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CO 186
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: [] Poor Quality Originals: [] Other: DIGITAL DATA [] Diskettes, No. [] Other, No/Type NOTES: BY: ROBIN Scanning Preparation BY: ROBIN OVERSIZED (Scannable with large plotter/scanner) [] Maps: [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) · V~B Logs of various kinds [] Other Production Scanning Stage1 PAGE COUNT FROM SCANNED DOCUMENT: ! PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: /~* YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES ~ NO BY: MARIA DATE: ~_ Is~ (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) I II I General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION CO~qMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 Re: THE APPLICATION OF ARCO, ) ALASKA, INC. on behalf of ) the Prudhoe Bay Unit Working) Interest Owners, for (1) ) additional recovery by ) miscible enriched hydro- ) carbon gas injection and ) (2) approval as a qualified ) tertiary recovery project ) for purposes of the Crude ) Oil Windfall Profit Tax Act ) of 1980. ) Conservation Order No. 186 Prudhoe Bay Field Prudhoe Oil Pool November 29, 1982 IT APPEARING THAT: · ARCO Alaska, Inc., by letter dated August 31, 1982, requested the Alaska Oil and Gas Conservation Commis- sion to hold a public hearing to provide an opportunity for the Prudhoe Bay Unit Working Interest Owners to enter testimony into the public record in support of their request for approval of the Flow Station 3 Injec- tion Project under Section 20 AAC 25.400 and approval as a qualified tertiary recovery project according to paragraphs (A), (B), and (C) of IRC Section 4993(C)(2). · Notice of public hearing was published in the Anchorage Times on November 3, 1982. · A public hearing was held in the Captain Cook Hotel, Anchorage, Alaska on November 19, 1982. FINDINGS: · An additional recovery project to waterflood the Prudhoe Oil Pool was approved on March 20, 1981. · The Flow Station 3 Injection Project involves 3650 acres and is a portion of the Sadlerochit sandstone reservoir of the Prudhoe Oil Pool and effects about 2% of the total reservoir. · The Flow Station 3 Injection Project compliments the additional recovery project approved in March 1981 by offering additional crude oil recovery to be obtained by the injection of miscible enriched hydrocarbon gas alternating with the injection of water (WAG). 10031793 Conservation Order 3. 186 Page 2 · · · Reservoir simulation model studies indicate that about 5.5% of the original oil in place, or 24 M~bls, may be recovered over and above that projected' by primary and conventional waterflood as a result of the Flow Station 3 Injection Project. The gas, natural gas liquids and water to be injected are compatible with reservoir fluids since they are indigenous to the reservoir. The approval of the Flow Station 3 Injection Project as a qualified tertiary recovery project for purposes of the Crude Oil Windfall Profit Tax Act of 1980 should be covered in a separate decision. CONCLUSION: · The Flow Station 3 Injection Project will not cause waste and correlative rights will be protected. · The Flow Station 3 Injection Project could increase recovery from the specific area by up to 24 million barrels of oil beyond that predicted by primary and conventional waterflood. · There will be no impairment of the reservior from the WAG project and other Enhanced Oil Recovery methods could be employed in the future. NOW THEREFORE, IT IS ORDERED THAT:. The Flow Station 3 Injection Project is approved as an additional recovery method, for the 3650 acre portion of the Sadlerochi't Reservoir, defined in the record as the Flow Station 3 Injection Project Area. Semiannual reports, in January and July of each year, beginning in January, 1983, shall be submitted and will include the following: 1. Reservoir pressure. 2. Volumes (by month and well) of injected gas, injected water, injected Iow molecular weight liquids, and produced fluids (oil, water, and g.as). 3. Results of production logging surveys. 4. Results of radioactive tracer tests. 5. ResUlts of observation well surveys. Additional information concerning the Flow Station 3 Injection Project may be requested by the Commission. These reports are in addition to present reporting requirements required by Conservation Order 165 and the waterflood program. AGO 10031794 Conservation Order ~. 186 Page 3 DONE at Anchorage, Alaska and dated November 29, 1982. C V Chatterton/ [gha~rman Alaska Oil and Gas Conservation Commission Harry W. Kugler, CommisSioner Alaska Oil and Gas Conservation Commission Lonnie C. Smith, Commissioner Alaska Oil and Gas Conservation Commission AGO 10031795 ARCO Alaska, IncI" Post Office , ,x 100360 Anchorage, ~iaska 99510 Telephone 907 265 6513 Leland E. Tate Vice President January 18, 1984 Alaska Oil & Gas Conservation Commission State of Alaska Division of Oil & Gas 3001 Porcupine Drive Anchorage, AK 99501 Gentlemen: RE: Prudhoe Bay Unit State of Alaska Third Semiannual Progress Report Flow Station 3 Injection Project In compliance with Conservation 0rder No. 186, ARCO Alaska, Inc., as Eastern Area Operator, submits the Third Semiannual Progress Report for the Flow Station 3 Injection Project, Prudhoe Bay Unit. This report covers the period from July 1 through December 31, 1983. Sincerely, L. E. Tate LET/MLB / la AGO 10031798 ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany THIRD SEMIANNUAL PROGRESS REPORT TO THE STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION FLOW STATION 3 INJECTION PROJECT PRUDHOE BAY UNIT SADLEROCHIT RESERVOIR DATA THROUGH DECEMBER 31, 1983 CONSERVATION ORDER NO. 186 ~" ~..,,~,,f,~,~ 0~ ? q',~ C,'vm~ ~ .. ',LL,,~.,.~_, .. ~.. , ..... ,d .- '-, AGO 10031799 THIRD SEMIANNUAL PROGRESS REPORT FLOW STATION 3 INJECTION PROJECT P..ro~ect Statu. s Summary The following report summarizes the status of the project, its operation, and the data collected during the period July 1 through December 31, 1983. The attached exhibits detail the project production and injection, the logging performed, the bottomhole pressure data, and specific information obtained from the Observation Pattern. Copies of individual logs and injection pro- files are forwarded routinely and are not included in this report. Miscible gas injection began in the Flow Station 3 Injection Project on December 30, 1982. Although an explosion in the miscible gas injection module on May 26, 1982 temporarily halted miscible gas injection, produced water injection continued throughout the remainder of the year. Operations during the second half of 1983 reflected the objective of preserving reservoir conditions until the resumption of miscible gas injection, expected in the first quarter of 1984. Special attention was given to maintaining reservoir pressure well above the minimum miscibility pressure by limiting offtake in the project area. During normal operations, project production was limited to 10 to 15 MBOPD from four wells offsetting the observation pattern WAG well 13-6. These wells served the dual purpose of maintaining sufficient production to keep DS 1'3 facilities warm and to facilitate uninterrupted progress of the previously injected miscible gas slug as water injection continued in the 13-6 pattern. AGO 10031800 Production was increased in the project area for brief periods to provide additional field rate during scheduled facilities shutdowns. Produced water injection volumes ranged from 6 to 13 MBWPD, distributed to one to four wells, until the interim gas lift compressors and water source wells were restarted on November 6, 1983. From that point on, water injection averaged 47 MBWPD distributed to three upstructure water injectors on the northern project boundary and seven WAG injectors. All project area injection wells are now mechanically ready to receive injection. Refer to Exhibit 4 for the status of injection wells. To date, 58 of the 64 project-related wells have been perforated. Exhibits 5 and 12 indicate the perforating status and location of project wells. Production and Injection Volumes Exhibit 1 summarizes the production and injection volumes for the project area prior to and since the project beginning date. Exhibit 2 provides detail by well. Exhibits 10 and 11 are plots of production and injection volumes allocated to the project area. Bottomhole Pressure Exhibit 9 is a tabulation of bottomhole pressure data obtained during the second half of 1983. The current volume-weighted average reservoir pressure in the project area is 3860 psig at the 8800' ss datum or about 3880 psig at the midpoint of the light oil column. This compares to 3870 psi at datum reported in the July, 1983 report. AGO 10031801 Observation Well Wireline surveys run during the second half of 1983 in Observation Well 13-98 and its offset, WAG injection well 13-6, are tabulated in Exhibit 6. Exhibit 7 is an overlay of several Dual Induction Logs (DIL) taken since injection began in Well 13-6 compared to the base DIL run on 1/14/83. The most recent DIL indicates a continuous 90 feet (MD) of water swept interval from the top of the Sadlerochit down. The Compensated Neutron Logs run to date have shown no evidence of increased gas saturation. Surveillance and Diagnostic Lo~s Exhibit 8 tabulates the surveillance and diagnostic logs run in the rest of the project area. The list includes: (1) initial surveillance logs, (2) pulsed neutron logs, (3) injection profiles and pressure transient survey tests and (4) pump-in temperature surveys for cement channel detection. Pulsed neutron and CNL logs will be repeated when changes in GOR or water cut are observed. This work is being coordinated with the field water-oil contact and gas-oil contact monitoring programs. Radioactive Tracer No additional radioactive tracer material has been injected into the project area since four wells received tracer in May, 1983. Analyses of the produced fluid samples taken to date have shown no trace of the radioactive material. AGO 10031802 EXHIBITS 1. Summary of Pertinent Data 2. Production and Injection Volumes from July 1, 1983 to December 31, 1983 3. Percent of production/Injection Assigned to Project Area 4. Status of Injection Wells 5. Perforating Status 6. Observation Pattern Logs 7. Well 13-98 DIL Log Overlays 8. Surveillance and Diagnostic Logs 9. Bottomhole Pressure Data 10. Project Area Production Plot 11. Project Area Injection Plot 12. Project Area Map AGO 10031803 EXHIBIT 1 FLOW STATION 3 INJECTION PROJECT SUMMARY OF PERTINENT DATA* As of 12/31/83 First Oil Production from Project Area Project Beginning Date Project Area Production Prior to Project Beginning Date Oil (STB) 43,003,156 Gas (MCF) 34,201,531 Water (STB) 6,672,630 Project Area Production Since Project Beginning Date Oil (STB/RVB) 8,373,587/11,292,064 Gas (MCF) 6,900,024 Water (STB) 1,228,107 Project Area Injection Prior to Project Beginning Date Water (STB) 389,294 Project Area Injection Since Project Beginning Date Miscible Gas (MCF/RVB) Water (STB) Reservoir Pressure @ 8800' ss Datum Initial (psig) Current (psig) Project-Related Wells (Perforated/Ultimate) Production Produced Water Injection Water-Alternating-Gas Water Source Wells 3,904,309/2,695,089 9,448,703 4,420 3,860 36/42 7/7 11/11 4/4 March 1979 December 30, 1982 *Ail "Project Area" volumes take into account the fraction of each well's production or injection assigned to the project area (Exhibit 3). AGO 10031804 EXHIBIT 2 Flow Station 3 Injection Project Volumes from July 1, 1983 to December 31, 1983 (Not Adjusted by Project Fraction) oil (STB) 2,548,647 Production Injection Water ($TB) Gas (MSCF) Water (BBL) Gas (MSCF) 260,739 1,901,714 3,717,409 0 Well 1-18 Total: 6-6 6-9 6-11 6-12 Total: Individual Wells Production Month Oil (STB) Water (BBL) 7/83 20,800 0 8/83 17,693 0 9/83 7,556 0 10/83 9,389 0 11/83 0 0 12/83 3,494 0 58,932 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. -- NO PRODUCTION FROM 7/1/83 to 12/31/83. -- NO PRODUCTION FROM 7/1/83 to 12/31/83. Gas (MSCF) 16,448 15,816 7,857 9,511 0 2,991 52,623 7/83 0 0 0 8/83 0 0 0 9/83 620 31 416 10/83 2,663 128 1,883 11/83 48,305 3,650 36,965 12/83 0 0 0 51,588 3,809 39,264 6-17 12-4A Total: -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 7/83 82,089 2,027 51,351 8/83 88,095 1,924 82,109 9/83 69,802 1,742 72,164 10/83 73,066 1,517 67,728 11/83 13,406 96 13,337 12/83 96,738 1,294 92,921 423,196 8,600 379,610 AGO 10031805 , Well 12-83 Total: 12-9 Total: 12-12 Total: 12-15 Total: 12-16 Total: 12-17 Total: 12-18 Total: Month 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 10183 11/83 12/83 7/83 8/83 9/83 lO/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 Oil (szB) 26,707 4,761 18,234 13,143 0 188 63,033 25,125 22,822 10,217 9,215 0 0 67,379 11,452 72,971 33,931 24,579 0 64,004 206,937 0 0 0 0 0 486 486 0 0 0 0 0 3,259 3,259 0 0 0 0 0 760 760 0 0 0 0 0 831 831 Water (BBL) 6,268 1,264 5,347 3,523 0 30 16,432 516 250 247 207 0 0 1,220 9,678 43,866 43,531 41,586 0 6,822 145,483 AGO Gas 10031806 (MSCF) 13,245 2,819 14,363 8,706 0 104 39,237 13,756 14,624 7,693 5,944 0 0 42,017 6,851 51,540 27,458 17,699 0 54,511 158,059 0 0 0 0 0 330 330 0 0 0 0 0 2,434 2,434 0 0 0 0 0 522 522 0 0 0 0 0 626 626 'i 13-1 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-2A -- NO PRODUCTION FROM 7/1/83 to 12/31/83. Well Month Oil (STB) 13-3 Water (BBL) Gas (MSCF) 9/83 19,053 738 14,392 10/83 0 0 0 11/83 52,460 4,247 36,226 12/83 0 0 0 Total: 112,811 6,835 81,448 13-4 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-5 7/83 78,080 2,528 63,288 8/83 17,065 425 10,844 9/83 56,446 1,610 31,403 10/83 75,268 2,269 43,275 11/83 73,568 3,882 46,331 12/83 69,272 1,549 42,870 Total: 369,699 12,363 238,011 13-7 7/83 59,565 2,729 49,314 8/83 13,905 416 9,013 9/83 57,789 1,887 32,373 10/83 64,717 2,116 33,883 11/83 64,183 4,148 38,111 12/83 51,828 1,746 26,841 Total: 311,987 13,042 189,485 13-8 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-10 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-11 -- NOT PERFORATED. 13-].2 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-13 -- NOT PERFORATED. 13-14 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-26 -- NO PRODUCTION FROM 7/1/83 to 12/31/83. 13-27 -- NOT PERFORATED. 13-28 -- NOT PERFORATED. 13-29 -- NOT PERFORATED. Well Month Oil (STB) Water (BBL) 13-30 Gas (MSCF) Total: 7/83 1,915 82 2,026 8/83 632 26 597 9/83 0 0 0 10/83 0 0 0 11/83 61,962 5,079 65,784 12/83 0 0 0 64,509 5,187 68,407 AGO 10031807 13-33 -- Well 13-34 Total: 14-7 Total: 14-8 Total: 14-9B Total: 14-12 Total: 14-22 Total: NOT PERFORATED. Month 7/83 8/83 9/83 lO/83 11/83 12/83 7/83 8/83 9/83 lO/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 lO/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 lO/83 11/83 12/83 Oil (STB) 75,955 19,473 32,991 0 46,392 0 174,811 0 0 0 0 0 10,091 10,091 0 0 0 0 2,189 0 2,189 23,952 45,998 29,055 0 0 916 99,921 0 11,517 0 0 52,429 2,029 65,975 0 0 0 0 840 817 1,657 Water (BBL) 4,641 1,124 2,010 0 5,707 0 13,482 0 0 0 0 0 7,482 7,482 0 4,251 2,912 0 0 234 7,397 0 242 0 0 232 142 616 0 0 0 0 2,030 1,209 3,239 Gas (MSCF) 61,933 14,194 22,375 0 32,292 0 130,794 0 0 0 0 0 7,052 7,052 0 0 0 0 1,478 0 1,478 20,025 33,012 17,049 0 0 544 70,630 0 13,454 0 0 54,183 1,410 69,047 0 0 0 0 665 573 ~1,238 AGO 10031808 Well 14-26 Total: 14-28 -- 14-29 Total: 14-30 Total: Month 7/83 8/83 9/83 10/83 11/83 12/83 NO PRODUCTION 7/83 8/83 9/83 10/83 11/83 12/83 7/83 8/83 9/83 10183 11/83 12/83 FROM Oil (STB) 0 0 0 0 52,928 8,125 61,053 7/1/83 to 12/31/83. 24,750 53,472 25,872 18,943 61,080 41,468 · 225,585 20,440 52,198 29,871 18,530 50,919 0 171,958 Water (BBL) 0 0 0 0 6,138 1,472 7,610 0 0 193 543 2,593 2,944 6,273 575 492 270 133 199 0 1,669 Gas (MSCF) 0 0 0 0 46,516 5,612 52,128 17,468 36,882 15,248 12,378 41,122 27,737 150,835 17,412 39,298 18,774 12,364 38,591 0 126,439 AGO 100B1809 EXHIBIT 2- (CONTINUED) Individual Well Totals Injection 12-19 -- NO INJECTION FROM 7/1/83 to 12/31/83. 12-20 -- NO INJECTION FROM 7/1/83 to 12/31/83. Well Month Water (BBL) 13-6 Total: 7/83 8/83 9/83 10/83 11/83 12/83 104,753 34,565 88,249 169,480 210,050 154,307 761,404 13-9 -- NO INJECTION FROM 7/1/83 to 12/31/83. 13-15 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 27,980 27,044 55,024 13-16 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 81,800 87,143 168,943 13-17 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 174,110 299,486 473,596 13-18 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 529 0 0 0 21 556 Gas (MSCF) AGO 10031810 Well Month Water (BBL) 13-19 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 87,720 90,854 178,574 13-20 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 95,820 101,251 197,071 13-21 Total: 7/83 8/83 9/83 10/83 11/83 12/83 44,679 24,405 39,944 112,134 176,100 128,343 525,605 13-22 -- NO INJECTION FROM 7/1/83 to 12/31/83. 13-23A -- NO INJECTION FROM 7/1/83 to 12/31/83. 13-24 Total: 7/83 8/83 9/83 lO/83 11/83 12/83 45,441 15,821 49,124 119,209 168,740 128,400 526,735 13-25 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 21,816 0 21,816 13-32 Total: 7/83 8/83 9/83 10/83 11/83 12/83 0 0 0 0 88,530 79,107 167,637 Gas (MSCF) AGO 10031811 I Well 14-13 Total: 14-14 Total: Month 7/83 8/83 9/83 lO/83 11/83 12/83 7/83 8/83 9/83 10/83 11/83 12/83 Water (BBL) 0 0 0 143 0 424 567 0 132,544 15,569 15,462 285,610 190,702 639,887 Gas (MSCF) AGO 10031812 EXHIBIT 3 Flow Station 3 Injection Project Percent of Production Assigned to Project Area Well 1-18 6-6 6-9 6-11 6-12 6-17 12-4A 12-8B 12-9 12-12 12-15 12-16 12-17 12-18 13-1 13-2 13-3 13-4 13-5 13-7 13-8 Percent (%) Well Percent (%) 52 13-10 100 100 13-11 100 41 13-12 34 100 13-13 68 100 13-14 100 100 13-26 100 100 13-27 38 49 13-28 54 50 13-29 53 100 13-30 100 56 13-33 100 48 13-34 100 100 14-7 51 26 14-8 57 100 14-9B 26 100 14-12 49 100 14-22 34 100 14-26 100 100 14-28 50 100 14-29 25 32 14-30 75 Percent of Injection Assigned to Project Area Well Percent (%) Well Percent (%) 12-19 12-20 13-6 13-9 13-15 13-16 13-17 13-18 13-19 51 13-20 36 13-21 100 13-22 100 13-23 100 13-24 100 13-25 48 13-32 46 14-13 100 14-14 63 100 100 100 100 100 100 26 59 AGO 10031813 EXHIBIT 4 Flow Station 3 Injection Project Inj ectilSn History Well · , 13-6 13-9 13-15 13-16 13-19 13-21 13-22 13-23 13-24 13-25 13-32 12-19 12-20 13-17 13-18 13-20 14-13 14-14 Well Type WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG PWI PWI PWI PWI PWI PWI PWI INjection Period 2-17 to 5-01 5-01 to 5-26 6-02 to 8-10 9-04 to 12-31 11-08 to 12-31 11-08 to 12-31 12-30 to 4-11 4-11 to 5-26 11-07 to 12-31 4-11 to 5-26 6-21 to 8-10 9-04 to 12-31 12-27 to 4-08 4-08 to 5-26 12-30 to 4-30 4-30 to 5-26 4-19 to 5-26 6-22 to 8-10 9-04 to 12-31 1-09 to 3-27 3-27 to 5-26 4-17 to 5-26 11-07 to 12-31 11-23-82 to 5-26 6-10 to 6-15 11-09 to 12-31 11-22-82 to 5-26 12-15-82 to 5-26 6-11 to 6-21 11-18 to 12-31 1-24 to 5-26 1-15 to 5-26 8-09 to 12-31 Injectant Water Miscible Gas Water Water Water Water Miscible Gas Water Water Water Water Water Water Miscible Gas Water Miscible Gas Water Water Water Water Miscible Gas Water Water Water Water Water Water Water Water Water Water Water Water AGO 10031814 EXHIBIT 5 Flow Station 3 Injection Project Perforating Status 1/01/84 Well Well Type Date Perforated 12-15 P 9/22/83 12-16 P 9/23/83 12-17 P 9/24/83 12-18 P 9/24/83 12-19 WI 9/25/83 12-20 WI 9/25/83 13-9 WAG 2/09/83* 13-11 P NP 13-13 P NP 13-27 P NP 13-28 P NP 13-29 P NP 13-33 P NP 14-13 WI 4/14/83' *Additional interval remains to be perforated. Perforating was completed in all other project-related wells prior to 7/01/83. KEY: P = Producer WI = Water Injector WAG = WAG Injector NP = Not Perforated AGO 10031815 EXHIBIT 6 Flow Station 3 Injection Project Observation Pattern Surveys Well 13-6 13-98 Well Type WAG OB Log Type Spinner/Temp DIL/CNTG DIL/CNTO DIL/Gradio CST CNTG DIL/CO DIL Date Logged 10/21/83 7/07/83 8/10/83 9/29/83 10/01/83 10/17/83 11/11/83 12/15/83 KEY: Well Type OB = Observation Well WAG = WAG Injector Log Type CO = Carbon Oxygen CNTG = Compensated Neutron Log GST = Gamma Spectroscopy Tool DIL = Dual Induction Log AGO 10031816 EXHIBIT 7 G~gi~LO ,~GAPI) 13-98 0.0 !00.00 ', TOS 10500 12-15-83 ILD~;110 0.2000 RO00.O 11-11-83: ILD~IIIO (OHMM) ~ -' ~' ' 2000.0 9~29_-.~.. ILDa~.%OS. ~PH~,~ ............... 0.~000 2000.0 8-10-83 ILD~;106 (OHMM) ,). ;~000 1-14-83 0. ~ 000 12'15-83'. ' · .t 9-29-83 ILD@; I0~ <nHMM) 2000.0 8-10-83 : ::;:: 1-14-83 .... 11-11-83 .i 10600 -HOT EXHIBIT 8 Flow Station 3 Injection Project Surveillance and Diagnostic Surveys* Well Well Type Sur~ey Type 13-14 P Pump-in Temp 14-7 P CNL 1-18 P CNL 13-3 P CNL 6-12 P CNL 6-12 P TDT 12-12 P Spinner 13-30 P Spinner/PBU 13-24 WAG Spinner/HP/Temp/PFO 6-11 P CNL 13-19 WAG Spinner/HP/Temp/PFO Date 7/06/83 9/29/83 lO/O2/83 10/05/83 lO/O6/83 10/06/83 1o126183 11/20/83 1112ol83 12/21/83 12129183 *Does not include cement bond logs. KEY: Well Typ,e P = Producer WI = Water Injector WAG = WAG Injector Log Type NLL = Neutron Lifetime Log TDT = Thermal Decay Time CNL = Compensated Neutron Log AGO 100B1818 EXHIBIT 9 Flow Station 3 Bottomhole Injection Project Pressure Data BHP Surveys Well 6-17 13-4 13-7 13-15 14-30 14-7 13-3 12-8B 13-4 13-14 13-18 14-7 14-8 1-18 6-17 12-15 12-16 12-17 12-18 12-19 12-20 13-2A 14-28 14-22 13-30 12-20 13-4 13-14 12-15 6-17 12-16 13-18 1-18 14-7 Type Static Static Static Static Static Static PBU PBU Static Static Static Static Static Static Static Static Static Static Static Static Static Static Static Static PBU Static Static Static Static Static Static Static Static Static Date 7/Ol/83 7/Ol/83 7/Ol/83 7/Ol/83 7/02/83 7/04/83 7/13/83 8/04/83 8/31/83 8/31/83 8/31/83 8/31/83 8/31/83 9/01/83 9/01/83 9/25/83 9/25/83 9/25/83 9/25/83 9/25/83 9/26/83 10/07/83 10/10/83 10/13/83 11/20/83 12/07/83 12/07/83 12/07/83 12/08/83 12/09/83 12/10/83 12/11/83 12/15/83 12/22/83 Reservoir Pressure (?sia) at 8800' ss 3888 3900 3923 3868 3910 3882 3886 3842 3891 3903 3868 3878 3925 3833 3882 3821 3828 3841 3806 3841 3846 3853 3900 3956 3931 3840 3879 3894 3866 3875 3865 3857 3848 385O AGO %0031819 ~nno0 .,. , -I ................. ~ .................................. ~ : = ................ ,,, ~, ~ · : ' /:5 ~ ................. ~. ................. :. ................. ~. .............. /[" :" '~ ,, ............. ................. ~ ................. ~ ................................ ~ ............... , ooc :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: j '" ~ --~ , ~ .' 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WATER ]~;CT~ ~ ~ ~ ~ ~ TOP OF S~DLEROCHIT ~'FLOW STATION ~ mSE.V,;~ ~c INJECTION PROJECT AREA ~~~ ~-~ ~J"~~, I~ IT' AGO 10031822 _ , 10 11 12 13 14 15 16 17 18 19 2O 9.1 22 23 24 25 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING P.RUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT CHAT CHATTERTON, Chairman LONNIE SMITH, Member HARRY KUGLER, Member November 19, 1982 9:00 A.M. Quadrant Room Hotel Captain Cook Anchorage, Alaska STREET. SUITE 101 Z77-O57Z - 277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023676 1007 W. 3RD AVENUE 272-7515 10 1! !3 14 15 16 17 18 !9 2O 9,1 22 23 24 -2- P R O C E E D I N G S MR. CHATTERTON: If I may have your attention, we'll try to get your -- this show on the road, so we'll officially open this hearing and I'll ask Commissioner -- first, before we do that, why, I'd like to introduce the people at this table that you're facing right up here. At the far end, sitting at 90° ,~to us is the R & R Court Reporter. Her name is Meredith Downing, and she will be recording the prceedings. Seated next on the far end is Anne Prezyna, she's from the A.G.' office and looks after our legal affairs. Next to that is the Commission's consultant, Dr. Van Poollen from Denver, and he's been retained consultant for a good many years. Next is Commissioner Lonnie Smith, followed by Commissioner Harry Kugler and I am -- will chair this meeting. I'm Chat Chatterton. And as things require, why, I would ask Commissioner Kugler to read into the record the purpose of this hearing. MR. KUGLER: Notice is hereby given that ARCO Alaska, Inc. has requested the Alaska Oil and Gas Conservation Commission by letter dated August 31st, 1982, to hold a public hearing to providei~the Prudhoe Bay unit operators an opportunity to enter testimony into the public record and answer questions concerning the flow station three injection project. This project involves the alternating injection of water and miscible enriched natural gas, WAG, into the portion of the Sadlerochit Reservoir in the Prudhoe Bay Field. 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS ~09 W. 3RD AVENUE 277-8~43 ANCHORAGE, ALASKA 99~01 AGO 10023677 007 W. 3RD AVENUE 272-7515 10 11 12 14 17 lg 2O 22 24 25 -3- The applicant requests approval of, one, the flow station three injection project as required by section 20 AAC 25.400, and, two, approval as a qualified tertiary recovery project according to paragraphs (a), (b) a~d (c) of IRC Section 4993 (c)(2). This notice was published in the Anchorage times on November 3rd, 1982. MR. CHATTERTON: Thank you, Commissioner Kugler. For those that may be in the audience that are not aware of this, our-- the procedure of this hearing will be held, and unde~ our regulation, it's it's Title 20 of the Alaska Administrati~ Code and it's Chapter 25 thereof,, subsection -- or section 540 subsection (b). And I'll highlight this a little bit, why, the applicant~ will first put on their testimony and if there are others that wish to testify, why they may make arragments with B.J. Erlich who seated back there. She is. She's hold -- in the back there by the door. The-- In the procedures of these hearings, we also will take oral statements from people and we'll also take written statements from people, Those written statements will be taken after all testimony and or- -- and oral presentations are given. Should any method-- the --the audience is not, and under this regulation, is not permitted to question directly any of those that testify. If you do indeed have questions, again AGO 10093678 R & R COURT REPORTERS 810 N STREET. SUITE 101 50g W. 3RD AVENUE 1007 W. 3RD AVENUE 277-0572 - 277-0573 277-8543 272-75 ! .~ ANCHORAGE. ALASKA 99501 10 11 13 14 15 16 17 18 19 2O 21 22 25 -4- use -- to B.J. Erlich back there, write out your questions, she will gather them at the end of all the testimony and oral statements and so forth and the Commission will ask those questions of whomever they're directed to, providing that the Commission considers in their judgment that it is germane.~to the decision that the Commission must make. I think that's~about the highlights of it. I would hope that after .- I understand that the direct testimony of the applicants will take about an hour and a half, something of that order. I would PrOpose that we take a break. Hopefully everyone would be willing, if we're not -- if it looks like we're reasonably close to the end, why would -- we would carry on int¢ the lunch hour so we can wind it up and all take a late lunch. With that, I would ask the Applicants to come forward, and'they are forward, and they're seated over here. I guess a panel. The Applicant consists of a panel of five and, Mr. KugleI, I would ask you that they be sworn in. (Mr. Kugler swears in the representatives of the MR. :i.KUGLER: You may be seated. MR. CHATTERTON: Gentlemen, the floor is yours. MR. MARQUEZ: Thank you, Mr. Chairman. ~ Mr. Chairman, members of the Commission, ladies and gentlemen, my name: is Dave Marquez, and I'm an attorney with ARCO Alaska, Inc., one oftheoperators in the Prudhoe Bay Field. AGO 10023679 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE 277-0572 - 277-O573 277-8543 272-7515 ANCHORAGE, ALASKA 99501 Applicant) 10 11 12 13 15 16 17 18 19 2O 21 22 23 24 25 -5- The working interest owners of the Prudhoe Bay Field have requested this public hearing this morning before the Alaska Oil and Gas Conservation Commission for two purposes. First, we are requesting that the Commission approve our application for additional recovery by miscible enriched hydrocarbon gas injection. This application has been filed previously in accordance with Article 5, Section 400 of the AOGCC regulations. Secondly, we are requesting that the Commission, in -- in its capacity as a designated jurisdictional agency within the meanin¢ ofthe Crude Oil Windfall Profit Tax Act of 1980, approve the Flow Station Three injection project as meeting the requirements of subparagraphs~ (A), (B), and (C) of the Internal Revenue Code, Section 4993, sub (c), sub (2). As the Commission may recall, ARCO on behalf of the working interest owners submitted documents supporting both the application for additional recovery and the certification .application on August 31, 1982. We request that these documents be entered as part of.thepublic record. Four representatives of the working interest owners will present testimony today. Our testimony will focus on those items required by the AOGCC regulations, and how -- on how the Flow Station Three injection project meets the requirements of the Windfall Profit Tax Act as a bona fide teriary recovery project. Because of the documents that were submitted previousl' our presentation will be fairly brief. I believe it will last 810 N STREET. SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023680 1OO7 W. 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 24 -6- approximately one to one and a half hours. Our intent is to emphasize those points which we feel are the most important and to provide a forum from which the Commission can ask questions on project specifics. In our testimony today, the working interest owners will show that the Flow Station Three injection project meets the following three requirements as stated in the Windfall Profit Tax Act: First, that the project involves the applicatio~ of a qualified tertiary recovery method in accordance with sound engineering principles that will result in more than an insignificant amount of incremental crude!~oil. Second, that the project beginning date is after May, 1979. And, third, that the project area is adequately delineated. To do this, we have divided our testimony into three parts as shown on Slide One ARCO, as operator of the project, will be presenting the majorit~ of the testimony. The first part of our testimony will briefly discuss theoverall projectand will include a summary of project objectives, project delineation, project design, required facilities, implemntation plans and surveillance plans. This part ofthe testimony will not only support our certification request, it ~ill also discuss the significant information required by Section 20 AAC 25.400 of the Commission regulations regarding an application for additional recovery. The second part of our testimony will involve a discussioi by each of the major working interest owners of their numerical 810 N STREET. SUITE 101 277-057Z-Z77-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023681 1007 W. 3RD AVENUE 272-75 ! 5 10 11 14 17 18 19 9,1 9.2 9.4 simulation studies that have indicated that significant incremental oil recovery will result from implementation of the miscible gas process. Finally, the last part of our testimony will tie togethe] the presentation and focus specifically on how the project meets each of the Internal Revenue Code requirements. I would, at this time, like to introduce the four witnesses that will be present- -- that will be presenting evidence today. They are Mr. Bill Nelson, Mr. Terry Day, Mr. Scott Williamson and Mr. Roger Doughty. At the end of our presentation this morning, the witnesses would like to form a panel from which to answer the Commission's questions. This panel could also answer at that time any questions you might have concerning the application for additoinal recovery. ' ~ '~,/,~ The witnesses have been sworn in. Previously we have filed our testimony and each of the witnesses has included in that testimony a short statement of his qualifications. I would also like to ask that they be accepted as ex- -- experts. MR. CHATTERTON: We will -- we shall -- we do accept the~m as expert witnesses. MR. MARQUEZ: Thank you. At this time I would like to call on Bill Nelson. MR. NELSON: Members of the Alaska Oil and Gas Conservation Commission, ladies and gentlemen, my name is Bill AGO 10023682 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-O572-277-O~73 277-8543 272-7~15 ANCHORAGE. ALASKA 99501 10 11 14 17 18 19 -8- Nelson. Since receiving my graduate degree in engineering from Purdue University in 1975, I have been employed by ARCO. I have spent over seven years working various aspects of Arctic and reservoir engineering. I became involved with the Prudhoe Bay development plans and reservoir engineering studies in 1979, and I presently hold the title of Senior Area Enginee~ for Prudh~ Bay EOR. This morning I would like to briefly summarize the engineering aspects of the Flow Station Three injection project. I'd first like to discuSs the reasons why the working interest owners have decided to pursue miscible gas as a viable process for Prudhoe Bay at this time. I'd then like to discuss the design of our project and the 'facilities required, and follow that with a brief overview of our implementation plans and surveillance program. The Flow Station Three injection project is a small scale miscible enriched hydrocarbon gas project. As you can see in Slide Two, the project is located within the Prudhoe Bay unit in the western downstructure area of the ARCO operated portion of the field. Our planned execution of primary and secondary operation~ at Prudhoe Bay is projected to yield an estimated ultimate recovery of approximately nine billion barrels of oil, leaving more than ten billion barrels of oil trapped in the Sadlerochit reservoir. With such a large volume of oil at stake, the AGO 10023683 R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-O572-277-O573 277-B$43 272-7515 ANCHORAGE, ALASKA 99501 10 11 19. 