late Cretaceous. Thestructure of the Schrader Bluff sandstones is a northeast-dipping homocline that is cut by north and northwest-trending faults. These faults divide the sandstones into six main reservoir compartments that are sealed from one another and from the West Sak and Ugnu oil that lies up-dip to the southwest. The name Schrader Bluff Pool is proposed for oil accumulated in these reservoirs at Milne Point. This name is in agreement with formal North Slope stratigraphic nomenclature. 5 RESERVOIR DESCRIPTION This portion of the testimony will summarize various reservoir properties necessary to perform volumetric calculations for determination of original oil in place (OOIP). Discussions of permeability, fluid properties, primary recovery mechanisms and recovery estimates are also included. Discussion will be limited to the Schrader Bluff Reservoir "N" and "0" series sands, which have tested oil of 14 degree API or higher. The upper series sands (K, L, and M)have large quantities of oil in place. With high in-situ viscosity and low API gravity (less than 14 degrees), development of these sands will require additional study and the application of a completely different recovery technique. Conoco requests 20 acre well spacing to allow flexibility in placement of wells to maximize recovery from the "N" and "0" series sands within the Schrader Bluff reservoir. Since projected recovery and flow rates are based on anticipated waterflood response, approval for implementation of a waterflood is also requested. Information contained in this section is intended to provide the Commission with sufficient justification to formulate these rulings. Porosity A detailed analysis including data from 26 wells (See Table 1) was conducted to determine effective porosity from well logs. This data base is considerably larger than the available core data base; therefore, logs were selected as the basis for determining porosity. Areal distribution of this data extends across the Milne Point Unit. The results were used in volumetric estimates of OOIP, determination of effective permeability, irreducible water saturation and oil saturation. A shale corrected neutron-density crossplot technique was used to calculate porosities. Crossplotting corrects for the effects of solid clay particles on the log readings. Shale correction eliminates that portion of the porosity filled with clay-bound water. In addition, logs were normalized to correct for systematic errors, such as tool miscalibrations or hole washouts. The resulting effective porosity values were used in determination of reservoir storage capacity and development of hydrocarbon-feet maps. Figure 5 is a plot of calculated log porosity versus core porosity utilizing data from well B-2, indicating a very good correlation between log-derived porosity and core porosity. Water Saturation Well logs were also used to calculate water saturations for the wells listed in Table 1. Core data is available from four wells in the Unit, and capillary pressure derived water saturations from Well B-2 were used to choose the most appropriate log analysis technique. The modified Simandoux technique provided the best match with capillary pressure derived saturations, and this technique was applied to the well data base shown in Table 1 to determine water saturation. This log technique accounts for clay bound water, which is suspected to be present in some of the sands, and is considered to be a more accurate determination of water saturation than core-derived data. All of the wells in Table 1 have electric logs that were corrected for hole diameter and standoff. True resistivity was calculated using standard published log correction charts. A water resistivity of 0.178 ohm-meters at 100 degrees F was calculated using 100% water saturated sands. This value was used as formation water resistivity in the log analysis. Reservoir Fluids and PVT Properties Reservoir pressure, oil gravity and temperature in the Schrader Bluff Pool vary widely within the unit. Fluid properties were calculated at various structural elevations using equations derived from published correlations. Based on this methodology, average values for fluid properties are as follows: Average Reservoir Pressure: Average Reservoir Temperature: Average Crude Oil Gravity: Bubble Point Pressure: Sol uti on Gas-Oil Ratio: Oil Formation Volume Factor (above bubble point): Oil Viscosity (reservoir temperature) 1,750 psig 90 degrees F 17 degrees API 1,388 psig 191SCF/STBO 1.06 bbl/STBO 300 cp Net Pay Determination For the purpose of the "N" and "0" series sands, net pay is defined as pay with a mobile oil saturation and permeability above 1 md. The oil/water contact is defined as the limit of mobile oil; therefore, the oil/water contact coincides with the zero net pay line. Figure 6 is a plot of core air permeability vs. porosity (MPU Well B-2) indicating that a permeability cutoff of 1 md results in a porosity cutoff of approximately 16%. The two distinct data groupings around 16% porosity suggest that sands and shales tend to segregate at this point. The water saturation cutoff of 62.5% was arbitrarily set to approximate the condition of residual oil saturation. Original Oil-In-Place Based on well control, areas of oil accumulation were divided into six major fault blocks (See Figure 4). Table 2 lists the oil water contact levels by sand in each fault block, indicating varying oil/water contacts in the different fault blocks across the structure. Appendix I contains correlations for each sand in each well. The pay zones within each well were identified using the net pay criterion discussed above. Within each pay zone, the values of net pay, effective porosity, effective water saturation and hydrocarbon-feet were calculated in each well according to procedures previously established in this testimony. The net effective pay values were entered into Conoco's computer mapping program (digitized on a 500' by 500' grid) and contoured on a sand by sand basis. The NEP contour maps treated the fault blocks as separate areas. The program forced the oil/water contact to the zero NEP contour and modified NEP trends in those locations accordingly. The result was that NEP trends near wells reflected the log analysis; while the contours between wells reflected regional trends. Contours approaching O/W contacts were closely gathered together, reflecting rapidly changing NEP values in the transition zone. The effective porosity maps were generated in the same manner, with the exception that trends were not truncated at the oil/water contact or by faults. Therefore, the effective porosity maps reflected more broad regional trends implied by the well data. The initial effective water saturation maps were computer generated (500' by 500' grid) directly from the porosity maps. Each porosity value was converted to effective water saturation by applying the initial water saturation equation previously discussed. As a control, the computer-derived saturations were checked with individual well locations and found to be in close agreement. The NEP, porosity and saturations maps were combined mathematically on 500' by 500' grids to produce HCF maps on the individual sands. The contours were planimetered within each four section tract (See Figure 4). Within each tract, the contours were planimetered separately within each fault block. HCF volumes were converted to OOIP by applying the factor 7758 divided by the oil formation volume factor. Permeability. Permeability ranges from 27 md to 5,896 md in the "N" sand and from 21.2 md to 143 md in the "0" sand. Since 1980, twelve production tests conducted in the "N" and "0" series sands have produced reliable permeability values. The results of seven of these tests are summarized in Table 3, indicating an average flow capacity of 6,410 md-ft. A recent production test on MPU well G-1 (located in tract 14) indicated a flow capacity of approximately 82,000 md-ft and permeability of 2,000 md. In cores taken from G-l, air permeability ranged from 5,000 md to 10,000 md and from 200 md to 700 md for the "N" and "0" series sands respectively. primary Recovery Mechanisms Primary recovery from the MPU Schrader Bluff reservoir will predominantly result from pore volume compressibility with a minimum amount of solution gas drive. Laboratory analysis indicates sufficient core compressibility to contribute to primary recovery. Recovery Predictions The MPU Schrader Bluff reservoir was modeled using the Todd, Dietrich and Chase (TDC) Volatile Oil Steamflood Simulator in the isothermal mode. The TDC model 8 is three-dimensional and able to handle multiple, non-communicating layers, as well as simultaneous flow of oil, gas and water. In addition, the TDC model will handle pressure dependent pore volume and permeability. MPU wells A-3 and N-lB were selected to represent average wells in two distinctly different areas of the reservoir. These wells provided porosity, permeability and oil gravity data for the respective areas. Each of the "N" and "0" sands were treated as separate homogeneous layers. Porosity and water saturation data were read directly from well logs using techniques discussed in the determination of OOIP. PVT properties were calculated (see the Reservoir Fluids Section) and assigned to the various sands in different areas of the field based on observed oil gravities. Permeability and relative permeability characteristics (see the Permeability Section) were generated and entered into the model. The wells were pressure constrained to a producing bottom-hole pressure of 800 psig.. Injection well pressures were constrained to minimum fracture gradient of 0.70 psi/ft. The wells were not water-cut constrained. The model was set up on a 7 x 7 grid, which results in five grid blocks between wells on opposite corners. Well spacing was changed by increasing or decreasing horizontal dimensions of the grid blocks. Injection patterns were simulated by placing wells at the appropriate positions and adjusting grid block sizes. Various well spacing and injection well patterns were modeled, and the results clearly illustrate that waterflooding on 80 acre 5-spot or inverted 9-spot patterns will result in increased recovery over primary (on any spacing to 40 acres) or a regular 80 acre 9-spot pattern. Primary recovery cases show high initial rates approaching those of waterflooding, indicating that injection can be delayed for a period of primary production. Cases run on delayed injection indicate that reservoir pressure will be maintained with injection delays up to two years. Model results indicate delayed injection to have negligible impact on ultimate recovery. Faulting and stratigraphy will ultimately play an' important role in determination of optimum spacing and pattern placement. Increasing well density to 20 acres may become necessary to achieve necessary communication between injectors and producers in some areas of the field. The following is a summary of major conclusions presented in the reservoir description portion of this testimony: 1) Based on well control, areas of oil accumulation were divided into six major fault blocks (See Figure 4). 2) Primary recovery from the MPU Schrader Bluff reservoir will predominantly result from pore volume compressibility with a limited amount of solution gas drive. 3) Computer model results clearly illustrate that waterflooding on 80 acre 5-spot or inverted 9-spot patterns will result in increased recovery over primary. i 9 4) Cases run on delayed injection indicate that pressure will be maintained with injection delays up to two years. Model results indicate delayed injection will have negligible impact on ultimate recovery. A period of primary production will provide additional production data for use in design of the waterflood pattern, which may result in a more efficient waterflood and increased recovery. 5) Faulting and stratigraphy will ultimately play an important role in determination of optimum spacing and waterflood pattern. Increasing well density to 20 acres may become necessary to achieve necessary communication between injectors and producers in some areas of the field. RESERVOIR SURVEILLANCE To monitor depletion and optimize recovery from the Schrader Bluff reservoir, an active program of reservoir surveillance will be initiated in the early stages of development. This portion of the testimony will discuss a proposed reservoir surveillance program, which will include careful monitoring of reservoir pres- sure, gas-oil ratio, produced volumes, injected volumes, injection well surveillance and well surveys. Reservoir Pressure In the Schrader Bluff reservoir, both permeability and pore volume are thought to be pressure dependent; therefore, careful monitoring of reservoir pressure and pressure maintenance are considered to be very important aspects of the depletion program. Monitoring of reservoir pressure will commence with the initial drilling phase. The static bottom-hole pressure will be measured in each well prior to initiating sustained production. These pressure measurements will be obtained either by DST or RFT during the drilling and logging phase. If a DST or RFT is not conducted, the static reservoir pressure will be measured after completion using mechanical or electric gauges run on wireline. These static pressure surveys will be conducted for at least 8 hours, to insure that accurate information is obtained. After six months of sustained production, the reservoir pressure will be measured in one well per 640 acre section. In areas of the reservoir producing on primary production, these measurements will be conducted every six months until water- flooding is initiated. In areas of the reservoir under active waterflood, the pressure will be measured in one well per 640 acre section after six months of sustained production and again after 18 months of production. In addition, one well per 640 acre section will be designated as a key well. The static reservoir pressure will be measured after 30 months of sustained production and annually thereafter for the life of the well. Bottom-hole pressures will be obtained by 24 hour static tests, pressure buildup surveys, multiple flow rate tests or in injection wells by pressure falloff tests. For consistency, the pressure datum plane in the MPU Schrader Bluff reservoir shall be 4,000' subsea. All necessary data and well conditions to perform a complete engineering analysis, including rates, pressures, depths, temperature and times will be recorded and forwarded to the Commission by the last day of the month following the month in which the survey was conducted. Reservoir Report Form 10-412, complete with any necessary attachments, will be utilized to report the data. Due to complicated faulting and stratigraphy in the Schrader Bluff reservoir, it may be necessary to implement a pressure-transient, interference testing program to insure proper pattern arrangement and communication between injectors and producers. The purposes of this testing program will be to identify reser-voir boundaries, such as faults, facies changes or other permeability barriers that may adversely influence the waterflood project. Information gathered from interference testing will be forwarded to the Commission upon request. 11 In addition to the static pressure monitoring program, the producing bottom-hole pressure will be routinely monitored in all production wells. In injection wells, the surface injection pressure will be continuously monitored. Gas-Oil Ratio Testing With an initial solution gas-oil ratio (GOR) of 191SCF/STBO and an initial oil formation volume factor of 1.06 bbl/STBO, the MPU Schrader Bluff reservoir is considered highly under-saturated. As previously discussed, primary recovery from solution gas drive will be negligible compared to pore volume compressibility, which is considered to be the most significant drive mechanism for primary recovery. Current plans are to produce the reservoir under primary means for a period of one year and then implement a full scale waterflood project. Due to the under-saturated nature of the reservoir, water channelling problems or extremely large fillup volumes resulting from buildup of gas saturation in the reservoir are not anticipated. In addition, sufficient structural relief to form a secondary gas cap is not thought to be present in ~he MPU Schrader Bluff reservoir. Based on these assumptions, it is concluded that pressure depletion resulting from primary production, and the anticipated increase in GOR, will have negligible impact on ultimate recovery from the Schrader Bluff reservoir. Computer model runs on cases delaying production up to two years, confirm this conclusion (see the section on Recovery Predictions). Between 90 and 120 days after continuous production, a gas-oil ratio test will be taken on each producing well. To ensure accuracy, the test will be a minimum of 12 hours in duration and conducted at the normal producing rate and pressure of the well. All tests will be reported on the Gas-Oil Ratio Form 10-409, by the 15th day of the month following the month that the test was conducted. Subsequent gas'-oil ratio tests will be performed every six months on wells producing on primary production (prior to implementation of the waterflood or wells isolated from injectors). Based on this testimony, Conoco requests that the gas-oil ratio limitation in 20 AAC 25.240(b) be waived for a period of time not exceeding eighteen months from the date of initial sustained production from the Schrader Bluff reservoir. Should the GOR increase above current regulatory limits, this waiver will allow for a period of primary production prior to initiating the waterflood. Data collected during primary production will be used in waterflood design. This should ultimately result in a more efficient secondary recovery project and increased reserves. Produced Volumes It is proposed that surface commingling of production from the Schrader Bluff Pool with production from the Kuparuk River Pool be allowed at any point downstream of the well test system for final separation and sales at the MPU Central Facilities Pad. The current Kuparuk River Pool has an estimated economic life of approximately seven years without commingled Schrader Bluff production. Commingling of production will prevent both economic waste from and under- utilization of existing facilities in the Field and loss of reserves from the Kuparuk River reservoir. 12 Prior to commingling, the Commission may approve the proposed method of testing and allocation; and also approve the proposed design and operating procedure for the test equipment. The following is Conoco's proposed methodology for well testing and allocation between the two pools. Produced volumes of oil, water and gas from the MPU Schrader Bluff Pool and Kuparuk River Pool will be monitored with individual well tests. Well tests will be the basis for allocating monthly production volumes (oil, water and gas) for the individual wells. The individual well tests will be of at least six hours in duration and performed a minimum of twice monthly. Schrader Bluff wells will be produced with artificial lift equipment. The producing bottom-hole pressure will be routinely monitored with surface readout or by shooting fluid levels. The producing bottom-hole pressure will be recorded at the beginning of each test cycle (test equipment will be discussed in detail later in the Facilities and Scheduling portion of the testimony). (Bi-monthly well tests will be in agreement within 10% ~ error to be validated for allocation usage.) Wells testing outside of this tolerance will be retested a third time. Individual pad production will be summed to determine total production from the individual pools. It is also proposed to commingle gas from the Schrader Bluff Pool with gas from the Kuparuk River Pool. This gas will be reinjected into the Lower Kuparuk River gas displacement project in MPU well E-3. Under no circumstances will gas be transported out of the Milne Point Unit. All gas produced from the Schrader Bluff Pool will be allocated based on individual well tests and utilized in accordance with Rule 20 AAC 25.235. Injected Volumes and Waterflood Surveillance A daily record of injection rate and surface pressure will be maintained for each injection well in the Schrader Bluff Pool. In addition, a record of cumulative injection and pressure will be maintained per well and per pad. This data will be measured and totalized on an individual well basis. Initial surface injection pressure will not exceed 1,000 psig, which is below the estimated parting pressure (based on an estimated frac gradient of 0.70 psi/ft). After six months of continuous stabilized injection, step-rate tests will be conducted in one well per ADL tract to determine actual parting pressure and fracture length at various rates and pressures. Injection pressure may be increased based on the results of the step-rate tests. Injection wells will be pressure parted only if it can be clearly demonstrated, using industry accepted reservoir engineering analysis, that the waterbank extends beyond the fracture half-length. A second round of step-rate tests will be conducted after 36 months of continuous injection. In conjunction with the step-rate testing program, pressure falloff tests may be conducted in one well per pad to determine average reservoir pressure. The results of step-rate and falloff tests will be reported to the Commission upon request. Injection surveys using wireline conveyed temperature logs, radio-active logs, mechanical flow measuring tools or a combination of these devices will be run in each injection well after twelve months of continuous injection. Following 13 the initial surveys, each injection well will be routinely surveyed every third year. Surveys will be conducted in any well exhibiting major changes in either injection rate or pressure. Completed surveys will be filed with the Commission within 90 days after performing the survey. As Unit Operator of the Milne Point Unit Schrader Bluff Pool Unit Waterflood, Conoco Inc. will submit an annual report to the Commission on the Schrader Bluff Pool Waterflood. The report will be submitted by April 1 of each year for the period ending December 31 and will contain the following information: a) A tabulation by month, and on a cumulative basis, of produced volumes (oil, water and gas) and injected volumes and pressures. b) A summary of all injection surveys, injection well testing and injection well performance for the period. c) A summary of pressure surveys conducted on either producers or injectors during the peri od. ( 14 WELL PLANNING Casing and Cementinq The Schrader Bluff Pool casing and cementing requirements are generally consistent with AOGCC Regulation 20 ACC 25.030, requiring that casing and cementing programs meet the following criterion: 1) Provide adequate proteCtion of all fresh water zones. 2) Prevent fluid migration between strata. 3) Provide protection from pressures that may be encountered, including pressure due to thaw subsidence and freezeback within the permafrost interval. The proposed standard casing design for a typical Schrader Bluff well is very similar to that currently used in Milne Point Unit Kuparuk River wells: 13 3/8" conductor set at 80', cemented to surface; .9 5/8" surface casing set at least 500' below the base of the permafrost and cemented to surface utilizing an arctic set cement; 7" production casing from surface to approximately 5,000' TVD, cemented from TD to 500' above the top of the Prince Creek "K" sand. An alternate design currently under consideration is to substitute the above design with 16" conductor, 13 3/8" surface casing and 9 5/8" production casing, which may better facilitate running wire wrapped screen liners for gravel packing. A typical open hole completion currently under consideration is as follows: 13 3/8" conductor set at 80', cemented to surface; 9 5/8" surface casing set.500' below the base of the permafrost and cemented to surface with arctic set cement; 7" production casing set approximately 50' above the top of the Schrader Bluff "N" sand, cemented from TD to 500' above the top of the "K" sand; open hole under- reamed to 12 1/4" from the 7" casing point to 150' below the base of the "0" sand. The open hole section may be completed with either slotted or wire wrapped liner and possibly gravel packed. To provide insulation, the surface casing/production casing annulus will be arctic packed in all wells. It is proposed that the Schrader Bluff casing and cementing rules be written as specified in 20 AAC 25.030 and in accordance with the current Kuparuk River Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75' below the surface and sufficient cement will be used to fill the annulus behind the pipe to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze back, a string of surface casing will be set at least 500' MD below the base of the permafrost section. Sufficient cement shall be used to fill the annulus behind the casing to the surface. 15 3) To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. To be approved for use as surface casing, the Commission shall require evidence that the proposed casing and connections meet the above requirement. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back, based on sound engineering principles, may be approved by the Commission upon application. 4) It is proposed that the Commission approve a ruling that intermediate casing not be required. 5) It is proposed that the Commission approve a ruling allowing the following alternative completion methods: a) slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hole and which may be gravel packed; b) open hole completions provided that the casing is set not more than 50' above the uppermost oil bearing zone. Open hole completions may subsequently be completed with slotted liners, wire-wrapped screen liners, or combinations thereof, and may be gravel packed. c) horizontal completion with liners, slotted liners, wire wrapped screens, or combination thereof, landed inside the horizontal extension and which may be gravel packed. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engi- neering principles. Blowout Prevention It is proposed that the rule for blowout prevention in the Schrader Bluff Pool be written identically to the provisions established in Regulation 20 AAC 25.035 (Secondary Well Control: Blowout Prevention Equipment (BOPE) Requirements) of the AOGCC regulations dated April 2, 1986. Except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance with API Recommended Practice 53 for blowout prevention systems. Automatic Shut-in Equipment It is recommended that it be mandatory to install a Commission approved, fail- safe, automatic surface safety system on all producing wells. The system may be hydraulically, pneumatically or electrically controlled and must be able to simultaneously close the wellhead valve and shut-in the artificial lift equipment, if present, to prevent uncontrolled flow of liquid hydrocarbons. To insure that the surface safety system is functioning properly, a Commission representative may witness operation and performance tests at intervals and times specified by the Commission. 16 FACILITIES DESCRIPTION AND PROJECT SCHEDULE There are approximately 16,800 developable acres in the Milne Point Unit Schrader Bluff Pool. Due to directional drilling limitations on these 4,800 foot TVD wells, the largest area developable by a drill pad is approximately one section (640 acres). This implies the potential for a total of 26 pads. The major constraint on development in the Schrader Bluff reservoir will be available processing capacity at the MPU Central Facilities Pad (CFP). Without major modifications, CFP handling capacity is estimated at 40,000 BOPD. Total capacity of the Kuparuk is currently estimated at 30,000 BOPD, requiring injection of 40,000 BPD. CFP injection capacity is currently 50,000 BPD, leaving approximately 10,000 BPD excess for Schrader Bluff injection. Therefore, total excess facility capacity (crude processing and injection) in 1990 is estimated at 10,000 BPD. The available capacity will increase substantially as Kuparuk production declines. It will become necessary to increase injection capacity of the facility as the Schrader Bluff development proceeds to fully implement the waterflood project. However, this expansion should not be necessary in the early development. Due to the close proximity to the CFP, development will begin in Tract 14. The shorter roads and pipelines result in the most economical development scenario. Plans are to drill 12 additional Schrader Bluff wells and complete 160 acre primary development in Tract 14 on H, I and J pads during 1990 (Figure 7). Installation of pad facilities and pipeline hookup are planned for the third quarter, with initial production scheduled to commence by year-end. Infill drilling to 80 acres and implementation of a waterflood is planned for 1991. Development will continue at a pace set to maintain facilities at full capacity as the Kuparuk reservoir declines (See Figure 8). Economical development of the Schrader Bluff Pool is contingent upon utilizing the existing Kuparuk facilities. As previously stated, it will be necessary to surface commingle Schrader Bluff crude with Kuparuk River crude. Plans are to install test facilities at each pad consisting of a two phase separator and an emulsion meter. Microwave absorption meters have been extensively tested in other Conoco operations and by other major oil companies. The available test data indicates that these meters will be applicable for use in Schrader Bluff test systems. Unlike other emulsion meters, microwave absorption meters are relatively unaffected by phase percentages and specific gravity. Test systems utilizing these meters are approved by the Texas Railroad Commission for allocating commingled production. Additional data concerning the design, installation, and testing of these meters has been previously furnished to the Commission. The current Kuparuk River test system on B and C pads utilizes three-phase test separators. Kuparuk tests, as an aggregate, are generally within 10% of the sales volume. The Kuparuk test system operates at essentially the same working pressure as normal manifold pressures, resulting in reliable test data. Based on test data gathered for the microwave absorption meters, it is anticipated that the proposed Schrader Bluff system will be within this accuracy range. This system will also be designed to operate as closely as possible to normal pro- 17 ducing pressures, which should enhance performance of the system. CONCLUSION This testimony has been based on Conoco's present knowledge of the Schrader Bluff reservoir and contains results from theoretical analysis, laboratory analysis, model studies, reservoir management considerations and operational requirements. Conoco is confident that present knowledge of the reservoir is adequate to devise a prudent and economic course of action for development of the Schrader Bluff Pool, and trusts that this data is sufficient for the Commission to formulate Pool Rules consistent with the plan of development as currently envisioned. 18 REFERENCES Carmen, G. J., and Hardwick, P., 1983, Geology and Regional Setting of Kuparuk Oil Field, Alaska: American Association of Petroleum Geologists Bulletin, v. 67, p. 1014- 1031. Detterman, R. L., Reiser, H. N., Brosge, W. P., and Dutro, J. T., Jr., 1975, Post-Carboniferous Stratigraphy, Northeastern Alaska: United States Geological Survey Professional Paper no. 886, p. 32 - 39. Finley, E. A., 1959, The Definition of Known Geologic Structures of Producing Oil and Gas Fields: United States Geological Survey Circular 419, 6 p. Jamison, H. R., Brockett, L. D., and McIntosh, R. A., 1980, Prudhoe Bay--A Ten Year Perspective, in Giant Oil Fields of the Decade, 1968-1978: American Association of Petroleum Geologists Memoir 30, p. 289 - 314. Masterson, W. D., and Paris, C. E., 1987, Depositional History and Reservoir Description of the Kuparuk River Formation, North Slope, Alaska: Pacific Section, Society of Economic Paleontologists and Mineralogists, Alaskan North Slope Geology, v.1, p. 95- 106. Werner, M. R., 1987, West Sak and Ugnu Sands: Low-Gravity Oil Zones of the Kuparuk River Area, Alaskan North Slope: Pacific Section, Society of Economic Paleontologists and Mineralogists, Alaskan North Slope Geology, v.1, p. 109 -118. , 1984, Tertiary and Upper Cretaceous Heavy Oil Sands, Kuparuk River Unit Area, Alaskan North Slope: Arco Alaska, Inc., unpublished pre-print, 20 p. 19 TABLE 1 LOG ANALYSIS DATA BASE WELL NAME DIL SP NGT A-1 X X A-2 X X X A-3 X X X B-1 X X B-2 X X B-3 X X B-4 X X B-4A X X X B-5 X X X C-1 X X X C-2 X X X C-3 X X C-4 X X D-1 - X X X D-2 X X X D-2A X X X L-1 X X X M-1 X X X M-lA X X X N-1 X X X N-lA X X X N-lB X X X HB 18-1 X X Sohio West Sak 17 X X X ARCO West Sak 25 X X Texaco Prudhoe 1 X X X ,GR/FDC X X X X X X X X x X X X X X X X X X X X X X X X X X CNL X X X X X X X X x X x X X X X x X X X X X X X X X X TABLE 2 OIL/WATER CONTACT DEPTHS BY FAULT BLOCK BY SAND O/W Contact Depth (TVDss) Sand 6 5 4 3 2 NA 3550 3550 3750 4i00 4425 4425 NB 3700 3700 3900 4200 4425 4425 NC 3750 3750 3900 4225 4425 4425 ND 3600 3600 3850 4250 4425 4425 · NE 3675 3765 3900 4250 4425 4425 OA 3850 3850 4175 4350 4500 4500 OB 3900 3900 4200 4450 4400 4550 TABLE 3 WELL-TEST DATA WELL A-1 B-2 G-1 ZONE(S) OA (DST) OB (DST) NC/ND NC/ND NC/ND NC/ND NB/NC/NE NB/NC/NE NB/NC/NE PERFS IMD) 4366 - 4372 4518 - 4542 4372 - 4402 4372 - 4402 4372 - 4402 4372 - 4402 4164 - 4816 4196 - 4202 4216 - 4228 ~oh 2520 1190 6517 8845 9457 9923 43100 43100 43100 INDEX MAP MILNE POINT UNIT PRUDHOE BAY UNIT HEMI SPRINGS UNIT FIGURE .sos REGION~,, STRUCTURL WITH -T ' \ KUPARUK UNIT --_ MILES WEST SAK OIL ACCUMULATION' MILNE POINT UNIT ~.. RIVER \ i ,, ', ,. \ \ \ PR[~,I)I · L;\ll' , £(', I \ ! 1' SDURCE ~ WERNER 1987. FIGURE 3. 0 SOS: 0L~TOK PT. ~,WELLS MILNE POINT TOP OF NA SAND STRUCTURE -% .:....- . . · ::: 'i'i. :. ':..::: 1.'. .':.1.'..:. ':. '..'.1 .:. 5 · INTERCEPT FAULT BLOCK Miles FIGURE 4. - . LOG CALCULATED TOTAL POROSITY vs CORE POROSITY ( MPU B- 2} C o o o o o~> o o o o o _.9 ~.~ .~ ~× ~ o ,j o 4~o 0 o o c, o o '0 C'~O 0 CORE POH, OSITY (°/o ) CORE AIR PERMEABILITY vs CORE POROSITY (MPU B-2) io, ooo:t L_J_ !. 1_. ---I~__L ~'~ -1 / / / / c~-.~ ~r~.~ ~.~ ~ CORE ./ J-] / 2? / 1335008 0 PRDPDSEO LDCFIT I C iT PLANES RSECTING E HDRIZDNS 5O MILNE POINT PRODUCTION SCHEDULES ITl 40- TOTAL = KUP TAL 30- ~0 '; ". I ; I .";. 20 q TIME 50 CONSERVATION ORDER 255 May 18, 1990 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Chatterton' Conoco Inc. Suite 200 3201 C Street Anchorage, AK 99503 (907) 564-7600 Enclosed is the following information' A brief discussion of Conoco's well testing philosophy for the Schrader Bluff Pool; The results of some extensive field testing conducted by Conoco on the Texaco Microwave Watercut Monitor (TMWM) and another device; An article on the TMWM prepared by Texaco; Typical installation of the TMWM; and Operating specifications for the TMWM. We are also tabulating a comparison of our existing well test data compared to LACT shipped volumes. We are obtaining this data from the field, and should have the results to you within the next two weeks. If you need any additional information, please give me a call at 564-7650. Very t_ruly yours, Director, External Affairs AEH(jr) File 500.22 RECeIVeD MAY 2 2 1.990 .Oil & Gas ConS', Commiss[off '~ ~nchom~ CONOCO INC. Proposed Well Testinq Facilities Philosophy General Principle- Fluids from the well in test will enter a 2-phase test separator in order to separate the liquids from the associated gas. As the gas exits the separator through the gas outlet, it will be continuously measured by a turbine meter. The liquids leave the vessel via the liquid outlet and are pumped or flow through a Texaco Microwave Water cut Monitor (TMWM) and downstream flowmeter. By emitting microwave energy, the TMWM will continuously measure oil and water percentages due to the vastly different energy absorption capabilities of the liquids, despite the emulsion's outer phase. The flowmeter will be either a turbine or positive displacement device, depending on viscosity effects, and will measure total liquid rate. A net oil computer will use the percentages measured by the TMWM with the total liquid rate to calculate separate oil and water rates. After measurements are made, the gas and liquids will recombine and enter the production pipeline for processing at the Central Facilities Pad (CFP). Advantaqes of 2-phase versus 3-phase Test Separation' · Accuracy Well test accuracy has always been an elusive goal, and historically tests within 10% of LACT metered production have been viewed as acceptable. In the past, test systems have generally been unattended 3-phase systems or 2-phase systems which required frequent spot sampling. A reliable 0 -100% oil-in-water monitor in conjunction with properly applied flowmeters measuring total liquid flow has provided extremely accurate results. Additionally, continuous automated monitoring removes the operator's judgement from the test results. Conoco's recent Gulf Coast testing of the TMWM concluded that the device is capable of + 1% water cut determination from 0 - 100% on a routine basis. 2, Cost Although the TMWM is an expensive instrument, many cost savings are realized by using it in a 2-phase system versus 3-phase test separation. The time necessary to remove gas from liquid requires only 20 - 33% of the retention of that required to separate free water from oil. Therefore, a separator 3 - 5 times larger is required for 3-phase separation· Furthermore, a reasonably sized 3- phase separator will only remove free water. Hence, a heater is generally required to break the water and oil emulsion. In the specific case of the Schrader Bluff production, a very tight emulsion is anticipated due to the cold viscous low gravity crude properties and the thorough mixing anticipated in the electric submersible pump completions. To ensure accurate measurement, a method of sampling the oil stream is recommended. This means an operator must take frequent spot samples or an automatic stream sampler must be incorporated into the 3-phase system. IVIAY 2 2 1990 Ahska.Oil .& Gas Cons. Oommiss~ ~ Anchora[~ e Summary: Labor Requirements A 3-phase test system is much more labor intensive than the proposed 2-phase system. The more numerous components of a 3-phase system require more labor to operate, monitor, and maintain. The automatic calibration feature of the TMWM is also a labor saving device. In summary, Conoco and many other major oil companies are unsatisfied with past well testing systems. By utilizing the proven technology of 2-phase separation in conjunction with continuous oil and water percentages monitoring, we intend to achieve more accurate well tests for reduced capital investment and reduced operating costs. NOTE: Texaco has received approval to use the TMWM from regulatory bodies in the United Kingdom for the Tartan Platform and The Texas Railroad Commission granted Shell approval to use similar technology (Agar's microwave based monitor) for allocation accounting on unitized and consolidated lease operations. C. Van Lineberger%~ Sr. Prod. Engineer MONITOR TMWM CUT REPORT & WIOM WATER CUT MONITORS TESTS AT GRAND ISLE, LOUISIANA BY B. M. TUSS PER REPORT No. S-10-89 OCT. 10, 1989 WATER CUT MONITOR TEST GRAND ISLE, LOUISIANA INTRODUCTION BACKGROUND OVERVIEW DESIGNS INSTALLATION DATA ANALYSIS DATA REDUCTION RESULTS CONCLUSIONS RECOMMENDATIONS APPLICATIONS ACKNOWLEDGMENTS PHOTOS TABLE OF CONTENTS Page No..~ 2 11 11 14 16 16 16 APPENDIX A I' CONOCO INC. PRODUCTION ENGINEERING & RESEARCH BOX 2197 HOUSTON, TEXAS 77252 TO: REPORT: AUTHOR: SUBJECT: Dis tribution DATE: S-10-89 B. M. Tuss Field Test of Water-In-Oil Monitors October 10, 1989 The need for metering devices to determine the amount of water in oil qn an accurate, continuous, real-time basis has been recognized within the industry for some time. Recent advances in electronics and computer technology have brought forth a number ox different detection scenarios. Two of the advanced development units were tested as part of this report. These field trails provided a real-time, live crude, operational evaluation of the Texaco Microwave Watercut Monitor (TMW~) and the Fluenta Water-In-Oil Monitor (WIOM-300) devices. The results are compared to one another and to the existing spot and composite sampling analysis standards. It is envisioned that other multiphase metering devices will be tested and evaluated on the installed Grand Isle test loop as they reach further development and are available for field trials. AUTHOR: Sr. Staff Engineer Production Equipment Section klc/I1013.BMT Distribution: H C. Sager W K. Dietrich R L Abel J M Bohannon R E McKee J R Kemp G E Watkins R. D Riley G J Bergman Report File Field Subject File [H~S I.,S~ A CONFIDENTIAL PRODUCTION ENGINEERING & RESEARCH REPORT PP. EP"'-RED FOR THE EXCLUSIVE USE Olc CONOCO INC AND ITS AFFILIATES TH~S IS A PROCE~,ON~.L SHOULD N()T B~ CONSTRUED A~ REP~%ENT NG MANA~]F~ AL ~L.JTHORtTY ~ ~ I~ IT ~c ,~'ff~,T ,~ f~'E~; '~¢ , t~.~:'c c~,,~T,~.. ~,5' ~.~ ....... , S-10-89 (' t' 2 Introduction The objective of the water cut monitor test was to study the water cut detection capabilities of the Texaco Microwave Watercut Monitor (T~M) and Fluenta's Water-In-Oil-Meter (WIOM). The TMWM and WIOM were installed in a loop on the liquids side of a two-phase separator at Conoco's Grand Isle Tank Battery, Grand Isle, Louisiana. To verify the accuracy of the monitors, spot sample grind outs, composite sample grind outs, and composite sample lab analyses were conducted. The Texaco monitor is a precision, 0 to 100% water cut monitor; therefore, the offshore 43 Field stream was initially selected for the test because of the nominal high water percentage. The WIOM was installed in series with the TMWM to check its operation on water determination when the production stream was within its parameters. The Texaco monitor transmits microwave energy through the production fluid to determine water cut. The transmission of microwaves through a medium is governed by the complex dielectric permittivity of the medium. The TMWM takes a continuous sample of the production fluid through a 50 milliliter cavity, where microwave energy is radiated through it as it passes the sensor. The polarity of the medium fluid is the major determinant of the amplitude and phase shift of the wave. Water, being highly polar, demonstrates different effects to the microwave than oil, which is highly non-polar. The degree of the attenuation and velocity as measured by amplitude and phase shift when compared to the reference fluid exposed to tke same microwaves, is integrated into an output signal indicating percentage of water. The prototype TMWM unit that was tested consisted of the piping and spool piece, the slip stream sampling and microwave unit with its accompanying electronics and sensors, and an assc..~iated 386 personal computer. The field equipment was interconnected to the computer with a 27-pair cable. Production models of the TMWM will have a purpose build computer integrated into the field electronics package, and will require only power and output signal wiring. The Fluenta WIOM 300 is a capacitance type device; hence, limited to oil external characteristics. The unit was designed for ~ 5% accuracy and consists of a spool piece and its transducer, and a separate, small purpose built computer. The unit's outputs are 300 to 600 Hz and a 4 to 20 ma signal. The unit is also capable of data transmission via an RS 232 port. Background Long negotiations with Texaco E & P on 5he use and testing of the TMWM preceded the current testing program. The negotiations culminated in the signing of secrecy and testing agreements in the fall of 1988. The testing agreement provided a prototype TMWM for the test. S-i0-89 Scaled down tests on the Fluenta 300 ~q had been conducted by Production Research under the auspices of the Conoco Norway R & D (CNRD), but no long-term operational data was available on the unit. The project p. 9vided an opportune time to utilize our test .facility to do two tes%s simultaneously. The Texaco monitor (TMWM) testing was funded by EPI and EPNG-NA, and the Fluenta WIOM testing was covered by a project funded by CNRD. The units under test could then be compared against one another, to spot sample grind outs, to composite sample grind outs, and to composite sample lab analysis. The duration of the testing was scheduled to be for a three-month period. Before concluding the testing on the 43 Field, it was determined that the 47 Field could be switched through the 43 Field separator and the test loop. It was decided to extend the testing for an additional period of time in order to satisfactorily test both the Texaco and the Fluenta units on a lower water percentage stream and correlate those results with the high water content stream of 43 Field. As part of the testing agreement with Texaco, it was decided that the Texaco monitor, which would be tested at Grand Isle, would be built to the specifications and design requirements as provided on the Green Canyon project. If the test of the unit proved it to successfully perform the water cut determination and if Conoco decided to subsequently purchase it, the ultimate placement of the Texaco monitor could be on the Block 184 wet oil metering skid on the Tension Leg Well Platform. The Texaco monitor's spool was designed, built, inspected and certified for offshore installation and inserted into the Texaco "Inch Worm" configuration for the Grand Isle test. Space and provisions were made on the "Inch Worm" for installation of the Fluenta WIOM. Start up of the test was delayed for approximately six weeks from the original anticipated date awaiting the safety certification of the Texaco unit. The TMWM was conditionally certified in May and received formal certification confirmation by Factory Mutual on June 21, 1989. The Fluenta WI©M carries a BASEFA certification. The duration of the test and the amount of data that was anticipated, dictated that a computerized data logging and information retrieval system be utilized. This system proved to have a definite advantage and considerably reduced the overall cost and on site manpower requirements. Temperature, pressure, differential pressure, flow rate, incremental volume, total volume, and the two water cut monitors outputs were averaged and logged every six minutes. Eight (8) reports were generated every 24 hours listing all variables at six minute intervals. Four (4) of the reports con%ained the logged data, the S-10-89 remaining four .ntained data relevant on~,. to the Texaco monitor and were provided to Texaco E & P on an ongoing basis as part of the testing agreement. These reports were transmitted to Houston on demand via a data link and provide the basis for the ongoing documentation and this report. From those six-hour reports, graphs were generated depicting the readings received from the Texaco Monitor, the Fluenta WIOM, spot sample grind outs, and flow rates. In addition to the six-minute averages, the system also continuously logged all variables once every six seconds as trends. These six- second trends were only available via computer disk. These virtually continuous logs were copied to floppy disk and forwarded to Houston on a weekly basis. The six-second trending provided valuable information on the nature of the flow regi~ne, and an insight into the nature of the water cut variations. ~l~grcut. Monitor DesiaDs Although both water cut monitors gauge the same information, their designs are completely different. The Texaco monitor utilizes microwave detectors for amplitude and phase detection. The wave guide and sample cavities, utilized in the channeling and shaping of the transmitted microwave are machined from an inconel steel block. Within the sensor element are two dielectric lined cells. One contains a reference sample and the other contains a flow through sample taken from the stream. The detector and associated amplifiers and integator are used to achieve the electronic detection. The Texaco unit was also designed with special safety barriers in order to provide absolute protection from any discharge of energy from the electronic system. I(L' '$1F4]i4 t T 1.-t\,/P-1 ES L C-I IPI. fT . - Figure 1 Figure 1 shows the Texaco patented information. S-10-89 5 The Fluenta utilizes somewhat conventional capacitance design philosophies, except that the two electrodes are housed within a ceramic inner liner. The sensor element is made on a through conduit type of design, with the electrodes imbedded in a high-strength, cement-based insulating material known as Ceramite. Within this layer, two platinum temperature probes were also cast. One was connected to the inner ceramic liner and the other to the external steel piping. The electronic circuitry used on the Fluenta consisted of an integrator with its output fed back to the input through a bistable oscillator. LINING I I RS CAPACITAHC£ TRAI,13~UCE'R FRACTTFII, I CFI?IPIJTET. R FLUENTA BLI< D[A, Figure 2 Installation The testing was accomplished at Conoco's Grand Isle Tank Battery at Grand Isle, Louisiana, with the aid of Conoco's North American Production, New Orleans Division operations and engineering personnel. The testing took place from May through August, 1989. The liquid stream originated from offshore 43 and 47 Fields. The test loop was installed on the liquids line of ~he 43 Field, number 2, two-phase separator at Grand Isle. The system was operated at normal flow (2000 - 3000 bph) on the 43 Field and 500 to 750 bph for the 47 Field. A schematic of t]~e test set up in shown in Fig. 3. Photographs of the field installation at Grand Isle are shown in Appendix A. S-10-89 6 Temperature, pressure, differential pressure and flow meter values were scanned and logged continuously. The temperature and pressure were measured upstream of the static mixer. Differential pressure was measured across the Texaco "Inch Worm". Temperatures varied from 90 to 102 degrees Fahrenheit; pressure ranged from 75 to 90 psi. [-'-F TERCL!T ISLE TEST" Figure 3 The Texaco "Inch Worm" is an inverted "U" configuration. The Grand Isle unit is six inch diameter piping. The vertical pipe J. nstallation contained bott] the Texaco monitor (Tt,IWI'4) and the Flue[lEa 300 (%'1IO~.I) connected in series as shown in Figure 4. o. TEXACO \,v'ATERCUT MONITEIR I1",1S T AL L A T 101',1 < ~#IL]M ) $-10-89 7 1E)(ACO 140JlITOR FLDL~ FIGURE 4 Composite samples were drawn from the stream immediately downstream of the water cut monitors. Approximately 4.5 gallons of liquid was drawn at 0.5 cc increments tllroughout every 24 hour period. Sample extraction was proportional to flow at a ratio of approximately 0.5 cc per every 7 barrels. A turbine meter was relocated downstream of the inch worm. The meter output was fed to its accompanying electronics, which provided a one pulse per barrel signal for volume accountability and input for the proportional to flow sampling. The test loop was connected back into the existing level control valve and piping for normal flow to tl~e gu~ barrel tan]{. Data Analysis S-10-89 8 Four six-hour reports were received daily from the field containing all the logged data. They were transmitted via data link and in ASCII format. Once received, they were formatted into Lotus by the use of Lotus, version 2.0 macros. This system proved to be very efficient. It reformatted the data in a fraction of the time it would have taken for someone to reformat it manually. The numbers could then be configured to produce figures suitable for comparison. At the bottom of each report, the average percent water cut detected by the Texaco monitor, was calculated for the period covered on the report. A portion of a typical report is shown in Figure 5. ~ C 0 I'1 0 C 0 W R T E R C LI 1' D A [ L ¥ L O G ]~,ei:~r'f,: COrll .~'83 T Il'IR '[!-101 Pl-lgZ DP-i~3 Tr~104 I,R'1--105 Mrl-28Z Ffl-382 TOT-UOLi. R) degf ps ig ps lg l~cZ pc~ H2 bph bb 1~ 06: 86 182,5 ??, 2 06: 2'] 182. ~ ~1. ? ~G: qB' I~Z · 6 82.8 06 :S4 102.7 80.3 ~7:~ 18Z,? 81,3 U?: 18 182,6 75.6 ~7:Zq 1~2.~ 73 9 07:36 18~-, ? 81 ~8: 18 1~Z. 8 182 *. 8 78. ? 6 0 382,8 3132 1191]77 16 ~,13 0 382,8 3132 119383 18 9S,1 0 382,8 Z628 119665 19 4q,69 47,4 388 3?88 1.2~1~19 17 61,79 0 382,? 3248 1~48 15 f-~1.77 8 382,? 29~2 1~72 11 ~,81 ~ 382,9 2772 121289 18 64.59 ?2.8? 388 2988 121~86 19 q7,91 49.19 ~88 3788 121929 16 69.86 8 38Z.6 2592 1~62 13 67.71 0 382,5 3132 123482 16 ~,79 ~ 38~.~ 3~q 1~73 19 71,69 0 382,2 382q 1~993 18 ~.77 0 382.3 Z?3~ 1~89 3~96 1~89 32q0 1~81 328q 1~12 2888 l~Z1 2988 128q30 08:38 182,7 76,1 6,18 2~3,03 L~.?7 387,7 88:36 102,? 76,1 6.17 54.57 0 382 08:42 182.7 79.3 6,1S 67,96 0 382.1 88:54 102,7 82..3 6.19 72.74 0 382 09:06 182,6 77,1 6,18 3?.89 2~.63 888 Figure 5 After reformatting and inputing the data, graphs were produced so as to compare the data pictorially. Through the use of Harvard Graphics, Lotus data could be plotted in a form containing the relevant data, yet easy to understand. In Figure 6 the Texaco monitor and Fluenta readings have been plotted along with spot sample values for the same report as in Figure 5. COIIOCO I)~ IL¥ ~IER £/29/119 LOG S-10-89 9 86 48 28 IllltllllllillltltlttJtllttlttltliJllJlJlliillll_~tlitltllt !86 ' ' 7 8:BG 9:t]~ lO:Ob ll:UG TIH£ · TEXACO IlOtl I Figure 6 The Fluenta unit was designed to be accurate for low water cuts, below 80%. Anytime it read a water cut higher than 80%, it would reset. On the graph above, the unit resets to 98% water cut. CO{tOCO D~iL¥ URTER CIIT LOG 06/29/09 1888 8 6:86 , t.lJ_l_i_l.l_LLJ_{ J_U_.LLI_i. LLIJ_t_LL.LLI.J_L~J_, ,, LI_I.£L t_~.~-,-', .~_L~_.~ 7:86 fi:fl& 9:fl~ 1fl:fl6 11 :i16 'l'ltlE --.-- i'I.OURAT£ Figure 7 Figure 7 shows the flow rate data associated with ¥;ater cut trends in Fig 6. It was interesting to note that at times as tile flow rate increased, the water cut decreased, exllibitirlg ail inverse relationship, indicative of large crude oil slugs ill the pipelil]e. ~q-10-89 10 As a result o% the analysis of the datat ~ceived from the 43 Field, it was decided that the two monitors should be tested on a stream with a low water cut. It was determined that the separator could be switched to the 47 Field line, and that switch was made. The results provided information that enabled a constant comparison between the two monitors. Below are two grapl]s generated from the water cut and flow rate data received during the time tile line change was made. COtlOCO I)flIL¥ UAT£R CU! LOG 188 08 68 48 28 43 Field-------- ,4'7 Field ,~-t- ' ' · '++ ' " -' 0 12: 86 13'86 14:86 15:86 16:86 17:86 Tii"1£ ...... T EY. qCO I~OHI TOR ~ FLIJ£HT~ Figure 8 SPOT SAMPL£S 4808 F L o w 2008 1808 O 12 CO~IOCO DAILY UAT£B Cfi! LO,(; 88/UZ/89 43 Field ~'1' 47 Field ,.L.LLI_LLJ...I.4_ Id.! t I !,.I t,LI.i. Li.4_I_l I.I_.LJ.I.LLI..LLLd._LI. I..A.LLLJ-.I.LLLI_L..I.LI_LI LL.J, 06 13'86 14:86 15:86 16:86 17'86 1 Ir tlr.; -.-- FLOURATE Figure 9 It is interesting to note that when the change was made from the 43 Field to the 47 Field, the wa~er cut dropped to less than 60% and the Fluenta unit began to read almos~ the exact figures as ttle Texaco monitor. S-10-89 11 As can be seen from Figure 9, the flow rate was much more consistent on the 47 stream. Data Redq.ct~on As part of the data reduction, Lotus and Harvard Graphics were used as stated before. The amount of schematic information needed required the use of drawing softwares. All drawings were produced utilizing Autosketch software. To produce this report, a software called Inset was utilized. This software enables the importation of drawings, charts, or any other data from other softwares. For example, most of the charts presented in this report were imported, via Inset, from Harvard Graphics. The entire report was done on a personal computer and Paint Jet printer. Results As stated earlier, daily 24-hour composite samples, of approximately 4.5 gallons of liquid were taken to a lab in New Orleans for analysis. In Figure 10 the results received from the lab are compared with the 24-hour weighted averages from the Texaco monitor. The weighted average was determined by the amount of barrels that flowed during a six minute time interval, multiplied by the percent water cut. LAB RESULTS VS TEXACO MOI',IITOR £ C ?.8- U ! ~ LAU SAI'U'L£ ~ Z£XA(.