13 14 15 16 17 18 19 2O 9.1 22 23 24 25 working interest owners recognized the potential of increasing recovery through the application of tertiary recovery methods, and the need to evaluate this potential as quickly as possible so as to ensure proper development. Screening studies were conducted to better define the applicability of the leading enhanced recovery methods at Prudhoe Bay. The studies fell into four categories: one, miscible gas displacement processes, two, surfactant flooding, three, enhanced waterflood techniques, and four, thermal processes. I'd like to now summarize the results of these studies. The miscible gas processes were found to be the most i. viable for the Sadlerochit reservoir at this time. The miscible gas process has been technically proven and has been used in the petroleum industry for several years. Although surfactant flooding may have some potential in the long term, our studies did not find a surfactant currently available that could with- stand the wide range of' temperatures and salinities that are expected tobe present in the reservoir. Enhanced waterflood techniques, suCh as caustic or polymer flooding, were found to possess some limited potential in -- in -- in improving our waterf~ood performance. However, the techniques are not cost effective because of problems associated with the logistics of supplying large quanti.ties of chemicals to this remote Arctic location. Finally, thermal processes were eliminated since the depth and pressures of the Sadlerochit formation make these 810 N STREET. SUiTE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 9950! AGO 10023684 1007 W. 3RD AVENUE 272-7515 10 11 14 15 16 17 18 19 9.0 9.1 9.3 9.4 25 processes economically infeasible. Of the various types of miscible gas processes, miscible enriched hydrocarbon gas injection was chosen at this time because the required injectant properties can be formed using presently available Prudhoe Bay Field processing streams. The miscible gas will beinjected sequentially with water in a manner referred to as WAG injection, or water-alternating-gas injection. Thisinjection is expected to continue for at least ten years oruntilmore than a 10% pour volume slug of miscible gas has been injected. We expect the EOR project to start up by the end of 1982, and we expect the project to recover at least an incremental 24 million stock tank barrels of crude oil. In moving forward,~ the working interest owners see this project as accomplishing the three main objectives listed in Slide Three. First, the project will add to the recoverable reserves of the field; secondly, the project will allow us to test the effectiveness of a miscible gas process at Prudhoe; and finatly, the~project will provide us with design and operating information that could be used in possible future applications. Up to this point I've presented a brief overview of why we're pursuing miscible gas at Prudhoe. I'd now like to describethis project in a little more detail. As can be seenin Slide Four, the Flow Station Three injection project is located in all or parts of drill sites 1, 6, 12, 13 and 14 in the eastern operating area. Specifically, 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023685 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 - 11= the area chosen encompasses all or portions of sections 10, 11, 12, 13, 14, 15, 16, 22, 23, and 24 in Township 10 north, Range 14 east, and sections 18 and 19 in Townships 10 north, Range 15 east. The project encompasses approximately 3,650 acres and contains approximately 1.02 billion barrels of pore volume. The original oil in place is estimated to be 440 million stock tank barrels. This particular area of the Prudhoe Bay Field was chosen for three reasons. First, the area possesses a relatively low free gas saturation. Thismeans that contamination or dilution of'the injectant will be minimized in this downstructure area. Secondly, the project area possesses a relatively high reservoir pressure. Currently the average reservoir pressure in the project exceeds 3900 psi. The high formation pressure makes it easier to maintain miscibility conditions for the injectant and reduCes the amount of water injection required prior to start up. Finally, the area has access to sufficient volumes of water and miscible injectant. Flow Station Three, that is the gas-oil-water separation facility for this general area of the field, is located nearby and acts as a centralized point for processing the miscible gas and produced water needed for injection. In fact, the name of the teriary project is taken from the importance attached to Flow Station Three. As can also be seen in Slide Four, the project boundarie~ 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8545 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023686 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 have been delineated areally by the upstructure water injectors on thenorth, by the outermost producing wells in the patterns on the east and west and by the down dip development limit in the south. The vertical delineation is shown in Slide Five. Vertically, the project encompasses the light oil column of the Sadlerochit. That is, the interval from the top of the Sadlerochit formation to the top of the heavy oil/tar zone. The heavy oil/tar zone will not be affected by the miscible gas injection. The basic geology ofthe area is also shown in Slide Five. The Sadlerochit formation is commonly divided into five main zones. In order of.increasing depth, these zones are referred to'as the Zulu, X-Ray, Victor, Tango, and Romeo. Within the project boundaries, only the X-Ray --- only the Zulu/X-Ray and part of the. Victor will be affected. The Zulu/X-Ray zones are composed of fine to medium grained sand- stones with many interbedded, mostly discontinuous, shales. The Victor on the other~'~hand is composed of a conglomerate secti¢ in the upper half grading to a coarse grained sandstone in the lower half. A shale separating the X-Ray and Victor zones is found in a large portion of the project area, as are several faults. No original gas cap is present within the project area, but some localized free solution gas may be present near the existing producers. By year end, the average reservoir 810 N STREET, SUITE 101 Z77-O572-Z77-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023687 1OO7 W. 3RD AVENUE 272-7515 ~n 10 11 12 13 14 15 16 17 18 19 2O 9.1 22 23 24 pressure in the area should be approximately 3900 psi. At this pressure, the gas saturation will be at or near the critical gas saturation of around three to 4%, but this volume of gas will not have a significant impacton project performance. A substantial water interval underlays the entire project area. Directly overlying the aquifer is a heavy oil/tar zone consisting ofhighly viscous crude which ranges from 20 to 60 feet in thickness. As I mentioned earlier, due to the low mobility of this heavy oil/tar zone, injectivity into this zone is expected to be Very low and the WAG injectors will not be perforated in this portion ofthe oil column. The next slide, Slide Six, begins to address the reservoir engineering aspects ~f the Flow Station Three injectior project. Within this~3,650 acre project are 11 WAG injectors, seven upstruCture water injectors and 42 producers. On the slide the WAG injectors are represented by triangles, the water ~ ~. injectors by squares, and theproducers by circles. The injectio~ pattern chOsen for the project is an inverted nine-spot pattern developed on 80 acre well spacing. Thus, each pattern itself encompasses approximately 320 acres. The inverted nine spot was selected primarily for its flexibility in conversion to other pattern configurations and for its initial three to one producer to injector ratio. Since the well injectivity is expected to be jigherthan the well productivity, the three to one ratio should allow more versitility in balancing pattern withdrawals AGO 10023688 810 N STREET, SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 and injection. It is anticipated that about 40 to 45 million standard cubic feet of enriched hydrocarbon miscible gas will be injected into the project on a daily basis using the WAG injectors. This is equivalent to an injection rate of 27 to 30,000 reservoir barrels per day at the temperatures and pressure expected to be present within the project area. Injection will continue until at least a 10% pore volume slug of miscible gas has been injected. As I mentioned earlier, the Flow Station Three injection project requires the injection of water as well as miscible gas. Produced water Will. be alternately injected With the enriched gas intothe WAG injectors to provide pressure maintenance and to reduce the channeling tendency of the lower viscosity gas. In the literature this benefit is referred to as mobility control Water will also,be injected into the seven upstructure water injectors to help maintain miscibility pressure, to help confine the miscible gas to the project area and to help shut off.gas cap gas thatmight otherwise enter the project area. Approximately 90,000 barrels of water per day is estimated to be required in the WAG wells and 100,000 barrels of Water per day may be required in the upstructure water injectors when the project has been underway for many yaers. To provide the water and miscible gas to the project area in this time trame necessitates a substantial investment in new facilities. I'd liketo briefly discuss the facility AGO 10023689 R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE I~7 W. 3RD AVENUE 277-0572-277-0573 277-8543 272-7515 ANCHORAGE, ALASKA 99501 l0 ll 12 13 14 15 l? 18 19 2O 21 22 23 24 25 design for the Flow Station Three injection project. The : additional facilities are required for two purposes: first, to process, blendand injectthe miscible gas, and second, to provide adequate water volumes prior to the fieldwide waterflood. The miscible injectant is composed of several liquid and gaseous streams from existing Prudhoe Bay facilities as show~ in Slide Seven. One source of liquids is the field fuel gas unit, or FFGU. The FFGU processes separator off-gas in the field and by lowering the hydrocarbon dewpoint of this bas to -40° fahrenheit, produces fueld gas that is used in the field and by Alyeska in its first four pump stations. Low molecular weight hydrocarbon liquids drop out as a by-product of the gas conditioning. Currently, a portion of these liquids are spiked into the 0il pipeline. After project start up, these liquids will be used to form the miscible gas. All of the other sources for the enriched gas are connected with Flow Station Three. As indicated in the faciliti~ block diagram, they include scrubber liquids from the separator off-gas processing equipment and compressed off-gas from the intermediate pressure or IP separator. If required, dehydrated high pressure residue gas will be added to supplement the IP compressor gas volumes. The flash drum liquids from the FFGU, the scrubber liquids from Flow Station Three, and the IP compressor gar are all sent to a new process module located adjacent to Flow Statio~ 810 N STREET. SUITE 101 277-O§72-Z77-O573 R & R COURT REPORTERS 509 W, 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 AGO 10023690 1OO7 W. 3RD AVENUE 272-751S 10 11 12 14 15 16 17 18 19 2O 22 23 24 25 -16- Three. As shown in Slide Seven, in this adjacent module the liquids are pumped and the gas is compressed up to a pressure of approximately 4,000 psi. The fluids are then blended to form a supercritical fluid that is subsequent delivered to drill site 13 for injection. This mixture, which contains about 42% methane, 12-1/2% carbon dioxide and 45-1/2% hydrocarbon intermediates, is miscible with Sadlerochit crude oil at approximately 3,700 psi. The facilities for the miscible gas have been designed to be compatible with previously planned Prudhoe Bay faciliites and should provide 40 to 45 million standard cubic feet per day of gas for at least ten years. However, it should be noted that the availability of enriching feedstocks is time dependent. The supply of miscible gas is not infinite. Due to the declinin¢ oil rates expected in the 1990s, and the volumes of scrubber liquids and IP compressor gas are expected to decrease, which will affect the injectant availability. The water requirements of the project are largely provided for by the existing and planned produced water and source water injection facilities. However, new facilities are required to aument the supply of water prior to the start up of the Beaufort Sea waterflood in mid-1984. Therefore, to supply the necessary supplemental water, four wells at drill site 14 will be perforated in the Sadierochit aquifer and artificially lifted with high pressure gas. The gas lift gas AGO 10023691 R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-O572-277-O573 277-8543 272-7515 ANCHORAGE, ALASKA 99501 -17- ! will be sUpplied by three new 100 horsepower turbine compressors 2 housed in a separate module at Flow Station Three. The four 3 wells are expected to provide 40 to 60,000 barrels per day of 4 supplemental water in. addition to the 25 to 35,000 barrels 5 per day of water produced with the oil from other wells in the 6 Flow Station Three area. This total volume of water, namely ? 65 to 95 .... 95,000 barrels of water per day will be sufficient 8 to supply the project needs until Beaufort Sea water is availab 9 In addition, as water produCtion within the field increases due 10 to lower pressure separation and artificial lift being made 11 availalbe to the produCing well, s, the suPplemental water from 12 drill site 1.4 will be gra~dua!l~y.phased out. 13 The anticipated well and facilitY costs for the Flow 14 Station Three injection project are estimated to be $110 million. 15 In Slide Eight, the new facilities and pipelines required for 16 the project are shown in. yellow. The major investment items 17 are: one, the ~process or injection module, two, the gas lift 18 compressor module, three, the flash drum liquid pipeline to 19 Flow .Station Three, and four, the miscible gas pipeline to 20 drill site 13. 21 I'd like to now leave the design of the project and move forward and address our implementation and surveillance plans. As I mentioned earlier, our North Slope construction personnel are moving forward as expeditiously as possible to ready the new facilities for start uP by year end. Project 810 N STR~ET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 9950! ' OO7 W. 3RD AVENUE AGO 10023692 272-7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -18- start up will occur in several stages as shown in Slide Nine. The first stage will involve some pre-injection of water into some of the WAG injectorsand into the upstructure water injectors Produced waterat Flow Station Three which is currently being disposed of in the Cretaceous sands will be redirected to the project area through existing produced water injection or PWI facilities starting in late November. Following start up of the three small interim gas lift compressors in early December, the supplemental produced water from drill site 14 will join the other produced water and bring the total pre-injection to approximately 50 to 70,000 barrels of water per day. Besides providing pressure support and retarding the advancement of the gas tongues into the project area, the pre-injection of water will also reduce the free solution gas concentration around the WAG injectors and will improve the injectivity profile of the miscible gas when injected. The next start-up phase involves the injection of the 40 to 45 million standard cubic feet per day of miscible gas intothree or fourofthe 11 WAG injectors. This is expected to incur -- occur near the ~end..Of the year and this date will be the "project beginning date" for the Windfall Profit Tax purposes After a period of gas injection into these first wellS, water injection will follow into these initial wells and another set of WAG injectors will commence taking miscible gas. It is anticipated that several sequences will be required before all 810 N STREET, SUITE 101 277-O572-277-O§73 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 AGO 10023693 I OO7 W. 3RD AVENUE 272-75 ! 5 l0 ll 12 13 14 15 16 l? 18 19 2O 21 22 23 24 of the 11 WAG injectors have received miscible gas. Although the actual length of each enriched gas cycle will be determined by operational experience and reservoir performance, it is currently estimated that the miscible fluid will be injected in one to three month periods. The WAG ratio, that is, the amount of water to be injected alternately with the gas, will be adjusted to maintain the pressure in each pattern above the minimum mis'cibility pressure. By January 1st, 1983, 51 of the 60 planned project wells are expected to have been drilled. This includes all 11 of the WAG injectors, five of the seven upstructure water injectors and' 35 of the 42 produCers. The other nine wells will be made available throughout the year 1983 as part of our planned field development. Total produCtion rates from the project area will be controlled as closely.as possible to achieve a balance between injection and produCtion with the overall goal of individual pattern balancing and maintenance of miscibility conditions. Althouth not a part of our start-up plans, a number of other field expansions will occur during the first two years ~'hat will affect project operation. Low pressure separation and artificial lift will become available to the project producers during the first 15 months of operations. These facility expansions till greatly enhance the productivity of our wells, they will allow us more flexibility in pattern 810 N STREET, SUITE 101 Z77-O§7Z-Z77-O$73 R & R COURT REPORTERS 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023694 1OO7 W. 3RD AVENUE 272-7515 10 ll 12 13 14 15 16 l? 18 19 2O 21 22 23 24 25 -20- balancing and will allow us to handle more water production in the project wells. As a result of the ability to produce more water in the Flow Station Three area, we should be able to phase out the supplemental water production at drill site 14 within two to three years. Another major expansion, the Beaufort Sea waterflood, is expected to start up in mid-1984 and will make available approximately 100,000 barrels per day of sea water for injection into the upstructure water injectors. It is important to note that the Beaufort Sea water cannot be used in the WAG injectors. Only relatively warm produced water can be used in these wells since unheated sea water would form hydrates with the miscible gas in the wellbore during change overs between gas and water injection. That concludes my remarks on implementation. I'd next like to summarize some of our surveillance plans. As I mentione~ at the beginning of my presentation, one of the objectives of the Flow Station Three injection project is to test the effectiveness of the miscible gas process. For this reason, an extensive surveillance program has been planned to monitor and optimize the enriched gas drive process. The existing fieldwide surveillance program will be supplemented by the use of observation wells, cores, an expanded case hole logging program, morefrequent production well surveys, and a radioactive gas tracer program designed to track actual injectant movement in AGO 1002~695 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-0572-277-0573 277-8545 272-7515 ANCHORAGE, ALASKA 9950! l0 ll 12 15 14 15 16 l? 18 19 2O 21 22 -21- the reservoir. As shown in Slide Ten, we have designated the inverted nine-spot pattern surrounding WAG well 13-7 as the key observation pattern. As presntly envisioned, one or two non-perforated observation wells will be drilled around well 13- to monitor gas and water movement and to help evaluate the near term effectiveness of the tertiary process. These wells will completed with non-conductive Fiberglass casing to facilitate the periodic use of induction logs to monitor water saturations. The propagation oftheenriched gas front past the observation wells wiill!~be monitored with neutron logging devices. The observation well logging program will provide a time-lapse description of changes inwater and gas saturations versus depth. From these measurements, we hope to evaluate, perhaps within one to two years after project start up, the effect' of a tertiary process in forming a miscible zone and in mobiliz the crude oil. Additional coring has also been performed'within the project area to increase our understanding of the reservoir properties in this portion of the field. By January, 1983, five wells will have been cored within the project boundaries as indicated in Slide 11. These wells are 12-9, 13-4, 13-19, 13-25, and 13-98. Well 13-98 is one of our observation wells. The cores will provide us with information on permeatibilty, porosit' , lithology and fluid saturation for use in future performance 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023696 11 ¸12 13 14 16 17 18 19 20 21 22 23 24 25 -22- studies. To better monitor the operational aspects of the project, an expanded case hole logging and well survey program has been developed. Baseline logs will be run in the producing wells to establish the gas and water saturations existing at the beginning of the project. Periodic repeats will be run in selected producers to monitor floo~ performance throughout the project life. In addition, spinner and tracer surveys will be used to monitor the ~production and injection profiles. Finally, bottomhole pressure build-ups will be obtained in each inverted nine-spot pattern to ensure that the reservoir pressure is being maintained above theminimum miscibility conditions. One of the best over-all qualitative tools to assess project performance will be the use of radioactive gas tracers. A program has beendeveloped to inject one of four different tracers intoeach WAG injector during its first miscible gas cycle. Gas samples will then be taken from each project producer monthly and analyzed for the presence of each tracer. The gas analysis results will provide a means of determining areal gas movement and may giu'e us an indication of volumetric sweep efficiency. These results may be especially important in those areas where faults are present. The surveillance program that I have just outlined is not inexpensive. For1983 alone, the program is estimated to cost over $4 million and that is excluding the cost of the 810 N STREET. SUITE 101 Z77-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023697 10 11 12 14 15 16 17 19 22 24 -23- observation wells and cores. This represents a significant on-going commitment by the working interest owners to the projec' objectives that I outlined earlier. Mr. Marques indicated at the beginning of our testimony this morning that the second part of our presentation would involve a discuSsion of the numerical simulation results that evaluated the.:~ecovery potential of the miscible enriched hydrocarbon gas process. I would now like to begin that discussion. Miscible gas has not been used previously in the Sadlerochit formation, and accordingly, the recovery estimates are based on extensive numerical simulation ofthe tertiary process in the downstruCtion portion of the Flow Station Three area. BecauSe ofthe importance of the incremental recoveries to overall project e~conomics, all three major co-owners, that is, ARCO, Exxon and Sohio, have performed their own independent simulation studies. Although each company used different approaches and different reservoir models, the results from the three companies indicate thatthe displacement of a 10% pore volume slug of miscible gas will recover an additional 5-1/2% of the original oil in place over conventional pattern water- flooding developed on 80-acre spacing. This corresponds to a 24 million stock tank barrel increase in ultimate recovery from the project a~ea. At this time each of the three major working interest R & R COURT REPORTERS 810 N STREET. SUITE 101509 W. 3RD AVENUE 1OO7 W. 3RD AVENUE AG0 277-0572-277-0573 277-8543 272-751S ANCHORAGE, ALASKA 99~O1 1002B698 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -24- owners would like to present their simulation work in more detail. I will first present ARCO's results. ARCO undertook a large scale reservoir model study to, one, determine the incremental recoveries associated with miscible gas injection, two, define project sensitivities, and three, develop an optimum implementation plan. Themodel employed was a sequential, semi-implicit four component miscible simulator which is ~,~ formulated to represent gas, oil, water and solvent systems. ARCO chose to use the four component model instead of a more rigorous fully compositional model for three reasons. First, the four component model runs computationally much faster which makes it easier to evaluate a larger number of cases; secondly, the model results were easier to interpret; and thirdly, the recoveries predicted by the four component model are comparable to those found using a fully compositional model since, as I'll describe a little later, compositional model results were used tocalibrate our four component model. Slide 12 shows the portion ofthe project area that was simulated. The symmetrical strip extended north into the gas cap and south into the aquifer to correctly incorporate pressure boundary effects. Slide 13 shows the actual grid used. The three-D strip was repre- -- represented by a 36 in the X direction, seven in the Y direction and ten in the Z direction, a grid that contained over 2500 grid cells. The model was history matched to existing actual project R & R COURT REPORTERS ~,, o. S'rREE'r. Su,'r£, O, ~O9 w. 3.o ^V£NUE ,OO7 W. 3RO AV£.U£ ~77-0572- ~'77-0573 277-8S43 272-7Sl S AGO 1 O0 23 699 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -25- area primary performance and t othe predicted future pressure performance generated with ARCO's full field three-D simulator. Wellbore hydraulics were added to the model such that the availability of hi~pressure, low pressure, and artificial lift could be handled. Finally, one last calibration of the four component model wasobtained. Several two-D cross-sectional runs using a fully compositional model were made for a hydro- carbon miscible WAG processand the four component model was adjusted to match these results. I would like to discuss the results of six major cases encompassing three different reservoir producing mechanisms that were studied withthe three-D reservoir model. The first case involved the prediction of natural depletion performance utilizing the current 160 acre spacing, while the remaining five scenarios modeled frontal displacement employing an inverte~ nine-spot pattern with 80 acre well development. The pattern development casesthat were simulated consisted of a conventional waterflood and a WAG miscible displacement process with a 10, 15, and 25% pore volume slug of enriched gas being injected. The final case considered a deferral of miscible gas injection for 15 years. All of the cases were run for 30 years. The results of the natural depletion, waterflood, and 10% pore volume gas injection cases are shown in tabular form on Slide 14. The results show that the injection of a 10% pore volume slug of miscible gas is estimated to increase recovery 810 N STREET, SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023700 10 11 12 14 15 16 17 18 19 2O 21 22 23 25 -26- by 5-1/2% overthe 80 acre spaced waterflood. This corresponds to the incremental recovery of 24 million stock tank barrels per day of oil that I quoted earlier. The potential does exist for higher incremental recoveries, however. Slide 15 shows the relationship between incremental recovery over waterflooding and pore volume of miscible gas injected. Injection of a 25% pore ~olume slug of miscible gas, which corresponds roughly to about 25 years of injection, could raise the incremental recovery due to the EOR process to almost 11%. The decision to inject volumes much greater than a 10% pore volume slug will depend upon actual project performance, injectant availability and furture economics. One thing that is apparent from our discussion this ~.' morning is that the Flow Station Three injection project will be started up before a waterflood has been performed in this area of the field. During the planning stages of the project, one of the sensitivities that was evaluated was whether recoveries might be higher if EOR were postponed until after the waterflood had been underway formany years. To evaluate this possibility, ARCO ran the last case that I mentioned previously. Namely, thai of a 15-year deferral of the miscible gas implementation. Also, both Exxon and ARCO conducted laboratory core floods to determine whether the residual oil saturation left behind after the miscible gas displacement was influenced by the presence and am.ount of ~prior~ waterf!oo~ing. The resu!ts of,ARCO's last case 810 N STREET. SUITE 101 277-0572-277-0575 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023701 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -27- indicated that with a 30-year field life, no recovery advantage was seen for delaying the injection of the miscible gas. In fact, several disadvantages were observed. Besides the problem of injectant availability, deferral resulted in lower recoveries ofthe enriched gas and higher produCed water volumes. Moreover, the laboratory results.showed that the same residual oil saturation in the cores was obtained regardless of whether miscible gas was preceded by water injection or not. Thus, the working interest owners of the Prudhoe Bay field are in support of implementing the Flow Station Three injection project at this time. This concludes my testimony this morning. Our next witnesses will be representatives from Exxon and Sohio who~.will present and discuss their numerical simulation results. Mr. Terry Day from Exxon Corporation will testify next. Thank you. MR. DAY: Mr. Chairman, members of the CommissioI ladies and gentlemen, my name is Terry Day. I am Exxon's Western Division Reservoir Engineer. I received a Master's of Science degree in electrical engineering from the University of Florida in 1971. In the same year I was employed by Exxon Company, U~.iS.A., and have spent most of the past 11 years responsible for various aspects of petroleum reservoir .~ i~ ~ engineering. Since November of 1980 I have been involved with Prudhoe Bay unit studies including the coordination of several STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023702 10 1! 12 13 15 16 17 18 19 2O 21 22 23 24 25 -28- engineers studying enhanced recovery methods. This morning I would like to describe Exxon's evaluation of the Flow Station Three inj~.ection project. As has been indicated, the technical work relative to apllying EOR methods at Prudhoe started with a screening study which evaluated appli- -- applicability of several leading EOR metnods. Based on this review of processes, Exxon has concluded that miscible WAG displacement is the most promising EOR method for application at Prudhoe. However, we are continuing to perform research in other areas. Exxon's technical work concerning miscible processes at Prudhoe has ineluded slim tube tests to verify requirements for miscibility, laboratory displacement tests to determine residual oil saturations, and numerical simulations of portions of theFlow Station Three injection project. Exxon ran slim tube experiments which confirmed and supplemented several such tests that were carried out by ARCO. In a laboratory slim tube experiment, a gas with known composi-i tions displaces oil from a long, narrow coiled tube that is packed with sand. The gas injection rate, outlet pressure and temperature are closely regulated. Experiments using gas obtained by mixing 70% Flow Station Three separator gas with 30% field hydrocarbon liquids to displace Prudhoe Bay oil at reservoir temperature and various pressures, indicate that the gas and Prudhoe Bay oil would be miscible at expected reservoir , , R & R COURT REPORTERS I 810 N~T~EET. SUITE I O 1 ~O9 W. 3RD AVENUE m I 1 ~7 W. 3RD AVENUE 277-0572-277-O~73 277-8~43 272-7~1~ ANCHORAGE, ALASKA 99~01 AGO 10023703 10 11 12 13 14 15 16 17 18 19 2O 21 29. 23 24 9.5 -29- pressure. I will show the results of one test in a moment. Mr. Nelson has already described the results of our displacement test that were carried out using Prudhoe Bay Sadlerochit crude and cores. Themajor objective of the simulation study was to assess the feasibility of injecting enriched separator gas in the Flow Station Three area and to evaluate the additional recovery potential. Exxon's fully comp- -- compositional reservoir simulator program and a three dimensional reservoir model were used for numerical simulation~ which predict reservoir behavior in the Flow Station Three area under waterflood and under several miscible WAG displacements. In a compositional simulator, the oil or liquid and gas phases must each be represented or characterized by a fixed number of chemical components, ~usually less than ten, since a complete specification is not practical. The components used are standard compoenents such as carbon dioxide, methane, ethane, et cetera, and pseudo components defined to represent complex mixtures of heavier hydroCarbons. The simulator Program calculates liquid and gas phase densities, phase viscosities and mass transfer between phases using analytical methods based on the composition of theoil and gas phases. Exxon's simulator program uses ten components: carbon dioxide, methane, ethane, propane, and six heavier-than-propane hydrocarbon compoenents to characterize the actual 'reservoir 810 N STREET. SUITE 101 277-0572-~77-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023704 10 11 12 13 14 15 16 17 18 19 2O 21 29. 25 -30- oil and gas. The fluid characterization was developed by closely matching laboratory determined buble points, oil densities and oil viscosities to those analytically calculated. The characterization was verified by comparing simulation results with laboratory slim tube tests. Predicted versus actual recoveries are shown in Figure Two for one slim tube test comparison. As discussed earlier, actual -- actual slim tube data was obtained from enriched miscible gas displacing Prudhoe Bay reservoir crude. A one- dimensional simulator model was designed which represented the 20 foot long slim tube. Numerical dispersion causes the simulate prediction to be slightly conservative in this case. However, the miscible condition has been closely predicted as shown by the very high recovery, almost 90%, after one pore volume of injection. A confined nine-spot model of a portion of the Flow Station Three area and fully compositional as well as four component simulators were used to investigate in detail the mechanics of the miscible flood. The rectangle shown on Figure Three is a 320 acre inverted nine-spot pattern -- pattern within the Flow Station Three area included in the model. Parts of three 320-acre inverted nine-spot patterns are included. The configuration was chosen to minimize the effects of grid orientation on the movement of gas within the model. AGO 10023705 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -31- Gridding of the model is shown in Figure Four. The model thickness including the aquifer is 450 feet represented by nine layers. Thin vertical blocks were used at the top so that tendencies of the miscible gas to gravity overrun could be simulated. Porosities, permeabilities, saturations, pressures and fluid properties were based on Flow Station Three area reservoir data. The heavy oil/tar zone effect was included by reducing rock'permeabilities and porosities through this zone. This model contains 60 million standard barrels of original oil in place, or about 15% of that in the Flow Station Three injection project. To closely duplicate field practices, the production wells were completed about 120 feet above the aquifer. Water and miscible gas were injected over the intervals shown to be perforated. Injection was managed to match reservoir withdrawal~ Theestimate of vertical miscible gas conformance near injection wells is important to our studies and has been determined using separate radial models. The results of' these studies have been cor .... incorporated into the following model results. That's fine there. Hold that one. Hold that -- yeah, tha%'s fine. UNIDENTIFIED: That one back? MR. DAY: A base waterflood case and several cases in which water was laternately injected with enriched field gas were run using this pattern model. Termination of 810 N STREET, SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023706 10 1! 12 13 14 15 16 17 18 19 20 21 22 23 24 25 -32- production'was based on a ten to one water/oil ration in all cases. These cases indicated that recovery is a function of the total miscible gas injected and the WAG raio used. If miscible gas were available and could be continued to depletion, additional recover over a waterflood was calculated to be 8% of original oil in place. Since the supply of miscible gas will decrease with time, cases using various volumes of miscible gas and WAG ratios were also simulated. Our analysis of these cases indicates that a recovery of about 8% of the original oil in place can also beachieved by a 15% pore volume slug of miscible gas with proper reservoir management. As.previous testimony has stated, the actual length of miscible gas injection and the WAG ratios employed will be managed based on actual well productivity, injection well capacities and overall project performance. Figure Five shows a plot of estimated production from the total Flow Station Three injection project area based on a scale up of Exxon's reservoir simulation of typical pattern performance. The evaluation indicates that production from the planned waterflood would peak at sli- -- slightly above 55,000 thousand barrels perday, and then decline to depletion after the year 2000 with a recovery of about 40% of the oil originally in place. Injection of a 10% miscible gas slug at WAG ratios sufficinet to maintain reservoir pressure should increase production starting in the last 1980s and increase ultimate 810 N STREET, SUITE 101 277-O572-277-O575 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10O23707 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 -33- recovery by about 5-1/2% of the oil originally in place. Based upon our work and the work presented today by other~.°owners, Exxon has concluded that the Flow Station Three injection project is a worthwhile project which will increase oil recovery from the Prudhoe Sadlerochit reservoir. We recommend thatthe AOGCC approve the application for additional recovery and approve the project as meeting the requirements of a qualified tertiary recovery project for puposes of the Crude Oil Windfall Profit Tax Act of 1980. That concludes Exxon's remarks in support of the Flow Station Three injection project. The next witness will be Dr. Scott Williamson from Sohio Petroleum Company. Dr. Williamso will present the results of Sohio's numerical simulation work in support of the miscible gas project. DR. WILLIAMSON: Commissioners, ladies and gentlemen, my name is Scott Williamson. I received my graduate degree in engineering from Stanford University in 1970. Since then I have been engated in oil and gas production research, reservoir modelling and field operations. I began working on North Slope reservoir engineering in 1980, and currently I am themanager of enhanced oil recovery and reservoir modelling for Sohio Petroleum Company. I wish to take this opportunity of addressing you today to describe briefly the work which Sohio undertook to evaluate the Flow Station Three miscible gas injection project. 810 N STREET, SUITE 277-0572 - 277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-85A3 ANCHORAGE, ALASKA 99501 AGO 10023708 1OO7 W. 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -34- Let me begin with a review of the basic idea of miscible gas drive by contrasting it with conventional gas drive. In a conventional gas drive it's generally found that where gas does penetrate, the fraction of oil displaced is rather low, say some 30% of the local;.oil content. This is generally referred to as the microscopic recovery. The overal or macroscopic recovery is drastically reduced from this modest level by two effects. First, becasue gas is buoyant, it floats up through the oil to form a thin layer near the top of the reservoir bypassing much of the oil. Second, even this thin gas layer has a pronounced tendency to break up into channels which again bypass oil and contribute to hig~h GOR production'. The end result is not an effective process forincreasing oil recovery. In miscible gas drive, the injected gas on contacting the reservoir oil, combines to form a single fluid, usually a liquid. Gas mixing in this manner to form a miscible fluid effectively displaces virtually all of the oil from the portion ofthe reservoir accessed by it. Many laboratory tests have demonstrated thatin this process the microscopic recovery usually exceeds 90%. Now, unfortunately in a reservoir the injected miscible gas still exhibits the two deleterious effects already described. It was observed a number of years ago that if water were injected with the miscible gas stream, then the tendency for the gas flow to break up into thin channels would be greatly diminished. The upward segregation of gas may also 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023709 10 1! 