~ i'lOt, l lTOi! Figure 10 Observing the results from this ten day period, a mean of 76.2% water cut was calculated from the lab results and a mean of 76.25% water cut was calculated by the Texaco monitor; indicating a difference of .05%. To provide a better look and comparison of the data, a plot (Figure 11) was generated in whic~ t~e lab result data was plotted against the Texaco monitor data. °¢ 4o 31 VATER L':I. JT V~ LAB. .Sr-,NPLE PLOT 30 4-0 50 60 70 80 ~0 100 LAB RESULTS ( Y. t,/ATER ) S-10-89 12 Figure 11 The Fluenta unit was not compared due to the fact that the 43 Field had a high water cut, and as a result, the Fluenta unit would reset frequently. Once the switch to the 47 Field was made, the Fluenta could also be compared. Tile graph below shows tile comparison between lab results, the Texaco monitor, and tile Fluenta unit. i'LIJI:~TA, T~CO rlOItiTOR, £~J,) LAU i~L,'~tILZ'~& ~ 58 A T 38 R 20 U 8/3 8/6 DATE ~ FI.IJ£H?A l~t~i TEX**tCO rlOtl I ?OR ~ IJ~B COrlPOS 1 TES ALL Figure 12 For this comparison, the mean water cut as read by tile Texaco monitor was 33.45%. Tile mean for the Fluenta %~as 38.58%, and tile mean given by tile lab results was 41.7%. S-10-89 13 Throughout the test period, spot samples were taken to provide more information for comparison. While the stream flowed from the 43 field, only the Texaco monitor and the spot sample grind outs were compared due to the high water cut. The comparison consisted of 266 spot sample grind outs and the Texaco monitor readings taken at the same time as the samples. 108 28- COMPARISON TEXACO Mor, IITOR VS SPOT SAMPLES Figure 13 This comparison indicated that 55.0% of the time, the Texaco monitor was within + 5% of the spot sample readings. A portion of this comparison is shown above . A comparison between spot samples, Texaco monitor, and the Fluenta unit was possible after the switch to the 47 field line. This comparison consisted of 78 spot sample grind outs and the corresponding readings on both the Texaco monitor and Fluenta uni't. The findings indicated that the Texaco monitor was within +_ 5% of the spot samples 72.8% of the time. The Fluenta was within that same range 34.6% of the time. Figure 14 shows a portion of the results. COMPARISON Figure 14 $-10-89 14 To clearly understand why the percentage was not higher, a human factor must be considered. Although the time was noted when the spot samples were taken, it was impossible to verify the accuracy of that time. Tile spot sample grind out water cut percentages were attained through the use of centrifuge tubes. ? q Figure 15 Since most centrifuge tubes do not have measurement lines drawn for~ every percentage point, oPerators were forced to interpolate. This also contributed to some inaccuracy. Figure 15 demonstrates the centrifuge tubes that were used. For tile high water cuts, it became difficult for operators to give a precise water cut value. For example, water cut could be 85%, yet the operator could read the measurement as 80% or 90%. So, most of tile measurement was up to the discretion of tile operator. Conclusion Both tile Fluenta and tile Texaco monitors performed well during the period of tile test. Some initial commissioning problems were experienced on tile Texaco unit because of some incorrectly assembled manual three-way valves and subsequent tubing connector damage. All items were repaired or replaced prior to start of the test. ., The Fluenta monitor operated continuously throughout the test period without any interruptions or problems. Tile Texaco unit was taken off line periodically tllrougltout tile test via a data link by Texaco E & P, Bellaire to off load data and to make slight changes in the computer software. Several instances of extended outage of the Texaco unit occurred wlten the data link failed before the unit could be put back on line. Both units performed well within their quoted specifications and in most cases with accuracies beyond the capabilities of the grind out procedures and equipment. With consistently varying and rapidly changing water content, it was difficult to precisely coordinate spot sample timing with monitor outputs. The ou'tput from tile two monitors paralleled one another consistently (within a few percentage points difference) when tile water cut was ill range of both instruments as is indicated below from a trend line chart of the 47 Field. , ,,, IiX :Mil Figure 16 In Figure 16, the Texaco monitor is in blue, the Fluenta is in pink, and tile flow rate is in brown. The Fluenta WIOM 300 is capable of ± 5% water cut determination when utilized on production streams that have water percentages that do not exceed oil external characteristics. Tile Texaco [4icrowave Watercut Monitor is capable of + 1% water cut determination from 0 to 100 percent on a production stream on a routiz~e basis. Both the Fluenta and tile Texaco units si~ould have a homogeneous mix of tile liquids streams as can be experienced by a static mixer to insure that water slugs do uot overwhelm the unit, present representative sampling, and to more properly account for the amount of water on alt ongoing basis. i.' i~ S-10-89 16 A homogeneous mix of the stream is essential for the proper operation of the TMWM and is highly recommended for the Fluenta. A static mixer with the flow diverted through a vertical blinded tee proved to be adequate on the Grand Isle test loop. Proportional level controls on the liquids line of a separator will eliminate a large percentage of the water slugging that can occur. Small two phase production and/or test separators with the least liquid residence time are advantageous to continuous water cut monitoring. RECOMMENDATIONS: It is recommended that the tentative plans to install the Texaco Microwave Watercut Monitor on the Jollier TLWP Blk 184 Wet Oil Metering Skid be carried through and the necessary verification and testing be done to satisfy the operators and the regulatory agency (MMS) that the unit will perform satisfactorily and provide a real time, accurate water cut that can be incorporated into a net flow computer. It is further recommended that the TMWM be considered for application on any existing facility for either on-line production separator water determination or well/production test separator application. The Fluenta WIOM-300 has proven very satisfactory when operated within its capabilities. It would have limited application on two phase separators that have any extended residence time that would be conducive to oil/water separation, or production streams with water content exceeding 60 - 70%, or 100% water slugs. POTENTIAL FUTURE APPLICATIONS: The use of water cut monitors could be utilizied to a considerable advantage on application to test separators; water flood production metering to evaluate water flood effectivenes; and for production metering for allocation. Precision water cut monitors can readily be applied to custody transfer metering applications. ACKNOWLEDGMENTS: The following personnel assisted in the installation, testing, data acquisition and data reduction. Mr. Orlando Marintez, PER, Summer engineer Mr. Ron Moore, NAP, New Orleans Mssrs. McDougal, Dantin & Martin, NAP, Grand Isle Grand Isle Operators and Technicians Figure A-l: Back side of Inchworm and composite sampler ................. :7 ..... - .......... : ..... ~¥~ · ' .... -.~.Z:? Figure A-2: Piping to and from separator Figure A-3: Side view of Inchworm and Instrumentation . _:.. ~~~. ,:: Figure A-4: Front view of Inchworm A WATER CUT MONITOR BASED ON MICROWAVE TECHNOLOGY ABSTRACT by G. J. Hatton D. A. Helms J. D. Marrelli* M. G. Durrett Texaco has developed and tested a water-cut monitor suitable for use on a wide range of production fluids. The monitor automatically measures water cut from 0-100% accurately despite changes in temperature, water salinity, crude properties, and the presence of gas. Approved by Factory Mutual Research for use in Class 1, Division 1 areas, this microwave technology based water- cut monitor is designed for unattended operation at remote locations -- subsea, topside, or onshore. INTRODUCTION A Texaco Exploration and Production Technology Division (EPTD) team was responsible for developing a water-cut monitor to measure water/oil ratios for a wide range of production fluids accurately despite changes in oil composition, emulsion state, water conductivity and geochemistry, temperature and flow rate. The successful long term field test installation of Texaco Microwave Water cut Monitors (TMWM) has demonstrated the achievement of this objective. The installed units stand alone, are unattended and operate in remote hostile environments. Existing and intended applications include subsea North Sea, offshore Gulf of Mexico, and in a high temperature desert. The unit has also met American Bureau of Shipping (ABS) and Factory Mutual Research (FM) standards required for operation in critical areas (Class 1, Division 1). Two basic models are in operation; the ALL-LIQUID Model designed for liquid streams - e.g., the liquid leg of test separators; and the GAS- LIQUID Model designed to monitor gas/liquid streams - e.g., full wellhead production. A number of TMWM field tests have been performed in the Middle East, on-shore in the U.S. and in the North Sea. Instantaneous water cuts ranged from 0 to 100% while the average water cut over a well test period ranged from 0 to 80%. The results of the TMWM agree with the alternative water-cut measurement (usually a test separator system) to the accuracy of the alternative system. During these field tests, two types of field problems previously unknown to the operators were uncovered by the ALL-LIQUID TMWM systems. · The first was the presence of several percent free gas in the presumed gas-free liquid leg of gas/liquid separators, and · the second was the frequent change (several times a minute for periods of hours) of the continuous phase of the emulsion in some operations. Typical water-cut monitors read erroneously in the above cases. In the first case, the TMWM detects and estimates gas carry-under and provides quantitative correction of water cut under many conditions of gas entrainment. This correction can be carried out in both oil-continuous and water-continuous emulsions. Efforts to extend gas correction to greater gas fractions are in progress. In the second case, the TMWM correctly predicts water cut despite frequent changes between emulsion states. THEORY OF OPERATION The TMWM electronics measure absolute dielectric values of fluids in the sensor cell, allowing accurate measurement of several fluid properties (in addition to water cut) such as water salinity, free gas fraction, and crude average paraffin number, without operator recalibration. The ability to measure several fluid properties is necessary to retain calibration even though produced fluids change unpredictably at a particular well in fields under waterflood and at well test sites with manifolds. Detection of salinity and crUde composition using internal electronic and chemical calibration is called autocalibration. Autocalibration with reference to internal absolute standards is very advantageous, perhaps essential, in ..- subsea and manifold apPlications - such as Texaco's subsea and topside three-phase well test systems in the North Sea1 and the Middle East - where operator intervention may be limited. The TMWM, using an internal 286/386 computer control system, was developed to improve on traditional capacitance and resistive methods of water-cut determination. A major source of error found with capacitative or resistive based sensors is their inability to determine water cut in~ all emulsion states. As indicated, immiscible oil and brine production mixtures can vary between oil- continuous and water-continuous emulsions, in some case, several times per minute. Instrument calibrations dependent on the assumption of the presence of a particular emulsion state, therefore, have a high probability of error in such cases~ Variations of other field conditions such as temperature, salinity, crude oil gravity and gas fraction also contribute significantly to the error in traditional methods of water-cut measurement. The wide variety of oil reservoirs developed by Texaco prevents selection of a "standard set" of properties as design parameters. The design of the TMWM assumes that measurement of oil-water ratio basically reduces to determining as many production fluid properties as are necessary to accurately specify the water cut. The TMWM, therefore, (1) uses the transmission of microwave energy through the production fluids to constantly monitor' important chemical features of the production, (2) automatically corrects water-cut measurements if necessary, and (3) reports the basis for those corrections in terms of effective water salinity and average molecular weight (or potentially, gravity) of the oil. To provide the necessary sensitivity to fluid chemical composition, a frequency near 10,000 mHz. was chosen. This frequency is several orders of magnitude higher than that used by conventional water- cut measurement probes. .. The technology underlying the TMWM may be separated into three general areas: (1) sampling and separation systems, (2) electronic system design, and (3) fluid property analysis. Figure 1 illustrates schematically the two general configurations: (Figure la) GAS-LIQUID, and (Figure lb) ALL-LIQUID. Several configurations of the water-cut monitor are installed, each appropriate to the fluid sampling needs at that site. However, all systems are identical electronically and in the fluid property analysis methodology and are approved by Factory Mutual (FM) Research Laboratories for use in Class 1, Division 1 areas. SAMPLING & SEPARATION SYSTEMS For most flow lines it is impractical to transmit microwave energy through the full production stream, so a sidestream sampling system is used. The objective of the sampling method is to continuously obtain representative samples under all operational conditions and to flow samples at pipeline pressure and temperature through the measurement electronics. A pair of three-way valves, one on each end of the sensor element (Figure 1), permits capture of a sample at operation temperature and pressure as it passes the sensor. This sample can be removed and tested for oil, water and gas ratios, salinity and API gravity to permit.immediate verification of sYstem accuracy. The three-way valves also provide a variety of calibration option, and access for system corrosion monitoring, cleaning and sensor changing. We have designed sampling configurations specific to two general classes of fluid flow: GAS-LIQUID and ALL-LIQUID. Both are designed without moving parts to maximize reliability and to minimize maintenance. The'three-component (oil/water/gas) production configuration is for the entire well stream. This system is the GAS-LIQUID model (Figure la); it is intended for use near the wellhead (subsea, topside, or on-shore). The GAS-LIQUID model is called the 'incline' model because it uses the Texaco patented design of the inclined main pipeline segment, the slope of which insures i · stratified gas/liquid flow down the incline over a wide range of flow rates, and · a very high degree of mixing of the liquids over a wide range of flow rates without moving mechanical devices and without a large pressure drop. The goal of the incline separator is to provide a well mixed liquid sample with relatively little entrained gas for delivery into the sensor electronics. The stratification of gas and liquid phases is a natural property of gas/liquid mixtures when flowing down slopes and is a key element in the incline design. Appropriate slope inclination is determined from production rates and fluid properties such as API, temperature and GOR. Even after stratification, the 'liquid' phase in the inclined section of pipe still may have a significant amount of gas in the form of small bubbles. These bubbles will remain in the 'liquid' phase all the way down the incline if buoyancy forces do not exceed velocity- induced mixing forces. By design, the mixing forces in the Incline Design Separator are quite large. Gravity can force the liquid phase down the incline at velocities of twenty feet per second, with typical Reynolds numbers of 30,000 and greater. Consequently, not all free gas is removed from the 'liquid' phase, but the liquids (oil/water) are very well mixed. The result of the incline design is that for large swings in gas-oil ratio and liquid flow rate, the incline system provides a continuous representative sample of the produced liquids with some entrained gas to the TMWM for analysis. The electronics of the TMWM are designed to deal with this level of entrained gas. The two-component (oil/water) production configuration is intended for use on the liquid outlet leg of a gas/liquid separator. This system is the ALL-LIQUID model (Figure lb). The ALL-LIQUID version of the Texaco Microwave Water-cut Monitor has a choke at the point of sample return to the mainline to insure that for a large range of flows, the sample extraction to the bypass is nearly isokenetic. Provided the liquid stream is well mixed at the by- pass inlet, this system is the best passive way to acquire a representative sample. The ALL-LIQUID version of the system is designed to operate in cases where no gas is present; however, the small amount of gas evolves from the live oil stream due to piping- related pressure losses. Ail production piping produced by Texaco for the Microwave Water- cut Monitors placed in service has been reviewed and approved by the American Bureau of Shipping for installation on offshore platforms over which they have regulatory jurisdiction. ELECTRONIC SYSTEM DESIGN The sensor element, machined from a solid bar of inconel steel, is a precision tolerance, high pressure, fluid cell which directs microwave~energy to interact with the crude oil stream. Figure lb illustrates the cross section of the sensor cell showing the sample flow line and temperature resistant (dark bars) dielectric material which fills part of the waveguide and determines the calibration properties of the sensor. Two identical fluid cells are embedded within the sensor. One carries the production stream and one contains a stable reference fluid in close proximity to the production stream. The electronic hardware: · provides a stable microwave signal through both sensor cells, and accurately measures the interaction of the microwave signal with the sample stream and the reference fluid. The process is further stabilized by the system continually comparing the results from the sample stream to those of a reference fluid held in a cell in the same inconel block. (Because of the close proximity of the reference and sample cells, the temperatures of the reference and sample fluids are very close.) shift (measured in degrees). Both measurements are made relative to similar measurements of a stable calibration fluid embedded within the inconel sensor block. Values of attenuation and phase shift depend on the sensor geometry. While it is possible to convert the relative attenuation and relative phase shift to values of complex dielectric, a measure independent of sensor geometry, we have not presented that information here. The transmission through and reflection from fluids at microwave frequencies are strong functions of the polarity of the fluids. Since water has high polarity and oils have low polarity, water cut is a key parameter in describing microwaves in liquids. The properties of pure fluids and their mixtures are discussed below. PROPERTIES OF REFINED OILS, CRUDES AND BRINES The standard method chosen to represent the data used for water cut prediction is the crossplot form shown in Figure 2. Figure 2 , presents graphically the entire range of phase and attenuation detection of the Texaco Microwave Water-cut Monitor. The attenuation and phase shift of several representative oils, waters and alcohols are indented as this crossplot. Because the relative scale of the water crossplot is much greater than that of the oil crossplot, Figures 3 and 4 present those two regions separately. 11 We have demonstrated empirically that any given pure substance, oil or water, has a unique point on these plots for a given temperature. The location of the point depends on the chemical family to which the pure fluid substance belongs. The collection of all of the points representing all of the members of the homologous group forms a single curve. A separate curve exists for each temperature and the resulting plot consists of a map in which knowledge of any three of the four mapped parameters - attenuation, phase shift, carbon number (or molecular weight) and temperature - allows prediction of the fourth. For example, specifying temperature as constant means that attenuation and phase shift predict the carbon number and homologous family of a refined oil in the sensor cell. Furthermore, blends of miscible pure fluids plot in locations on the homologous series line in between the pure points. Therefore, in the case of oils the effective carbon number of a crude sample as obtained by distillation analysis is predicted by the location of the attenuation and phase shift point. An analogous situation exists for solutions of water and salts (Figure 4). In the case of water, we have found that microwave propagation in solutions of NaCl mimic behavior of microwaves in all naturally occurring brines that we have so far examined. We therefore report properties of field brines in terms of effective NaCl salinity. 12 Electronic detection is achieved with amplifiers which range in gain by a factor of 100,000 and differential recording methods which minimize error due to noise or internal drift. Further compensation of electronic drift is provided by computer-based calibration curves for those electronic components which have shown sensitivity to temperature. This internal temperature compensation is important as, in some field installations, the electronic enclosure may experience a 25°C temperature change during one day. Texaco designed and developed special safety barriers which guarantee quality transmission of the microwave signal while strictly conforming to the electrical safety codes requiring absolute protection from hazardous discharge of energy from the electronics systems. Use of these barriers has allowed the TMWM to receive an "intrinsically safe" rating by Factory Mutual Research. FLUID PROPERTY ANALYSIS Microwave transmission through and reflection from a medium are governed by the complex dielectric permittivity of the medium. In the TMWM, the transmission properties are measured in terms of: (1) the power transmitted through the sensor cell, referred to here as attenuation (in decibels); and (2) the change in phase shift of the received sinusoidally oscillating wave, referred to here as phase 10 The crossplots shown in Figures 3 and 4 are essentially chemical maps superimposed on the attenuation-phase shift plane. In Figure 3 the map is a carbon number vs. temperature map while in Figure 4 the map is a salinity vs. temperature map while in Figure 4 the map is a salinity vs. temperature map. These crossplots provide a basis for the prediction of salinity, crude composition and water cut. MIXTURES OF OILS AND BRINES Experimental combination of oil and brines in a mixing loop in which temperature, pressure and water/oil ratio are controlled yields fluids whose amplitude and phase shift crossplot points form one of two possible paths between the pure water and pure oil regions. These paths are completely determined by the end points - i.e., by the pure water and pure oil points for the component mixture. If the dielectric of the oil or water changes, the paths will shift, allowing detection. Figure 5 is an attenuation versus phase shift plot for mixtures, of a typical oil and water ranging in water cut from 0-100%. The solid curves (upper curve for water-continuous and lower curve for oil-continuous) are from laboratory experiments; the dashed curves are model-extrapolated values. The transition from water- continuous to oil-continuous is unpredictable but in general occurs at a much lower phase shift and water cut than the transition from 13 oil-continuous to water-continuous. Study of these paths as a function of temperature, salinity and crude oil composition provides the methods required for automatic calibration of the TMWM. Discussion of the laboratory apparatus and experiments used in the mixture studies, automatic calibration methods, salinity prediction, and emulsion state determination have been presented previously.2 SUMMARY The Texaco Microwave Water-cut Monitor is designed for installation at remote or subsea well-heads to continuously monitor production streams. It can also be configured to monitor the percent water in wet oil transport pipelines, in the liquid line from two phase separators, or the oil line of three phase separators. It is capable of accurately measuring the water cut of an oil-continuous emulsion or a water-continuous emulsion over a 0 to 100% water- cut range. The unit can also provide estimates of water phase salinity and crude oil effective paraffin carbon number. Potential exists for quantitative estimates of free gas present in the sample stream. Offshore, test separators and test lines are a substantial cost element of new developments. The microwave system can reduce well and production test facilities costs in many applications. This continuous measurement system provides data to improve facilities 14 performance and to optimize reservoir management. The system is sufficiently compact to be mounted at wellhead locations and within existing production and/or test facilities with minor modifications to the existing piping. ACKNOWLEDGEMENTS We wish to recognize the contribution of the entire Texaco EPTD Multiphse Flow Systems Team. In particular we wish to thank M. C. Carlsen, E. L. Dowty, J. D. Stafford, L. L. Pepin, F. Siddiqui, S. M. Stockman, D. Stavish and T. M. Williams, all of whom contributed in the development of the TMWM. Also, we gratefully acknowledge the support of Saudi Aramco during the development of this monitor. REFERENCES I · Cottril, A., "Summer Test Set for Texaco's Multiphase Meter". Offshore Engineer, March 1989, 31-32. · Durrett, M. G., Hatton, G. J., Helms, D. A., Marrelli, J. D., "Texaco Water-Cut Monitor - Microwave Based Technology", Proceedings of the Eighteenth Annual Convention, Indonesia Petroleum Association, 1989. 15 Fig. I - Pictorial Representation of the Two Versions of the TMWM. (a) The GAS-LIQUID model uses the "Incline" configuration to produce a separation of liquid and gas prior to extraction of fluid by the side stream sampler. (b) The ALL-LIQUID model consists of a pipeline element with associated extraction and return piping and choke. Fig. 2 - Standard Crossplot Presentation Format for TMWM Primary Data. When the relative phase shift of the transmitted microwave signal is plotted against the relative attenuation for a given fluid sample, the location of the point on the graph is uniquely determined by the chemical structure of the fluid components and the temperature. Fig. 3 - Expanded View of the Crossplot of Attenuation and Phase Shift in the ,'Oil" Region of the TMWM Detection Range. The bottom left corner of Fig 2. is enlarged 30 times to illustrate the curves generated by pure oils such as the paraffins, or mixtures of oils such as crudes as temperature is changed from 5 degrees C to 75 degrees C. Fig. 4 - Crossplot of Attenuation and Phase Shift for Samples of Brines (NaCl). The upper right corner of Figure 2 is presented indicating the family of curves produced by plotting the microwave properties of brines as their salinity is diluted from saturated to fresh at constant temperature. Fig. 5 - Use of Standard Crossplot Data for the Basis of Determining Water-Continuous or Oil-Continuous Watercut. The determination of the microwave properties of the component fluids, as illustrated if Figures 3 and 4, is used to construct the curves indicating the microwave properties of all emulsions between 0 and 100% watercut. Two curves are generated, one for each continuous phase. ~ VENT : I! '- ~ ,. ~- , . ..... II ~ ~ . PO~ER-' SUPPLED : : · i" SEE NO~ t.'~, I ~ -- '~ A '---~~;~-~ OPTIONAL OUTPUTS _ , ,/ -- -~ k~~] ,.. ~ SPECI~ED BY ~TOM~ N~T~S~ 2~00.00 ...... ~E ~E~ OUANT. ~ATER~L . ~ ~ NONE TEXACO WATER CUT MONITOR mS,ALE. m mm , " ~~DJS OA~E 01/~2/90 ~T~ .. M~ +/~ +/~J3 ~AWN EBH ~01/12/90 ~ +/~.~. +/~.~5 c~ DA~ F~~ +/- ~ 32 A~R +/- ~ ~ ~K'D ~V~D~ BY DATE ~CK~ DATE .... , , , OPERATING SPECIFICATIO~ TEXACO MICROWAVE WATER-CUT METER (TMWM) OPERATING CONDITION WATERCUT RANGE 0- 100% SALINITY RANGE 0 - 250,O00 PPM SALINITY SENSITIVITY LOW and Electronically Compensated SENSOR TEMPERATURE RANGE 0 - 212 F ELECTRONICS TEMPERATURE RANGE -2O TO 180 F PRESSURE 0 TO 10,000 psi FLOW RATE 0 TO 70,000 or greater* BPD NET OIL COMPUTER YES GAS SENSITIVITY LOW TO VERY LOW ** SAFETY CLASSIFICATION Factory Mutual (FM) Approved for Class 1, Division 1 Gas groups C,D American Bureau of Shipping (ABS) approved for Offshore Service BASE COST $50,000 DELIVERY 6 MONTHS FROM RECEIPT OF ORDER Instrument may be configured to take full flow at rates from 0 to 200 BPD. For rates higher than 200 BPD, a side stream sample is analyzed. In that case low to high flow rates are determined by piping specific to the installation but turn down can be estimated to be 15:1 TO 20:1 DEPENDING ON THE PIPING CONFIGURATION. Dielectric measurements of watercut are inherently of lower sensitivity to free gas than density measurements of watercut. For example, 2% entrained gas in an oil/water stream will result in a 10.% watercut error if watercut is determined by a density measurement for a .82 specific gravity oil and 1.00 specific gravity water. For heavier oils and 1.0 specific gravity water, the error is larger. For low watercuts, 2% entrained gas in an oil/water stream will result in a 0.4% water-cut error if watercut is determined by a dielectric measurement. As the watercut increases the error determined by a dielectric measurement grows to be approximately equal to the entrained gas fraction -- in this case 2% watercut. In addition, the TMWM is capable of reporting gas corrected water-cut. The accuracy of this feature is under study in the laboratory and the field. CONSERVATION ORDER 255 Conoco Inc. Suite 200 3201 C Street Anchorage, AK, 99503 (907) 564-7600 June 11, 1990 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Chatterton: Enclosed is a copy of data on the Texaco water cut monitor. Apparently the information that I had previously submitted was missing a few pages. Very truly yours, Director, External Affairs AEH(jr) File 500.22 ~ VENT NOTES= 1.) FULL PORT V~LVE REQUIRED JO'N 1 ~ 19~n 2.) PHANTOM LINES DENOTES RECOMMENDED r::"'~]~,ska.oii&~asCons. Oo~mi~sio~ CUSTOMER SUPPLIED E~UIPHENT '? AnChora~ ,,,, , ,, , ,, 2400.00 ...... ~ ~ NONE TEXACO WATER CUT MONITOR SCALE ~, , ,, ~~DJS OA~E 01/12/90 ,, ..... A~R +/- ~ 3~ ~K'D ~V~ BY DATE ~tECK~ DATE .... T~ ~ ~.. T~c,~~o~..,s,o. COMPONENT OF , , ...... .,,, TEXACO MICROWAVE WATER-CUT METER (TMWM) OPERATING CONDITION WATERCUT RANGE 0- 100% SALINITY RANGE 0 - 250,0O0 PPM SALINITY SENSITIVITY LOW and Electronically Compensated SENSOR TEMPERATURE RANGE 0 - 212 F ELECTRONICS TEMPERATURE RANGE -20 TO 180 F PRESSURE 0 TO 10,000 psi FLOW RATE 0 TO 70,000 or greater* BPD NET OIL COMPUTER YES GAS SENSITIVITY LOW TO VERY LOW ** SAFETY CLASSIFICATION Factory Mutual (FM) Approved for Class 1, Division 1 Gas groups C,D American Bureau of Shipping (ABS) approved for Offshore Service BASE COST $50,000 DELIVERY 6 MONTHS FROM RECEIPT OF ORDER Instrument may be configured to take full flow at rates from 0 to 200 BPD. For rates higher than 200 BPD, a side stream sample is analyzed. In that case low to high flow rates are determined by piping specific to the installation but turn down can be estimated to be 15:1 TO 20:1 DEPENDING ON THE PIPING CONFIGURATION. Dielectric measurements of watercut are inherently of lower sensitivity to free gas than density measurements of watercut. For example, 2% entrained gas in an oil/water stream will result in a 10.% watercut error if watercut is determined by a density measurement for a .82 specific gravity oil and 1.00 specific gravity water. For heavier oils and 1.0 specific gravity water, the error is larger. For low watercuts, 2% entrained gas in an oil/water stream will result in a 0.4% water-cut error if watercut is determined by a dielectric measurement. As the watercut increases the error determined by a dielectric measurement grows to be approximately equal to the entrained gas fraction -- in this case 2% watercut. In addition, the TMWM is capable of reporting gas corrected water-cut. The accuracy of this feature is under study in the laboratory and the field. ~¥~?El~ CUT ................................................................... M 0 N ITO'R ............ I~E'P O"RT TMWM & WIOIvl WATER CUT MONITORS TESTS AT GRAND ISLE, LOUISIANA BY B. M. TUSS PER REPORT No. S-10-89 OCT. 10, 1989 WATER CUT MONITOR TEST GRAND ISLE, LOUISIANA TABLE OF CONTENTS INTRODUCTION Page No. 2 BACKGROUND OVERVIEW DESIGNS INSTALLATION DATA ANALYSIS DATA REDUCTION RESULTS 11 11 CONCLUSIONS 14 RECOMMENDATIONS 16 APPLICATIONS 16 ACKNOWLEDGMENTS 16 PHOTOS APPENDIX A CONOCO INC. PRODUCTION ENGINEERING & RESEARCH BOX 2197 HOUSTON, TEXAS 77252 TO: Distribution DATE: REPORT: AUTHOR: SUBJECT: S-10-89 B. M. Tuss Field Test of Water-In-Oil Monitors October 10, 1989 The need for metering devices to determine the amount of water in oil on ..................................... an accurate, .continuous,,..real-.time-basis..has-been recognized within .the industry for some time. Recent advances in electronics and computer technology have brought forth a number o~ different detection scenarios. Two of the advanced development units were tested as part of this report. These field trails provided a real-time, live crude, operational evaluation of the Texaco Microwave Watercut Monitor (TMW~) and the Fluenta Water-In-Oil Monitor (WIOM-300) devices. The results are compared to one another and to the existing spot and composite sampling analysis standards. It is envisioned that other multiphase metering devices will be tested and evaluated on the installed Grand Isle test loop as they reach further development and are available for field trials. AUTHOR: Sr. Staff Engineer Production Equipment Section klc/I1013.BMT Distribution: H. C Sager W. K Dietrich R. L Abel J M Bohannon R E McKee J R Kemp G E Watkins R D Riley G J Bergman Report File Field Subject File rills IS A CONFIDENTIAL PRODUCTION ENGINEERING & RESEARCH FIEPORT P~Ee&~ED FOR T~E EXCLUSIVE USE Ol: CONOCO ~NC AND ITS A!I:~tLIATES THIS IS A PRO~EqS;iO~,,Ai. ~EoO~IT e~E~E%' %G S~OULD NOT E~E CONSTRUED AS REP!~FSENTING MANAI~ERIAL AUTHORITY %'~ ,~; ,' ',.c ,%-r%'r ,,'~ rc~;r~ ~ r ~.~.,,,-c c~,c.,~,r- .~..,,~tm .............. Introduction The objective of the water cut monitor test was to study the water cut detection capabilities of the Texaco Microwave Watercut Monitor (T~qM) and Fluenta's Water-In-Oil-Meter (WIOM). The TMWM and WIOM were installed in a loop on the liquids side of a two-phase separator at Conoco's Grand Isle Tank Battery, Grand Isle, Louisiana. To verify the accuracy of the monitors, spot sample grind outs, composite sample grind outs, and composite sample lab analyses were conducted. The Texaco monitor is a precision, 0 to 100% water cut monitor; therefore, the offshore 43 Field stream was initially selected for the test because of the nominal high water percentage. The WIOM was installed in series with the TMWM to check its operation on water determination when the production stream was within its parameters. The Texaco~monitor transmits'~"microwave energy~through 'the~Pr°ducti'~'n .......... fluid to determine water cut. The transmission of microwaves through a medium is governed by the complex dielectric permittivity of the medium. The TMWM takes a continuous sample of the production fluid through a 50 milliliter cavity, where microwave energy is radiated through it as it passes the sensor. The polarity of the medium fluid is the major determinant of the amplitude and phase shift of the wave. Water, being highly polar, demonstrates different effects to the microwave than oil, which is highly non-polar. The degree of the attenuation and velocity as measured by amplitude and phase shift when compared to the reference fluid exposed to tbs same microwaves, is integrated into an output signal indicating percentage of water. The prototype TMWM unit that was tested consisted of the piping and spool piece, the slip stream sampling and microwave unit with its accompanying electronics and sensors, and an assc..~iated 386 personal computer. The field equipment was interconnected to the computer with a 27-pair cable. Production models of the TMWM will have a purpose build computer integrated into the field electronics package, and will require only power and output signal wiring. The Fluenta WIOM 300 is a capacitance type device; hence, limited to oil external characteristics. The unit was designed for k 5% accuracy and consists of a spool piece and its transducer, and a separate, small purpose built computer. The unit's outputs are 300 to 600 Hz and a 4 to 20 ma signal. The unit is also capable of data transmission via an RS 232 port. Background Long negotiations with Texaco E & P on the use and testing of the TMWM preceded the current testing program. The negotiations culminated in the signing of secrecy and testing agreements in the fall of 1988. The testing agreement provided a prototype TMWM for the test. S-10-89 , Scaled down tests on the Fluenta 300 WzoM had been conducted by Production Research under the auspices of the Conoco Norway R & D (CNRD), but no long-term operational data was available on the unit. The project ~. ovided an opportune time to utilize our test .facility to do two tes%s simultaneously. The Texaco monitor (TMWM) testing was funded by EPI and EPNG-NA, and the Fluenta WIOM testing was covered by a project funded by CNRD. The units under test could then be compared against one another, to spot sample grind ou~s, to composite sample grind outs, and to composite sample lab analysis. The duration of the testing was scheduled to be for a three-month period. Before concluding the testing on the 43 Field, it was determined that the 47 Field could be switched through the 43 Field separator and the test loop. It was decided to extend the testing for an additional period of time in order to satisfactorily test both the Texaco and the Fluenta units on a lower water percentage stream and correlate those results with the high water content stream of 43 Field. As part of the testing agreement with Texaco, it was decided that the Texaco monitor, which would be tested at Grand Isle, would be built to the specifications and design requirements as provided on the Green Canyon project. If the test of the unit proved it to successfully perform the water cut determination and if Conoco decided to subsequently purchase it, the ultimate placement of the Texaco monitor could be on the Block 184 wet oil metering skid on the Tension Leg Well Platform. The Texaco monitor's spool was designed, built, inspected and certified for offshore installation and inserted into the Texaco "Inch Worm" Configuration for the Grand Isle test. Space and provisions were made on the "Inch Worm'.' for installation of the Fluenta WIOM. Start up of the test was delayed for approximately six weeks from the original anticipated date awaiting the safety certification of the Texaco unit. The TMWM was conditionally certified in May and received formal certification confirmation by Factory Mutual on June 21, 1989. The Fluenta WIOM carries a BASEFA certification. The duration of the test and the amount of data that was anticipated, dictated that a computerized data logging and information retrieval system be utilized. This system proved to have a definite advantage and considerably reduced the overall cost and on site manpower requirements. Temperature, pressure, differential pressure, flow rate, incremental volume, total volume, and the two water cut monitors outputs were averaged and logged every six minutes. Eight (8) reports were generated every 24 hours listing all variables at six minute intervals. Four (4) of the reports contained the logged data, the S-10-89 remaining four( ontatned data relevant on'~'~ 4 ~ to the Texaco monitor and were provided to Texaco E & P on an ongoing basis as part of the testing agreement. These reports were transmitted to Houston on demand via a data link and provide the basis for the ongoing documentation and this report. From those six-hour reports, graphs were generated depicting the readings received from the Texaco Monitor, the Fluenta WIOI.l, spot sample grind outs, and flow rates. In addition to the six-minute averages, the system also continuously logged all variables once every six seconds as trends. These six- second trends were only available via computer disk. These virtually continuous logs were copied to floppy disk and foB~arded to ttouston on a weekly basis. The six-second trending provided valuable information on the nature of the flow regime, and an insight into the nature of the water cut variations. Wat~rcut Monitor Designs Although both water cut monitors gauge the same information, their designs are completely different. The Texaco monitor utilizes microwave detectors for amplitude and phase detection. The wave guide and sample cavities, utilized in the channeling and shaping of the transmitted microwave are machined from an inconel steel block. Within the sensor element are two dielectric lined cells. One contains a reference sample and the other contains a flow through sample taken from the stream. The detector and associated amplifiers and integator are used to achieve the electronic detection. The Texaco unit was also designed with special safety barriers in order to provide absolute protection from any discharge of energy from the electronic system. T 1,,.1%/l',t BI_l( CI'i'IPI. I'T['P. Figure 1 Figure 1 shows t;he Texaco patented information. The installed units stand alone, are unattended and operate in remote hostile environments. Existing and intended applications include subsea North Sea, offshore Gulf of Mexico, and in a high temperature desert. The unit has also met American Bureau of Shipping (ABS) and Factory Mutual Research (FM) standards required for operation in critical areas (Class 1, Division 1). Two basic models are in operation; the ALL-LIQUID Model designed for liquid streams - e.g., the liquid leg of test separators; and the GAS- LIQUID Model designed to monitor gas/liquid streams - e.g., full wellhead production. A number of TMWM field tests have been performed in the Middle East, on-shore in the U.S. and in the North Sea. Instantaneous water cuts ranged from 0 to 100% while the average water cut over a well test period ranged from 0 to 80%. The results of the TMWM agree with the alternative water-cut measurement (usually a test separator system) to the accuracy of the alternative system. During these field tests, two types of field problems previously unknown to the operators were uncovered by the ALL-LIQUID TMWM systems. The first was the presence of several percent free gas in the presumed gas-free liquid leg of gas/liquid separators, and ~ the second was the frequent change (several times a minute for periods of hours) of the continuous phase of the emulsion in some operations. Typical water-cut monitors read erroneously in the above cases. In the first case, the TMWM detects and estimates gas carry-under and provides quantitative correction of water cut under many conditions of gas entrainment. This correction can be carried out in both oil-continuous and water-continuous emulsions. Efforts to extend gas correction to greater gas fractions are in progress. In the second case, the TMWM correctly predicts water cut despite frequent changes between emulsion states. THEORY OF OPERATION The TMWM electronics measure absolute dielectric values of fluids in the sensor cell, allowing accurate measurement of several fluid properties (in addition to water cut) such as water salinity, free gas fraction, and crude average paraffin number, without operator recalibration. The ability to measure several fluid properties is necessary to retain calibration even though produced fluids change unpredictably at a particular well in fields under waterflood and at well test sites with manifolds. Detection of salinity and crude composition using internal electronic and chemical calibration is called autocalibration. Autocalibration with reference to internal absolute standards is very advantageous, perhaps essential, in subsea and manifold applications - such as Texaco's subsea and topside three-phase well test systems in the North Sea1 and the Middle East - where operator intervention may be limited. The TMWM, using an internal 286/386 computer control system, was developed to improve on traditional capacitance and resistive methods of water-cut determination. A major source of error found with capacitative or resistive based sensors is their inability to determine water cut in all emulsion states. As indicated, immiscible oil and brine production mixtures can vary between oil- continuous and water-continuous emulsions, in some case, several times per minute. Instrument calibrations dependent on the assumption of the presence of a particular emulsion state, therefore, have a high probability of error in such cases. Variations of other field conditions such as temperature, salinity, crude oil gravity and gas fraction also contribute significantly to the error in traditional methods of water-cut measurement. The wide variety of oil reservoirs developed by Texaco prevents selection of a "standard set" of properties as design parameters. The design of the TMWM assumes that measurement of oil-water ratio basically reduces to determining as many production fluid properties as are necessary to accurately specify the water cut. The TMWM, therefore, (1) uses the transmission of microwave energy through the production fluids to constantly monitor important chemical features of the production, (2) automatically corrects water-cut measurements if necessary, and (3) reports the basis for those corrections in terms of effective water salinity and average molecular weight (or potentially, gravity) of the oil. To provide the necessary sensitivity to fluid chemical composition, a frequency near 10,000 mHz. was chosen. This frequency is several orders of magnitude higher than that used by conventional water- cut measurement probes. The technology underlying the TMWM may be separated into three general areas: (1) sampling and separation systems, (2) electronic system design, and (3) fluid property analysis. Figure 1 illustrates schematically the two general configurations: (Figure la) GAS-LIQUID, and (Figure lb) ALL-LIQUID. Several configurations of the water-cut monitor are installed, each appropriate to the fluid sampling needs at that site. However, all systems are identical electronically and in the fluid property analysis methodology and are approved by Factory Mutual (FM) Research Laboratories for use in Class 1, Division 1 areas. SAMPLING & SEPAP. ATION SYSTEMS For most flow lines it is impractical to transmit microwave energy through the full production stream, so a sidestream sampling system is used. The objective of the sampling method is to continuously obtain representative samples under all operational conditions and to flow samples at pipeline pressure and temperature through the measurement electronics. A pair of three-way valves, one on each end of the sensor element (Figure 1), permits capture of a sample at operation temperature and pressure as it passes the sensor. This sample can be removed and tested for oil, water and gas ratios, salinity and API gravity to permit immediate verification of system accuracy. The three-way valves also provide a variety of calibration option, and access for system corrosion monitoring, cleaning and sensor changing. We have designed sampling configurations specific to two general classes of fluid flow: GAS-LIQUID and ALL-LIQUID. Both are designed without moving parts to maximize reliability and to minimize maintenance. The three-component (oil/water/gas) production configuration is for the entire well stream. This system is the GAS-LIQUID model (Figure la); it is intended for use near the wellhead (subsea, topside, or on-shore). The GAS-LIQUID model is called the 'incline' model because it uses the Texaco patented design of the inclined main pipeline segment, the slope of which insures l® stratified gas/liquid flow down the incline over a wide range of flow rates, and · a very high degree of mixing of the liquids over a wide range of flow rates without moving mechanical devices and without a large pressure drop. The goal of the incline separator is to provide a well mixed liquid sample with relatively little entrained gas for delivery into the sensor electronics. The stratification of gas and liquid phases is a natural property of gas/liquid mixtures when flowing down slopes and is a key element in the incline design. Appropriate slope inclination is determined from production rates and fluid properties such as API, temperature and GOR. Even after stratification, the 'liquid' phase in the inclined section of pipe still may have a significant amount of gas in the form of small bubbles. These bubbles will remain in the 'liquid' phase all the way down the incline if buoyancy forces do not exceed velocity- induced mixing forces. By design, the mixing forces in the Incline Design Separator are quite large. Gravity can force the liquid phase down the incline at velocities of twenty feet per second, with typical Reynolds numbers of 30,000 and greater. Consequently, not all free gas is removed from the 'liquid' phase, but the liquids (oil/water) are very well mixed. The result of the incline design is that for large swings in gas-oil ratio and liquid flow rate, the incline system provides a continuous representative sample of the produced liquids with some entrained gas to the TMWM for analysis. The electronics of the TMWM are designed to deal with this level of entrained gas. The two-component (oil/water) production configuration is intended for use on the liquid outlet leg of a gas/liquid separator. This system is the ALL-LIQUID model (Figure lb). The ALL-LIQUID version of the Texaco Microwave Water-cut Monitor has a choke at the point of sample return to the mainline to insure that for a large range of flows, the sample extraction to the bypass is nearly isokenetic. Provided the liquid stream is well mixed at the by- pass inlet, this system is the best passive way to acquire a representative sample. The ALL-LIQUID version of the system is designed to operate in cases where no gas is present; however, the small amount of gas evolves from the live oil stream due to piping- related pressure losses. Ail production piping produced by Texaco for the Microwave Water- cut Monitors placed in service has been reviewed and approved by the American Bureau of Shipping for installation on offshore platforms over which they have regulatory jurisdiction. ELECTRONIC SYSTEM DESIGN The sensor element, machined from a solid bar of inconel steel, is a precision tolerance, high pressure, fluid cell which directs microwave energy to interact with the crude oil stream. Figure lb illustrates the cross section of the sensor cell showing the sample flow line and temperature resistant (dark bars) dielectric material which fills part of the waveguide and determines the calibration properties of the sensor. Two identical fluid cells are embedded within the sensor. One carries the production stream and one contains a stable reference fluid in close proximity to the production stream. The electronic hardware: · provides a stable microwave signal through both sensor cells, and accurately measures the interaction of the microwave signal with the sample stream and the reference fluid. The process is further stabilized by the system continually comparing the results from the sample stream to those of a reference fluid held in a cell in the same inconel block. (Because of the close proximity of the reference and sample cells, the temperatures of the reference and sample fluids are very close.) Electronic detection is achieved with amplifiers which range in gain by a factor of 100,000 and differential recording methods which minimize error due to noise or internal drift. Further compensation of electronic drift is provided by computer-based calibration curves for those electronic components which have shown sensitivity to temperature. This internal temperature compensation is important as, in some field installations, the electronic enclosure may experience a 25°C temperature change during one day. Texaco designed and developed special safety barriers which guarantee quality transmission of the microwave signal while strictly conforming to the electrical safety codes requiring absolute protection from hazardous discharge of energy from the electronics systems. Use of these barriers has allowed the TMWM to receive an "intrinsically safe" rating by Factory Mutual Research. FLUID PROPERTY ANALYSIS Microwave transmission through and reflection from a medium are governed by the complex dielectric permittivity of the medium. In the TMWM, the transmission properties are measured in terms of: (1) the power transmitted through the sensor cell, referred to here as attenuation (in decibels); and (2) the change in phase shift of the received sinusoidally oscillating wave, referred to here as phase 10 shift (measured in degrees). Both measurements are made relative to similar measurements of a stable calibration fluid embedded within the inconel sensor block. Values of attenuation and phase shift depend on the sensor geometry. While it is possible to convert the relative attenuation and relative phase shift to values of complex dielectric, a measure independent of sensor geometry, we have not presented that information here. The transmission through and reflection from fluids at microwave frequencies are strong functions of the polarity of the fluids. Since water has high polarity and oils have low polarity, water cut is a key parameter in describing microwaves in liquids. The properties of pure fluids and their mixtures are discussed below. PROPERTIES OF REFINED OILS, CRUDES AND BRINES The standard method chosen to represent the data used for water cut prediction is the crossplot form shown in Figure 2. Figure 2 presents graphically the entire range of phase and attenuation detection of the Texaco Microwave Water-cut Monitor. The attenuation and phase shift of several representative oils, waters and alcohols are indented as this crossplot. Because the relative scale of the water crossplot is much greater than that of the oil crossplot, Figures 3 and 4 present those two regions separately. 11 We have demonstrated empirically that any given pure substance, oil or water, has a unique point on these plots for a given temperature. The location of the point depends on the chemical family to which the pure fluid substance belongs. The collection of all of the points representing all of the members of the homologous group forms a single curve. A separate curve exists for each temperature and the resulting plot consists of a map in which knowledge of any three of the four mapped parameters - attenuation, phase shift, carbon number (or molecular weight) and temperature - allows prediction of the fourth. For example, specifying temperature as constant means that attenuation and phase shift predict the carbon number and homologous family of a refined oil in the sensor cell. Furthermore, blends of miscible pure fluids plot in locations on the homologous series line in between the pure points. Therefore, in the case of oils the effective carbon number of a crude sample as obtained by distillation analysis is predicted by the location of the attenuation and phase shift point. An analogous situation exists for solutions of water and salts (Figure 4). In the case of water, we have found that microwave propagation in solutions of NaCl mimic behavior of microwaves in all naturally occurring brines that we have so far examined. We therefore report properties of field brines in terms of effective NaCl salinity. 