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -35- be somewhat reduced. The final result is an effective process, with high macroscopic recoveries, as Mr. Nelson showed earlier discussing ARCO's results. In practice, simultaneous injection of gas and water is not necessary. An alternating gas/water injection cycle is as effective and is operationally more practical. This then isthe water-alternating-gas, or WAG, process which we are examining today. From the discussion so far you will appreciate that an analysis of a miscible gas injection project will require a good understanding of how oil, gas and water flow through the reservoir rock. This level of information would be required in any case for analysis of primary recovery or a waterflood. For a miscible gas flood, we require additional information about the miscibility ofthe gas; that is, whether it will mix with the reservoir oil to form a single fluid, or will remain as a gas, but possibly with altered composition. Factors which determine miscibility include the chemical compositions of the inj~ected gas and the reservoir fluids, and the pressure and the temperatur of the mixture. This topic is often referred to as phase behavior. I will start the detailed account of Sohio's work with sample results showing that we can satisfactorily represent the reservoir fluid flow at Prudhoe Bay, i.in.the Flow Station Three area in particular. I will also show results which demonstrate 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 100Z3710 10 11 12 13 15 16¸ 17 18 2O 21 22 23 24 25 -36- our understanding of the phase behavior. Figure One shows an outline of Prudhoe Bay with an areal view of the extent of the reservoir included in our compute model of the Flow Station Three injection project area. You will notice that the model does not contain all of the proposed project area, merely a representative portion. For these kinds of problems, it ~is often more efficient to analyze a somewhat simpler, representative situation, scaling the results as required to the total project area. During primary production there is a significant interaction between the project area and the remainder of the reservoir. The extension of the model into the main field area permits us to model this interaction. The Flow Station Three injection project area contained some 440 million stock, tank barrels original oil in place. Our strip model, shown in figure two,.~contains a total of 236 millior stock tank barrels with 72 million stock tank barrels located inside the project area. The model contains a total of 840 blocks in 14 layers with 20 rows and three columns. The reservoir description and many of the fluid and rock .properties used in our model were based on Sohio's previous reservoir simulation studies of Prudhoe Bay. Forthe period from 1977 to 1982 historical data are available for testingthe model results. Figure three shows a comparison of predicted and measured reservoir pressures for this relatively short production period. We can see that there 810 N STREET, SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W, 3RD AVENUE 272-7515 AGO 10023711 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -37- is reasonable agreement between model results and field data. It is also worth noting that when we ran a base primary production case using the Flow Station Three injection project model, the results were consistent with other Sohio Prudhoe Bay computer model results. The second ,- the second item of information.required for computer simulation of a miscible gas process is, you may recall, the phase behavior description. We chose to represent the reservoir hydrocarbons with eight components. Compositional simulations are frequently run with a fewer number of components. However, the use ofeight components enabled us to accurately match observed phase behavior data.. Figure four shows some experimental measurements made by ARCO, the ringed points, for a test in which a sample of reservoir oil is mixed with successively greater amounts of a particular miscible gas. Duringthis swelling test, the pressure is adjusted after each gas addition to the minimum value which creates a single phase liquid. Any further reduction in pressure would result in the emergence of a separate gas phase. 'The curve in figure four shows the corresponding results predicted by our phase behavior calculations. And theme is excellent agreement between theory and measurements. Let me now describe some sample results we obtained in our evaluation of the Flow Station Three Injection Project. Our primary concern was the performance of miscible gas drive 810 N STREET, SUITE 101 277-0~72-Z77-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RDAVENUE 272-75~5 AGO 10023712 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 -38- compared tothe anticipated waterflood. The next series of figures summarizes pertinent results of our model studies. First figure five shows the primary production performance expected for the Flow Station Three injection project area. The anticipated ultimate recovery is 28% of the original oil in place. The next plot, Figure six, shows the improved recovery ~i which could be expected from waterflood together with additional infill wells. This raises the ultimate recovery to 39.1% original oil in place after 30 years of production. The third figure of this series, figure seven, shows the further improvemer which miscible gas drive should attain. After an initial --- excuse me. After injection of a 15% pore volume slug of miscible gas this amounts to an additional 8.3% original oil in place, for an ultimate recovery of 47.4% original oil in place, which corresponds to some 33 million stock tank barrels of additional oil. We can see in passing that at 10% pore volume miscible gas injection, the incremental oil porduction is some 5.4% original oil in place. The precise recovery values --the precise recovery value depends on many variables: the project lifetime, theinjected gas composition, the miscible gas and waterinjection rates and the number and configuration of production wells. The final results we have inspected correspon~ to 25 years.!of misCible gas injection at a rate of approximately 0.6% of the pore volume per year with an average water-to-gas injection ratio of twoto one. This case was one of many which 810 N STREET. SUITE 101 277-O$72-277-O575 R & R COURT R£PORTER$ 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023713 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 9.5 -39- we examined during our evaluation work. As illustrated in figure eight, our conclusions may be summarized as follows: Number one, Sohio's evaluation of the Flow Station Three injection project shows that miscible gas drive with a 15% pore volume injection contributes an additional 8.3% original oil in place to the ultimate recovery. Number two, Sohio's results are in general agreement wit] ARCO's and substantiate the view that the Flow Station Three injection project does satisfy the requirements for a qualified tertiary recovery project. We therefore urge the Commission to permit the project for additional recovery and approve the project as a qualified tertiary recovery project. Thank you for the opportunity of making this brief presentation of our work on the Flow Station Three injection .' project. The next witness will be Mr. Roger Doughty from ARCO Alaska who will discuss how the project meets the requirements of the Windfall Profit Tax Law. MR. DOUGHTY: Members of the Alaska Oil and Gas Conservation Commission, ladies and gentlemen, my name is Roger Doughty and I have been employed as a petroleum engineel by ARCO since 1972. I received a B.S. degree in petroleum engineering from the University of Oklahoma in 1970 and I ~ received an M.S. degree in petroleum engineering from the same 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-85~3 ANCHORAGE. ALASKA 99501 ;007 W. 3RD AVENUE 272-7515 AGO 10023714 10 11 12 15 16 17 18 19 20 21 22 23 24 -40- university in 1972. I have been involved with the development of the Prudhoe Bay Field for over seven years and I am presently the Prudhoe Bay Regional Reservoir Engineer. In the next of the hearing, I would like to discuss how the proposed Flow Station Three injection project specifical meets each one of the requirements for a qualified tertiary recovery project for purposes of the Crude Oil Windfall Profit Tax Act of 1980. The Windfall Profit Tax Act provides that an enhanced oil recovery project is a qualified project if the operator submits a certification stating that the jurisdictional agency, in thisinstance the Alaska Oil and Gas Conservation Commission, has approved the project as meeting the requirements of the law. The specific requirements are found in subparagraphs (A), (B) and (C) of Section 4993(c) (2) of the Internal Revenue Code Slide one lists the requirements of those three para- -- subparagraphs. The subparagraphs specifically state that a project.Will qualify if: (A), the project involves the application, in accordance with sound engineering principles, Of one or more -- one or more tertiary recovery methods which can reasonably be expected to result in more than an insignificant increase in the amount of crude oil which will be ultimately recovered;~ (B), the project beginning date is after May 1979, and (C), the portion of the property to be affected by the 810 N STREET. SUITE 101 R & R COURT REPORTERS 509 W. 3RO AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023715 11 19. 13 15 16 18 19 9.1 22 23 24 25 -41- project is adequately delineated. We are requesting that the Commission approve the project as meeting each of these requirements and I would like to discuss each one in detail. There are basically three parts to the requirement in subparagraph (A). Namely, the application of a qualifired tertiary recovery method, the implementation of the project in accordance with sound engineering principles, and a reasonable expectation of more than an in- -- insignificant increase in the recovery of crude oil. First, the Flow Station Three injection project does involve the application of a qualified tertiary recovery methods as those methods are defined by the Windfall Profit Tax Act. The Windfall Profit Tax Act defines the tertiary recovery method as one that meets' one of two qualifications. Either the method is described in subparagraphs (1) through (9) of section 212.78(c) of ~e June 1979 energy regulations; or the method has been approved by the Secretary of the Treasury. As discussed previously, the enriched gas WAG injection method which is planned for use in the Flow Station Three injection project is a miscible fluid displacement method.~ Miscible fluid displacement is listed as a tertiary recovery method in paragraph (1) ofthe section 212.78(c) of the re~erence~ June 1979 Department of Energy regulations. The Flow Station Three injection project involves the injection of enriched ~I0 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 9950! ,oo? w. 3.D ^vE.u~ AG 0 272-7515 10023716 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 -42- natural gas into the oil reservoir at pressure levels such that the gas and reservoir oil will be miscible. The cumulative amount of~.injected gas measured at reservoir temperature and pressure is reasonably expected to be more than 10% of the reservoir pore volume being served by the injection wells. The muscible displacement process involves the alterna%ing injection of water and gas which is specifically recognized by the Department of Energy regulations. Thus, the Flow Station Three injection project does employ a qualified tertiary recovery method. Secondly, the miscible gas displacement project will be applied in the?Flow Station Three injection project in accordance with sound engineering principles. The planning and implementati of the project has been under the direct supervision of qualified and experienced reservoir engineers. Our testimony this morning and the cer- -- certification document have clearly shown that planning and integrated effort that has been applied to this project. Miscible fluid displacement using enriched hydrocarbon gas was selected as the best method to use at this time for this portion .of the reservoir only after a comparative examination of the various methods based on reservoir conditions, injectant availability and process costs. The results of our screening studies were discussed earlier in this hearing. The project facilities have been des- -- designated (sic)I to be compatible with previously planned facilities and AGO 10023717 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 )n 10 11 12 13 15 16 17 18 19 2O 21 23 24 -43- and construction has proceeded without impacting other Prudhoe Bay projects. The WAG method of injection and the inverted nine-spot injection pattern were chosen only after a thorough reservoir simulation study by the working interest owners. Implementation has been planned to give us as much flexibility as possible in our field operation. The legislative history to the Windfall Profit Tax Act provides that a tertiary recovery project which has not been preceded by secondary recovery methods will meet the tax " the certification sets forth an requirements if,.quOte, ..... explanation of why such action was in accord with sound engineering principles," end quote. Further, the legislative history provides that, quote, " ..... the project could qualify for tax purposes if the absence of secondary methods were explained adequately, andi~was due to peculiar characteristics of the reservoir or oil." Because of these statements, we thought thatl.it was important to discuss in this hearing in some detail why it islinaccordance with sound engineering for the tertiary recovery project to be implemented in the project area prior to the secondary recovery. Most of the~reasons we already addressed in our earlier testimony. However, I would like to summarize and reiterate them at this time. For the Commission's convenience, slide two gives a list of these reasons also. First, the implementation of this project as soon as AGO 10023718 810 N STREET, SUITE 101 Z77-O§7Z-Z77-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 10 12 !3 14 15 16 17 18 19 2O 21 22 23 24 25 -44- possible provides an opportunity to maximize oil recovery from within the project area by extending injection of miscible gas past the 10% pore folume slug, if that is economically feasible. As we indicated in our discussions of numerical simulation, i. higher volumes of miscible gas injection afford an opportunity for higher incremental recoveries, but the higher cumulative volumes will require more years of injection. This opportunity will not exist -- exist if we have to wait until the waterflood has been underway for many years before starting EOR. Second, the feedstock necessary for enriching the gas to make it miscible may not be economically available if the project is not implemented until after waterflooding. In our description of the project facilities, we mentioned the fact that our supply of miscible gas was time dependent. As the field offtake rate declines in the 1990, we see a somewhat proportionate drop inthe volume of scrubber liquids and IP compressor gas available. Implementation now will allow us to take advantage of the highest injectant availability. To develop another miscible gas source later in the field life may be prohibitedly expensive. Also, any substantial deferment in the Flow Station Three injection project could render the project uneconomical because of higher risk. Fluid migration, increased gas tonguing and high- -- higher gas saturations are all problems that may become worse in'the later years of the field life, and all 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023719 10 12 14 15 16 17 18 19 2O 21 22 23 24 -45- negatively impact the success -- success of the miscible gas process. Higher operating costs will defintely be a reality as we will be handling larger volumes of reproduced water from the Beaufort Sea waterflood. The remote and harsh Arctic environmen~ itself additionally burdens the implementation of a tertiary recovery process when compared to operations in the Lower 48. Another reason for moving forward with EOR~now is that valuable reservoir and operating knowledge will be gained. A successful WAG project at Flow Station Three will encourage the implementation of projects in other areas of the reservoir. It is necessary to start the project now to provide information early enough so that other projects may be designed and implemented in the unit. Finally, laboratory core experiments and reservoir simulations have indicated that no recovery advantage exists to deferring the start of miscible gas injection. However, initiation of the project at this time Will capitalize on the existing favorable conditions and reduce the higher risk associated with deferral. Deferral could poten- -- potentially preclude the project. The reasons that I have just summarized present a strong technical engineering case for showing that "sound engineering principles" are definitelyl.involved in our decision to implement the Flow Station Three injection project prior to waterflooding. Moreover-- Moreover, we are not alone in this assessment. R & R COURT REPORTERS s l0 N STREET. SUITE 101 509 W. 3RD AVENUE 1007 W. SRD AVENUE 277-0572-277-0573 277-8543 272-7515 AGO ANCHORAGE, ALASKA 99501 1002372O 12 14 15 16 17 18 19 2O 21 22 23 24 -46- Dr. H. K. vanPoollen, a respected industry consultant, presented a paper on tertiary recovery potential for the North Slope at an EOR symposium in Virginia in June of 1979. To quote Dr. vanPoollen, quote, "If we are going to use EOR, we should do it early. Again, the environment will not allow this field to be around for too many years. Things start falling apart. You have repairs. The cost of abandoning the field is going to be horrendous. It should be studied," end quote. We have now shown for this -- how this project meets two of the three requirements Qf subparagraph (A), Namely, the application of a qualified tertiary recovery method and the use of sound engineering principles. The project also satisfied the last requirements of recovering more than in insignificant amount ofincremental crude oil. There is estimated to be 440 million stock tank barrels of original oil in place in the project area. It is estimated that 122 million stock tank barrels or 27.7% of this original oil in place would be recovered if only primary operations were undertaken. An additional 65 million barrels is estimated to be recoverable if an 80 acre pattern waterflood is conducted. The implementation of the Flow Station Three injection project is estimated to recover at least 89 mill stock tank barrels of additional oil over primary recovery and at least 24 million additional barrels over recovery from an 80- acre pattern waterflood. This is equivalent to an increase in ultimate recovery of 20% original oil in place over primary and AGO 10023721 R&RCOURTR£PORTER$ 810 N STREET. SUITE 10!509 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-0572-277-0573 277-8543 Z72-7515 ANCHORAGE. A~A~KA 99501 i )n 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 -47- 5% original oil in place over 80-acre pattern waterflooding. An incremental recovery of 24 million stock tank barrels of oil corresponds to an increase of 12.8% in the recoverable primary and secondary reserves and is more than an insignificant increas~ in the ultimate recovery of crude oil. Therefore, the project clearly meets the third and final requirements of parapgraph (A). Subparagraph (B) of I.R.C. Section 4993(c) (2) requires that the project have a project beginning date after May 1979. The term "project beginning date" is defined in -- in the Windfall Profits Tax statute as the later of the date on which the injection ofliquids, gases or other matter begins, or the date on which the project is certified. Either of these two dates for the Flow Station Three injection project will be after May 1979, because the project has not been -- yet been certified and injection has not yet commenced. Miscible injection is expected to begin in December 1982. Subparagraph (C) of I.R.C. Section 4993(c) (2) requires that the area which will be affected by the project must be adequately delineated. If the tertiary recovery project is expected to increase the ultimate recovery of crude oil from only a portion of the D.O.E. proeprty, that portion is requimed to be treated as a separate property for incremental tertiary oil purposesand the operator must delineate that portion of the property in his certification. The Flow Station Three injection project as currently R & R COURT REPORTERS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1007 W. 3RD AVENUE 277.057Z-277-0573 277-8543 272-7515 A GO ANCHORAGE, ALASKA 99501 10023722 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 planned will affectonly a portion of the Prudhoe Bay Unit, which isone D.O.E. property. As discussed earlier in the hearing, the area which will be affected involves 11 injection patterns and encompasses approximately 3650 acres. The boundaries of the project area have been defined as the outer producing wells of ~ the nine-spot patterns to theeast and tMe west, by the limit of development drilling to the south and by .the seven water injection wells to the north. The project will affect the entir~ light oil column of the portion of the Sadlerochit reservoir which lies within the surface boundaries of the project. The area which will be' affected by this project was delineated in slide four. A reasonable allocation will be applied to production from any peripheral well determined to be producing oil from outside the project area which will be unaffected by the tertiary method. As evidenced by our testimony at this hearing and the application which has been submitted previously, the miscible fluid displacement project which is -- which we plan to implement at Prudhoe Bay in the Flow Station Three area meets all of the requirements for a qualified tertiary recovery project under the Windfall Profits Tax statute. It involves the application in accordance with sound engineering principles of a qualified recovery method, namely miscible fluid displacement, which is reasonably expected to result in the additional recovery of 24 million barrels of oil from the project area. 810 N STReET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-85~3 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 This is AG0 10023723 12 14 16 17 18 19 2O 21 22 23 24 25 49- clearly more than an insignificant amount of crude oil. The project beginning date is after May 1979 and the project has been adequately delineated. Based on the testimony we have presented today andthe information complained -- contained in thc application, we request that the AOGCC in its capacity as a designated jurisdic-i?- jurisdictional agency approve the project as meeting the requirements of subparagraphs (A), (B) and (C) of section 4993(c) (2) of the Internal Revenue Code. This concludes the testimony of the working interest owners. We will be happy at this time to form a panel and answer questions after the break. MR. CHATTERTON: Yes. Gentlemen, thank you very much. As I announced at the start of this hearing, why we'd take a break after the discussion. I hope it will be only about ten minutes approximately, and during that period if there are any people that wish to testify or present oral statements, please make it known at this time. The Commission will have questions of the panel, and we will excuse them until any other testimony or oral statements are given before we ask them questions. And with that we're -- we're all at recess for about ten minutes, please. (Off record) (On record) MR. CHATTERTON: I -- I -- P.~i., we have had no one -- is there anyone that wishes to testify? If so, we'll 810 N STREET, SUITE 101 277-0572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 ,oo7 w. 3.D AVENUE AGO 10023724 272~7515 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 -50- let these gentlemen abandon the hot seat over here. Are there any people that wish to testify? Yes? Oh. Any people who wish to make an oral statement? And as I mentioned earlier, why, written statements can always be handed in at the end of the proceedings and we will certainly honor them and they will become part of the record. With that, why, you people are seated. I know that some of the Commissioners have some questions, and we'll proceed with those questions if you wish. Harry, why don't you-- Lonnie,' . .... MR. KUGLER: Why don't you start with Lonnie? MR. SMITH: I'm not ...... MR. CHATTERTON: .... would ~ou like to start?~ MR. SMITH: ..... I'm not quite ready yead. You all go' ahead. (Indiscernible, simultaneous) MR. KUGLER: Go ahead. MR. CHATTERTON: I ask last. MR. KUGLER: All right. I have a question of Terry Day. MR. CHATTERTON: We'll direct -- excuse me. Ail questions shall be directed to the panel and as a panel of experts. They may chose within themselves as to how they respond, unless you get real sticky about it. Okay? MR. KUGLER: All right. Figure Five of Mr. Day' testimony indicates that production from the WAG process will 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 oo7 w. 3RD AVE.UE A G 0 10 0 2 3 7 2 5 272-75~5 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 - 51- essentially start in about the end of 1987, and you're going to get a 5.7% additional recovery. Other projections of the incremental oil come up say in 1984. Is there -- Could you tell me what in your modelling shows the late beginning of incremental oil recovery? MR. DAY: Yes. The -- the actual production increase from the project area depends on the facility constraint that exist, the artificial lift, low pressure systems, compressic and the actual responses that we would expect to see from the area however would occur by way of lower water cut, somewhat higher GORs in the project area aS Soon as a year and a half to -- to two years after we start injection. MR. KUGLER: But your chart shows no incremental oil until the end of '87 or first of '88, somewhere in there, as near as I can ..... MR. DAY: The -- the chart would indicate no production increase from the area before that time' as I say because that's basically reflecting facility constraints in the area. However, the -- the project should respond to -- we would expect it to respond to the injection within a year and a half to two years'and actually prOduce some say tertiary oil as you-- as you would in the first year and a half to two years, and we should be able to see that by our surveillance project by way of like --~ as I say, lower water cuts and --and higher GORs in the area. 810 N STRE£T, SUITE 101 Z77-O§7Z-Z77-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023726 1007 W. 3RD AVENUE 272-7515 mi 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 - 52- MR. KUGLER: MR. DOUGHTY: Okay. Well, then you used ..... I could add something to that if you ..... MR. KUGLER: ..... did you use different facility constraints than the other people in their modelling? Is that what you're saying? MR. DAY: The -- the constraints we used would be similar to -- to ARCO's .and I'm -- and I might want to leave it to -- to the other two working interest owners to -- to comment on that. MR. DOUGHTY: There's some flexibility in the project as to when we take the -- the fluids off. Our -- you know, the field is limited to a 1.5 million barrel a day off tak~ and we can either take more fluid out of this project area and reduce another area to the 1.5 limit or we can take a higher rate out of this area. And depending upon how the facility constraints are set up in the individual models, they would or would not allow the -- the models to produce that extra fluid. MR. KUGLER: I see. One other question while we're on this. The average gravity of the oil. coming off of the Prudhoe Bay field, is it about 27° now? MR. DOUGHTY: Yes, sir, it is. MR. KUGLER: What will be the gravity of the oil coming off of Flow Station Three injection project say six or seven years down into the ..... ? 810 N STREET. SUITE 101 277-0572-277-0575 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023727 1OO7 W. 3RD AVENUE 272-7515 10 1! 16 17 18 19 2O 21 22 23 24 25 -53- MR. NELSON: We would expect the gravity to be infitesimally lower than 27° to reflect the fact that some of this..miscible gas will probably partition itself in the oil which is produced, although Flow Station Three encompasses a lot more area in the field besides just Flow Station Three injection project, so it will be all blended into the stream leaving Fl, ow Station Three. So any of the lower -- the lower gravity oil produced out of Flow Statian Three will be blended at Flow Station Three and before it goes on, and so what we'll actually see leaving Flow Station Three will only be probably a very, very slight decrease -- or increase. Excuse me, increase. (Indiscernible, simlutaneous conversation). MR. KUGLER: I see. Oh, I wondered. Yeah. MR. NELSON: Increase in gravity. MR. KUGLER: Infitesimally? What is that? One-tenth? Or one- .... MR. NELSON: I wouldn't expect we'd see much more than that. MR. KUGLER: In other words, not much of the natural gas liquids are going to be combined with the production stream in this injection project? MR. NELSON: The amount of natural gas liquids which are being injected are -- are very small in comparison to the amount of oil being produced at Flow Station Three. So the ... MR. KUGLER: Yeah, but I'm just talking about the 810 N STREET. SUITE 101 277-057Z-Z77oO573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023728 10 12 13 15 16 17 18 19 22 24 -54- -- not the whole flow station, but the Flow Station Three injection project. Just the oil coming off of it? MR. NELSON: Yes, there will be some increase in the API gravity of that oil. MR.KUGLER: Well, there's a certain percentage of natural gas liquids being produced in Prudhoe Bay from the entire production. Do you -- we're going to be enriching this area with natural gas liquids. Will there be more natural gas liquids than produced from Flow Station Three later on as this project has a certain age to it, say five or six years, or is there going to be less? MR. NELSON: The -- in the field today, the only -- the only type of light molecular weight liquids being produced are coming out of the FFGU. All the other natural gas liquids which are associated with the gas are re-injected back into the cap. UNIDENTIFIED: Except the oil field gas. MR. NELSON: Right. And from Flow Station Three we're only putting in about, oh, somewhere around 10,000 barrels a day of -- of low molecular weight liquids into the project. That's the liquid part of the gas, ...... MR. KUGLER: Um-hm. MR. NELSON: ...... and so we wouldn't -- when that material is produced back, most of that material will end up in the gas like it is today and go up to our central ,~..,. ~ .. .,t. .~!. AGO 10023729 R & R COURT REPORT£RS 810 N STREET, SUITE 101 509 W. 3RD AVENUE 1 ~7 W. 3RD AVENUE 277-0572-277-0573 277-85~3 272-75~5 ANCHORAGE, AEASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 24 -55- compressor facility and be re-injected back into the cap, a very very small part will probably be diverted off and run through our field fuel gas unit again. But we don't expect to see a significant increase in the amount of natural gas liquid being produced as a result of this project. MR. KUGLER: Okay. Thank you. MR. SMITH: I'm not sure who should field the question here. Bill, perhaps you. How do you arrive at the composition of the injected gas? And was this an optimum composition? Or was it j~.ust due to the basis of the available 1 iquieds ? MR. NELSON: What we -- what we have done is we'vE looked at the pressure levels in the Sadlerochit reservoir and we have done extensive experimental work to more or less fine tune a miscible injectant whiCh will be miscible -- safely miscible at the reservoir pressures that we have in the field. As we said in our testimony, we have designedlthis miscible injectant to be miscible around 3700 psi, which is about 200 psi less than the prevailing reservoir pressure of 3900 psi. And what we have done is run these different experiments in the lab to determine the miscibility pressure of different compositions and found that this is the composition that gave us a significant safety factor under prevailing pressure levels in the field. MR. SMITH: Are the available liquids -- the 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023730 10 1! 12 13 14 15 16 17 18 19 2O 21 22 24 -56- liquids that are available to provide this composition, are there an abundance of them? I mean, extra amount of them in the early life and a shortage of them in the later life of the project? MR. NELSON: I think we -- we showed in our document,'¥we showed in that figure an availability, a projected availability of those liquids as miscible gas for the project, and as that figure showed, yes, in the early years we see a -- I guess you would call relative abundance for this project area. And in -- and as the oil flow rates decrease in the 1990s, of course, there's availability decreases. So that the -- the over~ all availability of miscible gas will decrease with time. MR. SMITH: Okay. Well, then did you explore also adding more liquids, different compositions for the early life when there was more--more enrichment liquids available? MR. NELSON: What we -- what we have tried to do is use the maximum available miscible gas in the early time frame in order to. put as much miscible gas into the reservoir in order to get the recovery benefits of the pore volume injecti( in the early time frames. In other words, if you -- if you look at the miscible gas decreasing over time, you'd probably like to get -- you probably use -- like to use all the available fluid in the near term you can, and not waste it. And so that what we've tried to do is utilize all the miscible gas that we have in the near term and put it into the project. 10023731 R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RD AVENUE 1 ~7 i. 3RD AVENUE 277-0572-277-0573 277-8543 272-7515 ANCHORAGE, ALASKA 99501 ~n 10 11 13 14 15 16 17 18 19 2O 21 23 25 -57- MR. SMITH: Well, do I understand the effect that if you did add a higher percentage of further enrichment of the gas then the trade off then would be to -- a different -- operate at a !.different pressure or can you -- or will you -- if you further enrich the gas, would you also get more recovery at the same pressure? MR.NELSON: Once you've -- I guess once you have a sufficient safety margin between the reservoir pressure and the miscibility pressure of the injectant, you don't gain that much by further enriching it uselessly, and so we would probably find a better use those -- those liquids if we had them, but we really don't. MR. SMITH: And here again, you fellows can decide which one should field the question. What is the residual oil saturation in the laboratory test that were run? MR. DAY: In the tests that Exxon ran, actually conducted those tests in two different ways. We ran one test where we first waterflooded the core to residual, and then displaced miscible gas through that core, and -- and we got on the order of 2%, Slightly less than 2% of pore volume left. There was' a second test where we did not pre-waterflood, and ran a miscible gas through the core, and in that case we got -- we obtained less than 1% pore volume residual oil. It's our feeling that the -- that the significant part of that test was that after a waterflood you can remobilize the 810 N STREET. SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 5og W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AG0 10023732 1 I 10 12 14 15 16 !7 18 19 2O 21 22 23 24 25 -58- -- the oil with miscible gas displacement, and I think secondly that in either case you get a very low residual oil saturation as indicated by those numbers. MR. SMITH: Okay. Well, then this -- since the laboratory work establishes this Very low 2% or less oil saturation following the miscible sweep, and -- and -- and your in- -- work indicated -- of course, the flip side is that it's a 90+% effectiveness where it's in contact. The main problem with the over-all low recovery of the project itself as compared to the theoretical work, is for what reason? I mean, what -- what's the difference in ..... ? DR. WILLIAMS. ON: I'll take that one. The -- the main reason is the fact that we can't get the gas to -- to move into all parts of the reservoir, because of boyancy. It tends to float upwards, by-passing the oil. And secondly, even with mobility control th~oug'h WAGging, there still is a tendancy'~' for the gas to channel~.towards the producer. And the combination of those two is that something like half the reservoir volume in the project area will probably not be substantially accessed by the injected gas. MR. SMITH: So further work or development of sweep efficiency so to speak both vertically and horizontally would greatly increase the -- the recovery of the project? DR. WILLIAMSON: Well, we -- we are -- we are looking at in great detail in fact at the shale description, 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023733 10 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -59- because by taking judicious advantage of the presence of shales, we can keep gas down low. And this is -- this is perhaps one technique that would accomplish the effect you're looking for. MR. SMITH: Okay. I ..... MR. DOUGHTY: Basically when you're pushing oil with gas you're never going to get a real high sweep efficiency. You know, this is --this is really what ~we ~can expect to occur in the reservoir. MR. SMITH: With regard to your statement there, Scott, on the pa- -- there was a statement in the original data submitted on page 20 about-- that shales should help to retard the gravity segretation of the injected fluids. Yet in the exhibits presented, 22 and 23 referred to -- there -- there appears to be minimal continuity of shales between the wells. It showed only a couple of them that had connected shales. Is there a contradiction in the statement and the -- and the projected data there or is it -- could you -- would you care to expand on that? DR. WILLIAMSON: The -- the -- a continuous shale would be one that has in fact no perforations at all between, you see, two wells or even three wells drawn in a line Now, -- now, the -- the greater the -- the distance you're looking at, the less probable it -- it becomes that in fact the shale will be completely unpunctured, will be completely sealing. And so when -- when the statement is made that there 810 N STREET. SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-B543 ANCHORAGE. ALASKA 99501 ,oo7 w. 3Ro AVENUE AGO 10023734 272-7515 10 11 19. 