12 The crossplots shown in Figures 3 and 4 are essentially chemical maps superimposed on the attenuation-phase shift plane. In Figure 3 the map is a carbon number vs. temperature map while in Figure 4 the map is a salinity vs. temperature map while in Figure 4 the map is a salinity vs. temperature map. These crossplots provide a basis for the prediction of salinity, crude composition and water cut. MIXTURES OF OILS AND BRINES Experimental combination of oil and brines in a mixing loop in which temperature, pressure and water/oil ratio are controlled yields fluids whose amplitude and phase shift crossplot points form one of two possible paths between the pure water and pure oil regions. These paths are completely determined by the end points - i.e., by the pure water and pure oil points for the component mixture. If the dielectric of the oil or water changes, the paths will shift, allowing detection. Figure 5 is an attenuation versus phase shift plot for mixtures, of a typical oil and water ranging in water cut from 0-100%. The solid curves (upper curve for water-continuous and lower curve for oil-continuous) are from laboratory experiments; the dashed curves are model-extrapolated values. The transition from water- continuous to oil-continuous is unpredictable but in general occurs at a much lower phase shift and water cut than the transition from 13 oil-continuous to water-continuous. Study of these paths as a function of temperature, salinity and crude oil composition provides the methods required for automatic calibration of the TMWM. Discussion of the laboratory apparatus and experiments used in the mixture studies, automatic calibration methods, salinity prediction, and emulsion state determination have been presented previously.2 SUMMARY The Texaco Microwave Water-cut Monitor is designed for installation at remote or subsea well-heads to continuously monitor production streams. It can also be configured to monitor the percent water in wet oil transport pipelines, in the liquid line from two phase separators, or the oil line of three phase separators. It is capable of accurately measuring the water cut of an oil-continuous emulsion or a water-continuous emulsion over a 0 to 100% water- cut range. The unit can also provide estimates of water phase salinity and crude oil effective paraffin carbon number. Potential exists for quantitative estimates of free gas present in the sample stream. Offshore, test separators and test lines are a substantial cost element of new developments. The microwave system can reduce well and production test facilities costs in many applications. This continuous measurement system provides data to improve facilities 14 performance and to optimize reservoir management. The system is sufficiently compact to be mounted at wellhead locations and within existing production and/or test facilities with minor modifications to the existing piping. ACKNOWLEDGEMENTS We wish to recognize the contribution of the entire Texaco EPTD Multiphse Flow Systems Team. In particular we wish to thank M. C. Carlsen, E. L. Dowty, J. D. Stafford, L. L. Pepin, F. Siddiqui, S. M. Stockman, D. Stavish and T. M. Williams, all of whom contributed in the development of the TMWM. Also, we gratefully acknowledge the support of Saudi Aramco during the development of this monitor. REFERENCES i · Cottril, A., "Summer Test Set for Texaco's Multiphase Meter". Offshore Engineer, March 1989, 31-32. · Durrett, M. G., Hatton, G. J., Helms, D. A., Marrelli, J. D., "Texaco Water-Cut Monitor - Microwave Based Technology", Proceedings of the Eighteenth Annual Convention, Indonesia Petroleum Association, 1989. 15 S-10-89 5 The Fluenta utilizes somewhat conventional capacitance design philosophies, except that the two electrodes are housed within a ceramic inner liner. The sensor element is made on a through conduit type of design, with the electrodes imbedded in a lligh-strength, cement-based insulating material known as Ceramite. Within this layer, two platinum temperature probes were also cast. One was connected to the inner ceramic liner and the other to the external steel piping. The electronic circuitry used on tile Fluenta consisted of an integrator with its output fed back to the input through a bistable oscillator. FLUENTA BLI< D[A, Figure 2 I~sta!la,tion The testing was accomplished at Conoco's Grand Isle Tank Battery at Grand Isle, Louisiana, witi] the aid of Conoco's Morth American Production, New Orleans Division operations and engineering personnel. The testing took place from May through August, 1989. The liquid stream originated from offshore 43 and 47 Fields. Tile test loop was installed on the liquids line of tile 43 Field, number 2, two-phase separator at Grand Isle. The system was operated at normal flow (2000 - 3000 bph) on the 43 Field and 500 to 750 bpi] for the 47 Field. A schematic of tl~e test set up ill shown in Fig. 3. Photographs of tile field installation at Grand Isle are shown ii1 Appendix A. S-10-89 6 Temperature, pressure, differential pressure and flow meter values were scanned and logged continuously. The temperature and pressure were measured upstream of the static mixer. Differential pressure was measured across the Texaco "Inch Worm". Temperatures varied from 90 to 102 degrees Fahrenheit; pressure ranged from 75 to 90 psi. GR'ANiD ISLE · W TERCUT TEST ii- Figure 3 The Texaco "Inch Worm" is an inverted "U" configuration. Tile Grand Isle unit is six inch diameter piping. The vertical pipe J. nstallation contained both the Texaco monitor (TI.1WM) and the Fluenta 300 (WIOI.I) connected in series as shown in Figure 4. $-10-89 7 TEXACEI \,,/ATERCUT HONITEIR INSTALLATIEIN < ~#IDH ) ]EA'ACD HnNITI]R ( TFtWH ) FLDI.~ FIGURE 4 Composite samples.were drawn from the stream immediately downstream of the water cut monitors. Approximately 4.5 gallons of liquid was drawn at 0.5 cc increments throughout every 24 hour period. Sample extraction was proportional to flow at a ratio of approximately 0.5 cc per every 7 barrels. A turbine meter was relocated downstream of the inch worm. The meter output was fed to its accompanying electronics, which provided a one pulse per barrel signal for volume accountability and input for the proportional to flow sampling. The test loop was connected back into the existing level control valve and piping for normal flow to t~e gul~ barrel tank. Data Analysis S-10-89 8 Four six-hour reports were received daily from the field containing all the logged data. They were transmitted via data link and in ASCII format. Once received, they were formatted into Lotus by the use of Lotus, version 2.0 macros. This system proved to be very efficient. It reformatted the data in a fraction of the time it would have taken for someone to reformat it manually. The numbers could then be configured to produce figures suitable for comparison. At the bottom of each report, the average percent water cut detected by the Texaco monitor, was calculated for the period covered on the report. A portion of a typical report is shown in Figure 5. CONOCO M ~ T E R C U T D ~ I L ¥ LOG T I~E TI-101 P1-182 DP-i~:I T!'~-184 Ml'[--l~ M1'l-202 FM-302 TOT-UOL£I~) degf psig Psl9 pcs pc% H2 bph bbl~ 86:86 182.5 77.2 6.16 65.2 8 382.8 86:12 182.5 ?5.9 6.16 66.13 0 382.8 86: 18 182.6 86:2~ 102.6 81 .? 6.19 86: 36 10~ · ~6: 42 10Z. S 86:48' 10~.6 82.8 6.11 ~.81 8 382.9 ~6: ~ 182. 87:08 102 .? 81. ~ 6.19 47.91 49.19 300 87 :~6 18~.V 79. V 6.19 87.91 0 38Z.8 ~ 18~.6 88.1 6.16 69.86 0 38~.6 07: 18 182.6 ?S.6 6.16 ~.33 0 382.6 87:2~ 102.6 ?~.9 6 1~ ~.76 0 382.6 8?: 30 182.6 ?3,8 87:36 182.? 81.4 8? :48 18~. ~ 79.8 08:88 182.7 ?S. 1 ~8: 12 192.7 82.6 88: 18 182.8 79.9 ~8:2~ 102.8 78. ? 88:30 10~.? 76 1 08:36 18~.V 76 1 ~8:48 102.~ 80 1 89:88 18~.V 78 9 09:06 182.6 77 1 13 67.71 8 382.5 18 81.32 8 382.5 19 91.25 8 382.4 17 61.18 0 382.3 16 6~.79 8 382.Z 17 43.64 48.61 388 16 87.64 0 382.4 19 71.69 8 382.2 18 8~3.?? 8 382.3 18 3~3.83 ~.77 387.? 17 ~4.S? 8 382 15 6~.96 0 38~.I 19 ?~.7~ 0 382 18 ~.86 0 382.1 18 37.89 ~.63 388 3132 119~77 3132 119383 Z62B 11%65 3?8B 12~8 324B lZ834B 3168 1~68 2952 2988 121S86 2592 1~62 3~Z~ Z~SZ 123180 3132 123~8Z ZgSZ 123769 392q 12~ 148 3898 2988 1247~3 329~ 1~73 188~ 1~85 Z?~6 1~89 3096 1~89 117198 2880 1~21 2898 1~139 2988 Figure 5 After reformatting and inputing the data, graphs were produced so as to compare the data pictorially. Through the use of Harvard . Graphics, Lotus data could be plotted in a form containing the relevant data, yet easy to understand. In Figure 6 the Texaco monitor and Fluenta readings have been plotted along with spot sample values for the same report as in Figure 5. CONOCO DrOlLY UfllER Cfi! LOG 6/29-139 3-10-89 9 188 £ 28 ii JJ I JJ i J IlJJlJ iJ JJ JllJJJJJt Il JJ Ii ill IJlJlJl I i JLJJJllJJi&J 6:~6 7!8& 8'8&: 9__ 10:86 ll;U& --.--TEXACO IIOHITOll , I FLUF. tlTA · ~ ,~I'OT GAili'Li~ Figure 6 The Fluenta unit was designed to be accurate for low water cuts, below 80%. Anytime it read a water cut higher than 80%, it would reset. On the graph above, the unit resets to 98% water cut. CO/tOCO i~IL¥ I,~TF, ll ClIT LOG 86/29/09 B 6:D6. ?:OB 8:O& 9:0& 10:06 Figure 7 Figure 7 shows the flow rate data associated with water cut trends in Fig 6. It was interestil)g to note that at ~imes as the flow rate increased, the water cut decreased, exliibiting an inverse relationship, indicative of large crude, oil slugs in the pipeline. $-10-89 As a result o the analysis of the data-_~ceived from the 43 Field, it was decided that the two monitors should be tested on a stream with a low water cut. It was determined that the separator could be switched to the 47 Field line, and that switch was made. The results provided information that enabled a constant comparison between the two monitors. Below are two graphs generated from the water cut and flow rate data received during the time the line change was made. COHOCO I~IL~ UATER CIJ! LOG 186 43 Fiel& ~ 47 Field £8 . 12:86 13:86 14'86 15:~6 16:86 17:86 ...... TEXI~O I~OH 1 TOR ~ FLIJEH TA Figure 8 SPOT SAMPL£S 4088 CONOCO DAILY UAT£R CIJ! LOG OO/UZ/O9 43 Field ~l 47 Field 2088 1888 8 12:06 _LLL[ I J I I_L t l.l i I..J..Lj_ L i. t' t_lJ-I_l ! I_I-I.I_t_LIJ_Lt.J_LI. I..LLt. L~.LLLLt..tJ.L~_L~ LLJ 13:86 14:86 15:06 16:86 17:86 IIIJE -o-- FLOURATE Figure 9 It is interesting to note that when the change was made from the 43 Field to the 47 Field, the water cut dropped l:o less than 60% and the Fluenta unit began to read almost tile exact figures as the Texaco monitor. , S-10-89 11 As can be seen from Figure 9, the flow rate was much more consistent on the 47 stream. Reduction As part of the data reduction, Lotus and Harvard Graphics were used as stated before. The amount of schematic information needed required the use of drawing softwares. All drawings were produced utilizing Autosketch software. To produce this report, a software called Inset was utilized. This software enables the importation of drawings, charts, or any other data from other softwares. For example, most of the charts presented in this report were imported, via Inset, from Harvard Graphics. The entire report was done on a personal computer and Paint Jet printer. Results As stated earlier, daily 24-hour composite samples, of approximately 4.5 gallons of liquid were taken to a lab in New Orleans for analysis. In Figure 10 the results received from the lab are compared with the 24-hour weighted averages from the Texaco monitor. The weighted average was determined by the amount of barrels that flowed during a six minute ti]ne interval, multiplied by the percent water cut. LAB RESULTS VS TEXACO MOI',IITOR u 1 2 3 4 5 6 '/ u 'J Z4 IIOUI{ [--L~U~'L~ --T~X~ ~ITO" 1 - ~1 Figure 10 Observing the results from this ten day period, a mean of 76.2% water cut was calculated from the lab results and a mean of 76.25% water cut was calculated by the Texaco monitor; indicating a difference of .05%. To provide a better look and comparison of the data, a plot (Figure 11) was generated in whic~ t)~e lab result data was plotted against the Texaco monitor data. 8-10-89 12 40 VATER OJT V~ LAB. S~-JtPLE PLnT x 0 ,4-0 50 60 70 80 90 100 LAB RESULTS ( X 'w'ATER ) Figure 11 The Fluenta unit was not compared due to the fact that the 43 Field had a high water cut, and as a result, the Fluenta unit would reset frequently. Once the switch to the 47 Field was made, tl%e Fluenta could also be compared. The graph below shows the comparison between lab results, the Texaco monitor, and the Fluenta unit. F~Jf:.'MTh, TI:..'.'.'.'.'.'.'.~CO l'lOfilTOK, id'W £AU EIc~IILT~ ~ 58 A 4~ ....................................................................................... 'r :3e .... ~ ............................... c 1D U T 8 8/3 8/'1 8/5 DATE i FIJlEflTi't ]:~;~l T£XACO MOM i TOR ~ LAB COMPOS l YES ALL DATA CORI~ESPi~It[3S TO 24 H6LIR fllJERfl~E$ Figure 12 For this comparison, tile mean water cut as read by tile Texaco monitor was 33.45%. The mean for the Fluenta was 38.58%, and Uhe mean given by the lab results was 41.7%. S-10-89 , , Throughout the test period, spot samples were taken to provide more information for comparison. While the stream flowed from the 43 field, only the Texaco monitor and the spot sample grind outs were compared due to the high water cut. The comparison consisted of 266 spot sample grind outs and the Texaco monitor readings taken at the same time as the samples. COMPARISON TEXACO MONITOR VS SPOT SAMPLES I ~ 5 7 9 I I 1 ~ 15 17' 1 9 21 23 25 27 29 SP01' SAIIPI.f: {tlllB£R ~ T£X~CO ~ SFO! S~41PI.F_.S Figure 13 This comparison indicated that 55.0% of the time, the Texaco monitor was within ~ 5% of the spot sample readings. A portion of this comparison is shown above . A comparison between spot samples, Texaco monitor, and the Fluenta unit was possible after the switch to the 47 field line. This comparison consisted of 78 spot sample grind outs and tile corresponding readings on both the Texaco monitor and Fluenta unit. The findings indicated that the Texaco monitor was within ~ 5% of the spot samples 72.8% of the time. The Fluenta was within that same range 34.6% of the time. Figure 14 shows a portion of the results. COMPARISON FI,II£HTh, T'EXrICO IIOH i TOX ~d'dl) ~lq)F :~AIIPI.E~ L l iii..' U T 4U .................................... t .... ............... . ........... Il C 1 o II ~ 6 I '! i ti 1 '.) Zll 2 1 zz Z~l 2.1 2!:~ 2G 2'/ 21l 2'J :3I'OT ~i'iHl'L~ /IIJIJUI'-'{I Figure ~ r'i JJENT~ :1.4 To clearly understand why the percentage was not higher, a human factor must be considered. Although the time was noted when the spot samples were taken, it was impossible to verify the accuracy of that time. The spot sample grind out water cut percentages were attained through the use of centrifuge tubes. I ll~l Figure 15 Since most centrifuge tubes do not have measurement lines drawn for every percentage point, operators were forced to interpolate. This also contributed to some inaccuracy. Figure 15 demonstrates the centrifuge tubes that were used. For the high water cuts, it became difficult for operators to give a precise water cut value. For example, water cut could be 85%, yet the operator could read the measurement as 80% or 90%. So, most of the measurement was up 'to the discretion of the operator. Conclusion Both the Fluenta and tile Texaco monitors performed well during tile period of the test. Some initial commissioning problems were experienced on the Texaco unit because of some incorrectly assembled manual three-way valves and subsequent tubing connector damage. All items were repaired or replaced prior to start of the test. 15 The Fluenta monitor operated continuously throughout the test period without any interruptions or problems. Tize Texaco unit was taken off line periodically ti~roughout ttte test via a data link by Texaco E & P, Bellaire to off load data and to make slight changes in the computer software. Several instances of extended outage of the Texaco unit occurred wilen tile data link failed before the unit could be put back on line. Both units performed well within their quoted specifications and in most cases with accuracies beyond the capabilities of the grind out procedures and equipment. With consistently varying and rapidly changing water content, it was difficult to precisely coordinate spot sample timing with monitor outputs. The output from the two monitors paralleled one another consistently (within a few percentage points difference) when the water cut was tn range of both instruments as is indicated below from a trend line chart of the 47 Field. ' - :""~5 .~ ',. ': ~ ':.:."~','" ¢'~ ',:/~/~' '1: ' , ........................................ : .............. '. ~ '. Figure 16 In Figure 16, tile Texaco monitor is in blue, the Fluenta is in pink, and the flow rate is in brown. The Fluenta WIOM 300 is capable of ± 5% water cut determination when utilized on production streams that ]lave water percentages that do not exceed oil external characteristics. Tire Texaco [4icrowave Watercut Monitor is capable of + 1% water cut determination from 0 to 100 percent on a production stream on a routine basis. Both the Fluenta and t]~e Texaco units st]ould have a homogeneous mix of the liquids streams as can be experienced by a static mixer to insure that water slugs do not overwhelm the unit, present representative sampling, and to more properly account for the amount of water on an ongoing basis. I i S-10-89 16 A homogeneous mix of the stream is essential for the proper operation of the TMWM and is highly recommended for the Fluenta. A static mixer with the flow diverted through a vertical blinded tee proved to be adequate on the Grand Isle test loop. Proportional level controls on the liquids line of a separator will eliminate a large percentage of the water slugging that can occur. Small two phase production and/or test separators with the least liquid residence time are advantageous to continuous water cut monitoring. RECOMMENDATIONS: It is recommended that the tentative plans to install the Texaco Microwave Watercut Monitor on the Jollier TLWP Blk 184 Wet Oil Metering Skid be carried through and the necessary verification and testing be done to satisfy the operators and the regulatory agency (MMS) that the unit will perform satisfactorily and provide a real time, accurate water cut that can be incorporated into a net flow computer. It is further recommended that the TMWM be considered for application on any existing facility for either on-line production separator water determination or well/production test separator application. The Fluenta WIOM-300 has proven very satisfactory when operated within its capabilities. It would have limited application on two phase separators that have any extended residence time that would be conducive to oil/water separation, or production streams with water content exceeding 60 - 70%, or 100% water slugs. POTENTIAL FUTURE APPLICATIONS: The use of water cut monitors could be utilizied to a considerable advantage on application to test separators; water flood production metering to evaluate water flood effectivenes; and for production metering for allocation. Precision water cut monitors can readily be applied to custody transfer metering applications. ACKNOWLEDGMENTS: The following personnel assisted in the installation, testing, data acquisition and data reduction. Mr. Orlando Marintez, PER, Summer engineer Mr. Ron Moore, NAP, New Orleans Mssrs. McDougal, Dantin & Martin, NAP, Grand Isle Grand Isle Operators and Technicians · · . · Figure A-l: Back side of Inchworm and composite sampler · , Figure A-2: Piping to and from separator Figure A-3: Side view of Inchworm and Instrumentation Figure A-4: Front view of Inchworm A WATER CUT MONITOR BASED ON MICROWAVE TECHNOLOGY ABSTRACT by G. J. Hatton D. A. Helms J. D. Marrelli* M. G. Durrett Texaco has developed and tested a water-cut monitor suitable for use on a wide range of production fluids. The monitor automatically measures water cut from 0-100% accurately despite changes in temperature, water salinity, crude properties, and the presence of gas. Approved by Factory Mutual Research for use in Class 1, Division 1 areas, this microwave technology based water- cut monitor is designed for unattended operation at remote locations -- subsea, topside, or onshore. INTRODUCTION A Texaco Exploration and Production Technology Division (EPTD) team was responsible for developing a water-cut monitor to measure water/oil ratios for a wide range of production fluids accurately despite changes in oil composition, emulsion state, water conductivity and geochemistry, temperature and flow rate. The successful long term field test installation of Texaco Microwave Water cut Monitors (TMWM) has demonstrated the achievement of this objective. Fig. I - Pictorial Representation of the Two Versions of the TMWM. (a) The GAS-LIQUID model uses the "Incline" configuration to produce a separation of liquid and gas prior to extraction of fluid by the side stream sampler. (b) The ALL-LIQUID model consists of a pipeline element with associated extraction and return piping and choke. Fig. 2 - Standard Crossplot Presentation Format for TMWM Primary Data. When the relative phase shift of the transmitted microwave signal is plotted against the relative attenuation for a given fluid sample, the location of the point on the graph is uniquely determined by the chemical structure of the fluid components and the temperature. Fig. 3 - Expanded view of the Crossplot of Attenuation and Phase Shift in the "Oil" Region of the TMWM Detection Range. The bottom left corner of Fig 2. is enlarged 30 times to illustrate the curves generated by pure oils such as the paraffins, or mixtures of oils such as crudes as temperature is changed from 5 degrees C to 75 degrees C. Fig. 4 - Crossglot of Attenuation and Phase Shift fOr Samples of Brines (NaCl). The upper right corner of Figure 2 is presented indicating the family of curves produced by plotting the microwave properties of brines as their salinity is diluted from saturated to fresh at constant temperature. Fig. 5 - Use of Standard Crossplot Data for the Basis of Determining Water-Continuous or Oil-Continuous Watercut. The determination of the microwave properties of the component fluids, as illustrated if Figures 3 and 4, is used to construct the curves indicating the microwave properties of all emulsions between 0 and 100% watercut. Two curves are generated, one for each continuous phase. CONOCO INC. Proposed Well Testinq Facilities Philosophy General Principle: Fluids from the well in test will enter a 2-phase test separator in order to separate the liquids from the associated gas. As the gas exits the separator through the gas outlet, it will be continuously measured by a turbine meter. The liquids leave the vessel via the liquid outlet and are pumped or flow through the TMWM and downstream flowmeter. The TLWM will continuously measure oil and water percentages. The flowmeter will be either a turbine or positive displacement device, depending on viscosity effects, and will measure total liquid rate. A net oil computer will use the percentages measured by the TMWM with the total liquid rate to calculate separate oil andwater rates-~ .... After measurements are made, the gas and liquids will recombine and enter the production pipeline for processing at the Central Facilities Pad (CFP). Advantaqes of 2-phase versus 3-phase Test Separation: · Accuracy Well test accuracy has always been suspect. If tests are within 10% of production, this is generally viewed as acceptable. In the past, test systems have generally been unattended 3-phase systems or 2- phase systems which required frequent spot sampling. A reliable 0 - 100% oil-in-water monitor in conjunction with properly applied flowmeters measuring total liquid flow has provided extremely accurate results. Additionally, continuous automated monitoring removes the operator's judgement from the test results. Conoco's recent Gulf Coast testing of the TMWM revealed accuracies of 5% when compared to spot sampling analysis and 0.5% when compared to laboratory results. 2~ Cost Although the TMWM is an expensive instrument, many cost savings are realized by using it in a 2-phase system versus 3-phase test separation. The time necessary to remove gas from liquid requires only 20 - 33% of the retention of that required to separate free water from oil. Therefore, a separator 3 - 5 times larger is required for 3-phase separation. Furthermore, a reasonably sized 3- phase separator will only remove free water. Hence, a heater is generally required to break the water and oil emulsion. To ensure accurate measurement, method of sampling the oil stream is recommended. This means an operator must take frequent spot samples or an automatic stream sampler must be incorporated into the 3-phase system. · Labor Requirements A 3-phase test system is much more labor intensive than the proposed 2-phase system. The more numerous components of a 3-phase system require more labor to operate, monitor, and maintain. The automatic calibration feature of the TMWM is also a labor saving device. Summary: In summary, Conoco and many other major oil companies are unsatisfied'with past well testing systems. By utilizing the proven technology of 2-phase separation in conjunction with continuous oil in water monitoring, we intend to achieve more accurate well tests for reduced capital investment and reduced operating costs. NOTE: Texaco has received approval to use the TMWM from regulatory bodies in the United Kingdom for the Tartan Platform and The Texas Railroad Commission granted Shell approval to use similar technology (Agar's oil in water monitor) for allocation accounting on unitized and consolidated lease operations. Sr. Prod. Engineer ,/ David L. Bowler Division Manager oONSERVATION ORDER 255 Con~,,., ,,,~.. Suite 200 3201 C Street Anchorage, AK 99503 May 30, 1990 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Chatterton' Attached are the following items in support of Conoco's request for the establishment of Pool Rules for the Schrader Bluff Pool' 1. A schematic line drawing of the planned well test facility for individual well testing for the Schrader Bluff Pool wells; 2. A summary comparison by month of projected well test monthly production volumes compared to LACT metered volumes for May 1989 through March 1990; and 3. Confidential reservoir and geological data in support of the public testimony. In reviewing the comparison of projected well test production and the LACT metered production, it is obvious that the months of June and July are significantly below the average value of 95.6%. Apparently, during late June and early July, a dump valve on the oil outlet of the B-Pad test separator was malfunctioning, and water was also being discharged through this valve and metered as oil production. After correcting this problem, the comparison indicates a good correlation for the other months. The attached report, "Initial Development Plan for the Shallow Oil Sands in the Milne Point Unit", contains information that is proprietary to the Milne Point Unit Owners, and we request that this report be kept confidential until specifically released by Conoco. Please contact A1 Hastings at 564-7650 if you have any additional questions. Very truly yours, Division Manager AEH(jr) File 500.21.08 TEST SEPARATOR ACCURACY SUMMARY: MONTH TEST MONTH RESULTS (BBLS) lViAy ('89) 326,175 JUNE 381,259 JULY 312,079 AUGUST 454,625 SEPTEMBER 561,760 OCTOBER 586,760 NOVEMBER 529,658 DECEMBER 596,796 JANUARY ('90) 555,708 FEBRUARY 575,243 MARCH 613,624 LACT VOLUME (BBLS) LACT/TEST (%) 306,748 289,644 260,336' 426,491 517,014 548,596 533,346 591,425 614,876 551,309 610,162 94.0% 76.0% 83.4% 93.8% 92.0% 93.5% 100.7% 99.1% 110.6% 95.8% 99.4% 5,493,687 5,249,947 95.6% ..... ~ ~ LI III _ 3111! I .... HI ~..~. ~ i I TYP I CALI/J PRODUCING VELL TEST SEPARATOR [ 2 ) 30' OD x ~'-6' ~/S : GDP ~F. ~ ~ i__~.d ~ 0' ~'~ Px~z~ Z/J . · .... ; ~ ~, ~. ' . WILLS ~NI ! I I ~..-c~ ...... G'~~" II ,. ~,~ ~ $ ..... ~,,~$ ,-~,,-~ ,. .- .. PRODUCING VELk ~ {{ ~ ~__~ ~ ~":~~~. ~' ~ · · .... ; · -nv : CFP TO VENT TANK i I I I I NOTES: 1 ] BAIL VN.I/~I~ ~ BE F1.LL, ~ TRACT 14 TEST FACILITY H-PAD NORTH SLOPE. ALASKA []I~I,'N BY: ~ 4/9B , , , APPENDIX I · .~ ", r r.r. SH,LLL.;I OIL SANDS .O~,-.ELATIDN SHEETS NA HORIZON ~ELL ~O~'m~ ~O SSYD SURFACE LCCATIO!t A'I A'2 A--3 42' 4.1'~ --4171 2114 ' FNL, 5&' 5232 --417'I 2013 FNL, 15B5 FEL, '~.~'I."'--IcE 5B' 4505 -4157 191B FNL, B-I · B-3 B-¢ B-qA B-5 4630 ' -4~04 §512 ' 21~ FHL, 4255 FEL, 19-1~X-IIE 5,,3 FSL, 4504 FEL. 49 FNL, 1129 F~L, I?-ISI;-I!E !5S FNL~ 11S~ FWL. 165 F!{L. llZB FNL. 19-IiX-lIE 6B FSL, 1100 FWL, IB-!3N-IIE C-I C-2 C-4 4B' 4257 ' -4207 ' 1167 ' FSL. 225S ' FEL, lO-13N-lOE 52' :::a~. -4236 1229 FSL, 2459 FEL, .O-IJN-IOE 45' 4544 ' -4iB3 ' i'175' FSL, 232& ' FEL, IO-13!(-tOE 52' 520B ' -4138 ' 1344 ' FSL. 2494 ' FEL, IO-13N-IOE D-2 D-2A 40' 4925 ' -43?0 ' 964 ' FNL. 1233 ' FEL. t3-1]N-IOE 52' 4805 ' -4372 ' I147 ' FNL. 14~S ' FEL, ~'j~ 5007 ' -4321 ' 114~ ' FNL, 1436 .1:. FEL, 8-1]X-InE L-t 56 4~u~ -3996 1770 FT(L, : "" · 5&' 4380 ' -~545 ' 24')0 ' FSL, 665 ' FWL, 55' :~A ',IA 2-9:H) ' FSL. 686 ' FYlL. N-lA N-lB ::' 35£2 ' -~507 ' 2£60 .... jj r:~. 1425 ' FEL, 55' 36!7 ' -34~5 ' 255!) ' FSL, 1415 ' FEL. 55' 3598 ' -3495 ' 2660 ' FSL, 1425 ' FEL, JO-IJIi-IOE -.~.~6J ' FNL. I479 FEL 14-11'.{- 9E 32.-14 37' S52B "'= = "' . 52-14A 37' 3632 ...... -j,~, I~92' FNL, 147~ ' FEL. 14-13N~ ~E Z2-25 ~7' 4255 ' -4218 ' iZ$O ' FXL, 1979 ' FEL, 25-1JN-loE IB-I 50' 4.'~14 ' -43~4 ' .IBSO ' FSL, 3030 ' F,~L, iI-IJN-IOE W S 25 63' 4002 3707 700 ' FNL, 570 ' FEL. Z2-!.IN-IOE '~1 S 17 60' I~2 ' -iCTg ' aO0 ' F!IL, 250 ' FEL. :~-I]X- CE FROM SURFACE )I. S E. 0 ° 0 273 ' S 1323 :sB S 877 N 99 ' E O' 695 · )4 .511 'E 1193 ' ~l 0 ° 0 ' 11 ' H 3125 · E ,.4j N 591 ~ 2606 ' N 7"5 ' E t~I2 'N 294 1141 ' N 1227 .) · ,) , ,116 ' S 7.g ' ~ .~.j S 163 W £1& ' S IS ' E 0 ° 0 ' 21~ ' S Ig ' E I ./ ~HALL~ OIL SANDS C~.,R~LhT,~ SEEETS !lB HO..! Zu.i ;iELL .KBE XO SSVD SURFACE LC'CATIC')4 A-I A-2 42' 42]6 ' -4194 ' 2114 ' FNL, 207.1 ' FEL, 23-1JN-IOE 5-~' =.,..7 -4!97 ' 2013 ' FNL, 1585 ' FEL, 2~-I5N-IOE B-I B-4A 46' 44!7 -4288 4~' 4353 -4312 59' 4522 -4J09 59' 4051 -4~20 59' 5012 -4344 57' 55;1 -4387 214 F~L, 4!55 FEL. tg-!;S-ttE 5278 FEL. 4304 FEL, [9-tJX-lIE 49 FXL, 1127 FWL. 1~5 FILL, 115~ F~L, lg-IJN-ItE 16§ FNL, 1158 FWL, 19-13N-ltE 68 FSL, IlO0 FWL, tS-lgN-iIE C-! C-2 C-3 C-4 48' 4276 ' -4223 ' 1167 ' FSL, 2255 ' FEL. IO-13N-10E 52' 5577 ' -~255 ' 1227 ' FSL, 245~ ' FEL. IO-15N-10E 4~,0 -420~ 13~5 FSL, £~25 FEL tO-!~N-I 52' 5225 ' -4[60 ' 1344 ' FSL. 24~4 ' FEL. tO-tjX-ruE D-£ D-2A 40 ..... ~o~ ' -44,)9 ..... 964 FNL, I~ ' FEL, 13-15:l-l"E. .~ 4826 -4571 !I%9 FNL, I43~ FEL. 13-12N-10E 52' 5'}3~ ' -43j7 ' 1149 ' FIIL, 1436 ' FEL. t;-I;:I-I')E L-I 5.~' 4078 ' -4021 ' '°70 ' F)iL, 51~ ' FEL, M-I 5S' 4411 ' -35~8 ' 2400 ' FSL. - ..... F~L. o~6 ' F'~L. sE )I-IA N-IB 55' 35?3 ' -35.13 ' 2~60 ' F~L, ~ .... , -o,.S F~L, FEL. ;0- '"' -.5~ 2~60 FSL, 1425 =EL, ~0-13!~-iOE ,~.-1 i I7' ..S.5 -'.'59 t 1~3. FNL, 1-179 FEL, o~,-" 14A 37' 3658 ' -3559 ' 1~92 ' FNL, 1479 ' FEL, J2-25 37 427& .... 1 ....... 25-1'u- 18-1 30' 4422 ' -13~2 ' 3~50 ' FSL, Z~O ' FWL. tl-I]N-IOE W S 25 63' 4042 ' -3740 ' '~ S 17 50' :57I ' -.'.]I1 ' 75' 41'~0 ' -4105 ' :75 ' F-.'L, 255 :'~L. ' !~.)i-ttE N, S E, W 0 ' 0 22.17 ' S 1402 272 ' S 1235 467 S 0 170 S 350 S 316 S 101 E 0 733 W 314 E 142~] i 2677 E 0' 3t37 'E ~00 · u 77..9 ' E ~I7 'X 0 0 ' 034 'E ,; 2~7 'S 5 ' S 176 ' x 23I ' S I] ' E A ' 0 ' UELL KBE X~ SSVD B-I C-I C-2 C-3 C-4 D-2 D-2A L-1 ,'I-t N- ! N-lA S2-25 18-1 ~S17 P-I 42' SHALL~N OIL SANDS CORRELfiTION SHEETS SURFACE 4262 · -4229 ' ' -4225 ' ' -4209 ' 2114 ' FNL, 2013 ' FEL, 23-I3N-102 2013 ' FNL, 1595 ' FEL. 2~-13N-IOE 1918 ' FNL, 1548 ' FEE, 23-1JN-IOE 4444 4375 4549 ~685 5063 5574 -431~ -4353 -4~46 -4371 -4416 2!4 FNL, 4235 FEL. 4304 FEL, 1129 FNL, 1159 FNL, 1159 FSL, IlO0 FEL. 1?-liN-tiE FEL. 19-11~-1!E FNL. i?-lZN-11E FWL. 19-157I-1!E FWL. 19-!~N-t!E FWL, 19-1JN-tlE 48' 430! ' -4255 ' 1167 ' FSL, £25~ ' FEL, iO-ISN-10E 52' 5&il ' -4294 ' ~ ....... I~ ' r:L. '~5u ' FEL, IO-13N-iOE 45' 4604 ' -42~0 ......... to~o FSL, ~a.5 FEL. iO-13N-IOE ~; ~a4 -41~5 1];4 F~L. 2494 FEL, IO-IJN-lt'E 40' 499a ' -44Ij ' 964 ' FNL. !2Z3 ' FEL, 13-I~-I,)E a. 4851 -44!4 1!4q FilL, 1436 FEL. i!-IZN-IOE J~ 5074 ' -4362 ' l!4g ' FNL, ~436 FEL -5514 4I,.:~ ' -4047 i170 ' F~L. ~'~.~. ' FEL, q-lJN-lnC,. -3557 £400 FSL, 686 ' FNL, 1]-t~N- ~E 2~,]0 FEL. :86 ' FWL. t~-i]N- ~E .... l.~j FEL . .. ZEL, i425 ' FEL, JO-Ij~-ioE FSL, 1425 ' FEL. ]O-IJ:i-tOE 37' 3590 ' -~62] ' 1~82 ' FNL. 1477 ' FEL. 14-1~N, ~E 37' 3~91 ' -3619 ' 1~2 ' FNL, 1477 ' FEL, 14-!]N- :E ]7' 4~.)0 ' -426~ ' 1250 ' FNL. 1979 ' FEL. 25-1J~-102 50' 4452 ' -4422 ' ]250 ' FSL, ;030 ' FWL, II-I]N-10E 4085 ' -3775 ' 700 ' FNL. 570 ' FEL, ;405 '-J..~"'= ' c80 ' FXL, :5') ' FEL. FROM SURFACE L~CATIC:( N, S E. ~ 0 ' 0 2255 'S 1406 272 ' S 1237 0 17t 913 357 ,) 717 1463 270~ O' O' 12 ' N $155 'E B7& 'N 612 ' w 2645 ' N 73& · E 12~0 I877 2!I4 S S41 ' E 183'W 2 · S 195 ' W :,1 S I0 E O' ') ' 0 ' ~HALL~ OIL ..:~DS TI~N ND ~DRIZDX ~ELL )~E ~D 42' 427V ' -~2;? ' ..... i~S~ , 55 5315 52' 4575 ' -42£g ' !919 ' FNL, 1546 ' FEL. Z3-1iN-I')E B-I 9-3 B-¢ B-4A B-5 46 .... !~ FXL, 4:35 FEL. 46' 4335 ' -~337 ' 5273 FSL. ;30; FEL, ~?-ITN-IIE 57' 4560 ' -~3¢2 ' 49 FNL, Ill? rWL, S? 4§98 -4356 t55 FNL, 11S~ F~L, 5~' FiO F/G 165 FNL, 1152 FWL, 5?' 55~9 ' -44Z& ' 6B FSL, 1100 FWL, C-I C-3 C-4 5~' ~S]~ -470~ ' I%? ' FSL, Z~S9 ' FEL, lO-llN-lvE ~5' ~529 ' -~ ' 1375 ' '~ ' . ,. ,.. r.L, 2125 FEL. !a-llN-t,',~ ~' ~'~,t ' -4'n~ ' '" F~L .... ...... :.. ~..~¢ ' 24~4 ' FEL, '"'-']N-I':E D-I 0-2 %' 5%? ' ~' ...... -. _.-. %4 FHL, !2~,l ;EL. 5Z' -:8~7, ' -44'25 ' ti.iQ ' FNL, I4.1A ' FEL, L-I C5' 4!"'0' -iF.,53 ' :770 ' FNL. C122 ' FEL. .;-t:X-t',E ?! 55' 4473 ' -3~!2 ' ta:,O ' F!L, aG6 ' F~L, ;3-tTH- :E M'IA 55' 4~117 ..... ~' ~0~ ' ~ ' - . , F... :Sa F~L. ~'-~:~- 'E N- ! N-!,4 N-lB S5' 17007' -~5~S?' Z67) ' F~L, I4~S ' FEL, ~"' ' ' .4.~ FEL ]0-1" t':'E 55' ~;~ HA ;:~o F;L, ~ 32-14 ;7' 3705 ' -3637 ' t~92 ' FNL. I47g ' FEL, t4-1:X- ~E 32-14A 37' 5707 ' -3~33 ' 1~32 ' FNL, i;79 ' FEL. 14-I:N- FE 37' 4316 -4279 !3!0 FNL, 1979 FEL. :Z-IiN-I')E 18-1 30' 4qS4 ' -4434 ' 3253 ' FSL. P-I 75' F;O,I SU~:F;£E LCCATIC. N 0 ' 0 ' ~78 ' S t,:; !75 ' ~ ~22 ~20 ' N 32i 532 ' S 27!5 ,)' I2'N '"":. SS ,i O' 819 'W 7~2 'E ! :97 271 ' W I~~4 W ,) 3 'E O' / ! SHALLC2 OIL SANDS CORRELATiCN SHEETS NE HOF, IZCN WELL A-! A-2 A-3 KBE MD $~:;D SURFACE LOCATIGN 42' 4288 ' -62~6 ' 211~, ' FNL, -2073 ' FEL, 23-13N-IOE 55' 5322' -4:54 2013 ' Ft;L. I585 ' FEL. 23-1]N-fOE 53' 4591 ' -;257 ' 19~8 ' FNL. 15;6 ' FEL, 2~-13N-tOE B-I B-4A ;)-5 46 4476 -4342 214 FNL, ~ FEL, 19-1iN-liE · ' ' " IE 46 44n5 -4359 527~ FEL. 4304 FEL, ,9-.~-I 57 4583 -4362 ' 49 F!JL, !129 F~L, I?-tSX-ItE 57 472~ -~177 ' ~ ~ .6~ FML. 115S FWL, I?-IJN-IIE 59 5094 -4!~ ' 165 FNL, I159 FWL, Ig-llN-I1E 5~ 5620 -4447 ' 68 FSL, 1100 FWL, 19-13N-i1E C-! C-Z C-$ 4B' 4317 ' -42B9 ' !I57 ' FSL, £2[5 ' FEL. tO-1]~-!OE [2' ESS~ ' -~ZZ ' ICC? ' FSL, CIS? ' FEL, iO-l~N-10E ~5' ~651 ' -42~6 ' I;SS ' FSL. 2!2~ ' FEL, ~4 FEL, 0-1'" D-1 D-2 D-2A ~w. -446V 964 FNL, ~2]J FEL. 13-13H-tl)E 52' 4889 ' -444~ ' !149 ' FNL, 1436 ' FEL, 13-I3N-10E ~, ~1~q , , ~ ' , * ~. ~ z; -4]94 ' lI4Q FXL ~J6 FEL IJ-I:N-!.'E 4140 56' 4489 ' -362] ' '2~00 F'iL. oG6 ' FHL. ~5-!]~;- CE 56' 4a3I ' -353[ ' 24~)0 FEL, :96 ' F~L, tJ-iiH- :E 266,) FEL, ;425 ' FEL, ]~-!21-1.)E 2660 ' F~L, ' .... F~l. ;0-'"' ~ 2660 ' FSL, 1425 ' FEL, JO-1iH-i'.'E 32-14 ~7' J7tg ' -365') 1862 ' FNL, !479 ' FEL, t4-tZN- cE 32-14A ~7' J721 ' -3646 ' 1882 ' FNL, 1479 ' FEL, ~-IJX- ~E 37' 432~ -4287 1~60 FNL. l'?Tg FEL. ~-I~N-I')E 18-1 JO' 4487 ' -4457 ' J850 ' FSL, JOJO ' FWL, ii-IiN-!uE W S 25 ~3 4107 -37%l 700 ~'~¢L, ,~,0 FEL, J S 17 ~.0 3~22 ' -3367. 600 ' F!~L, P-i FROM SURFACE LCCATiCN 487 ' S 0 ' 178 ' S ~&2'S 105 723 J25 1490 2737 ') ' 0 ' 12 'N 3176 'E 901 ' N &29 · w 1411 1162 "721 3 £61 ~75 'l~ 8'E O' · {' SHALLC~ OIL SANDS CC~ELATION SHEETS WELL >,BE ~D S~¥D SURFACE L~CATIGN A-1 A-2 A-3 42' 4:64 ' -4322 ' "!14 ' FNL. Sa' c,- .... 15S5 ' FEL. ~l.~ -~527 ' 2013 ' F,~L. · t .~ , * ~ , , B-I 3-2 8-4 B-4A B-5 46' J542 -4403 ~ _ -4-~ 5?' 4~05 5707 -4505 21~ FNL, ~2J5 FEL. I~-ISN-i1E 527~ F~L. ~]04 FEL. !65 FNL, !~5~ FWL, t?-tlN-lIE 155 FNL, !rCS F~L. aB FSL, 1100 FgL. !8-1~N-I!E C-I C-] C-¢ · lB' 4408' -4360 ' 1167 ' FSL, 2255 ' FEL. !O-!~'N-I,.,E 45' 4740 52' ~11~ ' D-! O-2 40' 5144 ' -.:5"5 ' 964 ' F~4L, :2~ ' FEL. ='"' 4¢54 ' -,.t~nc, · '~-I? ' FXL. !45,5 ' FEL ........... ~' ' "4¢ ..... :-~;& ' FEL L-! M-IR 5~' 42ZI ' -41~7 ' 1~7') ' FNL, S:22 ' FEL. N-lB .... 37' 43~6 .... r;JL ,~'70 ' -4 J,~? 13~0 I FEL-.,- 4213 -3885 ' 700 ' FqL, 570 ~'EL, '"'3,0, -.,.', .... .,,>0 ' :'4L, ..,.'¢' . 0 ' 0 ' ..... : l-~'Z: ' ~ 111 'E · 7~5 · 'W lit 'E 27?7 'E :"9 3217 'E 659 'W 757 'E 0' --:- : OIL SANDS rqc~r;ArION SHEETS B-1 4a' 4602 ' -445~ B-3 59' 4710 ' -4471 B-4 57' 4@75 ' -44~2 B-4A 59' 53J5 ' -4520 B-5 59' 57~ ' -455~ 211 FNL, 4255 FEL, IHI3N-I1E 5~5 : 527~ FSL, ?%4 FEL. 19-t3;-11E n ' 4~ FNL. !129 F~L. I?-!5X-t!E !?] ' ~ 155 FNL, 1~ c, IOZ9 .... WL. 19-1iN-lIE ' ~ 165 FNL, I15B FWL. I?-ISN-11E ]~? ' i 68 FSL, 1100 FWL, 18-15N-lIE ~7~ ' S I15 E ,'.t 1684 W Z~Si E C-I C-Z 4483 ' -4435 ' 1167 ' FSL, .~,a'"~' ' FEL. tO-';N-t,''r. .. 0 ' 4843 ' -4~t6 ' 1~75 ' FSL, "~a.: .... r...m [O-ISN-~.'E t00~ ' N ........... , F~L. Z494 ' FEL iO-I]N-I,.E .:~ N 7~9 E 2547 L-I l:! E ........... '~-": N-! 55 J;)2 -.,,47 -:~'} r,'=. ,-, :,~ N-!A :~' :.5,)9 ' -" .... :'"' ::' '~: FEL ti' '~.: ...:'~'.i.~75 ' -J72~ ..... '-=0 F¢L. 14/5 FEL, J0-1:,,,-t0E ,) 4 ,",) c i6 E Ig-I JO' :618 ' -,15~ :i[9 ' FSL, :~I:[) ' FNL, II-liN-fOE ')I i) ' ' cz: -",_ ~ ..... -' ' :'EL. '~,-i:N-:E ARCO Alaska, Inc.{ Post Office Box t 00360 Anchorage, ARaska 995! 0-03~0 Telept~one 907 276 1215 Jerry R. Pollock Engineering Manager Kuparuk River Field May 31, 1990 Mr. C. V. Chatterton Chairman, State of Alaska CONSERVATION ORDER 255 Gas 00ns, C0m/Jssi0r¢ ~nchora~ Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject: ARCO Alaska's Written Statement in Regards to Conoco's Schrader Bluff Pool Rules Submission Dear Mr. Chatterton: Listed below are ARCO Alaska's comments regarding Conoco's Schrader Bluff Pool Rules submission. We are submitting this letter as a written statement at today's public hearing. ARCO Alaska, Inc. is not making an oral statement because the rules, as drafted by Conoco, are acceptable if applied to the Schrader Bluff Pool contained within the Milne Point Unit (MPU). ARCO would like to point out the differences between the pool rules Conoco has proposed to apply to the Schrader Bluff Pool (which, according to their draft submission, incorporates the Ugnu K-13 and Upper West Sak sands, using ARCO's nomenclature) within the MPU, and the pool rules ARCO expects to propose for development of the West Sak sands (which would include the Upper and Lower West Sak sands) in the Kuparuk River Unit (KRU). Because the West Sak sands in the KRU differ substantially from the Schrader Bluff resource, different rules will be required to govern the KRU West Sak development. We understand that the AOGCC will allow different pool rules to be applied to the KRU West Sak development if justified by ARCO's submissions to the AOGCC at that time. ARCO's comments on Conoco's Schrader Bluff Pool Rules Submission are as follows: ARCO anticipates proposing a well spacing value in the KRU that is less, potentially much less, than the 40-acre value contained in Conoco's submission. This is because of the markedly different reservoir character of the West Sak sands in the KRU, with lower reservoir continuity and higher oil viscosities requiring tighter well spacing. What that spacing might be is under evaluation. ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieidCompany C. V. ChattY_ .on May 31, 1990 Page 2 ARCO supports the adoption of rules allowing for the allocation of oil production between reservoirs producing through a common facility. ARCO anticipates that the specific allocation procedures that it will propose for the KRU West Sak development will differ in detail, such as testing frequency, from those submitted by Conoco. ARCO understands that the AOGCC will determine these procedures on a case-by-case basis. Finally, ARCO anticipates proposing less elaborate automatic well shut-in equipment than has Conoco. The KRU West Sak wells will likely be unable to flow to the surface unassisted. Please contact Kevin Meyers (265-6156) if there are any questions regarding these comments. Very truly yours, J. R. Pollock Manager Kuparuk Engineering JRP/RMB:km c: A.L. Leske - BP Exploration BP EXPLORATION May 31, 1990 Mr. C. V. Chatterton Chairman, State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 CONSERVATION ORDER 255 ~ ~-xp~oration (Alaska) Inc, 900 East Benson Boulevard RO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Subject: BP Exploration (Alaska) Inc. Written Statement Regarding Conoco's Schrader Bluff Pool Rules Submission Dear Mr. Chatterton: BP Exploration (Alaska) Inc. is submitting this letter as a written statement at today's public hearing. We are not making an oral statement because the rules, as drafted by Conoco, are acceptable if applied to the Schrader Bluff Pool contained within the Milne Point Unit. We would like to point out that there will be differences between Conoco's proposed Schrader Bluff Pool Rules and any future pool rules proposed by ARCO for development of the West Sak sands in the Kuparuk River Unit (KRU), since the West Sak sands in the KRU differ substantially from the Schrader Bluff resource. We understand that the AOGCC will allow different pool rules to be applied to the KRU West Sak development if justified by submissions to the AOGCC at that time. Please contact Allan Garon (564-4077) if there are any questions regarding these comments. Very truly yours, A. E. Leske Manager Kuparuk/Shallow Sands AEL/tej xc: J.R. Pollock- ARCO Alaska Inc. 0311AEL David L. Bowler Division Manager Conoco Inc. Suite 200 3201 C Street Anchorage, AK 99503 April 5, 1990 CONSERVATION ORDER 255 Mr. C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Mr. Chatterton' Enclosed are proposed Pool Rules for the Schrader Bluff Pool on the North Slope. Also enclosed is supporting testimony for the proposed rules. If you have any questions, please contact A1 Hastings at 564-7650. Very truly yours, Division Manager AEH(jr) Enclosures File 500.22 APR - 6 1990 Al~S~a Oit ,& ~as Cons. C0~ 4/5/90 Rule 1. NAME OF FIELD DRAFT RECEIVED APR - 6 1990 Alasl a .Oil & Gas Cons, Go. mmissiO.~, ~cl~Omga The name of the Field shall be the Milne Point Field. The location of the Field shall be: T12N-R10E, Sect. 1, 2, N1/2 of 3, and N1/2 of 4; T12N-R11E, Sect. 4, 5, 6, N1/2 of 8, and N1/2 of 9; T13N-R9E, E1/2 of Sect. 11, Sect. 12, 13, 14, 23, 24, 26, 27, and 36; T13N-R10E, All; T13N-R11E, Sect. 7, 17, 18, 19, 20, 29, 30, 31, 32. Rule 2. DEFINITION OF POOL The name of the Pool in the Milne Point Field shall be the Schrader Bluff Oil Pool and is defined as the accumulation of oil that is common to and correlates with the accumulation found in the Milne Point Unit Well Number A- l between the depths of 4,180 and 4,683 feet. This pool has informally been called the West Sak Sands and the Shallow Oil Sands. Rule 3. WELL SPACING Not more than four wells may be drilled on any governmental quarter section or governmental lot corresponding to it, nor may any well be drilled on any governmental lot corresponding which contains less than 35 acres. The Pool shall not be opened in a well bore located outside of an approved Participating Area that is closer than 500 feet to.any property line, nor closer than 500 feet to the Participating Area boundary for well bores located within a Participating Area, nor closer than 500 feet to the Pool opened to the well bore in another well. Rule 4. CASING AND CEMENTING REQUIREMENTS (a) Casing and cementing requirements are as specified in 20 AAC 25.030. CASING AND CEMENTING. except as modified below. (b) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. (c) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze back, a string of surface casing shall be set at least 500 measured feet below the base of the permafrost section but not below 2500 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. (d) The surface casing, including connections, shall be sufficiently strong to prevent failure due to permafrost action. To be approved for surface casing, the Commission shall require evidence that the proposed casing and connection can meet these requirements. The evidence shall consist of one of the following: (1) (2) (3) full-scale tensile and compressive tests; finite element model studies; or, other types of axial strain data acceptable to the Commission. (e) Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back may be approved by the Commission upon application. (f) Intermediate casing shall not be required. (g) Alternative completion methods [to 20 AAC 25.030(d)(4) and (5)] which may be used include: (1) slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hole and which may be gravel packed; (2) open hole completions provided that the casing is set not more than 50 feet above the uppermost oil bearing zone. Open hole completions may subsequently be completed with slotted liners, wire-wrapped screen liners, or combinations thereof, and may be gravel packed. (h) The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on accepted engineering principles. Rule 5. AUTOMATIC SHUT-IN EQUIPMENT (a) Upon completion, each well shall be equipped with a pressure sensing device downstream from the wellhead. This pressure sensing device must be capable of: (1) causing the artificial lift device to shut in; and, (2) closing the wellhead valve. (b) A representative of the Commission may witness the operation and performance testing of the shut-in devices to confirm that all associated equipment is in proper working condition. Rule 6. GAS-OIL RATIO TESTS (a) Between 90 and 120 days after continuous production a gas-oil ratio test shall be taken on each producing well. The test shall be of at least 12 hours duration and shall be conducted at the normal producing rate of the well. Test results shall be reported on Gas-Oil Ratio Test, Form 10-409. All tests run in a calendar month shall be reported by the 15th of the following month. Subsequent gas-oil ratio tests will be required every six months for all wells on primary production (unsupported by waterflood injection) and all wells with production support provided by gas reinjection. (b) The gas-oil ratio limitation of 20 AAC 25.240 (b) shall be waived for a period of time not exceeding eighteen months from the date of initial sustained production from the Pool in order to obtain the necessary reservoir information to design and implement an additional recovery project. Rule 7. PRESSURE SURVEYS (a) The static Bottom Hole Pressure shall be determined for each well prior to initial sustained production. (b) Following initial sustained production from each governmental section, a transient pressure survey shall be taken on one well in the section after six months and after 18 months. (c) One of the wells from (b) above on each lease will be designated a key well and a transient pressure survey on this well shall be taken after 30 months production and annually thereafter. (d) Bottomhole pressures obtained by a static buildup pressure survey, a 24-hour shut-in instantaneous test or a multiple flow rate test will be acceptable. (e) Data from the surveys required in this rule shall be filed with the Commission by the last day of the month following the month in which each survey is taken. Reservoir Pressure Report, Form 10-412 shall be utilized for all surveys with attachments for complete additional data. Data submitted shall include, but are not limited to, rate, pressure, time, depths, temperature, and other well conditions necessary for complete analysis of each survey being conducted. The Pool pressure datum plane shall be 4,000 feet subsea. (f) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (e) of this rule. (g) By administrative order, the Commission may require additional pressure surveys or modify the key wells designated in (c) of this rule. Rule 8. SURFACE COMMINGLING AND COMMON PRODUCTION FACILITIES (a) Production from the Schrader Bluff Pool may be commingled at the surface with production from the Kuparuk River Pool provided that: (1) Individual well producing tests of at least six hours duration are conducted at least twice monthly; (2) Individual well testing equipment design and operation shall be approved by the Commission; (3) The method of allocating production between the commingled pools shall be approved by the Commission; and, (4) The concomitant area of the Kuparuk River Pool has also been approved by the Commission for surface commingling. (b) Separate measurement of the production from each Pool will not be required if the provisions of (a) above are satisfied. (c) Gas from the Schrader Bluff Pool may be commingled with gas production from Kuparuk River Pool without separate Pool measurement provided that no gas is transported from the unit and further provided that the terms and conditions of 20 AAC 25. 235 are satisfied. Rule 9. POOL WATERFLOOD SURVEILLANCE PROGRAM The Unit Operator for each unitized Schrader Bluff Pool will submit an annual report to the Commission on any Schrader Bluff Pool Unit waterflood. The report will be submitted by April I of each year for the period ending December 31 and will contain the following information. (a) A tabulation of all pertinent reservoir pressure and injection pressure data on wells in the waterflood permits. (b) A tabulation of all production logs, injections well surveys, and injection well performance data. (c) Produced fluid volumes (oil, gas, and water) and water injection volumes reported by month and on a cumulative basis. Rule 10. INJECTIVITY PROFILES A wireline injection profile survey will be obtained on each injection well during the first twelve months of sustained injection. Follow-up surveys will be performed on a rotating basis such that one-third of the total number of injection wells are surveyed during each calendar year. Additional surveys may also be required if rapid changes in either the injection rate or injection pressure are observed. The completed injection surveys will be filed with the Commission within 90 days after performing the survey. Rule 11. ADMINISTRATIVE ACTION The Alaska Oil and Gas Conservation Commission may, by administrative action, make changes and approve operations that will enhance the efficiency of and recovery from the Schrader Bluff Pool. MILNE POINT UNIT TESTIMONY FOR SCHRADER BLUFF POOL RULES APRIL 5, 1990 INTRODUCTION GEOLOGICAL DISCUSSION RESERVOIR DESCRIPTION RESERVOIR SURVEILLANCE WELL PLANNING FACILITIES DESCRIPTION CONCLUSION REFERENCES TABLE OF CONTENTS AND PROJECT SCHEDULE Page 1 2 6 11 15 18 19 20 LIST OF TABLES Table No. 1. Log Analysis Data Base 2. Oil/Water Contact Depths by Sand 3. Well Test Summary ii Fi gure No. 1. 2. 3. 4. 5. 6. 7. 8. LIST OF FIGURES Index Map SOS Nomenclature SOS Regional Structure Map SOS Milne Point Structure Log Porosity vs. Core Porosity Core Permeability vs. Core Porosity Tract 14 Map Anticipated Production Schedule iii APPENDICES I. SOS Correlation Sheets iv INTRODUCTION The purpose of this testimony is to provide support for establishment of pool rules for the Milne Point Unit Upper Cretaceous resource. Conoco has prepared testimony in behalf of the majority Working Interest Owners in the Milne Point Unit. It is requested that the new pool be named the Schrader Bluff Pool. Boundaries of the proposed pool will be justified in the geologic and reservoir description portions of this testimony. The scope of this testimony includes a discussion of geological and reservoir properties as they are currently understood, as well as Conoco~s proposed plans for reservoir surveillance, well planning, facilities installation and project scheduling. This testimony will enable the Commission to establish rules which will allow economical development of resources within the Schrader Bluff Pool. Development drilling, roads, pipelines and facilities installation are scheduled to commence in early 1990, with initial production beginning by year end. Conoco requests the Commission to approve several key concepts which are considered essential for economic development of the Schrader Bluff Pool. These concepts are: 1) Waterflood initiation within 18 months after primary production is commenced. 2) Well spacing of 40 acres to allow flexibility in placement of wells for maximum recovery of reserves. 3) Waiver of the gas-oil ratio limitation 20 ACC 25.240(b) for a period of time not exceeding eighteen months from the date of initial sustained production. Should the gas-oil ratio increase above the current regula- tory limits, the intent of this waiver is to allow for a period of primary production prior to waterflooding. 