13 14 15 16 17 18 lg 2O 9.1 9.9. 9.3 24 will not be many continuous shales, it's a completely continuous shale over that whole area. But even discontinuous shales you see force the gas to move along and then up and if it hits another shale, it will move out again. So discontinuous shales still benefit us. MR. SMITH: I see. So in any case you're taking advantage of'the shales as they are I mean~in your plan? DR. WILLIAMSON: (No audible answer) MR. SMITH: In your studies, I'm sure that -- I feel like there was probably a relative permeability curve or input data used in your program, and you -- you supplied no data of that sort and I wonder if -- if you have an example of that, or have -- well, verify, did you use relative permeability and capillary pressure curves or input data in~ your programs and to what ex%ent? MR. DOUGHTY: We don't have those data with us today, but we have supplied the Commission in the past with both our raw data and the -- our interpretation of that data that we use in our reservoir models. We've used the same relati% permeability data in these models and we use in our full field models. All our modelling work. MR. SMITH: So this is the same data that you've submitted to,!~us previously, is that what you're saying? MR. DOUGHTY: That's right. MR. SMITH: Okay. Based on it. Okay. Regardin~ ~10 N ~TREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W, 3RD AVENUE 272-7515 AG0 10023735 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -61- the sensitivity studies that were performed, would someone care to address the WAG injection ratios? How they were derived, and for instance it was -- it was pointed out in the text about that you expect operational experience to set this ratio or to -- to fine tune it, and give us an idea of the parameters you'll be looking at or how that -- you expect to accomplish that? MR. NELSON: I think a significant WAG ratio, probably up to at least one is -- is needed for mobility control, for the water to retard the overriding of the gas. WAG ratios above one will probably most likely be used to maintain miscibility conditions within the reservoir. As we said in our testimony, we will probably inject whatever water is necessary t¢ maintain the miscibility pressures in all our patterns, and as we take our pressure build up measurements in the patterns will determine how much water is actually necessary to supplement the miscible gas to maintain pressure levels. MR. SMITH: So the primary function there of the -- of the -- is to maintain that pressure and by the water injection phase then? MR. NELSON: Right. There -- there is a mobilit~ control, but .... MR. SMITH: Yeah. MR. NELSON: .... over a certain WAG ratio it's bas- -- it's basically to.~maintain miscibility conditions in the-- in the project. 810 N ST~EET.~UITE 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023736 1OO7 W. 3RD AVENUE 272-7515 10 11 12 13 15 16 17 18 19 2O 21 22 23 24 25 -62- MR. SMITH: Well, in your Exhibit 15 you indicate that certain producers are producing more than the solution gas/oil ratio, therefore there must be movable gas in some portions of the project rea. How do you expect this gas to go back in solution or do you and-- by just maintaining the pressure? MR. DOUGHTY: I think, yes, we do expect that -- the gas either to goi.into solution or to rapidly be produced from the area if it is mobile. To rapidly produce it in~l.the producing wells in the area. But during the -- in the areas around the injection wells where we are injecting the water and the gas into the project, the pressures will be higher. We will have driven the gas out of those areas so that that gas won't contaminate the -- the miscible injectant. MR. SMITH: Well, Bill, with regards to the surveillance program as you outlined to the Commission on page ten, do -- do you have any objection to submitting the base data and reports of the project progress on a -- on any frequent basis with regards to the reports at least? MR. NELSON: I think most of the -- the raw data itself is already given to the Commission, although we would have no problem with submitting progress reports, much like we do on the waterflood at' perhaps sir month intervals and after the project has been underway for several years perhaps change that to annual reports, but we would make that information available. 810 N STREET. SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023737 1007 W. 3RD AVENUE 272-7515 10 1! 12 13 14 16 17 19 20 21 -63- MR. SMITH: Fine. Just a word here on the operational end of it again, on page 36, it was -- it addressed the balance of the -- maintaining a balance of the injection and production in the -- in each area. How do you accomp- -- do you plan to accomplish this? I mean, as far as the -- the -- nuts and bolts of it? The metering or the -- how do you and keep track on a-- on a nine-spot pattern basis what's going in and what's coming out? MR. NELSON: As part of the Prudhoe automation system, we can allocate back all of the production in the field to a well basis, and so we'll have good records of the amount of water, oil and gas being produced out of all of our p~oject producers as well as the amount of miscible gas and water being injected into our project producers -- or into our project injectors. And we can go thr.ough and analyze these production and injection rates and determine exactly how much fluid is necessary to maintain pressure or to --how to balance -- how best to balance production and injection. Ii;.think the radio-active tracer tests will also give us an idea of where these fluids are running and give us some idea as to whether these fl. Uids are sweeping out in the basic directions that we have anticipated in our simulation models. MR. SMITH: And the allocation itself then, it -- well, it -- whether it be injectant or produc- -- produced fluids is based on well tests and metered .... ? AGO 10023738 R & R COURT REPORTERS 810 N STREET. SUITE 101 ~O9 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-O572-277-O~73 277-8~43 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 2O 21 22 24 -64- MR. NELSON: Right. Each well -- each well is produced into a test separator at least once a month. And it's that'information which is used to allocate the total field production back to the well level. MR. SMITH: Is this test frequency higher than normal for the rest of the field? Compared to the remainder of the field operations? Because of the sensitivity of this project area, is it -- is it the same or higher or ..... ? MR. NELSON: I would say certainly the same and it may be higher if we have resident's time in our test separator to -- to run more tests. MR. SMITH: Well, that's the bulk of my question~ for now, Chat. MR. CHATTERTON: Okay. Harry, do you? MR. KUGLER: No, go a head. MR. CHATTERTON: Gentlemen, I have listed down here, I -- I apologize as some of our questions may sort of overlap with previous questions, but I have about ten questions and I have been handed from the audience eight questions that I think are being answered, will be answered when I finish with my questions, but we will accept these into the record and we'll see if we can't try and get the intent of each of the questions together. First, I will make this statement, that of the eight questions that were handed to us from the audience by a person, 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-85~3 ANCHORAGE, ALASKA 99501 AGO 10023739 1OO7 W. 3RD AVENUE 272-7515 1! 12 13 15 16 17 18 19 20 9.1 29. 23 24 25 -65- why the first question of those eight, number one, question numb( one, I do not believe is germane to these discussions and -- or to our -- our making a determination, so I will not be asking yo~ that question. But we'll try and weave this together if we can. Gentleman, one-- one question I have is rule of thumb what--what is the current daily production on the entire Prudhoe Bay pool of-- of~.intermediates? Hydrocarbons or gas liquids? Do -- do you happen to know the order of magnitude? MR. DAY: 708? MR. NELSON: That's -- that's how -- the miscible gas we could form. (Whispered conversation between Mr. Day and Mr. Nelson) MR. NELSON: It's 30% methane and 15% ....... MR. DAy: (Indiscernible) 10,000 from Pump Static Three and scale that out ..... (Whispered conversatiOn) MR. NELSON: Well, I -- I think 200 maybe (indiscernible) natural gas liquids is probably (indiscernible). For the entire Prudhoe Bay . ..... MR. CHATTERTON: Maybe I can help. Would it approximate about .... MR. DOUGHTY: That's .... MR. CHATTER: ..... Go ahead and answer it, if 810 N STREET. SUITE Z77-O57Z-Z77-O573 you have .... ? R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023740 1007 W. 3RD AVENUE 272-7515 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -66- MR. DOUGHTY: 200,000 barrels of natural gas liquids is probably pretty close. MR. CHATTERTON: Per day? MR. DOUGHTY: Per day, right. MR. CHATTERTON: And of those -- of that 200,000 why a part of those being re-injected with '- with the natural gas? MR. DOUGHTY: I shouldn't call this natural gas liquids. They're -- they're not liquids. They're heavier -- heavier .... MR. NELSON: Seven plus. MR. DOUGHTY: ...... hydrocarbon components ..... MR. CHATTERTON: Heavy -- intermediate ..... MR. DOUGHTY: .... that you're referring to. MR. CHATTERTON: .... hydrocarbons, yes. MR. DOUGHTY: They're -- they are being reinject~ into the gas cap of the reservoir ..... MR. CHATTERTON: Right. MR. DOUGHTY: ..... in the gaseous phase. We have no technique for-- Or no capability of separating those fluids. MR. CHATTERTON: Okay. Maybe a better question that I would have to you then would be what is the -- the '~ recovered on the surface gas liquids from the fuel gas unit and the various scrubbers at the various flow stations? AGO 10023741 R & R COURT REPORTERS 810 N STREET, SUITE $O1 509 W. 3RD AVENUE 1~7 W. 3RD AVENUE 277-O572-277-O573 277-85~3 272-7515 ANCHORAGE, ALASKA 99501 1! 12 13 14 15 16 !7 18 !9 2O 21 22 23 24 25 - 67- MR. NELSON: Today? MR. CHATTERTON: Today. MR. NELSON: We -- yeah, we produce somewhere in the order of about 10,000 barrels a day of ~iquids from a combination of the field fuel gas units, and the scrubber liquids and whatnot that we're taking from Flow Station Three. However, only a very small fraction of these liquids could actually be stabilized and put~.into the crude oil pipeline. I think today we're using about 10% of those liquids as actuallY what can be put in the pipeline. MR.KUGLER: Chat, I'd like to interrupt. MR. CHATTERTON: Yeah. MR. KUGLER: We need to ..... MR. CHATTERTON: He wants to break right now. MR. KUGLER: We need to address this ...... MR. CHATTERTON: Okay. Okay. We'll take a break right now. (Off record) (On record) MR. CHATTERTON: Thank you for your indulgence on the most immediate recess that we had. I think it's only fair to tell you what the reason for it was is that our office got a call that there was an oil spill on the Slope at gathering center number one, one fatality, five people injured, and bomb threats at gathering station -- another gathering ~10 N STRE£T. SUITE 101 ~77~057Z-~77-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023742 1! 12 13 14 15 16 17 !8 19 2O 21 22 23 24 25 -68- station. And we have now confirmed that this was a test. I'm very happy to confirm that was a test. So I apologize for the interruption, but we did not know it was a test until we just reconvened. We'll continue with the questioning. I guess -- I guess where I -- if I think I remember where we left off, I -- I told Bill that I did not think one of his questions was applicable, so we won't answer it, and I'll see -- many of his other questions are a bit -- or very similar to ones I was going to ask you, and we'll continue from where we were asking you, and maybe -- I guess what I'm -- I'm looking for in where I left off With your questioning, is -- is a feel of the field -- field-- get -- to get a feel for from the Prudhoe Bay p~ol currently produCing in your current facilities roughly what the total liquid recovered condensate, whatever term you wish, intermediate hydro hydrocarbons are. And, of course, my next question that's going to follow, so you know where I'm coming from, is then the percentage of the intermediates from the three gas streams, how much -- what percentage of the total volue that you're going to use for this project is coming from the field fuel gas unit, from your residule gas scrubber and from your intermediate gas scrubber? Trying to get down to just in barrels so we don't have to all play standard pressure-- temperature and pressure conditions, what are we talking about? MR. NELSON: I can answer. In the project 810 N STREET. SUITE IO1 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023743 l0 ll 12 14 15 16 17 18 19 2O 21 22 23 24 25 - 69- itself, our planning studies have indicated that about 5800 barrels a day of light molecular weight hydrocarbons will come out of the FFGU, or the field Togiach (ph) unit, that about 10,000 barrels a day are required for the entire project itself, so the difference of that is about 4800 barrels --- or 4200 barrels a day, and that comes from Flow Station Three, that comes -- comes from a combination of those three fluid streams, and I can't really break it down because of the fact that depending upon the operations in the flow station, whether you'r~ in high pressure mode, low pressure mode, the various streams within the flow station change over time. Although basically they're pretty well evenly split between the residue -- the high pressure residue gas scrubber liquids, the IP residue gas, or IP scrubber liquids, those two streams more or less form to make those other 4200 barrels. MR. CHATTERTON: Okay. Now, are there more--wif~ your present facilities are there more of these light hydrocarbor available from the field fuel gas unit than the 5800 barrels? MR. NELSON: Currently no.. MR. CHATTERTON: Currently not. That is -- that is about it. Okay. That answers my -- that question. Let me ask you this, are there any other sources for these intermediate light hydrocarbons on the Slope today of any substantial quantity? MR. DOUGHTY: On the Slope? I think we're all 810 N STREET, SUITE 277-0572-277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023744 10 11 12 13 14 15 16 17 18 19 2O 21 24 9.5 -70- sort of experts in Prudhoe Bay field. I don't think we could answer what's available ..... MR. CHATTERTON: I appreciate that. The only .. MR. DOUGHTY: .... on the Slope. MR. CHATTERTON: ...... producing field is Kuparek, of course, and we -- we know that. ~ ~ ~i.. MR. DOUGHTY: Yeah. MR. CHATTERTON: There's not -- you -- well, ... MR. DOUGHTY: I -- I don't think any of us could comfortably answer whether or how much is available from other fields on the Slope or. .... MR. CHATTERTON: Okay.. Suffice to say probably not very muCh. That -- you have already answered my other question, but you couldn't do it if you wanted to, another question, but in any of your simulation runs,~ did you run any cases Where you injected the miscible fluid at twice the rate? Now you're planning to inject it at 40 million cubic feet a day, did you run any tests injecting it at a rate of 80 million cubic feet a day or something like that? MR. DOUGHTY: I -- I think not in the project area, 'cause we don't have 80 million cubic feet a day. ~i MR. CHATTERTON: I appreciate that. Okay. MR. DOUGHTY: I -- I would doubt if we ever would have run that. DR. WILLIAMSON: Could I add a point here? STREET. SUITE 101 Z77-O57Z-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023745 10 15 16 17 18 19 20 21 22 23 24 9.5 -71- MR. CHATTERTON: Yes. DR. WILLIAMSON: We do -- we do plan to conSider the effect of rate in different patterns within the project area. Not all injectors will be run at the same injection rate. MR. CHATTERTON: Understood. But you did not run any model studies that would tell you if -- if unltimate recovery or the additional increase in recovery was a function of the rate of injecting the miscible fluids, is that correct? DR. WILLIAMSON: at that question. MR. CHATTERTON: MR. DOUGHTY: Sohio has not looked in detail Okay. Thank you. I think just further on that same subject, the -- one of the objectives of operating Flow Three will be to -- to take a look at each one of the patterns and the average rates and determine whether -- what effects ther( are and --and how the total project does operate with regard to rate, WAG ratios, of those natures. MR. CHATTERTON: In other words you could take even a subsection of -- of the project area and -- and get a high rate of injection in the sub- -- subsection of it? MR. DOUGHTY: Um-hm. That's correct. MR. CHATTERTON: Okay. MR. DOUGHTY: We have -- on your second -- we answered your first question, which was we haven't looked at a higher rate than ..... 810 N STREET. SUITE Z77-O57Z-Z77-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023746 -72- ! MR. CHATTERTON: Right. 2 MR. DOUGHTY: ...... 40 million a day in the 3 total project, but we have run model cases looking at higher 4 rates in -- on an individual well basis and we're trying to 5 analyze what the -- the benefit of rate would be. 6 MR. CHATTERTON: Okay. You don't have that -- a 7 determination on that as yet? 8 MR. DOGHTY: No, we're not comfortable With what 9 the result will be to ..... 10 MR. CHATTERTON: Okay. These gas liquids that 11 are these intermediate hydrocarbons that are being injected in 12 this project area, are they forever lost or will they ultimately 13 be -- ultimately be reproduced? 14 MR. DOUGHTY: The ~ast majority of them will 15 ultimately be available later for other uses. 16 MR. CHATTERTON: Okay. One of the things that 17 we have to make a determination on, of course, as you readily pointed out is if --is this a miscible gas injection -- a miscibl 19 fluid injection, excuse me. Do you have anything other than your laboratory work and so forth and so on to assure us that it is an -- that it's a miscible fluid that you're injecting? Or it will become miscible? MR. DOUGHTY: I think the core displacement tests 24 and the low residuals we observed in those tests indicate that it is a miscible displacement. Otherwise we wouldn't have had that COURT REPORTERS ~og w. 3.D^v£.u£ ,007 w. 3.D^v£.u£ z77-ss~3 zT~-Ts,s AGO 10023747 10 ll 12 13 14 15 16 17 18 19 20 21 22 23 25 -73- low residual saturation. MR. CHATTERTON: By any remote chance have you run a simulation -- simulated study of a condition where you developed on a 40-acre spacing and then employ conventional waterflood versus as yQu are proposing here an 80-acre spacing pattern with a WAG injection project? MR. DOUGHTY: We don't have any results of waterflooding on a 40-acre spacing. And I might also add that we don't think that that would be economic to do in the fields. MR. DAY: No, we have no run such a case. MR. CHATTERTON: Okay. Thank you. I think Lonnie touched pretty well on that, and it becomes a matter of sweep efficiency, which is a problem in mechanics of fluid flow as much as anything else. But you do indicate that even with this process why there will be 50% of the original oil left in place, because of the efficiency or lack of efficiency of being able to contact the oil. You indicated you even get 95% plus if we contact the oil. Now, if you proceed with this Flow Static Three project that you propose, does it exclude the possibilities -- does it damage anything to the point that if research and development brings along methods that you can try and get that additional 50% or part of that additional 50% in your reservoir, if -- if there are such things on the horizon, or if they'are ever developed, why will they -- we -- we have -- have we changed things so much that they could not be applied? R & R COURT R£PORTER5 810 N STREET. SUITE 101 509 W. 3RDAVENUE 1OO7 W. 3RD AVENUE 277-0572-277-0573 277-8543 272-7515 AGO ANCHORAGE. ALASKA 9950' 10023748 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 -74- MR. DOUGHTY: Terry? MR. DAY: I don't'think so. DR.WILLIAMSON: I think a miscible gas is a very natural kind of process. We're not introducing foreign substanc( into the reservoir. So while it's hard to conceive of all future enhanced recovery processes that might be dreamt up, it seems like we are minimizing the --the -- the action we're producing in the reservoir. MR. CHATTERTON: In other words, you're say- -- if I hear you correctly, you're saying that we're working with nature, that nature originally put oil, gas and water in the reservoir, and we're still onlly playing with oil, gas and water and therefore we're not -- we're not trying to fool Mother Nature as yet? MR. DOUGHTY: Right. DR. WILLIAMSON: I think I said that. (indiscernible) phrasing. MR. CHATTERTON: I have real- -- one quick ques%~on. As I remember some material you sub- -- you submitted to us in the end of August, why, you were pretty sure that you would have two observation wells~ and in your testimony today unless I missed it, why, I only heard you say one that you're going to have one, which -- which is -- what's your plan? MR. DOUGHTY: We will definitely have one. We don't have a firm decision on the second observation well right R & R COURT REPORTERS 810 N STREET. SUITE 101 509 W. 3RO AVENUE 1007 W. 3RO AVENUE 277-0572-277-0573 277-8543 272-7515 AGO ANCHORAGE, ALASKA 99501 10023749 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 -75- now. MR. CHATTERTON: Okay. I think this is more -- this is certainly more of a --well, this is obviously a statement rather than a question, gentleman, but I think it's a statement that we should have in the record. As you've testified to, our responsibility as far as your application for this process to -- project to qualify for the Windfall Profits Tax, why, one of the findings is that-- that we have to make to be sure that it qualifies is that more than an insignificant amount of oil will be produced. Now, if we do find in favor of this, why, it will be on that basis that we say that there will be more than an insignificant amount produced, but in no -- no way that -- are we necessarily endorsing your figure of 5.5% which you collective arrived at. I'm not sure. Maybe this has been answered and I wasn't paying attention. On -- on -- I'll go to the application you submitted the end of August of '82, and on page 42 of that application, and this is incidently part of -- made part of the record, you set forth the percentage of ultimate recovery broken down for natural depletion, you read -- you set forth, ~for this project area 27.7%. I'll repeat the numbers, for pattern waterflood on 80-acre spacing, 42.2% recovery of original oil in place and with this WAG process, 47.7%. On page five of that same document -- I don't find it on page five. 810 N STREET. SUITE 101 277-O57Z-Z77-O573 R & R COURT REPORTERS 509 H. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023750 ly 10 13 14 16 17 18 lg 2O 9.1 24 25 -76- MR. KUGLER: Perhaps it ...... MR. CHATTERTON: Huh? MR. KUGLER: Perhaps a slide? Does that answer? MR. CHATTERTON: No, but you -- you also -- some pla- -- and I'm sorry and I can't repeat the number, but -- okay. Here it is. This -- you're speaking here sort of a field wide of the pool in its entirety, and you say you only recover an additional four to 7% of the original oil in place by waterflooding, Now, why the vast difference? Because for the project area you say waterflood is going to recover almost 15% for the pool wide area. I know this has been answered, but I'd like it answered for the record? MR. DOUGHTY: Waterflooding can only be applied effectively to a limited area of the field. And the areas that we do apply it to will receive more than the --~'~the four to 7% benefit which is an average over the whole field. In areas where the oil column is exposed to the gas cap, we can't go in and effectively waterflood it. I would -- I would guess that somewhere on the order of a third of the reservoir will be ultimately waterflooded. MR. CHATTERTON: Is your project going to be materially affected if the State of Alaska decides to take it's one-eighth royalty share of the produced intermediate hydro- -- hydrocarbons? MR. DOUGHTY: It would still be viable. 810 N STREET.~UITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023751 10 11 13 15 16 17 18 19 2O 21 22 23 24 25 -77- MR. DAY: Yeah. MR. DOUGHTY: It would -- it would still be a viable project without that one-eighth. MR. CHATTERTON: But you -- it would lengthen out the time period for you to get the 10% of the pore volume that's displaced, is that correct? MR. DOUGHTY: Yes. MR. CHATTERTON: Let me refer to the questions and carefully from the audience and -- and see ...... MR. SMITH: Chat, I have a couple more questions if you'll allow me to go first? MR. CHATTERTON: All right. Lonnie, if 'you would like to proceed, why, we'll take a look at these. MR. SMITH: As Chat brought up in these questions about the availability of -- of liquids used for the in- -- to make the injectant needed, I would like to ask a question along that line. Should this project as planned become highly successful and it's desirable to apply this and applicable to apply it to.~Other portions of this -- this reservoir, it -- what my understanding is, is that you probably won't be able to do it because there wouldn't be sufficient liquids for injectant Is there a possibility of gaining liquids for injectants in othe~ ways? He mentioned other reservoirs, you obviously hadn't explored that. Have you explored taking'-- creating these liquids from either the gas or the oil stream through catalytic 810 N STREET. SUITE 101 277-0572 - 277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023752 1OO7 W. 3RD AVENUE 272-7515 10 1! 13 !4 15 16 17 18 19 2O 21 22 25 -78- processes or something of that sort? Have you looked at any alternative like this? MR. DOUGHTY: There are a number of alternatives to obtain some of the liquids from the field. I -- we're still in a very conceptual phase, looking at any of those alternatives, and don't have a. ny~definite plans to -- to do anything like that. MR. SMITH: Okay. But juSt because you have a limited amount of liquids scheduled now in the flow stream doesn necessarily preclude further application of this process to this reservoir. Would you ....~.~. MR. DOUGHTY: MR. SMITH: MR. DOUGHTY: MR. SMITH: That's right. ..... agree with that? That's right. Oh, yes. Another question is you make -- would y'ou make some estimate of how much of this reservo~ that this type of process might be applicable to? MR. DOUGHTY: If we had an unlimited supply of miscible fluids, we could apply it basically to the same areas we can waterflood. The --the main waterflood areas, ..... MR. SMITH: So it's ..... MR. DOUGHTY: ..... so a third of the reservoir. MR. SMITH: A third. MR. DAY: Yeah. I think I would like to add to that, that it's fairly early in this process and I think 810 N STREET, SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1OO7 W. 3RD AVENUE 272-7515 AGO 10023753 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 -79- there's a ~- a lot of considerations that need to be determined, a number of parameters that to be determined yet before we know for sure whether this process has other expansion possibilities and-- and we're, like I say, early in that process at this point in ~ime. MR. SMITH: Okay. That's all the directi.questior I have right now. Chat, let me ask you, are you going to address (Indiscernible, whispered conversation between Mr. Smith and Mr. Chatterton). MR. CHATTERTON: Gentlemen, I think these are the questions that are being directed to you by Bill VanDyke of the Department of Natural Resources. I think that we have answered them, but just to make doubly sure, let me -- I think the answers that have been presented may be not specifically the way this question is, but we'll go ahead. And these are quickies. Is the process sensitive to the initial gas saturation in the reservoir? initial gas .... MR. DOUGHTY: In -~ in the project area? MR. CHATTERTON: In the project area, yes. MR. DOUGHTY: Yes, it is. It ...... MR. CHATTERTON: You -- you have a critical MR. DOUGHTY: That's ..... MR. CHATTERTON: ..... saturation of three to 4% or something that's ..... 810 N STREET. SUITE 10! 277-0572-Z77-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023754 1007 W. 3RD AVENUE 272-7515 12 13 14 15 16 18 !9 2O 21 23 24 25 -80- MR. DOUGHTY: Right. As --as we mentioned before, the -- one of the reasons we applied the project to this area of the field was because of the low initial gas saturations. MR. CHATTERTON: All right. Is the process sensitive to the WAG ratio? I presume that means the -- the ratio of how long you produce water -- or inject water into a WAG well compared to how long you inject liquids into the same well. MR. DOUGHTY: We ~hink it's fairly insensitive within certain limits. MR. CHATTERTON: Insensitive? MR. DOUGHTY: Yes. We .... MR. CHATTERTON: Okay. MR. DOUGHTY: ..... don't know what the limits of the effective range are though. MR. CHATTERTON: This I guess is a question we all want to know, and we can back into it. In the project area, what percentage ofthe hydrocarbon pore volume is likely to be contacted by the miscible fluid? MR. DAY: I think Scott's ..... DR. WILLIAMSON: 50%. MR. DAY: ..... Scott's about 50%. DR. WILLIAMSON: Well, perhaps in the neighborho¢ of 50%. 810 N STREET. SUITE 277-0572 - 277-0573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 AGO 10023755 1007 W. 3RD AVENUE 272-7515 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 -81- MR. CHATTERTON: DR. WILLIAMSON: MR. CHATTERTON: 50%? Something like that. Okay. Thank you. I think the next question that I~,have here has been fairly well answered. It's -- it's asking have --~.have your simulation runs been performed that show where the injected fluids actually will go in the reservoir. I think you've-- that is, showi'.the isopotential orthe streamlines of them. I presume they'll follow the path of least resistance and --and -- and. the maximum pressure gradients, right? MR. NELSON- MR. DOUGHTY: Urn-bm. Um-hm. already. that one. MR. CHATTERTON: I think that'one's been answered I think'that one has been also. And we've answered And we've answered that one I believe. Okay. Gentlemen, before I excuse you, I would like to ask our consultant, Dr. vanPoollen to make a statement regarding -- you.may sit where you are -- regarding his -- his observations to this point in time and -- and -- in the matters before the Commission, and I -- and I'm asking that here in the public arena so that it can be made Part of the public record. Dr. vanPoollen? DR. VANPOOLLEN: Well, thank you. I'd first of all like to complement the operators on the thorough evaluation of the projedt prior to going into it. And I'm awfully glad to 810 N STREET, SUITE 101 277-0572-277-0573 R & R COURT REPORTERS ~09 W. 