4) Waiver of the rule mandating installation of Surface Controlled Subsurface Safety Valves in the Schrader Bluff Pool. 5) Surface commingling of production from the Schrader Bluff Pool and Kuparuk River Pool. This testimony is intended to provide the Commission with sufficient information to formulate these rulings. The geologic portion of this testimony was prepared by Steve Davies, Staff Geologist, responsible for exploration and development geology in the Milne Point Unit area. Engineering testimony was prepared by Steve Rossberg, Senior Production Engineer, responsible for area engineering in the Milne Point Unit. GEOLOGICAL DISCUSSION Introduction This portion of the testimony will provide geologic data to the Commission in support of Conoco's proposed Schrader Bluff Pool. Geologic justification will be presented for limiting the areal extent of the pool. Stratigraphic Nomenclature The Upper Cretaceous and Lower Tertiary sandstones that are potentially oil bearing are generically called the Shallow Oil Sands (SOS) at Milne Point. The type log for this interval at Milne Point is the Conoco A-1 well, which is located near the center of the unit (Figure 1). Figure 2 compares informal Milne Point nomenclature with that used by Arco in the Kuparuk River Unit. At Milne Point, the Shallow Oil Sands are grouped into five intervals, which are named K, L, M, N and O, in descending order. The K and L intervals correspond to Arco's "upper Ugnu" and the M interval is termed "lower Ugnu". At Milne Point, reservoir sandstones within the N interval are equivalent to the mudstone/shale sequence that lies at the base of the lower Ugnu in the Kuparuk River Unit (Werner, 1984). Interval "0" corresponds to Arco's "West Sak Sands". For this testimony only, the N and 0 sandstones, which correspond to the Schrader Bluff formation in the Cretaceous, will be discussed. Major sandstone beds within each sequence are signified by the subordinate letters A, B, C, D, E and F. Thus, the tWo dominant sandstone beds in the "upper West Sak" of Arco are termed OA and OB within the Milne Point Unit. Strati_qraphic Description 0 Interval The 0 interval occurs between 4,362 and 4,604 feet measured depth in the A-1 well. It consists of fine-grained and silty sandstone interbedded with silt- stone and mudstone. These sandstone beds are medium brownish-gray to dark brown, moderately sorted, firm, but friable, and have trace amounts of glauconite scattered throughout. They are generally massive with scattered, faint, horizontal laminae. Evidence of bioturbation is common, and shell fragments are rare. The OA and OB sandstone beds each range in thickness from 20 to 50 feet. These two beds dominate the 0 interval and have a high degree of lateral continuity. These sediments were deposited under shallow marine conditions in the distal portions of a delta. N Interval In the A-1 well, the N interval is located between 4,196 and 4,362 feet measured depth. The sandstone beds of this interval are medium gray to dark brown, very fine to fine-grained, friable, massive to interbedded, and poorly to moderately sorted. Trace amounts of glauconite occur throughout the N interval. Some portions of the beds are distinctly mottled in appearance, suggesting extensive bioturbation. Sandstone beds in this interval are typically quite thin, ranging from 5 to 20 feet in thickness. The NB sandstone is the thickest, reaching 33 feet in the southeastern portion of the Milne Point Unit. The N interval was also deposited in a shallow marine environment along the margins of a large delta complex. Age of Sediments Based on palynology studies by Arco, the N interval and the lowest portion of the M interval are thought to be Late Cretaceous (Maestrichtian) in age. The upper M interval and all of the K and L intervals are assigned to the Early Tertiary (Paleocene; Werner, 1987). Work by Conoco indirectly supports placement of the Cretaceous/Tertiary boundary at this location. Detailed correlations of well logs place an unconformity at the base of the MC sandstone. This unconformity is an important dividing line. Below it, the SOS contain oil that ranges in gravity from 14 to 19.5 degrees API. Above it, the SOS reservoirs contain thick, viscous oil ranging in gravity from 10 to 13 degrees API. The unconformity is also an important economic dividing line: the oil trapped within the underlying N and 0 intervals is the target of current interest, while the more viscous oil in the overlying K, L and M intervals is a resource that will require additional cost and technology to recover. Proposed Pool Name Formal North Slope nomenclature is shown in figure 2. By definition, the Schrader Bluff Formation is the uppermost marine unit of the Cretaceous in central Alaska (Detterman and others, 1975). The sediments in the N and 0 intervals at Milne Point are Late Cretaceous, shallow marine, distal deltaic deposits. They should be collectively referred to as the Schrader Bluff Formation. The name Schrader Bluff Pool is proposed for oil accumulations within the N and 0 sandstones at Milne Point. Structure The structure of the Schrader Bluff Formation is a homocline that dips 1 to 2 degrees to the east-northeast (figure 3). This homocline is a regional feature that extends from southwest of the Kuparuk River Field to the offshore area beyond the barrier islands. Figure 4 is a generalized structure map in the Milne Point.area for the top of regional homocline. The first, which is dominant, trends north-south and has displacements ranging from 20 to 150 feet. Two-thirds of these faults are downthrown to the east, and the remainder are downthrown to the west. The second fault set trends northwest and has an average displacement of 40 feet. Three- quarters of these are downthrown to the northeast, with the rest being downthrown to the southwest. The current northeastern dip is the result of regional tilting in response to sediment loading as a massive system of deltas advanced from the Brooks Range toward the northeast during the Tertiary (Carmen and Hardwick, 1983). The faults that cut the Schrader Bluff are thought to have formed in response to this loading because of their dominant down-to-the-basin (east and northeast) geometry (Werner, 1987). Oil Accumulations The Schrader Bluff Formation contains tremendous quantities of oil. Combined oil-in-place estimates for the reservoirs within the Milne Point and Kuparuk River Units range from 15 to 25 billion barrels (Werner, 1987). Trapping Mechan isms The sandstones of the 0 interval are noted for their continuity throughout the Milne Point and Kuparuk River Units. Oil accumulated in these sandstone beds up-structure to the south and west where faulting provides the primary trapping mechanism (Werner, 1987). As with all of the Schrader Bluff sandstones, structural dip controls oil distribution to the north and east. Both structure and stratigraphy control distribution of oil within the N interval. The NA, NC and ND sandstone beds pinch-out up-dip to the south of the West Sak #25 well. The ultimate control over oil in these reservoirs is the up- dip sand limit. NB and NE are much more continuous, and faulting apparently controls the up-dip limit of their oil accumulations to the south and west in the Kuparuk River Unit (Werner, 1987). Controls over Oil Distribution The faults shown on figure 4 do not represent continuous individual faults. Rather, they depict fault zones that appear to control the Schrader Bluff oil accumulations. Current seismic control does not allow us to identify individual faults that are impermeable boundaries. However, different oil-water contacts in five of the six large fault "blocks" labeled on the map indicate that one or more faults within these zones divide the Schrader Bluff reservoirs into separate compartments. The north-south trending zone highlighted along the left margin of the map forms the western boundary of the Schrader Bluff Pool. Displacement along this fault ranges from 40 to 120 feet, and it effectively separates reservoir compartment #6 from the Oliktok Point wells that lie to the west. These wells have very little pay in the N series sandstones. North-south trending faults of similar magnitude comprise the fault zones that separate and seal the six large reservoir compartments within the Milne Point Unit. The northwest-trending fault zone highlighted along the lower margin of the map comprises several faults. Displacement along these faults is not great, ranging from 30 to 140 feet. However, by analogy with the north-south trending fault system, these faults have sufficient displacement to separate and seal oil in the Schrader Bluff Pool from West Sak-Ugnu oil in Arco's Kuparuk River Unit. The largest and most continuous of these faults forms the southern boundary of the Schrader Bluff Pool. Summar.y The Schrader Bluff Formation in the vicinity of Milne Point and Kuparuk River Units was deposited by a shallow marine deltaic complex during the Late Cretaceous and Early Tertiary. The structure of the Schrader Bluff sandstones is a northeast-dipping homocline that is cut by north and northwest-trending faults. These faults divide the sandstones into six main compartments that are sealed from one another. The name Schrader Bluff Pool is proposed for oil accumulated in these sandstones at Milne Point. This name is in agreement with formal North Slope. stratigraphic nomenclature. RESERVOIR DESCRIPTION This portion of the testimony will summarize various reservoir properties necessary to perform volumetric calculations for determination of original oil in place (OOIP). Discussions of permeability, fluid properties, primary recovery mechanisms and recovery estimates are also included. Discussion will be limited to the Schrader Bluff Reservoir "N" and "0" series sands, which have tested oil of 14 degree API or higher. The upper series sands (K, L, and M) have large quantities of oil in place. With high in-situ viscosity and low API gravity (less than 14 degrees), development of these sands will require additional study and the application of a completely different recovery technique. Conoco requests 40 acre well spacing to allow flexibility in placement of wells to maximize recovery from the "N" and "0" series sands within the Schrader Bluff reservoir. Since projected recovery and flow rates are based on anticipated waterflood response, approval for implementation of a waterflood is also requested. Information contained in this section is intended to provide the Commission with sufficient justification to formulate these rulings. Porosity A detailed analysis including data from 26 wells (See Table 1) was conducted to determine effective porosity from well logs. This data base is considerably larger than the available core data base; therefore, logs were selected as the basis for determining porosity. Areal distribution of this data extends across the Milne Point Unit. The results were used in volumetric estimates of OOIP, determination of effective permeability, irreducible water saturation and oil saturation. A shale corrected neutron-density crossplot technique was used to calculate porosities. Crossplotting corrects for the effects of solid clay particles on the log readings. Shale correction eliminates that portion of the porosity filled with clay-bound water. In addition, logs were normalized to correct for systematic errors, such as tool miscalibrations or hole washouts. The resulting effective porosity values were used in determination of reservoir storage capacity and development of hydrocarbon-feet maps. Figure 5 is a plot of calculated log porosity versus core porosity utilizing data from well B-2, indicating a very good correlation between log-derived porosity and core porosity. Water Saturation Well logs were also used to calculate water saturations for the wells listed in Table 1. Core data is available from four wells in the Unit, and capillary pressure derived water saturations from Well B-2 were used to choose the most appropriate log analysis technique. The modified Simandoux technique provided the best match with capillary pressure derived saturations, and this technique was applied to the well data base shown in Table I to determine water saturation. This log technique accounts for clay bound water, which is suspected to be present in some of the sands, and is considered to be a more accurate determination of water saturation than core-derived data. All of the wells in Table I have electric logs that were corrected for hole diameter and standoff. True resistivity was calculated using standard published log correction charts. A water resistivity of 0.178 ohm-meters at 100 degrees F was calculated using 100% water saturated sands. This value was used as formation water resistivity in the log analysis. Reservoir Fluids and PVT Properties Reservoir pressure, oil gravity and temperature in the Schrader Bluff Pool vary widely within the unit. Fluid properties were calculated at various structural elevations using equations derived from published correlations. Based on this methodology, average values for fluid properties are as follows: Average Reservoir Pressure: Average Reservoir Temperature: Average Crude Oil Gravity: Bubble Point Pressure: Solution Gas-Oil Ratio: Oil Formation Volume Factor (above bubble point): Oil Viscosity (reservoir temperature) 1,750 psig 90 degrees F 17 degrees API 1,388 psig 191SCF/STBO 1.06 bbl/STBO 300 cp Net Pay Determination For the purpose of the "N" and "0" series sands, net pay is defined as pay with a mobile oil saturation and permeability above 1 md. The oil/water contact is defined as the limit of mobile oil; therefore, the oil/water contact coincides with the zero net pay line. Figure 6 is a plot of core air permeability vs. porosity (MPU Well B-2) indicating that a permeability cutoff of 1 md results in a porosity cutoff of approximately 16%. The two distinct data groupings around 16% porosity suggest that sands and shales tend to segregate at this point. The water saturation cutoff of 62.5% was arbitrarily set to approximate the condition of residual oil saturation. Oriqinal Oil-In-Place Based on well control, areas of oil accumulation were divided into six major fault blocks (See Figure 4). Table 2 lists the oil water contact levels by sand in each fault block, indicating varying oil/water contacts in the different fault blocks across the structure. Appendix I contains correlations for each sand in each well. The pay zones within each well were identified using the net pay criterion discussed above. Within each pay zone, the values of net pay, effective porosity, effective water saturation and hydrocarbon-feet were calculated in each well according to procedures previously established in this testimony. The net effective pay values were entered into Conoco~s computer mapping program (digitized on a 500~ by 500~ grid) and contoured on a sand by sand basis. The NEP contour maps treated the fault blocks as separate areas. The program forced the oil/water contact to the zero NEP contour and modified NEP trends in those locations accordingly. The result was that NEP trends near wells reflected the log analysis; while the contours between wells reflected regional trends. Contours approaching O/W contacts were closely gathered together, reflecting rapidly changing NEP values in the transition zone. The effective porosity maps were generated in the same manner, with the exception that trends were not truncated at the oil/water contact or by faults. Therefore, the effective porosity maps reflected more broad regional trends implied by the well data. The initial effective water saturation maps were computer generated (500~ by 500~ grid) directly from the porosity maps. Each porosity value was converted to effective water saturation by applying the initial water saturation equation previously discussed. As a control, the computer-derived saturations were checked with individual well locations and found to be in close agreement. The NEP, porosity and saturations maps were combined mathematically on 500~ by 500~ grids to produce HCF maps on the individual sands. The contours were planimetered within each four section tract (See Figure 4). Within each tract, the contours were planimetered separately within each fault block. HCF volumes were converted to OOIP by applying the factor 7758 divided by the oil formation volume factor. Permeabi 1 i ty Permeability ranges from 27 md to 5,896 md in the "N" sand and from 21.2 md to 143 md in the "0" sand. Since 1980, twelve production tests conducted in the "N" and "0" series sands have produced reliable permeability values. The results of seven of these tests are summarized in Table 3, indicating an average flow capacity of 6,410 md-ft. A recent production test on MPU well G-1 (located in tract 14) indicated a flow capacity of approximately 82,000 md-ft and permeability of 2,000 md. In cores taken from G-l, air permeability ranged from 5,000 md to 10,000 md and from 200 md to 700 md for the "N" and "0" series sands respectively. Primary Recovery Mechanisms Primary recovery from the MPU Schrader Bluff reservoir will predominantly result from pore volume compressibility with a minimum amount of solution gas drive. Laboratory analysis indicates sufficient core compressibility to contribute to primary recovery. Recovery Predictions The MPU Schrader Bluff reservoir was modeled using the Todd, Dietrich and Chase (TDC) Volatile Oil Steamflood Simulator in the isothermal mode. The TDC model is three-dimensional and able to handle multiple, non-communicating layers, as well as simultaneous flow of oil, gas and water. In addition, the TDC model will handle pressure dependent pore volume and permeability. MPU wells A-3 and N-lB were selected to represent average wells in two distinctly different areas of the reservoir. These wells provided porosity, permeability and oil gravity data for the respective areas. Each of the "N" and "0" sands were treated as separate homogeneous layers. Porosity and water saturation data were read directly from well logs using techniques discussed in the determination of OOIP. PVT properties were calculated (see the Reservoir Fluids Section) and assigned to the various sands in different areas of the field based on observed oil gravities. Permeability and relative permeability characteristics (see the Permeability Section) were generated and entered into the model. The wells were pressure constrained to a producing bottom-hole pressure of 800 psig. Injection well pressures were constrained to minimum fracture gradient of 0.70 psi/ft. The wells were not water-cut constrained. The model was set up on a 7 x 7 grid, which results in five grid blocks between wells on opposite corners. Well spacing was changed by increasing or decreasing horizontal dimensions of the grid blocks. Injection patterns were simulated by placing wells at the appropriate positions and adjusting grid block sizes. Various well spacing and injection well patterns were modeled, and the results clearly illustrate that waterflooding on 80 acre 5-spot or inverted 9-spot patterns will result in increased recovery over primary (on any spacing to 40 acres) or a regular 80 acre 9-spot pattern. Primary recovery cases Show high initial rates approaching those of waterflooding, indicating that injection can be delayed for a period of primary production. Cases run on delayed injection indicate that reservoir pressure will be maintained with injection delays up to two years. Model results indicate delayed injection to have negligible impact on ultimate recovery. Faulting and stratigraphy will ultimately play an important role in determination of optimum spacing and pattern placement. Increasing well density to 40 acres may become necessary to achieve necessary communication between injectors and producers in some areas of the field. The following is a summary of major conclusions presented in the reservoir description portion of this testimony: 1) Based on well control, areas of oil accumulation were divided into six major fault blocks (See Figure 4). 2) Primary recovery from the MPU Schrader Bluff reservoir will predominantly result from pore volume compressibility with a limited amount of solution gas drive. 3) Computer model results clearly illustrate that waterflooding on 80 acre 5-spot or inverted 9-spot patterns will result in increased recovery over primary. 4) Cases run on delayed injection indicate that pressure will be maintained with injection delays up to two years. Model results indicate delayed injection will have negligible impact on ultimate recovery. A period of primary production will provide additional production data for use in design of the waterflood pattern, which may result in a more efficient waterflood and increased recovery. 5) Faulting and stratigraphy will ultimately play an important role in determination of optimum spacing andwaterflood pattern. Increasing well density to 40 acres may become necessary to achieve necessary communication between injectors and producers in some areas of the field. 10 RESERVOIR SURVEILLANCE To monitor depletion and optimize recovery from the Schrader Bluff reservoir, an active program of reservoir surveillance will be initiated in the early stages of development. This portion of the testimony will discuss a proposed reservoir surveillance program, which will include careful monitoring of reservoir pres- sure, gas-oil ratio, produced volumes, injected volumes, injection well surveillance and well surveys. Reservoir Pressure In the Schrader Bluff reservoir, both permeability and pore volume are thought to be pressure dependent; therefore, careful monitoring of reservoir pressure and pressure maintenance are considered to be very important aspects of the depletion program. Monitoring of reservoir pressure will commence with the initial drilling phase. The static bottom-hole pressure will be measured in each well prior to initiating sustained production. These pressure measurements will be obtained either by DST or RFT during the drilling and logging phase. If a DST or RFT is not conducted, the static reservoir pressure will be measured after completion using mechanical or electric gauges run on wireline. These static pressure surveys will be conducted for at least 8 hours, to insure that accurate information is obtained. After six months of sustained~.production, the reservoir pressure will be measured in one well per 640 acre section. In areas of the reservoir producing on primary production, these measurements will be conducted every six months until water- flooding is initiated. In areas of the reservoir under active waterflood, the pressure will be measured in one well per 640 acre section after six months of sustained production and again after'18 months of production. In addition, one well per 640 acre section will be designated as a key well. The static reservoir pressure will be measured after 30 months of sustained production and annually thereafter for the life of the well. Bottom-hole pressures will be obtained by 24 hour static tests, pressure buildup surveys, multiple flow rate tests or in injection wells by pressure falloff tests. For consistency, the pressure datum plane in the MPU Schrader Bluff reservoir shall be 4,000~ subsea. All necessary data and well conditions to perform a.complete engineering analysis, including rates, pressures, depths, temperature and times will be recorded and forwarded to the Commission by the last day of the month following the month in which the survey was conducted. Reservoir Report Form 10-412, complete with any necessary attachments, will be utilized to report the data. Due to complicated faulting and stratigraphy in the Schrader Bluff reservoir, it may be necessary to implement a pressure-transient, interference testing program to insure proper pattern arrangement and communication between injectors and producers. The purposes of this testing program will be to identify reser- voir boundaries, such as faults, facies changes or other permeability barriers that may adversely influence the waterflood project. Information gathered from interference testing will be forwarded to the Commission upon request. 11 In addition to the static pressure monitoring program, the producing bottom- hole pressure will be routinely monitored in all production wells. In injection wells, the surface injection pressure will be continuously monitored. Gas-Oil Ratio Testing With an initial solution gas-oil ratio (GOR) of 191 SCF/STBO and an initial oil formation volume factor of 1.06 bbl/STBO, the MPU Schrader Bluff reservoir is considered highly under-saturated. As previously discussed, primary recovery from solution gas drive will be negligible compared to pore volume compressibility, which is considered to be the most significant drive mechanism for primary recovery. Current plans are to produce the reservoir under primary means for a period of one year and then implement a full scale waterflood project. Due to the under-saturated nature of the reservoir, water channelling problems or extremely large fillup volumes resulting from buildup of gas saturation in the reservoir are not anticipated. In addition, sufficient structural relief to form a secondary gas cap is not thought to be present in the MPU Schrader Bluff reservoir. Based on these assumptions, it is concluded that pressure depletion resulting from primary production, and the anticipated increase in GOR, will have negligible impact on ultimate recovery from the Schrader Bluff reservoir. Computer model runs on cases delaying production up to two years, confirm this conclusion (see the section on Recovery Predictions). Between 90 and 120 days after continuous production, a gas-oil ratio test will be taken on each producing well. To ensure accuracy, the test will be a minimum of 12 hours in duration and conducted at the normal producing rate and pressure of the well. All tests will be reported on the Gas-Oil Ratio Form 10-409, by the 15th day of the month following the month that the test was conducted. Subsequent gas-oil ratio tests will be performed every six months on wells producing on primary production (prior to implementation of the waterflood or wells isolated from injectors). Based on this testimony, Conoco requests that the gas-oil ratio limitation in 20 AAC 25.240(b) be waived for a period of time not exceeding eighteen months from the date of initial sustained production from the Schrader Bluff reservoir. Should the GOR increase above current regulatory limits, this waiver will allow for a period of primary production prior to initiating the waterflood. Data collected during primary production will be used in waterflood design. This should ultimately result in a more efficient secondary recovery project and increased reserves. Produced Vol umes It is proposed that surface commingling of production from the Schrader Bluff Pool with production from the Kuparuk River Pool be allowed at any point downstream of the well test system for final separation and sales at the MPU Central Facilities Pad. The current KuparukRiver Pool has an estimated economic life of approximately seven years without commingled Schrader Bluff production. Commingling of production will prevent both economic waste from and 12 underutilization of existing facilities in the Field and loss of reserves from the Kuparuk River reservoir. Prior to commingling, the Commission may approve the proposed method of testing and allocation; and also approve the proposed design and operating procedure for the test equipment. The following is Conoco~s proposed methodology for well testing and allocation between the two pools. Produced volumes of oil, water and gas from the MPU Schrader Bluff Pool and Kuparuk River Pool will be monitored with individual well tests. Well tests will be the basis for allocating monthly production volumes (oil, water and gas) for the individual wells. The individual well tests will be of at least six hours in duration and performed a minimum of twice monthly. Schrader Bluff wells will be produced with artificial lift equipment. The producing bottom-hole pressure will be routinely monitored with surface readout or by shooting fluid levels. The producing bottom-hole pressure will be recorded at the beginning of each test cycle (test equipment will be discussed in detail later in the Facilities and Scheduling portion of the testimony). (Bi-monthly well tests will be in agreement within 10% error to be validated for allocation usage.) Wells testing outside of this tolerance will be retested a third time. Individual pad production will be summed to determine total production from the individual pools. It is also proposed to commingle gas from the Schrader Bluff Pool with gas from the Kuparuk River Pool. This gas will be reinjected into the Lower Kuparuk River gas displacement project in MPU well E-3. Under no circumstances will gas be transported out of the Milne Point Unit. All gas produced from the Schrader Bluff Pool will be allocated based on individual well tests and utilized in accordance wi th Rule 20 AAC 25.235. Injected Volumes and Waterflood Surveillance A daily record of injection rate and surface pressure will be maintained for each injection well in the Schrader Bluff Pool. In addition, a record of cumulative injection and pressure will be maintained per well and per pad. This data will be measured and totalized on an individual well basis. Initial surface injection pressure will not exceed 1,000 psig, which is below the estimated parting pressure (based on an estimated frac gradient of 0.70 psi/ft). After six months of continuous stabilized injection, step-rate tests will be conducted in one well per ADL tract to determine actual parting pressure and fracture length at various rates and pressures. Injection pressure may be increased based on the results of the step-rate tests. Injection wells will be pressure parted only if it can be clearly demonstrated, using industry accepted reservoir engineering analysis, that the waterbank extends beyond the fracture half-length. A second round of step-rate tests will be conducted after 36 months of continuous injection. In conjunction with the step-rate testing program, pressure falloff tests may be conducted in one well per pad to determine average reservoir pressure. The results of step-rate and falloff tests will be reported to the Commission upon request. 13' Injection surveys using wireline conveyed temperature logs, radio-active logs, mechanical flow measuring tools or a combination of these devices will be run in each injection well after twelve months of continuous injection. Following the initial surveys, each injection well will be routinely surveyed every third year. Surveys will be conducted in any well exhibiting major changes in either injection rate or pressure. Completed surveys will be filed with the Commission within 90 days after performing the survey. As Unit Operator of the Milne Point Unit Schrader Bluff Pool Unit Waterflood, Conoco Inc. will submit an annual report to the Commission on the Schrader Bluff Pool Waterflood. The report will be submitted by April I of each year for the period ending December 31 and will contain the following information: a) A tabulation by month, and on a cumulative basis, of produced volumes (oil, water and gas) and injected volumes and pressures. b) A summary of all injection surveys, injection well testing and injection well performance for the period. c) A summary of pressure surveys conducted on either producers or injectors during the period. 14 WELL PLANNING Casing and Cementinq The Schrader Bluff Pool casing and cementing requirements are generally consistent with AOGCC Regulation 20 ACC 25.030, requiring that casing and cementing programs meet the following criterion: 1) Provide adequate protection of all fresh water zones. 2) Prevent fluid migration between strata. 