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99~O1 1OO7 W. 3RD AVENUE 272-7515 AGO 10023756 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 -82- see that we are finally getting started on an EOR, quote/unquote project. I was quoted on some comments I made three years ago before the Department.of Energy relative to the enhanced oil recovery in Prudhoe Bay, and some of my remarks were quoted and I'm happy about that. At the same time my remarks were related to trying to get EOR going for more than 5% of a very small part of the field. My remarks in there indicated that we should do things relatively soon, because things might fall apart as I indicated, which says that if we are trying to do something with the existing facilities, roads, et cetera, et cetera, and wells that we should get something going earlier and even now I'd s like to re-emphasize the fact that we should do more than just trying to get 5-1/2% out of a small part of the field which we may not be able to apply to the whole field. We still have 1.9 or so million barrels of heavy oil and tar and even with this excellent effort that's being made, we're leaving 50% in the ground. So this is what I want to merely state and my complement to %he operators. Thank you. MR. CHATTERTON: Thank you. Commissioners, any other comments? MR. KUGLER: No. MR. CHATTERTON: Any oral statements from the audience or any further written questions? Gentlemen, I want to thank you very much and I want to thank your management for 810 N STREET. SUITE 101 277-0572-277-0573 R & R COURT REPORTERS 509 W, 3RD AVENUE 277-8543 ANCHORAGE, ALASKA 99501 1007 W. 3RD AVENUE 272-7515 AGO 10023757 10 11 12 13 14 15 16 17 18 19 2O 21 22 24 -83- undertaking an operation like this. I would echo what Dr. vanPoollen has just said. We hope you'll keep the RNB (ph) up. We hope you even think of hO.w you're going to improve the sweep efficiency. Quite a bit of work. B'ut thank you very much. For'the record, we -- we will close the record unless there's any request to have it left open. We will close the record on t~is hearing at the -- at the adjournment of this hearing. And lacking any -- any -- any request to keep the record open, it shall be closed. The Commission will issue its order on your -- on your applications hopefully within the early part of the forthcoming week. We did not want to take'the time this morning to -- you testified tha~you were going to monitor this process. That we appreciate. We did not want to take the time this morning to question you in detail as to that monitoring program, but we may have some suggestions to you as to how -- of the things that we the Commission feel that we would need that would not be burden- some to you, but we would need for us to also keep a finger in this. So that may be -- those things may be part of the order. If nothing else, why we sit and about to rise and stand adjourned. (END OF PROCEEDINGS) 810 N STREET. SUITE 101 Z77-O57Z-Z77~OS73 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 AGO 10023758 1007 W. 3RD AVENUE 272-75~5 10 11 12 13 14 15 16 17 18 19 20 9.1 22 23 24 25 -84- CERTIFICATE 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, do hereby certify: That the annexed and foregoing Transcript of Public Hearing was taken beforeme on the 19th day of November, 1982, beginning at the hour of 9:00 A.M. at the Quadrant Room, Hotel Captain Cook, Anchorage, Alaska. That the witnesses before testifying 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 hearing, taken by me electronically and thereafter transcribed by me; That the original has been retained by me for the purpose of filing the same with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska. I am not a relative or employee or attorney or counsel of any of the parties, nor am I financially intereested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 24th day of November, 1982. ~6t~r~ ~bli~ ~n and for ~laska My Commission Expires: 5/3/86 810 N STREET, SUITE 101 277-O572-277-O573 R & R COURT REPORTERS 509 W. 3RD AVENUE 277-8543 ANCHORAGE. ALASKA 99501 AGO 10023759 1007 W. 3RD AVENUE 272-7515 NOTICE OF PUBLIC HEARING STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO ALASKA, INC., on behalf of the Prudhoe Bay Unit Working Interest Owners, for (1) additional recovery by miscible enriched hydrocarbon gas injection and (2) approval as a qualified tertiary recovery project for purposes of the Crude Oil Windfall Profit Tax Act of 1980. Notice is hereby given that ARCO ALASKA, INC. has requested the Alaska Oil and Gas Conservation Commission, by letter dated August 31, 1982, to hold a public hearing to provide the Prudhoe Bay Unit Owners an opportunity to enter testimony into the public record, and answer questions concerning the Flow Station 3 Injec- tion Project. This project involves the alternating injection of water and miscible enriched natural gas (WAG) into a portion of the Sadlerochit Reservoir in the Prudhoe Bay Field. The appli- cant requests approval of (1) the Flow Station 3 Injection Project as required by Section 20 AAC 25.400 and (2) approval as a qualified tertiary recovery project according to paragraphs (A), (B) and (C) of IRC Section 4993(c)(2), The hearing will be held at 9:00 AM on Friday, November 19, 1982 in the Quadrant Room, Captain Cook Hotel, Anchorage, Alaska. All interested persons and parties are invited to give testimony. Harry W. Kugler C ommi s s ione r Alaska Oil and Gas Conservation Commission AGO 100B1825 PRUDHOE,BAY UNIT FLOW STATION 3 INDECTION ,PRO3ECT HEARING TESTIMONY November 19., 1982 Introduction Mr. Chairman, members of the Commission, ladies and gentlemen. My name is Da~e Marquez and I'm an attorney with ARCO Alaska, Inc., one of the operators in the Prudhoe Bay Field. · The Working Interest Owners of the Prudhoe Bay Field have requested this public' hearing this morning before the Alaska 0il and G.a.S Conservation CommiSsion for two purposes. First, We are requesting that the Commission approve our Application for Additional Recovery by MiS'Cible Enriched Hydrocarbon Gas · Injection. This Application has been filed 'previously in accordance with · Article 5, Section 400, of the AOGCC Regulations. Secondly, we are requesting that the Commission, in its capacity as a designated' jurisdictional agency within the meaning of the Crude 0il Windfall Profit T'ax Act Of 1980, approve the Flow Station.3 Injection Project as meeting the requirements of 'Subpara- graphs (A), (B), and (C) of the Internal Revenue Code, Section 4993(c)(2). .As the Commission may recall, ARCO, on behalf of the Working Interest Owners, submitted documents supporting both the Application for Additional Recovery and the Certificafion Application on August 31, '1982. We request that these documents be entered as part of the public record. Four representatives of the Working Interest Owners will present testimony today. Our testimony will focus on those items required by the AOGCC Regu- lations, and on how the Flow Station 3 Injection Project meets the requirements of the Windfall Profit Tax Act as a bona fide tertiary recovery project. Because· of the documents that were submitted previously, our presentation will be fairly brief~ I believe it will last approximately 1 to 1 1/2 hours. Our intent is to emphasize those points which we feel are the most' important and to provide a forum from which the Commission can ask questions on Project specifics. .I'n our testimony today, the Working Interest Owners will show that the Flow Station 3 Injection Project meets the following three requirements as stated in the Windfall Profit Tax Actl first, that the Project involves the application of a qualified tertiary recovery method in accordance with sound engineering principles that will result in more than an insignificant amount of incremental crude oil~ second, that the Project beginning date is after May, 19791 and third', th'~t the Project area is adequately delineated. To do this, we have divided our testimony into three parts as shown in Slide 1. ARCO, as Operator of the Project, will be presenting the majority.of the testimony. The first part of ou~ testimony will briefly discuss the overall Project and will include a summary of Project objectives, Project delineation, Project design, required facilities, implementation plans, and surveillance plans. This part of the testimony will not only support our cert'ification request, it will also discuss the significant information required by Section 20AAC25.400 of the AOGCC Regulations regarding an Application for Addi'tional Recovery. The second part of our testimony will involve a discussion by each of the major Working Interest Owners of their numerical, simulation studies that have indicated that significant incremental oil recovery Will result from implementation of the miscible gas process. Finally, the last part of our testimony will tie together the presentation and focus specifically on how 'the Project meets each of the Internal Revenue Code requirements. I would, at this time, like to introduce the four witnesses that will be pre- senting today. They are Mr Bill Nelson, Mr. Terry Day, Dr. Scott ~Villiamson, and Mr. Roger Doughty. At the end of our presentation this morning, the witnesses would like to form a panel from-which to answer the Commission's . questions. This panel could also answer at that time any questions you might have concerning the Application for Additio.nal Recovery. I would like to ask at this time if the witnesses could all come forward, in a group and be sworn in; and I would also like to ask that they be " accepted as experts. We have , · prefiled our testimony and each of the witnesses has included in that test- imony a short statement of his qualifications. I Testimony Outline . Project Overview - Supporting Reservoir Simulatiori Results · ARCO Alaska, InCo · Exxon Corporation · Sohio Alaska Petroleum Company - Windfall Profit Tax Law Requirements Discussion of Overall Project Members of the Alaska Oil and alas Conservation Commission, ladles and gentle- men; my name is Bill Nelson. Since receiving my graduate degree in engineering from Purdue University in 1975, I have been. empl-oyed by' ARCO. I have spent ove~ seven .years working various aspects of arctic and reservoir engineering. I became involved with the Prudhoe Bay development plans and reservoir engi- neering studies in 1979, and I presently hold the title of Senior Area Engineer for Prudhoe Bay EOR. This morning I'd like to briefly summarize the engineering aspec%s of the Fl°w · Station 3 Injection Project. I'd first like to discuss the reasons why the Working Interest Owners have decided to pursue miscible gas as a viable process for Prudhoe Bay at this time. I'd then like to discuss the design of our project' and facilities required, and follow that with a brief overview of our implementation plans and surveillance program. The Flow Station 3 Injection Project is ~ small scaie miscible enriched hydro- carbon gas project. As you can see in Slide 2, the Project is located within the Prudhoe Bay Unit in the western downstructdre area of the ARCO operated portion of the Field. Our planned execution of primary and secondary 'operations at Prudhoe Bay is projected to yield an estimated ultimate reco'very of approximately nine billion barrels of oil, leaving more than 10 billion barrels of oil trapped in the Sadlerochit reservoir. With such a large volume of oil at stake, the Working Interest Owners recognized the potential of increasing recovery through the application of tertiary r~.covery methods, and the need to evaluate this poten- tial as quickly as possible so as to ensure proper development. Screenin.o studies were conducted to better define the applicability of the leading enhanced recovery methods at Prudhoe Bay. The studies fell into four cate- gories: 1) miscible gas displacement processes, 2) surfactant flooding, 3) enhanced waterflood technioues, and 4) thermal processes. I'd like to now summarize the results of these studies. The miscible gas processes were found to be the most viable for the Sadlerochit reservoir at this time. The miscible gas process has been technically proven and has been used in the petroleum industry for several years. Although surfactant flooding may have some potential in the long term, our studies did not find a surfactant currently available that could withstand the wide range of temperatures and salinities that are expected t'o be present in the reservoir. Enhanced waterflood techniques, such as caustic or polymer flooding, were found to possess some limited potential in improving our waterflood performance. However, the techniques are not cost effective because of problems associated with the logistics of supplying large quantities of chemicals to this remote Ar.ctic location° Finally, thermal processes were eliminated since the depth, and pressures of the Sadlerochit formation make these processes economically infeasible. Of the various types of'miscible gas processes, miscible enriched hydrocarbon gas injection was chosen at this time because the required injectant properties can be formed using presently available Prudhoe Bay Field processing streams. The miscible gas will be injected sequentially with water in a manner referred t° as WAG injection or Water-Alternating-Gas injection. This' injection is expected to continue for at least 10 years or until more than a 10% PV slug of miscible gas has been injected. We expect the EOR Project to start-up by the end of 1982, and we expect the Project to recover at least an incremental 24 MMSTB of crude oil. In mo¥ing forward, the Working Interest Owners see this Project as accomplish- lng the three main objectives Iisted in Slide.3.- First, the Project will add t~'the recoverable reserves of the Field~. secondly, the Project wiI1 allow us to test the effectiveness of a miscible gas. process at Prudhoe~ and finally, the Project will provide us with design and operating .information that could be used in possible future ~pplications. ., Up to this point, I've presented a brief overview of .why we"re pursuing a miscible gas project at Prudhoe. I'd now like to describe this Project in a little more detail. As can be seen in Slide 4, the Flow Station 3 Injection Project is located in ail or parts of Drill Sites 1, 6, 12, 13 and 14 in the Eastern Operating Area. Specifically, the area chosen encompasses all or portions of Sections 10, 11, 12, 13, 14, 15, 16, 22, 23 and 24 in Town- ship 1ON, Range 14E, and Sections 18 and 19 in Township 1ON, Range 15E. The Project encompasses approximately 3650-acres and ~ontains approximately 1.02 billion barrels of pore volume. The original oil in place is estimated to be 440 MMSTB. This particular area of the Pru'dhoe Bay Field was chosen for three reasons. First, the area possesses a relatively Iow free gas satur- ation. This means that contamination or dilution of the injeetant will be minimized in this downstructure area. Secondly, the Project area possesses a relatively high reservoir pressure. Currehtly, the average pressure in the Project area exceeds 3900 psi. The high formation pressure makes it easier to maintain miscibility, conditions for the injectant and reduces the amount of' water injection required prior to start-up. Finally, the area has access to sufficient volumes of water and miscible inject, ant. Flow Station 3, the gas-oil-water separatioh facility for this general area of the Field, is located nearby and acts as the centralized point for processing the miscible gas and produced water needed for injection. In fact, the name of the tertiary project is taken from the importance attached to Flow Station 3. As can also be seen in Slide 4, the Project boundaries have been delineated · areally by the upstructure water injectors on the north, by the outermost producing wells in the patterns on the east and west, and by the down dip development limit in the south. The vertical delineation is shown in Slide 5. Vertically, the Project encompasses the light oil column of the Sadlerochit~ that is, the interval from the top of the Sadlerochit formation to the top of the heavY'oil/tar zone. The heavy oil/tar zone will not be affected by the miscible gas injection. The basic' geology of the area is also shown in Slide 5. The Sadleroehit formation is commonly divided into five main zones. In order of increasing depth, these zones are referred to as the Zulu, X-Ray, Victor, Tango, and Romeo. Within the Project boundaries; only the Zulu/X-Ray and part of the Victor will be affected.. The Zulu/X-Ray zones are composed of fine to medium grained sandstones with many interbedded, mostly discontinuous, shales. The Victor, on the other hand, is composed of a conglomerate section in the .upper half grading to a coarse grained sandstone in the lower half. A shale, separ- ating the X-Ray and Victor zones, is found in a lar.qe portion of the Project area, as are several faults. No original gas cap is present within the Project area, but some localized free Solution gas may be present near 'the existing produeers. By' year end, the average reservoir pressure in the area should be approximately 3900 psia. At 4 this pressure, the gas saturation will be at or near the critical .oas satur- ation of around 3 to 4%, but this. volume of gas will not have a significant £mpact on Project performance. A substantial water interval underlays the entire Project area. Directly over- 'lyi'ng the aquifer is a heavy oil/tar zone consisting of highly viscous crude which ranges from 20 to 60 feet in thickness. As I mentioned earlier, due to · . the low mobility of this heavy oil/tar zone,· injeet~ivity into this zone is expected to be very low and-the WAG injectors will not be perforated in this portion of the oil column. The next slide, Slide 6, begins .to address the reservoir engineering aspects of the Flow Station 3 Injection Project. ~Vithin this 3650 acre Project are 11 WAC injectors, 7 upstructure water injectors and 42 producers. On the slide, the WAC injectors are represented by triangles, the water injectors by squares, and the producers by circles. The injection pattern chosen for the Project is an inverted nine spot pattern developed on 80 acre well spacing. Thus, each pattern, itself, encompasses 320 acres.- The inver{ed nine spot was.selected primarily for its flexibility in conversion to other pattern configurations and for its initial. 3 to 1 producer to injector ratio. Since the well injectivity is expected to be higher than the well productivity, the 3 to 1 ratio should allow more versatility in balancing pattern withdrawals and injection. It is anticipated that about 40-45 MMSCF of enriched hydrocarbon miscible 'gas will be injected into the Project on a 'daily basis Usin~q the WAG injectors. This is equivalent to an injection rate of 27-30 MRVB/D at the temperatures and pres- sures expected to be present within the 'Project area. Injection 'will.continue until at least a 10% PV slug of miscible gas has been injected. As I mentioned earlier, the Flow Station 3 Injection Project requires the injection of water as well as miscible gas. Produced water will be alternately injected with the enriched gas into the WAG injectors to provide pressure maintenance and to reduce the "channeling" tendency of the lower viscosity gas. In the literature, this benefit is referred to as mobility-control. Water will also be injected into the 7 upstructure water injectors to help maintain miscibility pressure, to help confine the miscible gas to the Project area, and to help shut off gas cap gas that,might otherwise enter the Project area. Approximately 90 MBWPD is estimated to be required in the WAG wells and 100 MBWPD may be required in the upstructure water injectors when the Project has' been underway for several years. To provide the water and miscible gas to the Project area in this time frame necessitates a substantial investment in new facilities. I'd like to briefly discuss the facility design for the Flow Station 3 Injection Project. The additional faciltiies are required for two purposes~ first, to process, blend, and inject the miscible gas, ahd second, to provide adequate water volumes prior .to the fieldwide waterflood. The miscible injectant is composed of several liquid and gaseous streams from existing Prudhoe Bay Facilities as. shown in Slide 7. One source.of liquids is the Field Fuel Cas Unit or FFCU. The FFCU processes separator off-gas in the field, and by lowering the hydrocarbon dewpoint of this gas to -40°F, produces fuel gas that is used in the Field and by Alyeska in' its first four pump stations. Low molecular weight hydrocarbon liquids drop out as a by-product of the gas conditioning. Currently, a portion of' these liquids are spiked into the oil pipeline. After Project start-up, these liquids 6 w£11 be used to form the miscible gas. ^11 of the other sources for the enrlched gas are connected with Flow Station 3. As indicated in the facilities block dlagram, t~hey include scrubber 110uids from the separator off-gas processing equipment 'and compressed off-gas from the' 'Int~.~mediate Pressure or IP separator. If reouired, dehydrated hlgh pressure- resldue gas will be added to supplement the ]~P. compressor gas volumes. ., · .. The Flash Drum Liquids frqm the FFGU, the scrubber liquids from Flow Station 3, and the TP compressor gas are all sent to a new'Process module located ad,iacent to Flow Station 3. As shown in Slide 7, in this adjacent modul'e the liquids are pumped and the gas is compressed up to a pressure of approximately 4000 psi. The fluids are then blended t° fo~m a supercrltical fluid that is subse- quently delivered to Drill. Slte 13 for injection. This mixture, whleh contains about 42% methane, 12_ 1/2% COp_ and 45 1/2_% hydrocarbon intermediates, miscible with Sadleroehit crude oil at approximately 3700 ps1. The facilities for the miscible gas have. been designed to be compatible with previously pla.nned Prudhoe Bay facilities and should provide 40-#5 MMSCFD of gas for at 'least 10 years. However, it should b~, noted that the availability of the enriching feedstocks is time dependent. The supply of miscible gas is not infinite. .Due to the declining oil rates expected in the 1990's, the volumes of scrubber' liouids and IP cOmpressor gas are expected to decrease which will affect the injectant availability. The water requirements, of the Project are largely provided for by the .existing and planned produced water and source water injection facilities. However, new facilities are required to augment the supply of water prior to the start-up of the Beaufort Sea waterflood in mid-1984. Therefore, to supply the necessary supplemental water, four wells at Drill Site 14 will be perforated in the Sadlerochit aquifer and artificially lifted with high pressure gas. The gas lift gas will be supplied by three new 1200 hp turbine compressors housed in a separate module at Flow Station 3. The four wells are expected to provide 40-60 MBPD of supplemental water in addition to t~e 25-35 MBPD of water produced with the oil from other wells in the FS-3 area. This total volume of water, namely 65-95 MBWPD, will be sufficient to supply the Project needs until Beaufort Sea water is available. In addition, as water production within the Field increases due to Low Pressure Separation and Artificial Lift being made available to the producing wells, the supplemental water from Drill Site 14 will be gradually phased out. The anticipated well and facility costs for the Flow Station 3 Injection Project are estimated to be 110MM$. In Slide 8, the new facilities and pipelines required for the Project are shown in orange. The major investment items are: 1) the Process or Injection Module, 2) the Gas Lift Compressor Module, 3) the Flash Drum Liquid pipeline to Flow Station 3, and 4) the mis- cible gas pipeline to Drill Site 13. I'd like to now leave the design of the Project, and move forward and address our .implementation and surveillance plans. As I mentioned earlier, our North Slope construction personnel are moving forward as expeditiously as possible to ready the new faciliti6s for start-up by year end. Project start-up will occur in several stages as shown in Slide 9. The first stage will involve some pre-injection of water into some of the WAC injectors and i'nto the upstructure water injectors. Produced water at Flow Station 3 which is currently being disposed of in the Cretaceous sands will be redirected to the Project area through existing Produced Water Injection' or PWI facilities starting in late November. Following start-up of the three small interim gas lift compressors in early December, the supplemental produced water from Drill Site lZ~ will join the other produced water and bring the total pre-injection to approximately 50-70 HBWPD. Besides providing pressure support, and retarding the advancement of 'the gas tongues into the Project area, .the pre-injection of water will also reduce the free solution gas concentration around the WAG injectors and will improve the injectivity profile of the miscible gas when injected. .. ,, :,' The next start-up phase involves the injection"of the 40-45 MMSCFD o'f miscible gas into three or four of the eleven WAG injectors. This. is expected to occur .' near the end of the year and this date will be the "Project beginning date" for the Windfall Profit Tax purposes. After a period of gas injection into these first wells, water injection will follow into these initial wells and another set of WAG injectors will commence taking miscible gas. It is anticipated that several sequences will be required before all of the eleven WAG injectors have received miscible gas. Although the actual length of each enriched gas cycle will be determined by operational experfence and re'servoir performance, it is currently estimated that the miscible fluid will be injected in 1 to 3 month periods. 'The WAG ratio, that is, the amount of water to be injected alter- nately with the gas, will be adjusted to maintain the pressure in each pattern above the minimum miscibility pressure. By 3anuary 1, 1983, 51 of the '60 planned project wells are expected to have been drilled. This includes all eleven of the WAG injectors, five of the seven upstructure water injectors and 35 of the 42 producers. The other. 9 wells will be made available .throughout the year 1983 as part of our planned Field development. Total production rates from the Project area will be controlled as closely as possible to achieve a balance between injection and production with the overall goal of individual pattern balancing and maintenance of miscibility conditions. 'Although not a part of the start-up plans, a number of other Field expansions will occur during the first two years that 'will affect Project operation. Low Pressure Separation and Artificial Lift will become available to the Project producers during the first 15 months of operations. These facility expansions will greatly enhance the productivity of our wells; they will allow us more flexibility in pattern balancing and will allow us to handle more water pro- duction in' 'the Project wells. As a result of the ability to produce more water in the Flow Station 3 area, we should be able to phase out the supplemental water production at Drill Site 14 within two to .three years. Another major expansion, the Beaufort Sea waterflood, is expected to start-up in mid-1984 and will make available approximately 100 MBPD of sea water for injection into the upstructure water injectors. It is important to note that the Beaufort Sea water cannot be used in the WAG injector, s. Only relatively warm produced water can be used in these wells since unheated sea water would form hydrates with .the miscible gas in the wellbore during chan~e overs between gas and water injection. , · That concludes my remarks on implementation; I'd next like to summarize some of our surveillance'plans. As I mentioned at the beginning of my presentation, one of our objectives for the Flow Station ~ Injection Project is to test' the effectiveness of the miscible gas process. For this reason, an extensive surveillance program has been planned to monitor and optimize the enriched gas drive process. The existing fieldwide surveilla'nce program will be supple- lO mented by the use of observation wells, cores, an expanded cased hole logging prooram, more frequent production well surveys, and a radioactive gas tracer program designed to track actual injectant movement in the reservoir. As shown in Slide 10, we have designated the inverted 9-spot pattern surround~ lng WAG well 13-6 as the key observation pattern. As presently envisioned, one or two non-perforated observation wells will be drilled around Well 13-6 to · .,. monitor gas and water movement and to help evaluate the near term effectiveness ... of the tertiary process. These wells will' be. completed with non-conductive · . fiberglass Casing to facilitate the periodic· use of induction logs 'to monitor water saturations. The propagation of the enriched gas front past the observa- tion wells will be monitored with neutron logging devices. The observation well logging program will provide a time-lapse description of changes in water and gas saturations versus depth. From these measurements., we hope to evaluate, perhaps within 1 to 2 years after Project start-up, the effectiveness of the tertiary process in forming a miscible zone and in mobilizing the crude oil. Additional coring has also been performed within the Project area to. increase our understanding of the reservoir properties in this portion of the Field. By 3anuary, 1983, .five wells will have been cored wi. thin the Project boundaries as indicated in Slide 11. These wells are 12-9, 13-4, 13-19, 13-25, and 13-98. Well 13-98 is one of the observation wells. The cores will provide us with information on permeability, porosity, lithology and fluid saturation for use in future performance studies. To better monitor the operational aspects of the Project, an expanded cased hole logging and well survey program has been developed. Baseline logs will be run in the producing wells to establish the gas and water saturations existinO · . 11 at the beginning of the' Project. Periodic repeats will be run in selected producers to monitor floOd performance throughout the Project life. In addi- tion, spinner and tracer surveys will be used to monitor the production and injection profiles. Finally, bottomhole pressure build-ups will be obtained in each inverted 9-spot pattern to ensure that the reservoir pressure is being maintained above the minimum miscibility conditions, One of the best overall qualitative tools to assess Project performance will be the use of radioactive gas tracers. A progra, m has been developed to inject one of four different tracers into each WAC injector during its first miscible gas' cycle. Cas samples will then be taken from each Project producer monthly and analyzed fbr the presence .of each tracer. The gas analysis results will provide a means of determining areal gas movement and may give us an indication of volumetric sweep efficiency. These results may be. especially important in those area~ where faults are present. The surveillance program that I have just outlined is not inexpensive. For 1983 alone, the program is estimated to-cost over 4 MM$ and that is exoludino the cost of the observation wells and cores. This represents a significant on-going .commitment by the Working Interest Owners to the Project objectives that I outlined earlier. 12 Flow Station 3 Injection Project PROJECT LOCATION I I I I I I I I I I I i I I I I I I I ! I I I I J_ _L--,--.4---'----~- - I - I , I I -I- - -I .... ! - -- - I- - - ~- - - 4 - I I I I I I I , I I I I I I I I I I ! I i I I I I I I i 1I- ! ' Jr-'-- T ---,- - - ! , Flow Station 3 Injection Pro 100' gross light oil column Project Objectives · Increase Recoverable Reserves · Test Viability of Miscible Gas Process at Prudhoe · Provide Design and Operating Basis for Future Applications Drill Site 14 I I Drill Site 6 'O I I I · 'WAG Injector ,Producer I Drill Site 13 I ~ Upstructure Water Injector ! I I L_ Flow Station 3 Injection Project PROJECT DELINEATION I I I 1 0 0 I I Drill Site 1 I I I -O Drill Site 12 I ~'"" 100' gross light oil column I Flow Station 3 Injection ProjeCt Basic Geology and Vertical Delineation of prOject Original GOC Upstructure Water Injectors ;,:',"~-..~.'. . ~ . . Project Encompasses Light Oil Column Downstructure Development Limit / Gas HO/T Water Shale Flow Station 3 Injection Project AREAL PATTERN DESCRIPTION ·14-18 · 14-6 · 14-5 14-11 · 6-4 · 6-13 · 6-8 · 1-14 · 1-2 · 1.1.~ ~ ~6-9 · 6-10 ! · 1-7 · 1-13 · 1-10 ( 13-22 ~ ~'"~'~' X8 13-34 ' / ~2 17 &13 21 14-17 · 14-21 · 14-10 ' 14-9B Legend 14-30 \,~, -~ · ,~, "~'!~' -.. 13-24 /.,~a~\6.17 -. ~ '~'26 ,~6-6 \~"'13-1 4-8. ~ ~ / ~ 14-22 / X / ~13-33 / ~ 13-30 14-9 ~3-29 % / FS-3 INJECTION PROJECT A'REA ~12-4 O PUT RIVER " ~ ~ -- 18-1o-15 / X 13-4 ~13-5 ~-4A ~ 1 ~ / 2-9 ~ 12-3 13-15 ~ ,t3.16 ~13-11 _& ~.~ ~~].,,.Ax,~l ~ x /12-8A I -~ I R14E R15E · 1-1 · 1-11 ·12-1 ·12-5 · 12-7A J~12-7 12-14 WAG Injector Producer I~ Upstructure Water Injector Flow Station 3 Injection Project Source and Processing of Miscible Injectant Stream FFGU Process Module Flow Station 3 ! Flash Drum Liquids Scrubber Liquids Intermediate. Pressure Gas and/or Residue Gas Miscible Injectant to DS 13 ADDITIONS Flow Station 3 Injection Project MAJOR FACILITY~ ADDITIONS Gas Lift Compressor Module ~CCP and nU,;' Injection Module Drill Site Drill Site 14 Drill Site Drill · i~'"~/' 12" Flash Drum · - Liquid Line Flow :!: Station .~i~ . #3 ...?."?:" ':::?:'~:.~:. ..:..-.-'?':':"'~'r i I i Site '~.-':. '::'"..:::?::' 6 - :':"::::::::....... "'... 10" Miscible Fluid Ooo · -.... In ection Line '~'""-'-Drill Site Flow Station 3 Injection Project Start-Up Sequence November 1982 December 1982 Late December 1982 January - June 1983 January - July 1983 January - March 1984 July 1984 Produced Water Injection Upstructure Supplemental Produced Water from Drill Site 14 Miscible Gas Injection Initiated into 3 or 4'WAG Wells Sequential Start-Up of all 11 WAG Injectors Start-Up of Low Pressure Separation at FS-3 First Increment of Fieldwide Artificial Lift Major Beaufort Sea Waterflood 14-9B 14-13 14-12 10 I I I Flow Station 3 Injection Project LOCATION OF KEY OBSERVATION PATTERN 14-8 14-28 ~1~ 13-23A / / J~'14-26 / / 14-30 ~k 13-32 14-22 14-9 / / / / / 13-29 FS-3 INJECTION PROJECT AREA ~k, WAG Injector ~1~ Producer 14-14 · 13-17 6-11 \ 'e,~-~2 \ / ,~K 6-17 13-24. / \ J~6-6 / "\~i,,13.1 13-18 13-19 6-9 13-20 12-19 / 13-25 13-14 ~1~ ./ \ ~'1 13-22 3-34 \ '~ 13-30 13-15 .\ 13-12 13-13 ~I'~13-33 '~ 13-4 Observation Well 13-16 - ~ll~' 13.10 13-27 13-9 · 1 Upstructure Water Injector 13-8 R14E 12-17 12-20 ! .! ~'12-12 ~i~13-21 PUT RIVER 18-10-15 2-4A 12-9 12-18 12-16 12-8B 12-8A R15E 11 14-29 14-13 14-12 · J~k 13-23A 14-28 / / ~!~'14-26 / / 14-30 14-14 13-17 6-11 / ~,,6-12 \ \ ~ 6-17 14-9B ~ 13-24 / \ ~ 13-26 ~t'6 6 \ · "~ / ' ~t.13.1 14-8 "~ ,,. ~ 14-22 4-9A~- // ~ 13-30 ~13-33 INJECTION PROJECT AREA ~13-12 ~~8 ~ Upstructure'Water Injector 13-18 Flow Station 3 Injection Project CORED WELLS 6-9 13-19 13-20 12-19 / \ . 12-20 · ~ / ,e'~-2 -e,~-~ /. ' ,~, ~,12-17 ~, 13-21 \ ~ _ ' ~ . ~ 12-18 ~ / ~ 12-4 ~PUT RIVER 13-16 ~ 13-11 ~~ ' ' //' xx ! ' ~12-16 I ' x % .12:8A , a ~ 13-9 12-15~ 13-8 I R14E R15E Numerical Simulation Studies Mr. Marquez indicated at the beginning of our testimony this morning that the second part of our presentation would involve a discussion of the numerical simulation studies that evaluated the recovery-potential of the miscible ~ . enriched hydrocarbon gas process. I would now like to begin that discussion.. Miscible gas has not been used previously, in the Sadleroohit formation, . . and accordingly, the recovery estimates are based ..on extensive numerical simulation of the tertiary process in the down'Structure portion of the Flow ,. Station 3 area. Because of the importance of the incremental recoveries to overall Project economics, all three major co-owners; that is, ARCO, Exxon and Sohio, have performed their own independent simulation studies. Although each company used ,. different approaches and different reservoir models, the results from the three ,. companies indicate that the displacement of a 10% PV slug of miscible gas will recover an additional 5.5% of the original oil in place over conventional pattern waterflooding developed on 80 ac}e spacing. This corresponds' to a 24 MMSTB increase, in ultimate recovery from the Project area. At this time, each of the three major Working Interest Owners would like to present their simulation work in more detail. I will first present ARCO's results. ARCO undertook a large scale reservoir model study to: 1) determine the incremental recoveries associated with miscible gas injection,, 2) define project sensitivities, and 3) develop an optimum implementation plan. The model employed was a. sequential, semi-implicit four component miscible simu- lator which is formulated to represent gas, oil, water and solvent systems. ARCO chose to use the Four Component Model instead of a more rigorous fully Compositional Model for ~hree reasons. First, the Four Component Model runs computationally much faster which makes it easier to evaluate a larger number of cases~ secondly, the model results are easier to interpret~ and thirdly, the recoveries predicted by the Four Component Model are comparable to those found using a fully Compositional Model since, as I'll describe a little later, · Compositional Model results were used to calibrate our Four Component Model. Slide 12 shows the portion of the Project area that was simulated. The sym- metrical strip extended north into the gas cap and south into the aquifer to correctly incorporate pressure boundary effects. Slide 13 shows the actual grid used. The 3-D strip was represented by a 36 X 7 X 10 grid that contained over 2500 grid cells. The model was history matched to existing actual Project area primary perform- ance and to the predicted future pressure performance generated with ARCO's · full field 3-D simulator. Wellbore hydraulics were added to the model such that the availability of high pressure, low pressure, and gas lift could be handled. Finally~ one last calibration of. the Four Component Model was obtained. Several 2-D cross-sectional r~ns using a fully Compositional Model were made for ~a hydrocarbon miscible WAG process and the Four Component Model was adjusted to match these results. I wo. uld like to discuss the results' of 'six major cases encompassing three different reservoir producing mechanisms which were studied with the 3-D strip reservoir model. The first case involved the prediction of natural depletion performance utilizing the current 160 acre spacing, while the remaining five scenarios modeled frontal displacement processes employing an inverted 9-spot pattern with 80 acre well development. The Pattern development cas'es that were simulated consisted of a conventional waterflood and a WAG miscible displace- 14 ment process with a'lO, 15 and 25% PV slug of enriched gas being injected. The final case considered a deferral of miscible gas injection for 15 years. All cases were run for 30 years. The results of the natural depletion, watb. rflo~d, and 1096 PV miscible gas .. injection cases are shown in tabular form on Slide 14. The results show that the. injection of a 10% PV slug of miscible.'ga, s is estimated to increase the · · recovery by 5.5% over the 80 acre spaced waterflood.. "This corresponds' to the incremental recovery of 24 MMSTB of oil that'I ."quoted earlier. The potential ,. does exist for higher incremental recoveries, however. 'Slide 15 shows the relationship between incremental recovery over waterfloo'ding and pore volume of miscible gas injected. Injection of a 25% PV slug of miscible gas, which corresponds roughly to 25 years of injection, could raise the incremental recovery due to the EOR Process to almost 11%. The decision to inject volumes much greater than'a 1096 PV slug will depend upon actual project performance, injectant availability and future economics. One thing that is apparent from our discussion this morning is that the Flow Station 3 Injection Project will be started uP before a waterflood has been performed in t~is area of the Field. During the planning stages of the Pro- ject, one of the sensitivities that was evaluated was whether the recoveries might be higher if EOR were postponed until after the waterflood had been underway for many years. To evaluate this possibility, ARCO ran the last case that I mentioned previously; namely, that of a 15 year deferral in miscible gas implementation. AlSo, both Exxon and ARCO conducted laboratory core floods to determine whether the residual oil saturation left behind after the' miscible gas displacement was influenced by the presence and' amount of prior water- flooding. The results of ARCO's last case indicated that, with a 30 year field 15 life, no recovery advantage was seen for delaying the injection of the miscible gas. In fact, several disadvantages were observed. Besides the problem of injectant availability, deferral resulted in lower recoveries of the en- riched gas and higher produced water volumes. Moreover, the laboratory results showed that the same residual oil saturation in the cores was obtained regard- less of whether miscible gas was preceded by water injection or not. Thus, the Working Interest Owners of the Prudhoe Bay Field are in support of impIementing the Fiow Sation 3 Injection Project at this time. This coneIudes my testimony this morning. Our next witnesses wiiI be representatives fr.om Exxon and Sohio ~ho will discuss their numericaI simulation results. Mr. Terry Day from EX'xon, Corporation will testify next. REPRESENTATIVE AREA .STUDIED E) E) -(3 E) C) E) C) E) ~ WAG Injector OprOducer I-] UDstructure Water Inlector 100' gross light oil column Flow Station 3 Injection Project ARCO 3D STRIP MODEL GRID GOC GOC HOlT WOC HOlT WOC NORTH · . Legend ~ .. & WAG Injector " ~ Producer ~ ~r, struct,~re Water--r- -- Injector SOUTH 14 Flow Station 3 Injection Project ARCO Numerical SimUlation Results Ultimate Recovery, % Ultimate Recovery, MMSTB Natural Depletion 27.7 122 80-Acre Pattern Waterflood 42.2 187 Miscible WAG- 10% Slug 47.7 211 15 Flow Station 3 Injection Project Relationship of Incremental Recovery to Miscible Gas Slug Size o 12 8 0 o 4 0 0 5 10 15 20 25 % Pore Volume Slug Exxon's Numerical Simulation Results Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Terry Day, I am Exxon's Western Division Reservoir Engineer. I received a Master's of Science Degree in Electrical Engineering from the University of Florida in 1971. In the same year I was employed by Exxon Company, U.S.A., and have spent most of the past 11 years responsible for.v.ari,ous aspects of petroleum reser- voir engineering. Since November of 1980 I have been..involved with Prudhoe Bay Unit studies including the o'oordination of sev~.n engineers studying enhanced recovery methods. This morning.I would like to describe Exxon's evaluation of the Flow Station 3 Inject. ion Project. As has been indicated, the technical work relative to'applying EOR methods · at Prudhoe started with 'a screening study which evaluated applicability of several leading EOR methods (Figure 1). Based on this review of .processes, · , Exxon has concluded that miscible WAG displacement is the most promising EOR method for application at Prudhoe. However, we are continuing to perform research in other areas. ? Exxon's technical work concerning miscible processes at Prudhoe has included slim tube tests to verify requirements for miscibility, laboratory displacement tests to determin.e residual oil saturations, and numerical simulation of portions of the Flow Station 3 (FS-3) Injection Project. Exxon ran slim tube experiments which confirmed and supplemented several such tests that were.carried out by ARCO. In a. laboratory slim tube exper- iment, a gas with known compositions displaces oil from a long, narrow, coiled tube that is packed with sand. The gas injection rate, outlet pressure and temperature are closely r'egulated. Experiments using gas obtained by mixing 70% FS-3 separator gas with 3096 NGL's to displace Prudhoe Bay oil at reservoir temperature and various pressures, indicate that the oas and prudhoe Bay oil would be miscible at expected reservoir pressure. I will show the results of one test in a moment. Mr. NeIson has already described resuIt's of our dispIacement test that were carried out using Prudhoe Bay SadIeroch£t etude and cores. The major objective of the simulation study'was to assess the feasibility of injecting enriched separator gas in the Flow Station 3 area and to evaluate the additional r'ecovery potential. Exxon's fully compositional reservoir simulator. program and a three dimensional reservoir model were used for numerical simu- lations which predict reservoir behavior in the FS-3 area Under waterflood and 'under severa'l miscible WAG displac?ments. In a compositional simulator, the oil (or liquid) and oas phases must each he rep'resented~ or characterized, by a fixed number of chemical components, usually less than 10, since a complete specification is not practical. The components, used are standard components such ~s carbon dioxide, methane, ethane, etc., and pseudo components defined to represent complex mixtures, of heavier hydrocarbons. The simulator program calculates liquid and gas phase densities, phase viscosities and mass transfer between phases using analytical methods based on the composition of the oil and oas phases. Exxon's simulator program uses ten components - carbon dioxide, methane, ethane, propane, and six heavier-thah-propane hydrocarbon components to char- acterize the actuaI reservoir cji and gas. 2 The fluid characterization was developed by closely matching laboratory deter- mined bubble points, oil densities, and oil viscosities to those analytically calculated. The characterization was verified by comparing simulation results with laboratory slim tube tests. Predicted versus aetuai recoveries are shown in Figure 2 for one slim tube test. comparison. As discussed earlier, actual siim tube data was obtained for .~. enriched miscibie gas displacing recombined Prudhoe Bay reservoir crude. A one-dimensionai simuIator.modei was designed which represented the 20 foot long slim tube. NumericaI dispersion, causes the simQiator prediction to b~. slightly conservative in this case. However, the miscible condition has be~.n close'ly predicted as shown by the very high recovery, aimost 90 percent, after one pore volume of injection. A confined nine-spot model of a portion of the FS-3 area (developed on 80 acre spacing) and fully compositional as well as four component simulators were used to investigate in detail the mechanics of the miscible flood. The cross- hatched rectangle shown on Figure 3 is ~he 320 acres within the FS-3 IP area included in the model. Parts of three 320 acre inverted 9 spot patterns are included. This configuration was chosen to m'inimize the effects of grid orientation on the movement of .gas within the model. Cridding of the model is shown in Figure 4. The model thickness including the aquifer is 450 feet represented by nine layer~. Thin vertical blocks were use~ at the top so that tendencies of the miscible gas to gravity overrun could be simulated. Porositi. es, permeabilities, saturations, pressures, and fluid properties were based on Flow Station 3 area reservoir data. The heavy-oil-tar zone effect was include~ by reducing rock permeabilities and porosities through 3 this zone. This model contains 60 MMSTB of original oil in place or about 1596 of that in the Flow Station 3 Injection Project. To closely duplicate field practices, the production wells were completed about 120 feet above the aquifer. ~Vater and miscible gas were injected over the ~nter~als shown to be perforated. Injection was manaoed to match reservoir withdrawals. The estimate of vertical miscible gas conformance near injection wells is important to our studies and has been determined using separate radial models. The results of these studies have been incorporated in the following model results. A base wate'~flood case and several cases in which water was alternately in-. jeoted with enriched field gas were run using this pattern model. Termination of production was based on a 10 to 1 water-oil ratio in all cases. These cases indicated that recovery is a function of the total miscible gas injected and the WAG ratio used. If miscible gas.were available and could be continued to depletion, additional recovery over a Waterflood was calculated to be 8% of OOIP. Since the supply of misible gas ~ill decrease with time, cases using various volumes of miscible gas were also simulated. Our analysis of these cases indicates that a recovery of about 8% of the.' OOIP can also be achieved by a 15% PV slug of miscible gas with proper reservoir management. As previous testimony has stated, the actual length of miscible .oas injection and the WAG ratios employed wilI be 'managed based on actual' well productivity, injection well capacities and overall project performance. Figure 5 shows a plot of estimated production from the total FS-3 IP area based on a scale up of Exxon's reservoir Simulation of typical pattern' performance. The evaluation indicates that production from the planned waterflood would peak 4 at slightly above 55 thousand barrels per' day, and then decline to dePIetion after the year 2000 with a recovery of about 40 percent of the oil originally in place. Injection of a' 10% miscible gas slug at WAG ratios sufficient to maintain reservoir pressure shouId increase prOduction starting in the Iate 1980's, and increase ultimate recovery by-about 5-1/2 percent of the o£1' originalIy in piace. Based upon our work and the work presented tOday by. other owners, Exxon has concluded that the FS-3 IP is a worthwhile project which will increase oil recovery from the Prudhoe Sadlerochit reservoir,' We recommend that the AOGCC approve the Application for Additional Recovery and approve the P'roject as meeting the requirements of a qualified tertiary recovery project for purposes of the Crude 0il Windfall Profit Tax Act of 1980. That concludes Exxon's remarks in support of the Flow Station ) Injection ,. Project. The next witness will be Dr. Scott Williamson from Sohio Petroleum Company. Dr. Williamson will present the results of Sohio's numerical simu- lation work in support of the miscible gas project. PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT MISCIBLE GAS STUDIES 7791 SLIM TUBE EXPERIMENTS TO VERIFY MISCIBILITY REQUIREMENTS LABORATORY DISPLACEMENT TESTS TO DETERMINE RESIDUAL OIL SATURATIONS NUMERICAL SIMULATION OF FS-3 IP - Feasibility Of Injecting Miscible Gas - Additional Recovery Potential FULLY COMPOSITIONAL SIMULATOR PROGRAM - Phases Represented By Fixed Number Of Components - Phase Properties And Interaction Analytically Calculated - Accuracy Verified By Comparing To Actual Data Figure 1' SLIM TUBE DISPLACEMENT OF SADLEROCHIT OIL BY ENRICHED GAS AT A 150 PSIG AND 200 DEG. F COMPARISON OF PREDICTIONS WITH ACTUAL DATA 7792 100 8O 6O 4O 2O SLIM TUB£ D 0.0 0.2 0.4 0.6 0.8 I .0 I .2 I .4 VOLUME OF GAS INJECTED, FRACTION PV Figure 2 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT MODEL LOCATION 7794 ~'13-24 ~ .13-16 '"~ 13-~6 TION PROJE T AR LEGEND PROPOSED WAG INJECTOR PROPOSED WATER INJECTOR OIL PRODUCER Figure 3 FLOW STATION 3 INJECTION PROJECT 3-D MODEL GEOMETRY 7795 13-19 13-25 HOT 440' LEGEND · PRODUCER & INJECTOR MODEL DESCRIPTION THICKNESS - 450 FT. LAYERS- 9 AREA - 320 ACRES O01P- 60 MMSTB MODEL ANALYSIS 15% PV WAG - 8% O01P Figure 4 Z 6O 5O 4O 3O 2O 10 FLOW STATION 3 INJECTION PROJECT ESTIMATE OF PROJECT PRODUCTION 779~ F S 3 I P RECOVERY ESTIMATES _~~ ' CASTE RECOVERY____,, %__ O01__~P - ~ WATERFLOOD 40.1 ~. MISCIBLE WAG 45.8 ~_ %~%. ADD. RECOVERY 5.7 -.. . ~~MISCIBLE WAG - WATERFLOOD ~~ I I I 1985 1990 1995 2000 YEARS Figure 5 Sohio's Numerical Simulation Results Commissioners, ladles and gentlemen, my name is Scott Williamson. I received my graduate degree in engineering from Stanford University in 1970. Since then I have been engaged in oil and gas production research, reservoir modelling ~nd field operations. I began working on North Slope reservoir engineering in 1980, and currently I am the manager of Enhanced Oil Recovery and Reser¥oir Modelling for Sohio Petroleum Company. I wish t© take this opportunity of addressing you today to describe briefly the work which Sohio undertook to evaluate the Flow Station 3 Misolble Cas Injection Project. Let me begin with a review of the basic idea of miscible gas drive by con- trasting it with conventional oas drive. In a conventional gas drive it is generally found that, where gas does penetrate, the fraction of oil dis- placed is rather low, say some 30% of the local oil content. This is generally referred to as the microscopic recovery. The overall or macroscopic recovery is drastically reduced from this modest level by two effects. First, because gas is buoyant it floats up through the oil to form a thin layer near the top of the reservoir bypassing much of the oil. Second, even this thin gas layer has a pronounced tendency to break up into channels which again bypass oil and contribute to high GOR production. The end result is not an effective process for ihcreasing oil recovery. In miscible' 'gas drive the injected gas, on contacting the reservoir oil, cOmbines to form a single fluid, usually a liquid. Gas mixing in.'this manner to form a miscible fluid effectively displaces virtually all of the oil from the portion of the reservOir accessed by it. Many laboratory tests have demonstrated that, in this process, the microscopic recovery usually' exceeds 9096. Unfortunately in a reservoir 'the injected miscible gas still exhibits the two deleterious effects already described. It was observed a number of years ago that if water were injected with the miscible gas stream, then the tendency for gas flow to break up into thin channels would be greatly diminished. The upward segre- gation of gas may also be somewhat reduced. The 'final result is an effective process, with high macroscopic recoveries, as Mr. Nelson showed earlier in. 'di$cdssing ARCO's results. In practice simultaneous injection of gas ahd water is not necessa, ry, an alternating gas/water injection cycle is as effective and is operationally more · . practical. This then is the water-alternatingzgas, or WAC, process' which we are examining today. From the discussion so far you will appreciate that an analysis of a miscible gas injection project will require a good understanding of hOw oil, gas and water flow .through the reservoir rock. This level of information would be .. required in any case for analysis of primary recovery or a waterflood. For a miscible gas .flood We require additional information about the miscibility of the gas; that is, whether it will mix with the.' reservoir oil to form a single fluid, or will remain as a gas, but possibly with altered composition. Factors which determine miscibility include the .Chemical compositions of the injected gas and the reservoir fluids, and the pressure and the temperature of the mixture. This topic is often referred to as phase behavior. .· I will start the detailed account of Sohio's' wOrk with sample results showing that we can satisfactorily represent the reservoir fluid flow at Prudhoe, in · the Flow Station 3 area in particular. I will also show results which demon- · strate our understandi6g of the phase behagior. Figure 1 shows an outline, map of Prudhoe Bay with an areal view of the extent of the reservoir included in our computer model of the Flow Station 3 In3ection Pro3ect area. ~ou will notice that the model does not contain ali of the proposed Pro~ect area, merely a representative portion. For these kinds of problems it is often more efficient to analyse a somewhat simpler, repre- ~ent'a'tive situation, scaling results as reouired to the total project area. During primary production there is a. significant interaction between the Pro, eot area and the remainder of the reservoir. The extension of the model into the main field area permits us to model this interaction. The Flow Station 3 Injection Pro,eot area contained some 440 MMSTB OOIP. Our strip model, shown in Figure 2, contains a total of 236 MMSTB, with 72 MMSTB located inside the Project area. The model oon'tains a total of 840 blocks in 14 layers with 20 rows and 3 columns. The reservoir description and many of the fluid and rock properties used in our model were based on Sohio's previous reservoir . simulation studies of Prudhoe Bay. For the period from 1977 to 1982 historiCal data is available for testing the model results. Figure 3' shows a comparison of predicted and measured reservoir pressures for this relatively short production period. We can see that there is reasonable agreement 'between. model results and field data. It is also worth noting that when we ran a base primary production case using the Flow Station 3 Injection Project model the results were consistent with other Sohio Prudhoe Bay computer model result's. The second item of information required for Computer simulation of a miscible gas process is, you may recall, the phase behavior description. We chose to represent the reservoir hydrocarbons with .eight components. 'Compositional simulations are frequently run with a fewer number of components. However, 3 the use of eight components enabled us. to accurately match observed phase behavior data. Figure 4 shows some experimental measurements made by ARCO, the ringed points, for a .test in which a sample of reservoir oil is mixed with successively greater amounts of a particular miscible gas. During this swelling test the pressure is adjusted after each ..oas addition to the minimum 'value which creates a single phase liquid.. Any further reduction in pressure would result in the emergence of a separate, gas phase. The curve in Figure . .. 4 shows the corresponding results predicted by 'our Phase behavior calcul'ations. There is excellent agreement between theory and measurements. .. Let me now describe some sample results we obtained in our evaluation of the Fiow Station 3 Injection Project. Our primary concern was the performance of miscible gas drive compared to the anticipated waterfiood. The next series of figures summarizes pertinent resuits of our modei studies. 'First, Figure 5 shows the primary production performance expected for the Flow Station 3 ., Injection Project area. The anticipated uItimate recovery is 28% of OOIP. The next pict, Figure 6, shows the improved recovery which can be expected from waterflood together with additional infill wells. This raises the ultimate recovery to 39.1% OOIP after 30 years of production. The third figure of this series, Figure 7., shows the further improvement wh'ich miscibIe gas drive shouId attain. After injection of a 15% PV siug of miscibIe gas this amounts to an additionai 8.3% OOIP, for an uItimate recovery of 47.4% OOIP, that is, some 33 MMSTB of additionaI oiI. We can see, in passing, that at 10% PV miscibIe gas injection the incrementai oii production is 5.4% OOIP. The precise recovery vaIue depends on many variabies: the Project lifetime, the in,iected gas composition, the miscible gas and water injection rates and the number and configuration of produJtion weIIs. The finaI resuIts we have just inspected correspond to 25 years of miscible gas injection at a rate of approximately 0.6% of the pore volume per year with an average water-to-gas injection ratio of 2 to 1. This case was one of many which we examined during our evaluation work. As' il'iustrated in Figure 8, our conclusions may be summarized as-follows: · Sohio's evaluation of the Flow Station 3 Injection Project shows that miscible gas drive with a 15% pore volume injection contibutes an addi- tional 8.3% OOIP to the ultimate recovery. · Sohio'S' results are in general agreement with ARCO's and substantiate the view that the Flow Sation 3 Injection Project does satisfy the require- ments for a qualified tertiary recovery project, We therefore urge the Commission to permit the Project for additional recovery and approve the Project as a qualified tertiary recovery project· Thank you for the opportunity of making this brief presentation of our work on the Flow Station 3 Injection Project. The next witness will be Mr. Roger Doughty from ARCO Alaska who will discuss how the Project meets the require- . ments of the Windfall Profit Tax law. 5 SOHIO OPERATING AREA ARCO OPERATING AREA EXTENT OF ORIGINAL GAS CAP 100 FOOT OIL cOLUMN BOUNDARY PRUDHOE MAIN BAY FIELD AREA REA FLOW STRIP STATION 3 MODEL FS 3 STRIP MODEL AFFECTED AREA WOC GOC WOC O OIL PRODUCER WATER INJECTOR WAG INJECTOR · MODEL AND FIELD PRESSURE COMPARISON 440O 43OO 4200 4100 4OO0 3900 38OO 3700 3600 3500 - 3400 3300 o~ I I I I 1977 1978 1979 1980 1981 .1982 YEAR LOCATION MAP MODEL PRESSURE ROW I 24 HOUR SHUT IN PRESSURE FIELD DATA FROM WELL 2-6 PBU°S SWELLING ARCO EXPERIMENTS AT 200°F EXPERIMENTAL DATA Swelling Of Fluid D2 By Fluid E (Possible (Prudhoe Bay Crude) Miscible Gas .Mixture DJ 5OO0 4000 3O00 20O0 EXPERIMENTAL DATA R-K EOS (8 COMPONENTS) ESTIMATED CRITICAL POINT 1000 0 0.2 0.:4 0.6 0.8 1.0 MOLE FRACTION OF' FLUID E · 5, 6, & 7 0 t~ 0 5O 45 4O 35 3O 25 2O 15 I0 5 0 PROJECT PERFORMANCE PRIMARY 'PRODUCTION 78-82 DEPLETION FOLLOWED BY WATERFLOOD FOLLOWED BY MISCIBLE GAS INJECTION 980 19 85 199 O 1995 2000 2005 TIME, YEARS' WAG WATERFLOOD DEPLETION 2OIO CONCLUSIONS SOHIO'S EVALUATION OF PROJECT SHOWS THAT WITH A 15% ADDITIONAL RECOVERY. PV INJECTION 8.3% OOIP TO THE FS3 INJECTION MISCIBLE GAS DRIVE CONTRIBUTES AN THE ULTIMATE SOHIO'S RESULTS WITH ARCO'S AND THAT THE FS3 INJECTION THE REQUIREMENTS FOR 'RECOVERY PROJECT. ARE IN GENERAL AGREEMENT SUBSTANTIATE THE VIEW PROJECT DOES SATISFY A QUALIFIED TERTIARY Tax Discussion Members of the Alaska Oii and Gas Conservation Commission, ladies and gentIe- men~ my name is Roger Doughty and I have been employed as a petroleum engineer .by ARCO since 1972. I received a B.S. degree in petroIeum engineering from the University of Okiahoma 'in '1970' and received a M.S. degree in petroleum engineering from the same university in 1'972.~,.. I have been invoived with the deveiopment of the Prudhoe Bay Fieid for over seven' years and I am presently .. the Prudhoe Bay Regional Reservoir Engineer. '" ., .. In the next part of this hearing, we would like to discuss how the proposed Flow Station 3 Injection Project specifically meets each one of the reQuire- ments for a Qualified tertiary recovery project, for purposes .of the Crude Oil ~Vindfall Profit Tax Act of 1980. The Windfall Profit Tax Act provides that an enhanced oil recovery project is a quaIified project if the operator submits a certification stating that the jurisdictionai agency; in this instance, the Alaska Oil and Gas ConservatiOn Commission, has approved the project as meeting .the requirements of the law. · The specific requirements are found in subparagraphs (A), (B) and (C) of. Section 4993(0)(2) 'of the Internal Revenue Code. SIide 1 Iists the require- ments in those three subparagraphs. The subparagraphs specificaily state that a project wiii quaIify if: (A) the project involves the application (in accordance with sound engineering principles) of I or more 'tertiary recovery methods which can reas'onably be expected to result in more than an insig- nificant increase in the amount of crude oil which will ultimately be recovered, (B) the project beginning date is after May 1979, and (C) the portion of the property .to be affected by the project is ade- quately delineated. We are requesting that the Commission approve the Project as meeting each of these requirements and I would like to discuss each one in detail. There are basically three, parts to the requirement in subparagraph (A); namely, the application of a qualified tertiary recovery method, the implementation of the project in accordance with sound engineering principles, and a reasonable expectation of more than an insignificant increase in the recovery of crude oil. First, the Flow Station .3 Injection Project does involve the application of a qualified tertiary recovery method, as thosb, methods are defined in the Windfall Profit Tax Act. The Windfall Profit 'Tax Act defines a tertiary recovery method as one that meets one of two qualifications. Either the met.hod is described in subparagraphs (1) through (9) of section 212.78(c) of the 3une' 1979 energy regulations; or the method has been approved by the Secretary of the Ireasury. As discussed previously, the enriched gas WAC injection method which is planned for use in the Flow Station 3 Injection Project is a miscible fluid displace- ment method. Miscible fluid displacement is listed as a tertiary recovery 2 · . method in subparagraph (1) of the seetio'n 212.78 (c) of the referenced 3une 1979 Department of Energy regulations. The. Flow Station 3 Injection Project involves the injection of' enriched natural gas into the oil reservoir at pressure levels such that the gas and reservoir' oil will be miscible. The cumulative amount of injected gas measured at reservoir temperature and pres'- sure is reasonably expected to be more than 10~ of the reservoir pore volume being served by the injection wells. This miscible displacement process ' · -i · . involves the alternating Injection of water' and gas Which is specifically recognized in the Depart.ment' of Energy regulations. Thus, the Flow Station 3 Injection Project does employ a.qualified tertiary recovery method. Secondly, this miscible fluid displacement process will be applied in the Flow Station 3 Injection Project in accordance with sound engineering principles. The planning and implementation of the Project has 'been under the direct supervision of qualified and experienced reservoir engineers. Our testimony .. this morning and the certification document have clearly shown the planning and integrated effort that has been applied to this Project. Miscible fluid displacement using enriched hydrocarbon ~as was selected as the best method to use at this time for this portion of the reservoir Only after a comparative examination of' the various methods based on r6servoir conditions, injectant availability, and process cests. The results of our screening studies were discussed earlier in this hearing. The Project facilities have been designed 'to be compatible with previously planned facilities and construction has proceeded without impacting Other Prudhoe Bay projects. The WAG method of injection and the Inverted ~nine-spot inje'ction pattern were chosen only after a thorough reservoir simulation study by the Working Interest Owners. Implementation has been planned to give us as much flexibility as possible in our field operation. 3 The legislative history {o the Windfall Profit Tax Act provides that a tertiary recovery project which has not been preceded by secondary recovery methods will meet the tax requirements if the "... certification sets forth an explanation of why such action was in accord with sound engineering principles." Further, the legislative history provides that ". . . a project could qualify for tax Purposes if the absence of secondary methods were explained 'adequately, and was due to peculiar characteristics of the reservoir or oil." Because of these statements, we thought it was important to discuss in this hearing in some detail why it is in accordance with sound engineering for a tertiary recovery project to be implemented in the Project Area 'prior to a secondary waterflood. · . Most of these reasons were already addressed in our earlier testimony; however, I wouid like to summarize and reiterate them at this time. For the Commission's convenience, Slide 2 gives a list of these reasons also. First, the imple- mentation of this Project as soon as' possible provides an opportunity to maximize oil recovery from within the Project .Area by extending injection of miscible gas' past the 10% pore volume slug, .if that is economically feasible. As we indicated in our discussion of numerical simulation, higher volumes of miscible gas injection afford an opportunity for 'higher incremental recoveries, but the higher cumulative volumes will require more years of injection. 'This opportunity will not exist if we have to wait u,ntil the waterflood has been · underway for many years before starting EOR. Second, the feedstock necessary for enriching the gas to make it miscible may not be economically available if the Project is not implemented until after waterfIooding. In our description O'f the Project facilities, we mentioned the fact that our supply of miscible gas was time dependent. As the Field of. ftake 4 rate decIines in the 1990's, we see a somewhat proportionate drop in the voiume of scrubber Iiquids and IP compressor gas avaiIabIe. ImpIementation now wiII aiIow us to take advantage of the highest injectant avaiIabiIity. To deveIop another miscibie gas source later in the FieId Iife may be prohibitediy expen- sive. Also, any substantial deferment of the Flow .Station 3 Injection Project could ~ · render the project uneconomic because of higher risk.. Fluid migration, in- .. creased gas tonguing, and.higher free gas saturat.'tons are all problems that may become worse in the later years of the Field life, and all negatively impact the success of the miscible gas process. Higher operating costs wiII defintte!y be a reality as we will be handling large volumes of reproduced water from the Beaufort Sea waterflood. The remOte and harsh Arctic environment, itself, additionally burdens the~ implementation of a tertiary. recovery process when compared to operations in the lower #8. · , Another reason for moving forward with EOR now is that valuable reservoir and operating knowledge will be gained. A successful WAG project at Flow Station 3 will encourage the implementation of projects in other areas of the reservoir. It is necessary' to start the Project now to provide information early enough so that other projects may be designed and implemented in the Unit. Finally, laboratory core experiments and reservoir simulations have indicated that no recovery advantage exists .in deferring the start, of miscible gas injection. However, initiation of the Project at this time will. capitalize on existing favorable conditions and reduce the higher risk associated with deferral. Deferral could potentially preclude the project. ,. The reasons that T have just summarized present a strong technical engineering case for showing that "sound engineering principles" are definitely involved in our decision to implement the Flow Station 3 Tnjection Project prior to waterflooding. Moreover, we are not alone in this assessme'nt. Dr. H. K. VanPoollen, a respected industry consultant, presented a paper on tertiary recovery potential for the North Slope at an EOR symposium in Virginia tn 3une, li)79. To quote Dr. VanPoollen, "Tf we are going to use EOR, we should d° it early. Again, the environment will not allow this field to be around for too many years. Things start falling, apart. )ou have repairs. The cost .of abandoning the field is going to be horrendous. Tt should be studied.''~ , . ~Ve have now shown how this projeCt meets two of the three reauirements in subparagraph (A); namely, the application of ~ qualified tertiary recovery method and .'the use of sound engin.eering principles. The project also satisfies the last requirement of recovering more .than an insignificant amount of Incre- mental crude o11. There is estimated to be 440 MMSTB of original oil tn place tn the Project Area. It is estimated th-at 122 MMSTB or 27.7% of this origtnal oil in Place would be recovered if only primary operations were undertaken. An additional 65 MMSTB is estimated to be recove'rable if an 80 acre pattern waterf'lood is conducted. The implementation of the Flow Station 3 Injection Proj.ect is estimated to recover at least 89 MMSTB of additional oil over · primary recovery and at least 24 million additional barrels over recovery from an 80 acre pattern waterflood. This is equivalent to an increase in ultimate. recovery of 20.096 (OOIP) over primary and 5.5% (OOIP) over 80 acre pattern waterflooding. An incremental recovery of 24 MMSTB of oil corresponds to an increase of 12.8% in the recoverab'le primary and secondary reserves and Is more than an insignificant increase in the ultimate recovery of crude, oil. 6 Therefore the project clearly meets the 'third and final requirement 'of sub- paragraph (A). Subparagraph (B) of I.R.C. Section 4993(c)(2) reouires that a project have a project beginning date after May 1979. The term "project beginning date" is def'ined in the Windfall Profit Tax statute as the' latter of the date on which the injection of liquids, gases or other matter begins, or the date on which the project is certified. Either of these two dates~ for the Flow Station 3 Injection Project will be after May 1979 beeauSe the Project has not yet been certified and injection has not yet c°mmeneed.''' Miscible injection t~s expected to begin in December, 1982. · Subparagraph (C) of I.R.C. Section 4993(c)(2) requires that the area which. will be affected by the project must be adequately delineated. If a tertiarY recovery pr'oject is expected to increase the ultimate recovery of crude otl from only a portion of a D.O.E. property, that portion is required to be treated as a separate property for incremental tertiary oil purposes and the Operator must delineate that portion o~ the property in his Certification.. The Flow Station 3 Injection Project, as. currently planned, will affect only a portion of the Prudhoe Bay Unit which is one D.O.E. property. As discussed earlier'in the .hearing, the.area which will be affected tnvolves 11 injection . patterns and encompasses approximately 3650 acres. The boundaries of the Project Area have been defined as the oute~ producing wells of the nine spot patterns to the east and west, by the limit of development drilling to the south, and by the seven water injection wells to the north. The Project will affect the entire light oil column of the' portion of the Sadlerochit Reservoir which lies within the surface boundaries of t'he Project. The area which will be affected by this Proj6. ct was delineated on Slide 4. A reasonable allocation will be applied to production from any peripheral well determined to be produc- ing o£1 from outside the Project area which is unaffected by the tertiary method. As evidenced by our testimony at this hearing and the application which was submitted previously., the miscible fluid displacement project which we plan to implement at Prudhoe Bay in the Flow Station 3 area meets all of the require- ments for a qualified tertiary recovery project under the Windfall Profit Tax statute. It involves the application, in accordance with sound engineeri, ng principles, of a qualified recovery method~ namely, miscible fluid displace- ment, which is reasonably expected to result in the additional recovery of 24 million barrels of oil from the project area. This is clearly more than an insignificant amount of crude oil. The projec~t beginning date is after Hay 1979 and the project area has been adequately delineated. Based on the testi. mony. we have presented today and the information .contained in the application, We request that the AOGCC, in its capacity as a designated jurisdictional agency, approve this Project as meeting the requirements in Subparagraphs (A), (B) and (C) of Section 4993(c)(2) of the Internal Revenue Code. · This concludes the testimony by the Working Interest Owners. We would be happy at this time to form a panel from which to answer any questions the Commission might have. 8 Windfall Profit Tax Requirements ' For A :-'~.Qualified Tertiary Recovery Project'" . . Project Involves the Application (in Accordance with' Sound Engineering Principles) of One-or More Tertiary Recovery Methods which can Reasonably be Expected to Result in More than an Insignificant Increase in the Amount of Crude Oil which will Ultimately be Recovered - Project Beginning Date is after May, 1979 - Portion of the Property tO be Affected by the Project is Adequately Delineated Engineering Considerations For Starting Miscible Gas injection' Prior To' waterflooding · Maximizes Ultimate Oil Recovery 'Potential · Ensur. es Adequate Feedstock for Enriching.the Gas Injectant · Reduces the Higher Risk Associated with Substantial Deferral : · Provides Valuable Reservoir and Operating Knowledge in the Near Term that could be Used to Design other Projects · Laboratory Work and Reservoir Modeling Indicate No Recovery Advantage in ' Substantial Deferral ' T~E ~CHORAGE P.O. BOX 40 ANCHORAGE, AbASKA 99510-0040 PROOF OF PUBLICATION AK OIL AND GAS CONSERVATION CO 3001 PORCUPINE DRIVE ANCHORAGE, AK 99501 ~DELLA E. BLACK , BEING DULY $~ORN, ACCORDING TO LAW DECLARES: THAT SHE IS THE 5EGAL CLERK OF THE ANCHORAGE TI~ES, A DAILY NEWSPAPER PUBLISHED IN THE TOWN OF ANCHORAGE IN THE THIRD JUDICIAL DIVISION, STATE OF ALASKA, AND THAT THE NOTICE OF......,................... AO-08 5522/PUBLIC HEARIN A COPY OF WHICH IS HERETO ATTACHED, WAS PUBLISHED IN.................,. OF THE ANCHORAGE TI~ES. BEGINNING ON....................... ENDING ON.............','.'........,.. 1 ISSUES 11/03/82 11/03/82 THE SIZE OF THIS AD WAS...,,....... :THE PRICE OF THIS AD I$-....,.'...... $ 20.'40 THE AD NUMBER IS...,..,..,,....,..,.. 1432234 SUBSCRIBED AND SWORN TO BEFORE NE THIS...'