3) Provide protection from pressures that may be encountered, including pressure due to thaw subsidence and freezeback within the permafrost interval. The proposed standard casing design for a typical Schrader Bluff well is very similar to that currently used in Milne Point Unit Kuparuk River wells: 13 3/8" conductor set at 80~, cemented to surface; 9 5/8" surface casing set at least 500~ below the base of the permafrost but not below 2,500~ TVD, cemented to surface utilizing an arctic set cement; 7" production casing from surface to approximately 5,000~ TVD, cemented from TD to 500~ above the top of the Schrader Bluff "K" sand. An alternate design currently under consideration is to substitute the above design with 16" conductor, 13 3/8" surface casing and 9 5/8" production casing, which may better facilitate running wire wrapped screen liners for gravel packing. Atypical open hole completion currently under consideration is as follows: 13 3/8" conductor set at 80~, cemented to surface; 9 5/8" surface casing set 500~ below the base of the permafrost, cemented to surface with arctic set cement; 7" production casing set approximately 50~ above the top of the Schrader Bluff "N" sand, cemented from TD to 500~ above the top of the "K" sand; open hole under-reamed to 12 1/4" from the 7" casing point to 150~ below the base of the "0" sand. The open hole section may be completed with either slotted or wire wrapped liner and possibly gravel packed. To provide insulation, the surface casing/production casing annulus will be arctic packed in all wells. It is proposed that the Schrader Bluff casing and cementing rules be written as specified in 20 AAC 25.030 and in accordance with the current Kuparuk River Field rules as follows: 1) For proper anchorage and to divert an uncontrolled flow, a conductor casing shall be set at least 75~ below the surface and sufficient cement will be used to fill the annulus behind the pipe to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze back, a string of surface casing will be set at least 500~ MD below the base of the permafrost section but not below 2,500~ TVD. Sufficient cement shall be used to fill the annulus behind the casing to the surface. 15 3) To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength to prevent failure. To be approved for use as surface casing, the Commission shall require evidence that the proposed casing and connections meet the above requirement. The evidence shall consist of one of the following: a) full-scale tensile and compressive tests; b) finite element model studies; or, c) other types of axial strain data acceptable to the Commission. Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze back, based on sound engineering principles, may be approved by the Commission upon application. 4) It is proposed that the Commission approve a ruling that intermediate casing not be required. 5) It is proposed that the Commission approve a ruling allowing the following alternative completion methods: a) slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hole and which may be gravel packed; b) open hole completions provided that the casing is set not more than 50~ above the uppermost oil bearing zone. Open hole completions may subsequently be completed with slotted liners, wire-wrapped screen liners, or combinations thereof, and may be gravel packed. c) horizontal completion with liners, slotted liners, wire wrapped screens, or combination thereof, landed inside the horizontal extension and which may be gravel packed. The Commission may approve other completion methods upon application and presentation of data which shows the alternatives are based on sound engi- neering principles. Blowout Prevention It is proposed that the rule for blowout prevention in the Schrader Bluff Pool be written identically to the provisions established in Regulation 20 AAC 25.035 (Secondary Well Control: Blowout Prevention Equipment (BOPE) Requirements) of the AOGCC regulations dated April 2, 1986. Except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance with API Recommended Practice 53 for blowout prevention systems. 16 Automatic Shut-in Equipment The Schrader Bluff reservoir, with an average pressure gradient of 0.443 psig/foot, is not capable of continuous unassisted flow of liquid hydrocarbons through the permafrost interval to surface. This has been substantiated by numerous flow tests conducted on Schrader Bluff wells in the Milne Point Unit. Upon completion, Schrader Bluff wells will be produced utilizing artificial lift systems. It is proposed that the rule for automatic shut-in be written based on AOGCC regulation 20 ACC 25.265 (b) dated April 2, 1986 as follows: 1) It is proposed that the rule be written waiving mandatory installation of Surface Controlled Subsurface Safety Valves in the Schrader Bluff Pool. 2) It is recommended that it be mandatory to install a Commission approved, fail-safe, automatic surface safety system on all wells producing via artificial lift. The system may be hydraulically, pneumatically or electrically controlled and must be able to simultaneously close the wellhead valve and shut-in the artificial lift equipment to prevent uncontrolled flow of liquid hydrocarbons. To insure that the surface safety system is functioning properly, a Commission representative may witness operation and performance tests at intervals and times specified by the Commission. 17 FACILITIES DESCRIPTION AND PROJECT SCHEDULE There are approximately 16,800 developable acres in the Milne Point Unit Schrader Bluff Pool. Due to directional drilling limitations on these 3,000~ to 5,000~ TVD wells, the largest area developable by a drill pad is approximately one section (640 acres). This implies the potential for a total of 26 pads. The major constraint on development in the Schrader Bluff reservoir will be available processing capacity at the MPU Central Facilities Pad (CFP). Without major modifications, CFP handling capacity is estimated at 40,000 BOPD. Total capacity of the Kuparuk is currently estimated at 30,000 BOPD, requiring injection of 40,000 BPD. CFP injection capacity is currently 50,000 BPD, leaving approximately 10,000 BPD excess for Schrader Bluff injection. Therefore, total excess facility capacity (crude processing and injection) in 1990 is estimated at 10,000 BPD. The available capacity will increase substantially as Kuparuk production declines. It will become necessary to increase injection capacity of the facility as the Schrader Bluff development proceeds to fully implement the waterflood project. However, this expansion should not be necessary in the early development. Due to the close proximity to the CFP, development will begin in Tract 14. The shorter roads and pipelines result in the most economical development scenario. Plans are to drill 12 additional Schrader Bluff wells and complete 160 acre primary development in Tract 14 on H, I and J pads during 1990 (Figure 7). Installation of pad facilities and pipeline hookup are planned for the third quarter, with initial production scheduled to commence by year-end. Infill drilling to 80 acres and implementation of a waterflood is planned for 1991. Development will continue at a pace set to maintain facilities at full capacity as the Kuparuk reservoir declines (See Figure 8). Economical development of the Schrader Bluff Pool is contingent upon utilizing the existing Kuparuk facilities. As previously stated, it will be necessary to surface commingle Schrader Bluff crude with Kuparuk River crude. Plans are to install test facilities at each pad consisting of a two phase separator and an emulsion meter. Microwave absorption meters have been extensively tested in other Conoco operations and by other major oil companies. The available test data indicates that these meters will be applicable for use in Schrader Bluff test systems. Unlike other emulsion meters, microwave absorption meters are relatively unaffected by phase percentages and specific gravity. Test systems utilizing these meters are approved by the Texas Railroad Commission for 'allocating commingled production. The current Kuparuk River test system on B and C pads utilizes three-phase test separators. Kuparuk tests, as an aggregate, are generally within 10% of the sales volume. The Kuparuk test system operates at essentially the same working pressure as normal manifold pressures, resulting in reliable test data. Based on test data gathered for the microwave absorption meters, it is anticipated that the proposed Schrader Bluff system will be within this accuracy range. This system will also be designed to operate as closely as possible to normal pro- ducing pressures, which should enhance performance of the system. 18 CONCLUSION This testimony has been based on Conoco~s present knowledge of the Schrader Bluff reservoir and contains results from theoretical analysis, laboratory analysis, model studies, reservoir management considerations and operational requirements. Conoco is confident that present knowledge of the reservoir is adequate to devise a prudent and economic course of action for development of the Schrader Bluff Pool, and trusts that this data is sufficient for the Commission to formulate Pool Rules consistent with the plan of development as currently envisioned. 19 REFERENCES Carmen, G. J., and Hardwick, P., 1983, Geology and Regional Setting of Kuparuk Oil Field, Alaska: American Association of Petroleum Geologists Bulletin, v. 67, p. 1014- 1031. Detterman, R. L., Reiser, H. N., Brosge, W. P., and Dutro, J. T., Jr., 1975, Post-Carboniferous Stratigraphy, Nor. theastern Alaska: United States Geological Survey Professional Paper no. 886, p. 32 - 39. Finley, E. A., 1959, The Definition of Known Geologic Structures of Producing Oil and Gas Fields: United States Geological Survey Circular 419, 6 p. Jamison, H. R., Brockett, L. D., and McIntosh, R. A., 1980, Prudhoe Bay--A Ten Year Perspective, in Giant Oil. Fields of the Decade, 1968-1978: American Association of Petroleum Geologists Memoir 30, p. 289 - 314. Masterson, W. D., and Paris, C. E., 1987, Depositional History and Reservoir Description of the Kuparuk River Formation, North Slope, Alaska: Pacific Section, Society of Economic Paleontologists and Mineralogists, Alaskan North Slope Geology, v.1, p. 95- 106. Werner, M. R., 1987, West Sak and Ugnu Sands: Low-Gravity Oil Zones of the Kuparuk River Area, Alaskan North Slope: Pacific Section, Society of Economic Paleontologists and Mineralogists, Alaskan North Slope Geology, v.1, p. 109 - 118. , 1984, Tertiary and Upper Cretaceous Heavy Oil Sands, Kuparuk River Unit Area, Alaskan North Slope: Arco Alaska, Inc., unpublished pre-print, 20 p. 20 TABLE 1 LOG ANALYSIS DATA BASE WELL NAME DIL S~P NGT A-1 X A-2 X A-3 X B-1 X B-2 X B-3 X B-4 X B-4A X B-5 X C-1 X C-2 X C-3 X C-4 X D-1 - X D-2 X D-2A X L-1 X M-1 X M-lA X N-1 X N-lA X N-lB X HB 18-1 X Sohio West Sak 17 X ARCO West Sak 25 X Texaco Prudhoe 1 X GR/FDC CNL X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X TABLE 2 OIL/WATER CONTACT DEPTHS BY FAULT BLOCK BY SAND O/W Contact Depth (TVDss) Sand 6 5 4 3 2 NA 3550 3550 3750 4100 4425 4425 NB 3700 3700 3900 4200 4425 4425 NC 3750 3750 3900 4225 4425 4425 ND 3600 3600 3850 4250 4425 4425 NE 3675 3765 3900 4250 4425 4425 OA 3850 3850 4175 4350 4500 4500 OB 3900 3900 4200 4450 4400 4550 TABLE 3 WELL TEST DATA WELL A-1 B-2 G-1 ZONE(S) OA (DST) OB (DST) NC/ND NC/ND NC/ND NC/ND NB/NC/NE NB/NC/NE NB/NC/NE PERFS (MD) 4366 - 4372 4518 - 4542 4372 - 4402 4372 - 4402 4372 - 4402 4372 - 4402 4164 - 4816 4196 - 4202 4216 - 4228 koh 2520 1190 6517 8845 9457 9923 43100 43100 43100 INDE× MAP MILNE POINT UNIT ~'~ ,A- ! PRUDHOE BAY UNIT HEMI SPRINGS UNIT MILES 5 FIGU.R E I sbs NOMENCL~'~ URE , i TERMINOLOGY TYPE LOG " , .... MILNE PT. UNIT ~XrO~.~A~, tX~OaUAL MILYE POINT KUPARUK NORTH SLOPE A- 1 UNIT : RIVER UNIT . ~ ~ ~ C-P. j FORMATION ...... SA S U p SAGAVAN- P IRKTOK E SANDS ' '~~ ~ ~, B' SANDS ~ ~ PRINCE CREEK ~[']~- ~' SANDS Sa,l~ ~ SCHRADER sequence ~ BLUFF U. WEST , , , , ,,,, FIGURE 2 SO~ ~.EGIONAL STRJCTURE WITH WEST SAK OIL ACCUMULATION KUPARUK UNIT i MILES RIVEt~ .. > "' UNIT },?17'1 IT 1 I-l.t'l I. SPRINGS Nrr , \ . 5OUR£EI iJERNER l~@?, 1~4 FIGURE 3 SOS: MILNE TOP POINT STI~UCTURE OF NA SAND -% r,'--. ':% ,3 4: ...o~, \ \ -% "FIGUI~E · INTERCEPT FAULT BLOCK Miles LOG CALCULATED TOTAL POROSITY vs CORE POROSITY ( MPU B- 2) C m 0 0 o o otb o o 0 CD c9 0 0 oo o 0 o %0 8 o o 0 0 00 0 0 0 0 0 0 0 0 0 0 ~o o o 0 o o o o ooo __~_' .... 10 10 OcoO ,0 0 0 0 0 o o~o o o CORE POROSITY (%) --F--T--"I I ITl CORE AIR PERMEABILITY vs CORE POROSITY o o (MPU ___l I I __L__J __L__! 0 0 o 0 ----"-6 oo o o o o 0 o 0 0 o O- ~,0 C 0 o o o o o0 o 0 CORE 0 o o° o oo 2O POROSITY (%) $0 4O ~0 Z$555eB9 i C m J-] g__ 0 I__ H t3~SBBD -ZS65568B 0 PROPOSED LDCRTIOh PLRNES RSECTING HORIZONS i m i SHRLLDN OIL SRNDS STRUCTURE MR TO DE FRULT PLANES C:: 33' rn MILNE POINT PRODUCTION SCHEDULES .-~ 0 O- _ ".,I .~',. ?"SOS ! KUP ,_iff., o. .,. I0 TIME ~0 WELL A-1 42' 4211 A-2 56' 5232 A-3 APPENDIX SH,LLuW OIL SANDS CORRELATION SHEETS NA HORIZON SURFACE LOCATION -417[ ' 2114 ' FNL, -4173 ' 2013 ' FNL, -4159 ' 1918 ' FNL, B-I 46' 4400 ' -4272 ' S-2 44' 4334 B-S 59' 4504 ' B-4 59' 4630 ' -4304 '. B-4A 59' 4978 ' -4325 ' B-5 59' 5512 ' -4374 ' C-I 48' 4257 ' -4209 ' C-2 52' 5554 ' -4234 ' C-3 45' 4544 ' -4183 ' C-4 52' 5208 ' -4148 ' D-I 40' 4925 ' -~390 ' 0-2 52' 4805 ' -4372 ' D-2A c~. 5007 ' -4321 ' L-1 56' 4053 H-1 56' 43B0 .M-IA 53' ~A pS-1 55' 3562 H-IA 55' 56!7 N-!B 55' 3598 32-14 37' 3428 32-14A 37' 3632 32-2§ 37' 4255 1B-I 30' 4414 W S 25 63' 4002 W S 17 60' 3338 P-I 75' 4 ~ FROM SURFACE LOCATIC~ )4. S E. L( 214 5279 165 68 2073 ' FEL, 23-13N-tOE 0 ' 0 1585 ' FEL, 23-13!4-10E ..... S 131& 1546 ' FEL, 23-13~-10E 273 ' S 1323 FEL, I?-I3H-I1E FEL. 19-!~!~-1iE FWL, 19-1314-11E FWL, [9-13N-lIE FWL. 19-13~-11E FWL, IB-!3N-IIE FNL, 4233 FSL, 4304 FNL, 1129 FNL, 1158 FNL, ll:B FSL, 1100 1167 FSL ~i~ ' FEL. IO-13H-IOE 1229 ' FSL, 2459 ' FEL, !O-I3N-IOE ~3~5 ' FSL, 2326 ° FEL, IO-13N-IOE [344 ' FSL, 2494 ' FEL, £O-13N-IOE 456 ' S 99 0 ° 0 !68 ' S 695 877 ' N 311 343 ' S 1393 310 ' S 2444 0 ° 0 ° 11 'N 3125 ' E 945 ' ,'q 591 ' W 2604 ' N 725 ' E 964 ' FNL, 1233 ' FEL, 13-13N-IOE 1312 ' N 284 1149 ' FNL, 143~ ' FEL, 13-13N-IOE 1141 ' N 1227 1149 FNL, 1436 FEL, 13-13~4-t0E .'= N I830 -3996 ' 1970 ' FHL, 5122 ' FEL, 8-15N-I(IE -3545 ' 2400 ' FSL, 6~6 ' FWL, 13-13N- qE NA £~00 ' FSL. 684 ' FWL, !3-t3~{- ~E · -3507 ' 2650' r:,., I : ' FEL, 30-ISN-IOE · -3495' 245.0' F.CL, 1415 ' FEL. · -3495 ' 2660 ' FSL~ 1"~= ° FEL, JO-15N-10E ' -3565 ' 1892 ' FHL, I479 ' FEL, 14-1314- 9E ' '='= ' 1892 ' FNL, 1479 ' FEL 14-13){~ 9E ' -4218 ' 1340 ' F~L. 1979 ' FEL, 25-13N-lOE -4384 ' .3850' FSL, 3030 'FNL, ll-IJN-Ii)E 3707 700 ' FNL, 570 ' FEL. 32-13N-tOE ' ~ .... 26-I -,.,=~H 600 ' F!{L, 2~0 FEL, 3~4- ?E -407H ' 935 ' FHL. 565 ' FwL. 8-12N-IIE 0 ' 2064 ' S 528 · E .) . !) , 316 'S 7B'~1 ,' z..~ S 163 W 9 ' S !60 · ~ 216 ' S IB ' E 0° 0 ' 0 ' 0 ' 216 ' S lB ' E ,) ' 0 ' ,) ' 0 ' L_ ,f WELL KBE ~D SSVD A-I A-2 A-3 B-2 B-4 B-4A B-5 C-I C-2 C-3 C-4 D-1 D-2 D-2A L-! M-IA N-IA N-IB SHALLOW OIL SANDS CORRELATION SHEETS NB HO,.ITD,t SURFACE LOCATION 42' 4236 ' -4194 ' 2114 ' FNL, 2073 ' FEL, 56' 5259 ' -4!97 ' 2013 ' FNL, 1585 ' FEL, 58' 4530 ' -4183 ' 1918 ' FNL, I546 ' FEL, 44!7 435B 59' 4651 59' 5012 59' 5534 -4288 -4309 -4320 -4344 -438~ 214 5278 165 165 68 FNL, 4235 FSL, 4304 FNL, 1129 FNL, 1158 FNL, I158 FEL, ilO0 FEL, FEL, F~L, FWL, FWL, FWL, 48' 4276 ' -4228 ' 1167 ' FSL, 2256 ' FEL, .~ 5577 -4255 1229 FSL, 2459 FEL, 45' 4570 ' -4205 ' 1395 ' FSL, ~ · ' FEL, 52' 5226 ' -4t60 ' 1344 ' FSL, 2494 ' FEL, .~J -4409 964 FNL, 1233 FEL, .; 4826 -4371 !149 FNL, 1436 FEL, 52' 5034 ' -411.17 ' 1149 ' FNL, 1436 ' FEL, 4078 ' -4021 ' 1970 ' FHL, 5122 ' FEL, 56' 4411 ' -3568 ' 2400 ' FSL, 686 ' FYL. 56' ~IA ~(A 2400 ' FSL, 686 ' FNL, ......... 1425 ' FEL. JJ J~?~ -3538 2660 FSL, ~ 3653 -~.6 2660 FSL, 1 ~ FEL. 55' 36Z2 ' -3525 ' 2660 ' FSL, 1425 ' FEL, 32-14 37' 3655 ' -3591 ' 1892 ' FNL, 1479 ' FEL, 32-14A 37' 3658 ' -3589 ' 1882 ' FNL, 1479 ' FEL, 32-25 18-1 37' 4276 ' -4239 ' 1360 ' FNL, 1979 ' FEL, 30' 4422 ' -4392 ' ~850 ' FSL, 5030 ' FWL, W S 25 63' 4042 ' -3740' 700 ' FNL, 570 ' FEL, W S 17 60' ,3371 ' -7311 ' 600 ' FNL, 250 ' FEL, P-! 75' 4180 ' -4tC, 5 ' ~!5 ' FSL, 965 ' F~L, 23-13N-lOE 23-13N-I08 ~,~ -, -) ~.-lJ4-1tE I?-13N-I1E !9-13N-118 19-13N-!18 19-13N-118 19-13N-11E I8-13N-IIE IO-13N-IOE lO-13N-10E IO-13N-IOE IO-13N-IOE 13-13N-108 13-13N-IOE 13-1JN-IOE FROM SUEFACE LOCATION N, S E, l~ 0' O' 2247 ' 9 1'402 ' W 272 ' S 1235 ' W 467 0 170 891 ,50 316 S 101 0 S 703 N 314 S 1428 S 2677 O' !2 'N 3137 858 'tl 6OO 2619 'N 729 'E 'W 'E 1336 °N CB& 1147 'N 1234 217 °N !848 8-1.])I-IOE 0 ' 0 ' 13-!3N- 98 2085 ' S 634 ' E 13-1.]N- BE )iA );A ? ~ 'l 30-I..,J-IL.E JO-I~,I-IOE 30-13N-I08 !4-i3N- 9E I4-13N- 9E 0 ' I) ' 334 'S .q3 ' W 237 ' S 172 ' 'W 5 ' S 176 ' W 231 ' S 13 ' E 25-13N-IOE 0 ' 0 ' 11 - 13tl- 10 E 0 ' 0 ' 'L'-IJN-IOE 792 S 435 ~t 26-15N- OE 0 ' ,) ' ~-ICN-iiE 0 ' 0 ' (- 8-1 8-2 B-4A C-I C-2 C-3 C-4 D-I 0-2 L-I H-lA 32-14 32-14A 32-25 18-1 NS25 WSI7 P-I 42' 56' XD SS~D SHALLON OIL SANOS CORRELATION SHEETS NC HORIZON 4262 ' SURFACE LOCATION 4~' 4444 46' 4375 59' 4549 59' 4685 59' 5063 59' 5574 -4.~0 -4226 ' -4209 ' 2114 ' 2013 ' 1918 ' ~n-- ' 23-13N-IOE FNL, ~v~ FEL, FNL, 1585 ' FEL. 23-13N-IOE FNL, 1546 ' FEL, 23-13N-IOE -4313 -4329 -4333 -4346 -4371 -4416 214 5278 4q !65 165 FHL, 4235 FSL? 4304 FHL, 1129 FNL~ 1158 FNL, 1158 FSL, 1100 FEL, 19-13N-lIE FEL. 19-13N-1!E FNL. 19-13N-11E FWL, 19-13N-11E FWL~ 19-1~N-IIE FWL, 18-13N-lIE 48' 430! ' -4253 ' 1167 ' FSL, 2256 ' FEL, IO-13N-IOE 52' 5611 ' -4284 ' ~ FSL. 2459 FEL, IO-13N-IOE 45' 4604 ' -4230 ' 1395 ' FSL, 2326 ' FEL. IO-13N-IOE u~ u~4 -4195 1344 FSL. 2494 FEL, IO-13N-IOE 40' 4994 ' -4433 ' 964 ' FNL, 1233 ' FEL, 13-13N-10E 52' 4851 ' -44!4 ' !!49 ' FNL. 1436 ' FEL, 13-13N-IOE 52' 507~ ' -4362 ' 1149 ' FNL, 1436 ' FEL, !3-13N-IOE 56' 4104 ' -4047 ' 1970 ' FHL, 5122 ' FEL, 8-13N-lOE 56' 4454 ' -75!8 5S' 4793 ' -3514 362~ -3~o9 J~91 -3557 55' 3668 ' -355~ ' 37' 3690 ' -362~ ' 37' 3691 ' -3619 ' 37' 4300 ' -4263 ' 30 44u~ -4422 2400 ' FSL. 686 ' FWL, 13-13N- gE 2~00 ' FSL, 686 ' FNL, 13-13N- ~E 2660 ' FSL~ 1425 ' FEL, 30-13N-IOE 2660 ' FSL. 1425 ' FEL, 30-13N-10E 2660 ' FSL~ 1425 ' FEL? 30-13N-IOE 1882 ' FNL~ 1479 ' FEL? 14-13N- 9E 1882 ' FNL, 1479 ' FEL~ 14-13N- 9E 1360 ' FNL? 1979 ' FEL~ 25-13N-10E 3850 ' FSL, 3030 ' FNL, 11-13N-lOE 63' 4085 ' -3776 ' 700 ' FNL. 570 ' FEL, .]2-1SN-IOE 60 ~405 -~4~ 600 FNL. 250 tEL. ~6-13N- ~E 75' 4212 ' -4137 ' 935 ' FSL. 965 ' FWL. ~-!2N-IIE FROM SURFACE LOCATION N, S E? 0 ' 0 2256 ' S 1406 272 ' S 1237 475 0 174 913 357 328 S 103 0 S 717 N 319 S 1463 S 2706 0 ' 0 ' 12 'N 3155 ' E 876 ' N 612 ' W 2645 ' N 756 ' E 1373 ' N 289 ' W 1152 ' N 1240 ' W 203 ' N I877 ' W 0 ' i) ' 2114 ' S 641 ' E 2689 314 0 ' 0 ' 355 'S 89 'W 252 'S 183 'W 2 ' S 185 ' W 241 ' S 10 ' E O' O' 809 ' S 449 ' W 0 ' 0 ' (- WELL A-I B-1 ~-2 B-.3 B-4A B-5 C-1 C-2 C-4 L-1 ,",-1 M-IA N-I N-!A N-lB 32-14 32-14A 32-25 18-1 ~825 ~S17 P-1 42' 55' 58' ~D SSVD SHALLO~ OIL SANDS CORRELATION SHEETS ND HORIZON 5315 4575 SURFACE LOCATION -424~ ' -422~ ' 2114 ' 2013 ' 1918 ' 4&' 44~5 ' -432~ ' 214 46' 4385 ' -4339 ' ~"" -43~ 49 59' 4698 ° -4356 ' 165 59' F/O F/O 165 59' 5589 ' -4426 ' 68 FNL, 2073 FNL, 1585 FNL, 1546 FEL, ,io-13N-IOE FEL, .:3-1~N-!(!E FEL, 23-1.3N-10E FNL, 4235 FSL, 4304 FNL, 1129 FNL, l!5H FNL, 1158 FSL, II00 FEL. I?-I]N-I!E FEL. 19-I~X-I1E FWL, 19-1~N-!IE F~L. !?-!3N-liE FWL, I%ISN-IIE FWL~ 18-1SN-11E 48' 4322 ' -4274 ' 1147 ' FSL. 2255 ' FEL. IO-13N-IOE §2' ~32 ' -4302 ' 1229 ' FHL, 2459 ' FEL, lO-IGN-10E 45' 4628 ' -4248 ' 1395 ' FBL, 2326 ' FEL, !O-13N-IOE 52' 52?0 ' -4202 ' 1344 ' FSL. 2494 ' FEL, I')-t3N-IOE 40' 50')9 ' -4~'22 ' 0,44' ' FNL, 123,3 ' FEL. 13-1]N-IOE 52' 4853 ' -4425 ' 1149 ' FNL, 1435 ' FEL, 13-1~3N-IOE 52' 50?0 -4~71 1149 FNL, 1436 FEL. ,3-1J.4-1(;E 4!20 ' -4063 ' 1970 'FNL, 5~' 4473 ' Sa' 48117' ~ ..... · 55' 36349' -~5799' 2~0 ' FSL, !425 ' FEL, JO-IJN-iOE 55' 3700?' -~5~59' 2460 ' FSL, 1425 55' NA NA 2660 "FSL, !425 ' FEL, 30-13N-10E 37' 3705 ' -3637 ' 1882 ' FNL, 1479 ' FEL, 14-13N- 9E 37' 3707 ' -3533 ' 1882 ' FNL, 1479 ' FEL~ 14-13N- qE 37' 4316 ' -4279 ' 1340 ' FNL, 1979 ' FEL. 25-13N-IOE 30' 4464 ' -4434 ' 3850 ' FSL, 3030 ' FWL, ll-13N-10E A3' 4094 ' -3784 ' 700 ' F.RL, 570 ' FEL. 32-13N-lOE 60' NA NA aO0 ' FNL, Z50 ' FEL~ 26-13N-9E 75' 4226 ' -4151 ' 935 ' FSL. 865 ' FWL. 8-11X-liE FROM SURFACE LOCATION t4. S E. ~ 00 00 22&4 ' S 1409 ' W 272 ' S 1238 ' W 478 ' S 104 ' E O' 9' 175 ' S 722 'W 920 'N 321 'E NA 332 ' S 2714 ' E 0 ' 0 ' 12 'N 3166 ' E 887 ' N 619 ' W 2645 ' N 742 ' E !.385 N ~?1 W 1~ N 1244 W !97 ' N 1889 ' W O' .~ S 645 E 2704 ' S 313 ' E 0 ' ,) ' ~60 'S 90'W NA NA ~ S B E 0 ' 0 ' B18 ' S 456 ' W ') ' 0 ' C SHALLOW OIL SANDS CORRELATION SHEETS NE HORIZON WELL KBE MD SSVD SURFACE LOCATION A-I A-2 A-3 .a-IoN-IOE 42' 4288 ' -4246 ' 2114 ' FNL, 2073 ' FEL, ~' ' 56' 5322 ' -4254 ' 2013 ' FNL, 1585 ' FEL, 23-13N-10E 58' 4594 ' -4237 ' 1918 ' FNL, 1546 ' FEL, 23-13N-lOE B-1 B-2 8-3 B-4 B-4A B-5 C-! C-2 C-3 C-4 46' ~496 -43~2 46' 4405 59' 4583 -4362 5?' 4726 -4377 59' 5620 -4447 214 FNL, 4235 FEL. 19-15N-IIE 5278 FSL. 4304 FEL. 19-13N-lIE 49 FNL, !129 FWL, I~-ISN-I1E 165 FNL, 1158 FWL. 19-13N-lIE 165 FNL, 1158 FWL, 19-13N-IIE 68 FSL, I100 FWL, 18-13N-lIE 48' 4337 ' -4289 ' 1167 ' FSL, :'u FEL. tO-13N-10E 52' 5&55 ' -4722 ' I .~. FSL, 2459 FEL, ~O-l~N-10E 45' 4651 ° -4266 ' 13~5 ' FSL, 2~26 ' FEL, IO-13N-10E 52' 532I ' -4225 ' IJ44 ' FSL, 2494 ' FEL, 10-13N-IOE D-1 D-2 D-2A ,w~ -446~ 964 FNL, '~'? .~.J~ FEL, 1J-1JN-IOE 52' 4889 ' -4449 ' I14~ ' FNL, 1436 ' FEL, 13-IJN-IOE ~ 5127 -4~4 I149 F~L, 1436 FEL, 13-15N-10E L-I 5~' 4140 ' -4083 ' 1~70 ' FNL, 5122 ' FEL. 8-1JN-IOE ~-1 M-IA 56' 4489 ' :A"" ' 2400 ' FSL, ~86 ' FNL. ~-IJN-qE 56' 48JI ' -3535 ' 2400 ' FSL, :96 ' FWL, [3-13N-9E N-I N-IA N-t8 5' ~'+~ ' ' ' ~ ' Jb~J -~590 2660 FSL, :425 FEL, 50-1]N-IOE 55' 57!4 ' -~575 ' 2660 ' FSL, 1425 ' FEL, 30-15N-lOE ~ 36~0 -3575 2660 FSL, 144~ ' FEL, 30-13N-10E 32-14 37' J719 ' -3650 ' 1882 ' FNL, !479 ' FEL, 14-1~N- 9E 32-14A 37' 3721 ' -3646 ' 1882 ' FNL, 1479 ' FEL, 14-13N- 9E J:-:. 37' 432~ -4287 l~&O FNL, 1979 FEL, zS-15N-iOE 18-1 30' 4487 ' -4457 ' 3850 ' FSL, 3030 ' FWL, II-13N-toE ~..J 63' 4107 -3794 700 FNL, u~O FEL, .~2-1]N-10E W S 17 60' J422 ' -7362 600 ' FNL, 250 ' FEL, 26-1]N-~E P-i 75' 42]8 ' -~[6] ' 955 ' FSL, ~65 ' FWL, 8-12N-liE FROM SURFACE LOCATION N. S E. W 0 ' :,~o8 S I4!I 272 ' S 1239 487 S 0 178 S 9~9 N 362 S 340 S 105 E t:d W 325 1490 2737 E 12'N gOl 'N 2688 'N 3178 ' E 628 ' W 748 'E !411 1162 194 294 1252 1915 21J9 ' S 648 ' E 2721 ' S ]12 ' E 0' 0 ' 568 ' S 92 ' W 261 ' S 189 ' W 5 'S i95 ' W -". S 8 E 0' O' S23 ' S 461 ' W 0 ' 0 ' 0 ' 0 ' C WELL ...~.qc,. nD SSVD A-1 42' 45'64 ' A-2 56' .,.,v:~""~ ' -43.27 A-3 58 4662 B-1 B-2 B-4 B-4A B-5 C-I C-2 C-i C-4 D-I D-2 D L-! H-IA N-! A N-lB 46' 4464 59' ~52 59' 4806 59' 59' 5707 SHALLO~ OIL SANDS CORRELATION SHEETS OA HORIZON SURFACE LOCATION ~114 FNL, ' 2013 ' FNL, · 19iB ' FNL, -'070 1585 ' 1546 ' FEL, FEL, FEL, -4403 -4418 -4422 -4438 -4457 -4506 214 5278 ~? !65 165 68 FNL, 4235 FSL, 4304 FNL, 1119 FNL, !!58 FSL, 1100 FEL, FEL. F~L. FWL, F~L, FWL. 48' 4408 ' -4360 ' 1167 ' FSL, 2255 ' FEL, 52' 57J8 ' -43~4 ' ' .... ... ~ ~ ' .... c~ 2326 ' , 45 4740 -4555 !~95 F .... FEL ...... 94 ' . 52' 5~12 ' -~4 ' 1244 ' FSL, ~ FEL 5144 ' -.J~:'=~' ' 964 ' FNL, .~ .....FEL, 4954 -4509 I!49 F~L. 14~6 FEL. = u~~ .... -4451 ' 1!4¢ ' FNL, !436 ' FEL, 4224 ' -4!67 ' i'~70 ' FNL, :l"n ' ~.~ FEL, 5a 4612 -jT1; :4gO ' :eL, ~6 FNL, 56' 4988 ' -~6!~ ......,.)O'" ' FSL, 086 ' F~L., ~J ..9.. -J6.~4 2660 r:. 1425 ' FEL, 55' 37~2 ' -J661 ' 2660 "Fq~,.. 14'5~ ' FEL, ~- 4 ~7' ~818 -S74~ t882 FNL, 1479 FEL, 32-14A 37' 3784 ' -3702 ' 1582 ' FNL, 1479 ' FEL, I8-1 37' 4396 .... o , , , -,.J,, 1~0 FNL, 1979 FEL. ...... ~o~O FSL, ' F~L, ~0' 4~8 -4a,8 ..... . JOJO W S~.~ 5~' 4213 ' -~885 ' W S 17 50' 35!8 ' -~4SB ' P-1 75' 700 ' FNL, 570 FEL, ~00 ' FNL, -'50 FEL, 4.i05 ' -42~0 ' ~'~'..,~ ' FSL, ~.65 F~L, 23-13N-IOE ~3-1a,t-1 .E q? ( ~U t I'1~ 19-13N-lIE 19-15N-11E !?-!5N-!lE 19-t3N-IIE 1%13N-lIE 18-1~N-11E !O-!3N-IOE iO-I3N-IOE IO-13N-IOE !!)-lJN-!OE ¢ iJ-1JN-IOE 13- I J N- ! 0 E i3-1J);- -E 13-1]!I- 9E 5t)- 1J',;- IOE .]O-IJN-I('E JO-15N-IOE 14-1JN- 9E 14-1JN- 9E "5. -I~N-!OE !1- I JN- 10E ~-IJN-I 25-I.]N- :E ~-12N-11E FROM SURFACE LDCATiGN N, S E. W 0 ' 0 ' 270 ' S 1246 ' W 512 0 186 968 ~60 S 111 0 S 765 N .331 S 1573 S 2797 0 13 · O' 'N 3219 'E 'N 659 ' W 'N 767 ' E t178 15! ,lO1 ' W t~ t W i981 'W ~J S ~69 'E 428 0 ' S 108 ' W 'S 220'W · :Y? S 2~,1 W !) O' 491 ' W B-I B-4A B-§ C-I C-2 D-1 D-2 D-2A L-I ,'l-! ,M-IA -Tr, EHALLOW OIL SANDS CORRELATION 4430 ' -4~98 ' 5481 : -4400 ' 472B ' -43BI ' OB HDRIZO)t SURFACE LOCATION 2114 ' FNL, 2073 ' FEL, 23-13N-101 2013 ' FNL, 1585 ' FEL, 23-13N-101 !91B ' FNL, 1546 ' FEL, 23-13N-101 %' 4602 ' -4458 ' 214 4b: 4518 ' -!472 ' 5278 59' 4876 ' -4492 ' 165 59' 5333 ' -4520 ' 165 59' 578J ' -4559 ' 68 FNL, 4235 FSL, " FNL, ~ 1"'~ FNL. 1158 FHL, 1158 FSL, 1100 48' 4483 ' -4435 ' 1167 ' FSL, ~ 5325 -4470 .227 FSL, ,~ 4843 -4416 1395 'FSL, 52' 5522 ' -4J60" 1J44 ' FSL, FEL, FEL. FWL. FWL. FWL. FWL, 2256 ' FEL. 2459 ' FEL, 2326 ' FEL. Z494 FEL. 40' 5244 -4.,ov 964 FNL, ' "' "?' ='"'~" ' -457~' !149 ' FNL, 1456 52' 5~!5 ' -450? ' 1149 ' FNL, ~436 i9-13N-111 Ig-ISN-11E 19-13N'I11 19-13N-111 I%13N-IIE 18-13N-111 i0-!3N-101 IO-IjN-!OE IO-IjN-!OE iO-13N-IOE FEL. ! .... ,-. FEL. !3-13N-101 ~EL. 56' 43!2 ' -4255 ' 1970 ' FNL. 5!22 ' FEL. 8-IJN-IOE 4726 ,-~ ~ N-tA 55' 7~')B ' N-lB 55' ~=~ ~7' 37' 18-I WS25 WSI7 P-I J7' 2400 ' FSL, 5~6 ' F~L. 13-!3(-~E 2400 ' FEL, ~66 Fi:L, 13-13N- 91 £660 ' FSL, ta~= 2660 ' Fe,, I .... r--I ~c., ]0-1.?.,N- l(iE JO-1..,,J-lO£ FEL, 30 .... ' 1 o.-ltE F/O F,/O ,3868 -3776 1:582 F..%, 1479 ' FEL, 14-15, N- 91 1882 FNL, 1479 ' FEL, 14-13N- 91 4458 -4421 ' liaO rN~ 1°79 ' FEL, "~ ~"" '"~' ' : '! ' 30' 4618 ' -;5~B ' '"~ ' , Jo~O FSL, J050 FWL. ll-IJN-IOE ?FO ' FNL, 570 ' FEL :" ' ...... , o-'-I.~N-IOE 600 " :EO "£-i..,;,- ~E ;:~L ' -I:' -- 75' 4l&9 ' -4274 9=5 ' , . , 8_ .~ FSL %5 FWL, t2N-11E FRO~ SURFACE LDCATIGN N, S E. 0~ 0 =~' - 1435 270 ' S 1251 535 ' ~ tls 0 ' 0 193 ' S 79I 1029 ' N J44 399 ' S 1684 373 ' $ 2851 i.] ' N I002 ' N '0' ?~t~ · o~o,. E 694 'W 7'39 ' E I564 1194 117 N 310 N I291 ") ' 0 ' 6Gg ' E O' 420'5 0 106 W 247 'W NA ).lA 3lEI 'S i6 'E 0 ' 0 ' 0 ' 0 ' ~9 ' S 5!8 ' ~ 0 ' 0 ' L_ Notice of Public Hearing STATE OF ALASKA. Alaska Oil and Gas Conservation Commission Re: The application of Conoco Inc. for a public hearing to present testimony in order to establish pool rules for the development of the Schrader Bluff Oil Pool in the Milne Point Unit. Notice is hereby given that Conoco Inc has petitioned the Alaska Oil and Gas Consrvation Commission (hereinafter "the Commission") to issue a conservation order setting forth pool rules for the development of the Schrader Bluff Oil Pool in the Milne Point Unit. The hearing will be held at 9:00am May 31, 1990 at the Commission offices, 3001 Porcupine Drive, Anchorage, Alaska. All interested persons and parties are invited to give testimony. Lonnie ~ Smith Commi s s ioner Alaska Oil and Gas Conservation Commission Published April 24, 1990 , ,',~ ~ , la~. ~ ,,-~*~, , .... .te~¢~, ~. ~ ,, ~,'~ ..Inc ,or~"~ .'pu6ilC hearing to ~e "'~t testlm~y' In order to'~ /,,~,~T~m~nt the I..~Jc.e:: ...i,s ..: 6erei y ':given .C~Oco h~,'; has Petlfl°bed .~a~Ea Ol'l"and ;aS.Co~serva'. 'tl~n' commlssic ~: (hereTna~er II ~. ~,~h.~po0i.:L~ulm 'fort: t'he .':deve ~: 6~ment of t~e ~hr~Oir' .Bluf~ II ~1 ',, .,,,~, , ,', ~,' ~,~ Notice' of Public Hearing . , "STATE OF ALASKA Alaska 011 and Gas' · .'.:', Conservation Commission Re: The application of Conoco Inc. for'a public hearing to' present testimony in order to establish pool rules for the;' development of the Schrader',i BlUff OII Pool~ in the, AAIIne Point Unit~/. '~.,,;'~; ', i' Notice Is hereby given that Conoco inc.' has petitioned the AlaSka Oil and Gas Conserve-. lion Commission (hereinafter "the Commission") to ISsue conservation order Setting forth pool rules for the devel-,:' oPment of the Schrader Bluff 011 Pool In 'the Miln~ Point' :, ,/,.,, , , . ,,, unit.. ~, ,,, .::, ,,: .; :~ The hearing will be held at 9:00am ~ay 31; 1990 et the Commissi0n i~ffices, 3001 Po-', cuplne Drive, Anchorage/ Alaska; All Interested persons and parties are invlted to tes, tlmony. , "'~,.~?:;.'?':,:,,,.,, CommlssionerL°nnle C. Smith,, ,':~ "~ "' !' i'::',, ':',' Alaska Oil and Gas ConserVation Commission P,u,b: April 24,,,, i990 ;'": i' AC': 08-5626 ';.:; ,, ' i:~i:',:' ', R E C E IV E NiAY ] ]990 Alaska Oil & Gas Cons. Commissio.r~