...,............, 04 DAY OF NOV,1982 NOTARY PUBLIC .OF THE STATE OF ALASKA NOV 0 9 1982 Alaska Oil & Gas Cons,, Commission Anchorage AGO 10031823 2. PUBLISHER ADVERTISING ORDER Anchorage Tin~ 820 W. t~'burtb. Avenue Anchorage, Alaska 99501 NOTICE TO PUBLISHER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISE- MENT MUST BE SUBMITTED WITH INVOICE. VENDOR NO. DEPT. NO. A.D. NO. 5522 DATE OF October 26, 1982 DATES ADVERTISEMENT REQUIRED: AlasI~ Oil & Gas Conservation Cc~mission 3£~1 Porc%~. ~]e Drive Anchorage, Alaska 99501 -,-r 0¢,'3, ~,.,OVe~er 3, 1 ~ o,- THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. BILLING ADDRESS: S A t:[ E AFFIDAVIT-OF-PUBLICATION UNITED STATES OF AMERICA STATE OF \ ~ DIVISION. ~ BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED WHO, BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT HE/SHE IS THE OF PUBLISHED AT IN SAID DIVISION AND STATE OF,, AND THAT THE ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WAS PUBLISHED IN SAID PUBLICATION ON THE__DAY OF 19 ....AND THEREAFTER FOR. CONSECUTIVE DAYS, THE LAST PUBLICATION APPEARING ON THE_~DAY OF, !9, ,, AND THAT THE RATE CHARGED THEREON IS NOT IN EXCESS OF THE RATE CHARGED PRIVATE INDIVIDUALS. SUBSCRIBED AND SWORN TO BEFORE ME THIS DAY OF NOTARY PUBLIC FOR STATE OF MY COMMISSION EXPIRES REMINDER- ATTACH INVOICES AND PROOF OF PlJBLICATION PRUDHOE BA~ UNIT FLOW STATION 3 IN3ECTION PRO3ECT DRAFT HEARING TESTIMON~ ,., Novembe~ 9, 1982 ~la,~ka 0/1 ~ fi~s coos Introduction Mr. Chairman, members of the Commission, ladies and gentlemen. My name is Dave Marquez and I'm an attorney with ARCO Alaska, Inc., one of the operators in the Prudhoe Bay Field. The Working Interest Owners of the Prudhoe Bay Field have requested this public hearing this morning before the Alaska Oil and Gas Conservation Commission for tw° purposes. First, we are requesting that the Commission approve our Application for Additional Recovery by Miscible Enriched Hydrocarbon Gas Injection. This Application has been filed previously in accordance with Article 5, Section 400, of the AOGCC Regulations. Secondly~ we are requesting that the Commission, in its capacity as a designated jurisdictional agency within the meaning of the Crude Oil Windfall Profit Tax Act of 1980, approve the Flow Station 3 Injection Project as meeting the requirements of subpara- graphs (A), (B), and (C) of the Internal Revenue Code, Section 4993(c)(2). As the Commission may recall, ARCO, on behalf of the Working Interest Owners, submitted documents supporting both the Application for Additional Recovery and the Certification Application on August 31, 1982. We request that these documents be entered as part of the public record. FOur representatives of the Working Interest Owners will present testimony today. Because we feel that the Application for Additional Recovery document adequately addresses the information requested by the AOGCC Regulations, we do not plan any testimony specifically in support of this approval request this morning. However, the witnesses would be happy to answer any of the Commis- sion's questions on this Application at the end of our formal presentation. We do plan to testify today on how the Flow Station 3 Injection Project meets the requirements of the Windfall Profit Tax Act as a bona fide tertiary recovery project. Again, because of the documents that were submitted previously, our presentation will be fairly brief; I believe it wiI1 last approximately 1 to 1 1/2 hours. Our intent is to emphasize those points which we feel are the most important and to provide a forum from which the Commission can ask ques- tions on Project specifics. In our testimony today, the Working Interest Owners will show that the Flow Station 3 Injection Project meets the following three requirements as stated in the Windfall Profit Tax Act~ first, that the Project involves the application of a qualified tertiary recovery method in accordance with sound engineering principles that will result in more than an insignificant amount of incremental crude oil~ second, that the Project beginning date is after May, 1979; and third, that the Project area is adequately delineated. To do this, we have divided our testimony into three parts as shown in Slide 1. ARCO, as Operator of the Project, will be presenting the majority of the testimony. The first part of our testimony will briefly discuss the overall Project and will include a summary of Project objectives, Project delineation, Project design, required facilities, implementation plans, and surveillance plans. The second part of our testimony will involve a discussion by each of the major Working Interest Owners of their numerical simulation studies that have indicated that signifi- cant incremental oil recovery will result from implementation of the miscible gas process. Finally, the last part of our testimony will tie together the presentation and focus specifically on how the Project meets each of the Internal Revenue Code requirements. I would, at this time, like to introduce the four witnesses that will be pre- senting today. They are Hr. Bill Nelson, Mr. Terry Day, Dr. Scott Williamson, and Mr. Roger Doughty. At the end of our presentation this morning, the witnesses would like to form a panel from which to answer the Commission's questions. This panel could also answer at that time any ouestions you mi.oht have concerning the Application for Additional Recovery. I would like to ask at this time if the witnesses could all come forward in a group and be sworn- in~ and I would also like to ask that they be accepted as experts. We have prefiled our testimony and each of the witnesses has included in that test- imony a short statement of his qualifications. Testimony Outline - Project Overview - Supporting Reservoir Simulation Results · ARCO Alaska, Inc. · Exxon Corporation · Sohio Alaska Petroleum Company - Windfall Profit Tax Law Requirements Discussion of Overall Project Members of the Aiaska Oil and ~as Conservation Commission, ladies and gentle- men~ my name is Bill Nelson. Since receiving my graduate degree in engineering from Purdue University in 1975, I have been employed by ARCO. I have spent over seven years working various aspects of arctic and reservoir engineering. I became involved with the Prudhoe Bay development plans and reservoir engi- neering studies in 1979, and I presentiy hold the title of Senior Area Engineer for Prudhoe Bay EOR.. This morning I'd like to briefly summarize the engineering aspects of the Flow Station 3 Injection Project. I'd first like to discuss the reasons why the Working Interest Owners have decided to pursue miscible gas as a viable process for Prudhoe Bay at this time. I'd then like to discuss the design of our project and facilities required, and follow that with a brief overview of our implementation plans and surveillance program. The Flow Station 3 Injection Project is a small scale miscible enriched hydro- carbon gas project. As you can see in Slide 2, the Project is located within the Prudhoe Bay Unit in the western ~downstructure area of the ARCO operated portion of the Field. Our planned execution of primary and secondary operations at Prudhoe Bay is projected to yield an estimated ultimate recovery of approximately nine billion barrels of oil, leaving more than 10 billion barrels of oil trapped in the Sadlerochit reservoir. With such a large volume of oil at stake, the Working Interest Owners recognized the potential' of increasing recovery through the application of tertiary recovery methods, and the need to evaluate this poten- tial as quickly as possible so as to ensure proper development. Screening studies were conducted to better define the applicability of the leading enhanced recovery methods at Prudhoe Bay. The studies fell into four cate- gories: 1) miscible gas displacement processes, 2) surfactant flooding, 3) enhanced waterflood techniques, and 4) thermal processes. I'd like to now summarize the results of these studies. The miscible gas processes were found to be the most viable for the Sadleroch£t reservoir at this time. The. miscible gas process has been technically proven and has been used in the petroleum industry for several years. Although surfactant flooding may have some potential in the long term, our studies did not find' a surfactant currently available .that could withstand the wide range of temperatures and salinities that are expected to be present in the reservoir. Enhanced waterflood techniques, such as caustic or polymer flooding, were found to possess some limited potential in improving our waterflood performance. However, the techniques are not cost effective because of problems associated with the logistics of supplying large quantities of chemicals to this remote Arctic location. Finally, thermal processes were eliminated since the depth and pressures of the Sadlerochit formation make these processes economi cally i nfeasible. Of the various types of miscible gas processes, miscible enriched hydrocarbon gas injection was chosen at this time because the required injectant properties . can be formed using presently available Prudhoe Bay Field processing streams. The miscible gas will be injected sequentially with water in a manner referred to as WAC injection or Water-Alternating-Cas injection. This injection is expected to continue for at least 10 years or until more than a 10% PV slug of miscible gas has been injected. We expect the EOR Project to start-up by the end of 1982, and we expect the Project to recover at least an incremental 24 MMSTB of crude oil. In moving forward, the Working Interest Owners see this Project as accomplish- ing the three main objectives listed in Slide 3. First, the Pro~iect will add to the recoverable reserves of the Field; secondly, the Project will allow us to test the effectiveness of a miscible gas process at Prudhoe; and finally, the Project will provide us with design and operating information that could be used in possible future applications. Up to this point, I've presented a brief overview of why we're pursuing a miscible gas project at Prudhoe. I'd now like to describe this Project in a little more detail.. As can be seen in Slide 4, the Flow Station 3 Injection Project is located in all or parts of Drill Sites 1, 6, 12, 13 and 14 in the Eastern Operating Area. Specifically, the area chosen encompasses all or portions of Sections 10, 11, 12, 13, 14, 15, 23 and 24 in Township 1ON, Range IL~E, and Sections 18 and 19 in Township 1ON, Range 15E. The Project encompasses approximately 3650 acres and contains approximately 1.02 billion barrels of pore volume. The original oil in place is estimated to be 440 MMSTB. This particular area of the Prudhoe Bay Field was chosen for.three reasons. First, the area possesses a relatively low free gas saturation. This means that contamination or dilution of the injectant will be minimized in this down- structure area. Secondly, the Project area possesses a relatively high reser- voir pressure. Currently, the average pressure in the Project area exceeds 3900 psi. The high formation pressure makes it. easier to maintain misci- bility conditions for the injectan't and reduces the amount of water injection required prior to start-up. Finally, the area has access to sufficient volumes of water and miscible injectant. Flow Station 3, the gas-oil-water separation facility for this general area of the Field, is located nearby and acts as the centralized point for processing the miscible gas and produced water needed for injection. In fact, the name of the tertiary project is taken from the importance attached to Flow Station 3. As can also be seen in Slide 4, the Project boundaries have been delineated areally by the upstructure water injectors on the north, by the outermost producing wells in the patterns on the east and west, and by the down dip development limit in the south. The vertical delineation is shown in Slide 5. Vertically, the Project encompasses the light oil column of the Sadlerochit; that is, the ~ interval from the top of the Sadlerochit formation to the top of the heavy oil/tar zone. The heavy oil/tar zone will not be affected by the miscible gas injection. The basic geology of the area is also shown in Slide 5. The Sadlerochit formation is commonly divided into five main zones. In order of increasing depth, these zones are referred to as the Zulu, X-Ray, Victor, Tango, and Romeo. Within the Project boundaries, only the Zulu/X-Ray and part of the Victor will be affected. The Zulu/X-Ray zones are compOsed of fine to medium grained sandstones with many interbedded, mostly discontinuous', shales. The Victor, on the other hand, is composed of a conglomerate section in the upper half grading to a coarse grained sandstone in the lower half. A shale, separ- ating the X-Ray and Victor zones, is found in a large portion of the Project area, as are several faults. No original gas cap is present within the Project area, but some localized free solution gas may be present near the existing producers. By year end, the average reservoir pressure in the area should be approximately 3900 psia. At this pressure, the gas saturation will be at or near the critical oas satur- ation of around 3 to 4%, but this volume of gas will not have a significant impact on Project performance. A substantial water interval underlays the entire Project area. Directly over- lying the aquifer is a heavy oil/tar zone consisting of highly viscous crude which ranges from 20 to 60 feet in thickness. As I mentioned earlier, due to the low mobility of this heavy oil/tar zone, injeotivity into this zone is expected to be very low and the WAG injectors will not be perforated in this portion of the oil column. The next slide, Slide 6, begins to address the reservoir engineering aspects of the Flow Station 3 Injection Project. Within this 3650 acre Project are l l WAG injectors, 7 upstruoture water injectors and 42 producers. On the slide, the WAG injectors are' represented by triangles, the water injectors by squares, and the producers by circles. The injection pattern chosen for the Project is an inverted nine spot pattern developed on 80 acre well spacing. Thus, each pattern, itself, encompasses 320 acres. The inverted nine spot was selected primarily for its flexibility in conversion to other pattern configurations and for its initial 3 to 1 producer to injector ratio. Since the well injeotivity is expected to be higher than the well productivity, the 3 to 1 ratio should allow more versatility in balancing pattern withdrawals and injection. It is anticipated that about 40-45 MMSCF of enriched hydrocarbon miscible gas will be injected into the Project on a daily basis using the WAG injectors. This is equivalent to an injection rate of 27-30 MRVB/D at the temperatures and pres- sures expected to be present within the Project area. Injection will continue until at least a 10% PV slug of miscible gas has been injected. As I mentioned earlier, the Flow Station 3 Injection Project requires the . . injection of water as well as miscible gas. Produced water will be alternately injected with the enriched gas into the WAG injectors to provide pressure maintenance and to reduce the "channeling" tendency of the lower viscosity gas. In the literature, this benefit is referred to as mobility control. Water will also be injected into the 7 upstructure water injectors to help maintain miscibility pressure, to help confine the miscible gas to the Project area, and to help Shut off gas cap gas that might otherwise enter the Project area. Approximately 90 MBWPD is estimated to be required in the WAG wells and 100 MBWPD may be required in the upstructure water injectors when the Project has been underway for several years. To provide the water and miscible gas to the Project area in this time frame necessitates a substantial investment in new facilities. I'd like to briefly discuss the facility design for the Flow Station 3 Injection Project. The addi, tional faciltiies are required for two purposes~ first, to process, blend, and inject the miscible gas, and second, tO provide adequate water volumes prior to the fieldwide waterflood. The miscible injectant is composed of several liquid and gaseous streams from existing Prudhoe Bay Facilities as shown in Slide 7. One source of l~iquids is the Field Fuel Gas Unit or FFGU. The FFGU processes separator off-gas in the field, and by lowering the hydrocarbon dewpoint of this gas to -40°F, produces fuel gas that is used in the Field and by ^lyeska in its first four pump stations. Low molecular weight hydrocarbon liquids drop out as a by-product of the gas conditioning. Currently, a portion of these liquids are spiked into the oil pipeline. After Project start-up, these liquids will be used to form the miscible gas. All of the other sources for the enriched gas are connected with Flow Station 3. As indicated in the facilities block diagram, they include scrubber lio. uids from the separator off-gas processing equipment and compressed off-gas from the Intermediate Pressure or IP separator. If required, dehydrated high pressure residue gas will be added to supplement the IP compressor gas volumes. The Flash Drum Liquids from the FFGU, the scrubber liquids from Flow Station 3, and the IP compressor gas are all sent to a new process module located ad.iaoent to Flow Station 3. As shown in Slide 7, in this adjacent module the liquids are pumped and the gas is compressed up to a pressure of approximately 4000 psi. The fluids are then blended to form a supercritioal fluid that is subse- quently delivered to Drill Site 13 for injection. This mixture, which contains about 42% methane, 12 i/2% CO2 and 45 1/2% hydrocarbon intermediates, is miscible with Sadleroohit crude oil at approximately 3700 psi. The facilities for the miscible gas have been designed to be compatible with previously planned Prudhoe Bay facilities and should provide 40-45 MMSCFD of gas for at least 10 years. However, it should be noted, that the availability of the enriching feedstocks is time dependent. The supply of miscible gas is not infinite. Due to the declining oil rates expected in the 1990's, the volumes of scrubber liouids and IP compressor gas are expected to decrease which will affect the injeotant availability. The water requirements of the Project are largely provided for by the existing and planned produced water and source water injection facilities. However, new facilities are required to augment the supply of water prior to the start-up of the Beaufort Sea waterflood in mid-1984. Therefore, to supply the necessary supplemental water, four wells at Drill Site 14 will be perforated in the Sadleroohit aquifer and artificially lifted with high pressure gas. The .oas lift gas will be supplied by three new 1200 hp turbine compressors housed in a separate module at Flow Station 3. The four wells are expected to provide 40-60 MBPD of supplemental water in addition to the 25-35 MBPD of water produced with the oil from other wells in the FS-3 area. This total volume of water, namely 65-95 MBWPD, will be sufficient to supply the Project needs until Beaufort Sea water is available. In addition, as water production within the Field increases due to Low Pressure Separation and Artificial Lift being made available to the producing wells, the supplemental water from Drill Site 14 will be gradually phased out. The anticipated well and facility costs for the Flow Station 3 Injection Project are estimated to be 110MM$. In Slide 8, the new facilities and pipelines required for the Project are shown in red. The major investment items are: 1) the Process or Injection Module, 2) the Gas Lift Compressor Module, 3) the Flash Drum Liquid pipeline to Flow Station 3, and 4) the mis- cible gas pipeline to Drill Site 13. I'd like to now leave the design of the Project, and move forward and address our implementation and surveillance plans. As I mentioned earlier, our North Slope construction personnel are moving forward as expeditiously as possible to ready the new facilities for start-up by year end. Project start-up will in several stages as shown in Slide ¢. The first stage will involve some pre-injection of water into some of the WAG injectors and into the upstruoture water injectors. Produced water at Flow Station 3 which is currently being disposed of in the Cretaceous sands will be redirected to the Project area through existing Produced Water Injection or PWI facilities starting in late November. Following start-up of the three small interim gas lift compressors in early December, the supplemental produced water from Drill Site 14 will join the other produced water and bring the total pre-injection to approximately 50-70 MBWPD. Besides providing pressure support and retarding the advancement of the gas tongues into the Project area, the pre-injection of water will also reduce the free solution gas concentration around the WAG injectors and will improve the injectivity profile of the miscible gas when injected. The next start-up phase involves the injection of the 40-45 MMSCFD of miscible gas into three or four of the eleven WAG injectors. This is expected to occur near the end of the year and this date will be the "Project beginning date" for the Windfall Profit Tax purposes. After a period of gas injection into these first wells, water injection will follow into these initial wells and another set of WAG injectors will commence taking miscible gas. It is anticipated that several sequences will be required before all of the eleven WAG injectors have received miscible gas. Although the actual length of each enriched gas cy. cle will be determined by operational experience and reservoir performance, it is currently estimated that the miscible fluid will be injected in 1 to 3 month periods. The WAG ratio, that is, the amount of water to be injected alter- nately with the gas, will be adjusted to maintain the pressure in each pattern above the minimum miscibility pressure. By 3anuary 1, 1983, 51 of the 60 planned project wells are expected to have been drilled. This includes all eleven of the WAG ~injectors, five of the seven upstructure water injectors and 35 of the 42 producers. The other 9 wells will be made available throughout the year 1983 as part of our planned Field development. Total production rates from the Project area will be controlled as closely as possible to achieve a balance between injection and production with the overall goal of individual pattern balancing and maintenance of miscibility conditions. Although not a part of the start-up plans, a number of other Field expansions will occur during the first two years that will affect Project operation. Low Pressure Separation and Artificial Lift will become available to the Project producers during the first 15 months of operations. These facility expansions will greatly enhance the productivity of our wells; they will allow us more flexibility in pattern balancing and will allow us to handle more water pro- duction in the Project wells. As a result of the ability to produce more water in the Flow Station 3 area, we should be able to phase out the supplemental water production at Drill Site 14 within two to three years. Another major expansion, the Beaufort Sea waterflood, is expected to start-up in mid-1984 and will make available approximately 100 MBPD of sea water for injection into the upstructure water injectors. It is important to note that the Beaufort Sea water cannot be used in the WAG injectors. Only relatively warm produced water can be used in these wells since unheated sea water would form hydrates with the miscible gas in the wellbore during change overs between gas and water inject ion. That concludes my remarks on implementation~ I'd next like to summarize some of our surveillance plans. As I mentioned at the beginning of my presentation, ~ one of our objectives for the Flow Station 3 Injection Project is to test the effectiveness of the miscible gas process. For this reason, an extensive surveillance program has been planned to monitor and optimize the enriched gas drive process. The existing fieldwide surveillance program will be supple- 10 mented by the use of observation wells, cores, an expanded cased hole logging program, more frequent production well surveys, and a radioactive gas tracer program designed to track actual injeotant movement in the reservoir. As shown in Slide 10, we have designated the inverted 9-spot pattern surround- lng WAG well 13-6 as the key observation pattern. As presently envisioned, one or two non-perforated observation wells will be drilled around Well 13-6 to monitor gas and water movement and to help evaluate the near term effectiveness of the tert. iary process. These wells will be completed with non-conductive fiberglass casing to facilitate the periodic use of induction logs to monitor water saturations. The propagation of the enriched gas front past the observa- tion wells will be monitored with neutron logging devices. The observation well logging program will provide a time-lapse description of changes in water and gas saturations versus depth. From these measurements, we hope to evaluate, · perhaps within 1 to 2 years after Project start-up, the effectiveness of the tertiary process in forming a miscible zone and in mobilizing the crude oil. Additional coring has also been performed within the Project area to increase our understanding of the reservoir properties in this portion of the Field. By Oanuary, 1983, five wells will have been cored within the Project boundaries as indicated in Slide 11. These wells are 12-9, 13-4, 13-19, 13-25, and 13-98. Well 13-98 is one of the observation wells. The cores will provide us with information on permeability, porosity, lithology and fluid saturation for use in future performance studies. To better monitor the operational aspects of the Project, an expanded cased hole logging and well survey program has been developed. Baseline logs will be run in the producing wells to establish the gas and water saturations existing 11 at the beginning of the Project. Periodic repeats will be run in selected producers to monitor flood performance throughout the Project life. In addi- tion, spinner and tracer surveys will be used to monitor the production and injection profiles. Finally, bottomhole pressure build-ups will be obtained in each inverted 9-spot pattern to ensure that the reservoir pressure is b.eing maintained above the minimum miscibility conditions. One of the best overall qualitative tools to assess Project performance will be the use of radioactive gas tracers. A program has been developed to inject one of four different tracers into each WAG injector during its first miscible gas cycle. Gas samples will then be taken from each Project producer monthly and analyzed for the presence of each tracer. The gas analysis results will provide a means of determining areal gas movement and may give us an indication of volumetric sweep efficiency. These results may be especially important in those areas where' faults are present. The surveillance program that I have just outlined is not inexpensive. For 1983 alone, t. he program is estimated to cost over 4 MM$ and that is excludino the cost of the observation wells and cores. This represents a significant on-going commitment by the Working Interest Owners to the PrOject objectives that I outlined earlier. 12 Flow Station 3 Injection Project PROJECT LOCATION ,Flow Station 3 Injection Pro 100' gross light oil column Project Objectives increase Recoverable Reserves · Test Viability of Miscible Gas Process at Prudhoe · Provide Design and Operating Basis for Future Applications I I i 0 I I I f 0 0 0 0 DrIll Site 6 Drill Site 14 o Flow Station 3 Injection Project 4 O O PROJECT DELINEATION I I ; 0 0 ; I I I Drill Site 1 I I I O I L_ I I I I Drill Site 13 I I I I I I I I I I I I_ I WAG Injector Producer ~ Upstructure Water Injector Drill Site 12 I I O I 00' gross light oil column I Flow Station 3 Injection Project Basic Geology and Vertical Delineation of Project Original GOC / Upstructure Water Injectors Project Encompasses Light Oil Column Downstructure Development Limit / Gas [Oil HO/T Water Shale · 14-18 · 14-6 · 14-5 14-11 · 14-10 14-9B ~1 14-17 · · 14-21 Flow station 3 Injection Project 6 AREAL PATTERN DESCRIPTION - · 6-14 · 6-4 i · 6-13 O 6-8 ~14-29 ~ 13-23A ~ 13-17 I. 13-1. ~ I ~13-1 /~13-2 ~13-3 / // ~ 112-13 112-1 ~ ~ '~1 ~/ 13-25 ~ ~ 13-34 .... '~_~ ~ ~ I ~ 13-32 113-14 4 / ~ ~a-zz ~12-17 ~13-21 ~ 12 18 ~4-22 /' I ~ ~1333 ~ ~ ' ~2_/'~ ~ ~.-~o-~s /I I~2-5 4-9A~ /' I l~3-30 ~ ' ~~.-4 _~='= / ~12-4A ~ 12-~ t 12-3 / ~ ~ · ~ ~ 12-16 ,,JECT,O. PROJEC~ AREA I~= .... ~3-. ~=, ~3-~0 ~-~ . ~=-8~ B ~ ~9.~0.~,. ~2-~0 ~=.~ ~ 12-14 24-10-14 Legend R14E R15E WAG Injector Producer ~ Upstructure Water Injector Flow Station 3 Injection Project Source and Processing of Miscible Injectant Stream FFGU Flow Station 3 Flash Drum Liquids Scrubber Liquids Intermediate Pressure-Gas and/or Residue Gas Process Module Miscible Injectant to DS 13 F~ow Station 3 injection Project MAJOR FACILITY ADDITIONS Gas Lift Compressor Module Drill Site CC~P and ., I!iFACILITY ADDITIONS Injection Module Drill Site Dril~2Sit~e Flow ':. station ...i"i #3 .=:..'.""'~*'*? Drill Site %'..° '".-~..:. 10" Miscible Fluid % ~J' Injection Line '"'"~-'.-. Orill Site '.'... 12" Flash Drum Liquid Line November 1982 December 1982 Late December 1982 January - June 1983 January - July 1983 January - March 1984 July 1984 Flow Station 3 Injection Project Start-Up Sequence Produced Water Injection Upstructure Supplemental Produced Water from Drill Site 14 Miscible Gas Injection Initiated into 3 or 4 WAG Wells Sequential Start-Up of all 11 WAG Injectors Start-Up of Low Pressure Separation at FS-3 First Increment of Fieldwide Artificial Lift Major Beaufort Sea Waterflood 14-13 10 14-12 Flow Station 3 Injection Project LOCATION OF KEY OBSERVATION PATTERN 14-14 13-17 ~ 13-23A 13-18 / \ 6-11 / / / \ / \ / 13-20 12-19 14-30 14-9B ~ Upstructure Water Injector \ 13-19 ~' 6-17 , ! \ 12-20 ~ 13-24 / \ ~_~-~ ,e'~.~ ~ .... ,~.~ 'a~-~ I 14-8 ~ / ~ / X~ I ~12-12 L1'18 / 13-33 13 4 ~::~ ~~ -10-15 1 30 ~ ' :13-5::~ ~s-~ ~ / ' ~ECT~O~ ~O~ECT ~E~ I $~-~= ~?'=~ / ~ ~..-..:---~~~='~ WAG Injector ~ ~ I ~ Producer 13-8 R14E R15E 11 14-9B 14-13 14-12 4-29 14-28 ~ 13-23A / / ~'14-26 ! ! 14-30 14-8 \ ~1~'..~26 ~ 13-32 ~14-22 . 4-9A ~,,,~,~ 14-9 " /'1 FS-3 INJECTION PROJECT AREA WAG Injector Producer 14-14 13-17 '~6-12 \ \ ~ 13-24 /'~ 6-17 \ 6-11 / 13-13 13-12 13-18 6-9 Flow Station 3 Injection Project CORED WELLS 13-19 13-20 12-19 ! \ 12-20 ,~13-2 ' '~13-3 // / / %' ,. /~12-12 (~13-34 ' ~ ~3-22 ~'12-17 ~k13-21 ~ / /\ 12-4 ,-x PUT RIVER l 12-9 13-16 k' It~' 13.11 \ / ~ ~13-6 / \ 12-16 / \ {11~'13-10 '~,,,13-7 I \ 12-8A 12-18 13-27 13-9 12-1 ~ Upstructure Water Injector I 13-8 R14E R15E Numerical Simulation Studies Mr. Marquez indicated at the beginning of our testimony this morning that the second part of our presentation would involve a discussion of the numerical simulation studies that evaluated the recovery potential of the miscible enr£ched hydrocarbon gas process. I would now like to begin that discussion. Miscible gas has not been used previously in the Sadlerochit formation, and accordingly, the recovery estimates are based on extensive numerical simulation of the tertiary process in the downstructure portion of the Flow Station 3 area. Because of the importance of the incremental recoveries to overall Project economics, all three major co-owners; that is, ARCO, Exxon and Sohio, have performed their own independent simulation studies. Although each company used different approaches and different reservoir models, the results from the three companies indicate that the displacement of a 10% PV slug of miscible gas will recover an additional 5.5% of the original oil in place over conventional pattern waterflooding developed on 80 acre spacing. This corresponds to a 24 MMSTB increase in ultimate recovery from the Project area. At this time, each of the three major Working Interest Owners would like to present their simulation work in more detail. I will first present ARCO's results. ARCO undertook a large scale reservoir model study to: 1) determine the incremental recoveries associated with miscible gas injection, 2) define project sensitivities, and 3) develop an optimum implementation plan. The model employed was a sequential, semi-implicit four component miscible simu- lator which is formulated to represent gas, oil, water and solvent systems. ARCO chose to use the Four Component Model instead of a more rigorous fully Compositional Model for three reasons. First, the Four Component Model runs computationally much faster which makes it easier to evaluate a larger number of cases~ secondly, the model results are easier to interpret; and thirdly, the recoveries predicted by the Four Component Model are comparable to those found using a fully Compositional Model since, as I'll describe a little later, Compositional Model results were used to calibrate our Four Component Model. Slide 12 shows the portion of the Project area that was simulated. The sym- metrical strip extended north into the gas cap and south into the aquifer to correctly incorporate pressure boundary effects. Slide 13 shows the actual grid used. The 3-D strip was represented by a 36 X 7 X 10 grid that contained over 2500 grid cells. The model was history matched to existing actual Project area primary perform- anoe and to the predicted future pressure performance generated with ARCO's full field 3-D simulator. Wellbore hydraulics were added to the model such that the availability of high pressure, low pressure, and gas lift could be handled. Finally, one last calibration of' the Four Component Model was obtained. Several 2-D cross-sectional runs using a fully Compositional Model were made for a hydrocarbon miscible WAG process and the Four Component Model was adjusted to match these results. I would like to discuss the results of six major cases encompassing three different reservoir producing mechanisms which were studied with the 3-D strip reservoir model. The first case invoIved the prediction of naturai depletion . performance utilizing the current 160 acre spacing, whiie the remaining five scenarios modeled frontai displacement processes employing an inverted P-spot pattern with 80 acre well development. The pattern development cases that were simulated consisted of a conventional waterflood and a ~VAG miscible dispIaoe- ment process with a 10, 15 and 25% PV slug o¢ enriched gas being injected, The ¢inai case considered a deferraI of miscible gas injection for 15 years, ^II cases were run for 30 years. The results of the natural depletion, waterflood, and 10% PV miscible gas injection cases are shown in tabular form on Slide 14. The results show that the injection of a 10% PV slug of miscible gas is estimated to increase the recovery by 5.5% over the 80 acre spaced waterflood. This corresponds to the incremental recovery of 24 MMSTB of oil that I quoted earlier. The potential does exist for higher incremental recoveries, however. Slide 15 shows the relationship between incremental recovery over waterflooding and pore volume of miscible gas injected. Injection of a 25% PV slug of miscible gas, which corresponds roughly to 25 years of injection, could raise the incremental recovery due to the EOR process to almost 11%. The decision to inject volumes · much greater than a 10% PV slug will depend upon actual project performance, in,iectant availability and future economics. One thing that is apparent from our discussion this morning is that the Flow Station 3 In~eotion Pro~eot will be started up before a waterflood has been performed in this area of the Field. During the plann, ing stages of the Pro- ~eot, one of the sensitivities that was evaluated was whether the recoveries might be higher if EOR were postponed until after the waterflood had been underway for many years. To evaluate this possibility, ARCO ran the last case that I mentioned previouslyl namely, that of a 15 year deferral in miscible gas implementation. Also, both Exxon and ARCO conducted laboratory core floods to determine whether the residual oil saturation left behind after the miscible gas displacement was influenced by the presence and amount of prior water- flooding. The results of ARCO's last case indicated that, with a 30 year field 15 life, no recovery advantage was seen for delaying the injection of the miscible gas. In fact, several disadvantages were observed. Besides the problem of injectant availability, deferral resulted in lower recoveries of the en- riched gas and higher produced water volumes. Moreover, the laboratory results showed that the same residual oil saturation in the cores was obtained regard- less of whether miscible gas was preceded by water injection or not. Thus, the Working Interest Owners of the Prudhoe Bay Fieid are in support of impIementing the Fi°w Sation 3 Injection Project at this time. This concIudes my testimony this morning. Our next witnesses wiiI be representatives from Exxon and Sohio who wiIi discuss their numericai simuIation resuits. Mr. Terry Day from Exxon, Corporation wiIi testify next. 16 ARCO 3D STRIP MODEL REPRESENTATIVE AREA STUDIED (D 12 ~ WAG Injector ©Producer l'-! Upstructure Water Injector 100' gross light oil column 13 GOC Flow Station 3 Injection Project ARCO 3D STRIP MODEL GRID GOC HO WOC NORTH L__egend ~ WAG Injector Producer Upstructure Water Injector SOUTH HO/T WOC 14 Flow Station 3 Injection Project ARCO Numerical Simulation Results Natural Depletion 80-Acre Pattern Waterflood Miscible WAG- 10% Slug Ultimate Recovery, 27.7 42.2 47.7 Ultimate Recovery, MMSTB 122 187 211 15 Flow Station 3 Injection Project Relationship of Incremental Recovery to Miscible Gas Slug Size o 12 ~ 8 o 4 0 5 10 15 20 25 % Pore Volume Slug Exxon's Numerical Simulation Results Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Terry Day, I am Exxon's Western Division Reservoir Engineer. I received a Master's of Science Degree in Electrical Engineering from the University of Florida in 1971. In the same year I was employed by Exxon Company, U.S.A., and have spent most of the past 11 years responsible for various aspects of petroieum reser- voir engineering. Since November of 1980 I have been involved with Prudhoe Bay Unit studies including the coordination of seven engineers studying enhanced recovery methods. This morning I would like to describe Exxon's evaluation of the Flow Station 3 Injection Project. As has been indicated, the technical work relative to applying EOR methods at Prudhoe started with a screening study which evaluated applicability of several leading EOR methods (Figure 1). Based on this review of processes, Exxon has concluded that miscible WAG displacement is the most promising EOR method for application at Prudhoe. However, we are continuing to perform research in other areas. Exxon's technical work concerning miscible processes at Prudhoe has included slim tube tests to verify requirements for miscibility, laboratory displacement tests to determine residual oil saturations, and numerical simulation of portions of the Flow Station 3 (FS-3) Injection Project. Exxon ran slim tube experiments which confirmed and supplemented several such tests that were carried out by ARCO. In a laboratory slim tube exper- iment, a gas with known compositions displaces oil from a long, narrow, coiled tube that is packed with sand. The gas injection rate, outlet pressure and temperature are closely requlated. Experiments using .oas obtained by mixin.o 70% FS-3 separator gas with 30% NGL's to displace Prudhoe Bay oil at reservoir temperature and various pressures, indicate that the oas and Prudhoe Bay oil would be miscible at expected reservoir pressure. I will show the results of one test in a moment. Mr. Nelson has already described results of our displacement test that were carried out using Prudhoe Bay Sadlerochit crude and cores. The major objective of the simulation study was to assess the feasibility of in3ecting enriched separator gas in the Flow Station 3 area and to evaluate the additional recovery potential. Exxon's fully compositional reservoir simulator · program and a three dimensional reservoir model were used for numerical simu- lations which predict reservoir behavior in the FS-3 area under waterflood and under several miscible WAC displacements. In a compositional simulator, the oil (or liouid) and ~as phases must each be represented, or characterized, by' a fixed number of chemical components, usually less. than 10, since a complete .specification is not practical. The components used are standard components such as carbon dioxide, methane, ethane, etc., and pseudo components defined to represent complex mixtures of heavier hydrocarbons. The simulator program calculates liquid and gas phase densities, phase viscosities and mass transfer between phases using analytical methods based on the composition of the oil and oas phases. Exxon's simulator program uses ten components - carbon dioxide, methane, ethane, propane, and six heavier-than-propane hydrocarbon components to char- acterize the actual reservoir oil and gas. The fluid characterization was developed by closely matching laboratory deter- mined bubble points, oil densities and oil viscosities to those analytically calculated. The characterization was verlfied by comparing simulation results with laboratory slim tube tests. Predicted versus actual recoveries are shown in Figure 2 for one slim tube test comparison. As discussed earlier, actual slim tube data was obtained for enriched miscible gas displacing recombined Prudhoe Bay reservoir crude. A one-dimensional simulator model was designed which represented the 20 foot long slim tube. Numerical dispersion causes the simulator prediction to be slightly conservative in this case. However, the miscible condition has been closely predicted as shown by the very high recovery, almost 90 percent, after one pore volume of injection. A confined nine-spot model of a portion of the FS-3 area (developed on 80 acre spacing) and fully compositional as well as four component simulators were used to investigate in detail the mechanics of the miscible flood. The cross- hatched rectangle shown on Figure 3 is the 320 acres within the FS-3 IP area included in the model. Parts of three 320 acre inverted 9 spot patterns are included. This configuration was chosen to minimize the effects of orid orientation on the movement of gas within the model, Gridding of the model is shown in Figure 4. The model thickness including the aeuifer is 450 feet represented by nine layers. Thin vertical blocks were used at the top so that tendencies of the misoible gas to gravity overrun oould be simulated. Porosities, permeabilities, saturations, pressures, and fluid properties were based on Flow Station 3 area reservoir data. The heavy-oil-tar zone effect was included by reduoing rook permeabilities and porosities through this zone. This model contains 60 MMSTB of original oil in place or about 15% of that in the Flow Station 3 Injection Project. To closely duplicate field practices, the production wells were completed about 120 feet above the aquifer. Water and miscible gas were injected over the intervals shown to be perforated. Injection was manaaed to match reservoir withdrawals. The estimate of vertical miscible gas conformance near injection wells is important to our studies and has been determined using separate radial models. The results of these studies have been incorporated in the following model results. A base waterflood case and several cases in which water was alternately in- jected with enriched field gas were run using this pattern model. Termination of production was based on a 10 to 1 water-oil ratio in all cases. These cases indicated that recovery is a function of the total miscible gas injected and the WAG ratio used. If miscible gas were available and could be continued to depletion, additional recovery over a waterflood was calculated to be 8% of OOIP. Since the supply of misible' gas will decrease with time, cases using various volumes of miscible gas were also simulated. Our analysis of these cases indicates that a recovery of about 8% of the 00IP can also be achieved by a 15% PV slug of miscible gas with proper reservoir management. As previous testimony has stated, the actual length of miscible .oas injection and the WAC ratios employed will be managed based on actual well productivity, injection well capacities and overall project performance. Figure 5 shows a Plot of estimated production from the total FS-3 IP area based on a scale up of Exxon's reservoir simulation of typical pattern performance. The evaluation indicates that production from the planned waterflood would peak at slightly above 55 thousand barrels per day, and then decline to depletion after the year 2000 with a recovery of about #0 percent of the oil originally in place. Injection of a 10% miscible gas slug at WAG ratios suffiicient to maintain reservoir pressure should increase production starting in the late 1980's, and increase ultimate recovery by about 5-1/2 percent of the oil originally in place. Based upon our work and the work presented today by other owners, Exxon has concluded that the FS-3 TP is a worthwhiIe project which will increase oil recovery from the Prudhoe Sadlerochit reservoir. ~Ve recommend that the AOCCC approve the Application for Additional Recovery and approve the Pro,?ect as meeting the requirements of a qualified tertiary recovery pro,iect for purposes of the Crude Oil Windfall Profit Tax Act of 1980. That concludes Exxon's remarks in support of the FI'ow Station 3 Injection Project. The next witness will be Dr. Scott Williamson from Sohio Petroleum Company. Dr. Williamson will present the results of Sohio's numerical simu- lation work in support of the miscible gas project. PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT MISCIBLE GAS STUDIES ?'791 * SLIM TUBE EXPERIMENTS TO VERIFY MISCIBILITY REQUIREMENTS ~ LABORATORY DISPLACEMENT TESTS TO DETERMINE RESIDUAL OIL SATURATIONS · NUMERICAL SIMULATION OF FS-3 IP - Feasibility Of Injecting Miscible Gas - Additional Recovery Potential - FULLY COMPOSITIONAL SIMULATOR PROGRAM - Phases Represented By Fixed Number Of Components - Phase Properties And Interaction Analytically Calculated -. Accuracy Verified By Comparing To Actual Data Figure 1 SLIM TUBE DISPLACEMENT OF SADLEROCHIT OIL BY ENRICHED GAS AT A 150 PSIG AND 200 DEG. F COMPARISON OF PREDICTIONS WITH ACTUAL DATA 7792 100 8O 6O 4O 2O · · · · SLIM TUBE D I , I i i i ,I UO.O 0.2 0.4 0.6 0.8 1.0 1.2 1.4 VOLUME OF GAS INJECTED, FRACTION PV Figure 2 PRUDnOE BAY UNIT FLOW STATION 3 INJECTION PROdECT MODEL LOCATION 7794 13-23A 3-24 · '~ 3-32 1 3- 25 13-1 13-15 13-16 FS-3 INJECTION PROJECT AREA LEGEND PROPOSED WAG INJECTOR PROPOSED WATER INJECTOR OIL PRODUCER EXXON · 13 22 13-6 '13-21 Figure 3 FLOW STATION 3 INJECTION PROJECT 3-D MODEL GEOMETRY 7795 13-19 HOT 13-25 --~ ~ 440' LEGEND · PRODUCER A INJECTOR MODEL DESCRIPTION , , THICKNESS- 450 FT. LAYERS- 9 AREA - 320 ACRES O01P- 60 MMSTB MODEL ANALYSIS 15% PV WAG - 8% O01P Figure 4 6O 50 40 30 20 10 FLOW STATION 3 INJECTION PROJECT ESTIMATE OF PROJECT PRODUCTION · ~::: FS 3 IP ili RECOVERY ESTIMATES iil .'~ c^s__2~ .~cov~_~2.~_, _~ oo,__~. ' ~, WATERFLOOD 40.1 MISCIBLE WAG 45.8 _~,''~~ ADD. RECOVERY 5.7 - wATERFL ~OOD~~~~ - ~ 1985 1990 1995 2000 YEARS Figure 5 Sohio's Numerical Simulation Results Commissioners, ladies and qentlemen, my name is Scott Williamson. I received my graduate degree in engineering from Stanford University in 1970. Since then I have been engaged in oil and gas production research, reservoir modelling and field operations. I began working on North Slope reservoir engineering in 1980, and currently I am the manager of Enhanced 0il Recovery and Reservoir Modelling for Sohio Petroleum Company. I wish to take this opportunity of addressing you today to describe briefly the work which Sohio undertook to evaluate the Flow Station 3 Miscible Cas Injection Project. Let me begin with a review of the basic idea of miscible gas drive by con- trasting it with odnventional gas drive. In a conventional gas drive it is generally found that, where gas does penetrate, the fraction of oil dis- placed is rather low, say some 30% of the local oil content. This is generally referred to as the microscopic recovery. The overall or macroscopic recovery is drastically reduced from this modest level by two effects. First, because gas is buoyant it floats up through the oil to form a thin layer near the top of the reservoir bypassing much of the oil. Second, even this thin gas layer has a pronounced tendency to break up into channels which again bypass oil and contribute to high GOR production. The end result is not an effective process for increasing oil recovery. In miscible gas drive the injected gas, on contacting the reservoir oil, combines to form a single fluid, usually a liquid. Gas mixing in this manner to form a miscible fluid effectively displaces virtually all of the oil from the portion of the reservoir accessed by it. Many laboratory tests have demonstrated that, in this process, the microscopic recovery usually exceeds 90%. Unfortunately in a reservoir the injected miscible gas still exhibits the two deleterious effects already described. It was observed a number of years ago that if water were injected with the miscible gas stream, then the tendency for 9as flow to break up into thin channels would be greatly diminished. The upward segre- gation of .qas may also be somewhat reduced. The final result is an effective process, with high macroscopic recoveries, as Mr. Nelson showed earlier in discussing ARCO's results. In practice simultaneous injection of gas and water is not necessary, an alternating gas/water injeotion cycle is as effeotive and is operationally more practical. This then is the water-alternating-gas, or WAG, prooess which we are examining today. From the discussion So far you will appreciate that an analysis of a miscible gas injection project will require a good understanding of how oil, gas and water flow through the reservoir rock. This level of information would be required in any case for analysis of primary recovery or a waterflood. For a miscible gas flood we require additional information about the miscibility of the gas; that is, whether it will mix with the reservoir oil to form a single fluid, or will remain as a gas, but possibly with altered composition. Factors which determine miscibility include the chemical compositions of the injected gas and the reservoir fluids, and the pressure and the temperature of the mixture. This topic is often referred to as phase behavior. I will start the detailed account of Sohio's work with sample results showing that we can satisfactorily represent the reservoir fluid flow at Prudhoe, in the Flow Station 3 area in particular. I will also show results which demon- strate our understanding of the phase behavior. Figure 1 shows an outline map of Prudhoe Bay with an areal view of the extent of the reservoir included in our computer model of the Flow Station 3 Injection Project area. ~ou will notice that the model does not contain all of the proposed Project area, merely a representative portion. For these kinds of problems it is often more efficient to analyse a somewhat simpler, repre- sentative situation, scaling results as reouired to the total project area. During primary production there is a significant interaction between the Project area and the remainder of the reservoir. The extension of the model into the main field area permits us to model this interaction. The Flow Station 3 Injection Project area contained some 440 MMSTB OOIP. Our strip model, shown in Figure 2, contains a total of 236 MMSTB, with 72 MMSTB located inside the Project area. The model contains a total of 840 blocks in 14 layers with 20 rows and 3 Columns. The reservoir description and many of the fluid and rock properties used in our model were based on Sohio's previous reservoir simulation studies of Prudhoe Bay. For the period from 1977 to 1982 historical data is available for testing the model results. Figure 3 shows a comparison of predicted and measured reservoir pressures for this relatively short production period. We can see that there is reasonable agreement between model results and field data. It is also worth noting that when we ran a base primary production case using the Flow Station 3 Injection Project model the results were consistent with other Sohio Prudhoe Bay computer model results. The second item of information required for computer simulation of a miscible gas process is, you may recall,~the phase behavior description. We chose to represent the reservoir hydrocarbons with eight components. Compositional simulations are frequently run with a fewer number of components. However, the use of eight components enabled us to accurately match observed phase behavior data. Figure 4 shows some experimental measurements made by ARCO, the ringed points, for a test in which a sample of reservoir oil is mixed with successively greater amounts of a particular miscible gas. During this swelling test the pressure is adjusted after each &as addition to the minimum value which creates a single phase liquid. Any further reduction in pressure would result in the emergence of a separate gas phase. The curve in Figure 4 shows the corresponding results predicted by our phase behavior calculations. There is excellent agreement between theory and measurements. Let me now describe some sample results we obtained in our evaluation of the Flow Station 3 Injeotion Projeot. Our primary concern was the performance of miscible gas drive oompared to the antioipated waterflood. The next series of figures summarizes pertinent results of our model studies. First, Figure 5 shows the primary production performance expeoted for the FIow Station 3 Injeotion Project area. The anticipated ultimate reoovery is 28% of OOIP. The next plot, Figure 6, shows the improved recovery which oan be expected from waterflood together with additional- infill wells. This raises the ultimate recovery to 39.1% OOIP after 30 years of produotion. The third figure of this series, Figure 7, shows the further improvement which miscible gas drive should attain. After injeotion of a 15% PV slug of misoible gas this amounts to an additional 8.3% OOIP, for an ultimate recovery of 47.4% OOIP, that is, some 33 MMSTB of additional oil. We. can see, in passing, that at 10% PV miscible gas injection the incremental oil produotion is 5.4% OOIP. The preoise recovery value depends on many variables: the Project lifetime, the injected gas oomposition, the misoible gas and water injection rates and the number and configuration of produotion wells. The final results we have just inspected correspond to 25 years of miscible gas injection at a rate of approximately 0.6% of the pore volume per year with an average water-to-gas injection ratio of 2 to 1. This case was one of many which we examined during our evaluation work. As illustrated in Figure 8, our conclusions may be summarized as follows: 1. Sohio's evaluation of the Flow Station 3 Injection Project shows that miscible gas drive with a 15% pore volume injection contibutes an addi- tional 8.3% OOIP to the ultimate recovery. 2. Sohio's results are in general agreement with ARCO's and substantiate the view that the Fiow Sation 3 Injection Project does satisfy the require- ments for a qualified tertiary recovery project, We therefore urge the Commission to permit the Project for additional recovery and approve the Project as a qualified tertiary recovery project. Thank you for the opportuni'ty of making this brief presentation of our work on the Flow Station 3 Injection Project. The next witness will be Mr. Roger Doughty from ARCO Alaska who will discuss how the Project meets the require- ments of the Windfall Profit Tax law. SOHIO OPERATING AREA ARCO OPERATING AREA EXTENT OF ORIGINAL GAS CAP 100 FOOT OIL COLUMN BOUNDARY PRUDHOE MAIN BaY FIELD AREA FLOW STRIP STATION MODEL · 2 FS 3 STRIP MODEL GOC AFFECTED AREA WAG ,_ WOC WOC O OIL PRODUCER WATER INJECTOR WAG INJECTOR MODEL AND FIELD PRESSURE COMPARISON 0 0 oo oo 440O 43OO 4200 4100 4000 3900 3800 37O0 3600 3500 34OO 33OO x I i i I ! 1977 1978 1979 1980 1981 1~982 YEAR LOCATION MAP MODEL PRESSURE ROW 1 24 HOUR SHUT IN PRESSURE FIELD DATA FROM WELL 2-6 PBU'S SWELLING ARCO EXPERIMENTS AT 200°F EXPERIMENTAL DATA ISwelling Of Fluid D2 (Prudhoe Bay Crude) By Fluid E (Possible Miscible 'Gas Mixture)1 5O0O 4000 30OO 2O0O 1000 O EXPERIMENTAL DATA --- R-K EOS (8 COMPONENTS) · ~ ESTIMATED CRITICAL POINT 0 0.2 0.4 0.6 0.8 1.0 MOLE FRACTION OF FLUID E 5O 4.5 40 55 3O 25 20 15 I0 5 PROJECT PERFORMANCE PRIMARY PRODUCTION 78-82 DEPLETION FOLLOWED BY WATERFLOOD FOLLOWED BY MISCIBLE GAS 'INJECTION 1980 1985 1990 1995 2000 2005 WAG WATERFLOOD DEPLETION 2OIO TIME,- YEARS CONCLUSIONS SOHIO'S EVALUATION OF PROJECT SHOWS THAT WITH A 15% ADDITIONAL RECOVERY. PV INJECTION 8.3% O01P TO THE FS3 INJECTION MISCIBLE GAS DRIVE CONTRIBUTES'AN THE ULTIMATE SOHIO'S RESULTS ARE IN GENERAL AGREEMENT WITH ARCO'S AND SUBSTANTIATE THE VIEW THAT THE FS3 INJECTION PROJECT DOES SATISFY THE REQUIREMENTS FOR A QUALIFIED TERTIARY 'RECOVERY PROJECT. Tax Discussion Members of the Alaska 0il and Gas Conservation Commission, ladies and gentle- men~ my name is Roger Doughty and I have been employed as a petroleum engineer by ARCO since 1972. I received a B.S. degree in petroleum engineering from the University of Oklahoma in 1970 and received a M.S. degree in petroleum engineering from the same university in 197Z. I have been involved with the development of the Prudhoe Bay Field for over seven years and I am presently the Prudhoe Bay Regional Reservoir Engineer. In the next part of this hearing, we would like to discuss how the proposed Flow Station 3 Injection Project specifically meets each one of the require- ments for a qualified tertiary recovery project for purposes of the Crude 0il Windfall Profit Tax Act of 1980. The Windfall Profit Tax Act provides that an enhanced oil recovery project is a qualified project if the operator submits a certification stating ~hat the jurisdictional agency, in this instance, the Alaska 0il and Gas Conservation Commission, has approved the project as meeting the requirements of the law. The specific requirements are found in subparagraphs' (A), (B) and (C) of Section 4993(0)(2) of the Internal Revenue Code. Slide 1 lists the require- ments in those three subparagraphs. The subparagraphs specifically state that a project will qualify if: (A) the project involves the application (in accordance with sound engineering principles) of 1 or more tertiary recovery methods which can reasonably be expected to result in more than an insig- nificant increase in the amount of crude oil which will ultimately be recovered, (B) the project beginning date is after May 1979, and (C) ' the portion of the property to be affected by the project is ade- quately delineated. We are requesting that the Commission approve the Project as meeting each of these requirements and I would like to discuss each one in detail. , There are basically three parts to the requirement in subparagraph (A)~ namely, the application of a qualified tertiary recovery method, the implementation of the project in accordance with sound engineering principles, and a reasonable expectation of more than an insignificant increase in the recovery of crude oil. First, the Flow Station 3 Injection Project does involve the application of a qualified tertiary recovery method, as those methods are defined in the Windfall Profit Tax Act. The Windfall Profit Tax Act defines a tertiary recovery method as one that meets one of two qualifications. Either the method is described in subparagraphs (1) through (9) of section 212.78(c) of the Dune 1979 energy regulations~ or the method has been approved by the Secretary of the Treasury. As discussed previously, the enriched gas WAG injection method which is planned for use in the Flow Station 3 Injection Project is a miscible fluid displace- ment method. Miscible fluid displacement is listed as a tertiary recovery. method in subparagraph ('1) of the section 212.78 (c) of the referenced 3une 1979 Department of Energy regulations. The Flow Station 3 Injection Project involves the injection of enriched natural gas into the oil reservoir at pressure levels such that the gas and reservoir oil will be miscible, The cumulative amount of injected gas measured at reservoir temperature and pres- sure is reasonably expected to be more than 10% of the reservoir pore volume being served by the injection wells, This miscible displacement process involves the alternating injection of water and gas which is specifically recogn£zed in the Department of Energy regulations, Thus, the Flow Statlon 3 Injection Project does employ a qualified tertiary recovery method, Secondly, this miscible fluid displacement process will be applied in the Flow Station 3 Injection Project in accordance with sound engineering principles. The planning and implementation of the Project has been under the direct supervision of qualified and experienced reservoir engineers. Our testimony this morning and the certification document have clearly shown the planning and integrated effort that has been applied to this Project. Miscible fluid displacement using enriched hydrocarbon gas was selected as the best method to use at this time for this portion of the reservoir only after a comparative examination of the various methods based on reservoir conditions, injectant availability, and process costs. The results of our screening studies were discussed earlier in this hearing. The Project facilities have been designed to be compatible with previously planned facilities and construction has proceeded without impacting other Prudhoe Bay projects. The WAG method of injection and the inverted .nine-spot inject ion pattern were chosen only after a thorough reservoir simulation study by the Working Interest Owners. Implementation has been planned to give us as much flexibility as possible in our field operation. 3 The legislative history to the Windfall Profit Tax Act provides that a tertiary recovery project which has not been preceded by secondary recovery methods will meet the tax requirements if the "... certification sets forth an explanation of why such action was in accord with sound engineering principles." Further, the legislative history provides that ". . . a project could qualify for tax purposes if the absence of secondary methods were explained adequately, and was due to peculiar characteristics of the reservoir or oil." Because of these statements, we thought it was important to discuss in this hearing in some detail why it' is in accordance with sound engineering for a tertiary recovery project to be implemented in the Project Area prior to a secondary waterflood. Most of these reasons were already addressed in our earlier testimony; however, I would like to summarize and reiterate them at this time. For the CommiSsion's convenience, Slide 2 gives a list of these reasons also. First, the imple- mentation of this project as soon as possible provides an opportunity to maximize oil recovery from within the Project 'Area by extending injection of miscible gas .past the 10% pore volume slug, if that is economically feasible. As we indicated in our discussion of numerical simulation, higher volumes of miscible gas injection afford an opportunity for higher incremental recoveries, but the higher cumulative volumes will require more years of injection. This opportunity will not exist if we have to wait until the waterflood has been underway for many years before starting EOR. Second, the feedstock necessary for enriching the gas to make it miscible may not be economically available if the Project is not implemented until after waterflooding. In our description of the Project facilities, we mentioned the fact that our supply of miscible gas was time dependent. As the Field offtake rate declines in the 1990's, we see a somewhat proportionate drop in the volume of scrubber liquids and IP compressor gas available. Implementation now will allow us to take advantage of the highest injeotant availability. To develop another miscible gas source later in the Field life may be prohibitedly expen- sive. Also, any substantial deferment of the Flow Station 3 Injection Project could render the project uneconomic because of higher risk. Fluid migration, in- creased gas tonguing, and higher free gas saturations are all problems that may become worse in the later years of the Field life, and all negatively impact the success of the miscible gas process. Higher operating costs will definitely be a reality as we will be handling large volumes of reproduced water from the Beaufort Sea waterflood. The remote and harsh Arctic environment, itself, additionally burdens the implementation of a tertiary recovery process when compared to operations in the lower 48. Another reason for moving forward with EOR now is that valuable reservoir and operating knowledge will be gained. A successful WAG project at Flow Station 3 will encourage the implementation of projects in other areas of the reservoir. It is necessary to start the Project now to provide information early enough so that other projects may be designed and implemented in the Unit. Finally, laboratory core experiments and reservoir simulations have indicated that no recovery advantage exists in deferring the start of miscible gas injection. However, initiation of the Project at this time will capitalize on existing favorable conditions and reduce the higher risk associated with deferral. Deferral could potentially preclude the project. The reasons that I have just summarized present a strong technicaI engineering case for showing that "sound engineering principies" are definiteiy involved in our decision to implement the Flow Station 3 Injection Project prior to waterflooding. Moreover, we are not alone in this assessment. Dr. H. K. VanPoollen, a respected industry consultant, presented a paper on tertiary recovery potential for the North Slope at an EOR symposium in Virginia in Dune, 1979. To quote Dr. VanPoollen, "If we are going to use EOR, we shouId do it early. Again, the environment will not aiiow this field to be around for too many years. Things star't failing apart. ~ou have repairs. The cost of abandoning the field is going to be horrendous. It should be studied." We have now shown how this pro.iect meets two of the three requirements in subparagraph (A)~_ namely, the application of a qualified tertiary recovery · method and the use of sound engineering principles. The project also satisfies the last requirement of recovering more than an insionificant amount of incre- mental crude oil. There is estimated to be 440 MMSTB of originai oil in pi.ace in the Project Area. It is estimated that 122 MMSTB or 27.7% of this original oil in place would be recovered if only primary operations were undertaken. An additional 65 MMSTB is estimated to be recoverable if an 80 acre pattern waterflood is conducted. The implementation of the Flow Station 3 Injection Project is estimated to recover at least 89 MMSTB of additional oil over primary recovery and at least 24 million additional barrels over recovery from an 80 acre pattern waterflood. This is equivaient to an increase in ultimate ~ recovery of 20.0% (OOIP) over primary and 5.5% (OOIP) over 80 acre pattern waterflooding. An incremental recovery of 24 MMSTB of oil corresponds to an increase of 12.8% in the recoverable primary and secondary reserves and is more than an insignificant increase in the ultimate recovery of etude oil. Therefore the project clearly meets the third and final requirement of sub- paragraph (A). Subparagraph (B) of I.R.C. Section 4993(c)(2) reouires that a project have a project beginning date after May 1979. The term "pro,iect beginning date" is defined in the Windfall Profit Tax statute as the latter of the date on which the injection of liquids, gases or other matter begins, or the date on which the project is certified. Either of these two dates for the Flow Station 3 Injection Project will be after May 1979 because the Project has not yet been certified and injection has not yet commenced. Miscible injection is expected to begin in December, 1982. Subparagraph (C) of I.R.C. Section 4993(0)(2) requires that the area which will be affected .by the pro,iect must be adequately delineated. If a tertiary recovery project is' expected to increase the ultimate recovery of crude oil from only a portion of a D.O.E. property, that portion is required to be treated as a separate property for incremental tertiary oil purposes and .the Operator must delineate that portion of the property in his Certification. The Flow 'Station 3 Injection ProjeCt, as currently planned, will affect only a portion of the Prudhoe Bay Unit which is one D.O.E. property. As discussed earlier in the hearing, the area which will be affected involves 11 in,iection patterns and encompasses approximately 3650 acres. The boundaries of the Project Area have been defined as the outer producing wells of the nine spot patterns to the east and west, by the limit of .development drilling to the south, and by the seven water injection wells to the north. The Pro,iect will affect the entire light oil column of the portion of the Sadleroohit Reservoir which lies within the surface boundaries of the Project. The area which will be affected by this prOject was delineated on Slide #. A reasonable allocation will be applied to production from any peripheral well determined to be produc- ing oil from outside the Project area which is unaffected by the tertiary method. As evidenced by our testimony at this hearing and the appl'ication which was submitted previously, the miscible fluid displacement project which we plan to implement at Prudhoe Bay in the Flow Station 3 area meets all of the require- ments for a qualified tertiary recovery project under the Windfall Profit Tax statute. It involves the application, in accordance with sound engineering principles, of a qualified recovery method~ namely, miscible fluid displace- ment, which is reasonably expected to result in the additional recovery of 24 million barrels of oil from the pro3ect area. This is clearly more than an insignificant amount of crude oil. The project beginning date is after May 1979 and the proj'ect area has been adequately delineated. Based on the testi- mony we have presented today and the information contained in the application, we request that the A0C¢¢, in its capacity as a designated 3urisdietional agency, approve this Project as meeting the requirements in Subparagraphs (A), (B) and (C) of Section 4993(c)(2) of the Internal Revenue Code. This concludes the testimony by the Working Interest Owners. We would be happy at this time to form a panel from which to answer any questions 'the Commission might have. Windfall Profit Tax Requirements For A "Qualified Tertiary Recovery Project" Project Involves the AppliCation (in Accordance with Sound Engineering Principles) of One or More Tertiary Recovery Methods which can Reasonably be Expected to Result in More than an Insignificant Increase in the Amount of Crude Oil which will Ultimately be Recovered Project Beginning Date is after May, 1979 Portion of the Property to be Affected by the Project is Adequately Delineated 2 Engineering Considerations For Starting Miscible Gas Injection Prior To Waterflooding · Maximizes Ultimate Oil Reco~e'r~,Potential' · Ensures Adequate Feedstock for Enriching the Gas InjeCtant · Reduces the Higher Risk Associated with Substantial Deferral · Provides Valuable Reservoir and Operating Knowledge in the Near Term that could be Used to Design other Projects · Laboratory Work a~d Reservoir Modeling Indicate No Recovery Advantage in * Substantial Deferral ~ STATE OF ALASKA NOTICE OF PUBLIC HEARING , AlaMm Oil emi~E~commllsloo · I~: The application of ARCO ALASKA', INC., on behalf of Prudhoe Bay Unit Working Interest Owners, for (I) acldltlon recovery by miscible enrlctlecI hycIrncarix)n gas Ini~ctiofl ami (2) aPProval as CI qualified tertiary recovery prolect 'far Poses of the Crude OII Windfall Profit Tax Actof 19~). ,.**,~Noflce is hereby given that ARCO AlAsKA, INC. has --,~fie*Alaska OIl*oncl Gas Conservation Commlsolon, by letter ctat~ August :31,1982, to hold a public, hearing to provide the Pruclhoe Bay Unit Owners an opportunity to enter testimony info the p4zbllc:. record and answer cluestlons concerning the FlOw StatiOn 3' Inlet- tlon Prolect. This prolect involves the *alternating Inllctlml of water aml miscible enriched natural gas, (WAG) Into cz pertfofl of the Sodlernchlt Reservoir in the Prudhoe. Bay. Field, T_he.Cll~tlcant requests approval of (1) the Flow Station 3 Inlectlon F'r61lc~ as qulred by Section 20 AAC 25.400 Omi (2)approval as~.ol ql/~fied tertiary.recovery praltmt according' to..Imrograplts. (A}~ (B), and (C) of !RCSection4m(c)(2). , , - . :, i'TI~ hearing will be held at 9:00 AM on Friday, November 19, '982': In theQuadrant Room, Captain CcoK Hotel,' Afl.ChOCC~.., A~l~z~ka. All Interested Persons and. ;ar, eS are invited, to give testl- man-0 y, , , ' '... . ..... /S/Harry W. Kugler, Commlsoloner '~ ,:'- Alaska Oil and Gas COnsorvotlon :' · .!:~. . . Commlsolon. !'~: N°vember3. i . ,..'.., :, ,AO-Q855221 AGO 10031797 , ,, · Notice Is also given 'ltx~ MY ~erson interested may eresent written stat~ or a~ men~ re~t ~ ~ a~i~ ~ to ~ ~i~ ~ H~I~ Facllit~ U~ ~ ~lfF ~tl~, ~! C Strut, ~ I~ of ~ ~ ~ul~ are avoll~le ~ ~ ~rm ~ ~ltl~ ~ ~ ~, H~I~ Fm tion, ~1 C 5~t, P~ ~, An~r~, ~ ~. It is estimated rite ----m~--r tlon of Ii' censure regulations for the new categories of facilities and re- vised Iicensure regulations will reaulre increase om3ro~rlatlo~s in Flscx31 Year ~ of Fiscal Year ~ of ___eFt00__; Fis- cal Year 84-85 of $12,500 and Fls- col Year 8.~86 of $14,5(X).. The Health Fadlltles Llcensin~ , and Certification Section, Divi- sion of State Health Planning and Develoemeof, Dem3rtment. of Health and Sacral Services, upon its own motion m' at the in- stance of any Interested person, may oclo~t the m'm3esals sub- stontlally as described above without further notice or may decide to toke no action on them. Date: 10/27/82. '"- . o ' ~/s/ Portia Kautmonn: Chief, --- Health Facilities : ...... Licensing & Certification ...... 3601 C StreW, Pouch 6333 .... 9~2.0~, Aloha · .,,.'..Aa-06 L&C ~2-05: .,, ,,, ~,i.,, ,,,.:,,;,, !,,; :,'~.~, . P_.b: Novomber 3, ~" Lesal Notlces, t'.':~ :":' 188 case tu.~tner onrJ tlqot they De awaraecl costs om3 attorney fees incurred to date In ¥our~half. This Notice Is basedt ' the fact that rer~3tecl of~ s to contact ANITA BUR. , or other beneficiaries of PHILLIP HENRY BURKE, by mall or otherwise hove been futile. DATED at Anchorage, Alaska, this 25th day of October, 1982. McCarrey & McC~rre¥ Is/ J. E. McC~rrey, III PUb: Oct. 27, Nov. 3,10,17,1982 STATE OF ALASKA Office of the Governor~ Division of Budget & AN~ogement NO'TICE OF AVAILABILITY OF REQUEST FOR PROPOSAI~ The State of ALaska, Office of the Governor, Division Budget and Management, 'is pre,ring to Issue Request for Proposals to deslgn/~ a stasticolly valid survey for the collection of regional and demographic data. Sub- .mltted prolx)sols must demon- strate the vendors ability to con- duct a survey which meets the highest professional and ~clen- tlflc standards. Experience with sample design for rural Alaska Is alsa useful. The survey prolect will toke place b~twgen Dec:enll~r 15, 1~82 and June 301fl, 1~83. The detailed RFP Is available from fha address below. Responsdence ~ submit the survey i~rolx)sol by no toter than 5 I~.m, Nov. 2Mb, 1~62 to the Of- fica of the Governor. ,, . Authority Number 83-05-19 · Office of the Governo~ · Division of Budget " and Management: ' Juneau, Atoska ~811 - Atten. Thomas Chaser ~ ·: (~07) M5-2213 · Pub:: Nov. 1,2, 3, 4, S,.1~82 7', ;" · ~lllllOII uOItur $ The No~ SIo~ Bar. ah will accept ~1~ bl~ on,~e ~rovid~ until 1:~ a.m. time on Thur~Y, No~m~; 18, 1~ at t~ Delimit Public W~ks, ~1~ ~ t~ DI rector, Mr. I~1~ J. Igtoni~ NO~ Sl~ ~h Aamln sltratlon Building, Barrow Alusko, ut ~1~ time oll bids will ~ ~bllcly o~ r~ o1~. Bids r~l~ ~er ~ls tl~ will ~t ~ ac ~t~.' .... D~wi~ ~ P~I~' ore at t~ ~1~ ~ ~ E~I~ Review ~te~ In Anc~ ~ Fol~nkl Al~ko; o~ In ~, W~ tol~ ~m ~ ~i~ of ~nstru~i~ ~tro~ E~I ~r, LC~F, LIml~, u~ ~r~u~ble ~it ~ ~.~ ~r ~t (~ke ~k ~yuble LCMF, Limlt~). will ~ mull~ E~m ~11. Bid ~rl~ (~) In or umount ~ ~t Im ~n ~n ~r. ~m ~slc bid o~ mum ~bml~ with ~ b~. One hund~ ~r~t (1~%) Pe~rmo~ ~ hu~r~ ~t (1~) ~r end ~terlul B~s will ~ r~ ~ulr~ ~r ~ls ~1~. Bidders are advi#d to fake tlcular note of the reeulred Local Hir6 Plan and the rates on Public ~st~l~ as ~fln~ by Title ~ PUBLIC CONTRACTS. ~s p~vl~ with ~ B1~ ding and C~tr~ ~m~ are current, ~er, t~ tra~or ~11 ~Y. ~ ~ ~n t~ ~rr~t Orbiting ~gos as ~toi~ in ~ lat~ ~Hment of ~r. end of ~ ~y ~riN. . ~ld ~ !:~ p.m, I~l'tlme at' ~ DocUment Works, ~i~ of ~ DIr~, Mr. Irving J. lafonloc, North , REQUEST FOR PROPOSAL'~ . Slope Borough ,Adminl~trutlon :.., ' . NOTICE FOR PUBLICATION I~#;~'::......R_P.P..-~-12.~,. ":,Z:',~'~}~'..'. J ·Building, Berrow, Aloskaon No~ ' · Dute:Sept.,24,19~ I.'.',..~;,"'. MUNI~.I~'A&.ti'rU~':'""' '~',. , vember9 19~ , . ' , ' Notice 1, herMr/ given th~ ,',,", ......... ":*"':"'( ./,.... ' '. '"'", .... ;(iL,~%'":" L'"': ,- ' ·nessesAlaska'willlamtal~ther. H..MthRile¥.,Sr.,ofhls Mt- ,,:~ ' Th,o':' Mu~IclNIIlI~" °f'~An. ct~.'~'- J, larltles and I,to ,rolect,,my er all ' ' · ' ' ~rin~ M~,:~., ~1 ,;~'.num~ _,--[ ~, m=,.,",,,,,,f .... : ':'"' · .' :'<' .~.., ,,. t.:&' ' .;: ,t,..,'.: ;. ' ' F~~Ot~M.~'~. l'~,,Pr~ls ~11 N"~/.'""'.:':';'~'..'~;,:' :'.' '.~'??'.' ':.' '.. , .~rl~: ' "; ;~.', .,. .... ' · , .:.' ..~.,.~.;..,, ,.: '4" ~-.~-.,.' .'. ,. until 5 P.M., A,~.T, ~r .~,.., ....,, .... · .. ~..,..., ....... , Lot 1 ~ U.S. ~y No.. ~,l~e~~Pur- ' ...... , -'"'"'"'." '' '. ~, Aimko I~N o~rox- ' ~,Sln~ ~1~, ~,,W, 'SIx~ ~; ' ," ' ' Imotely !14 mile ~t~st - Ave.~' SIx~ FI~, An~r~, ~:' ' F~ ':' ,;,;~e~'~..., of Ho~l~ ~ ~roxl- 'AK (m.lll~ ~ P~ ~P~t~i~i~'~'~;,: . , iv- ~st d Anlok, ~& ;;'.,'. :..':' cu,l~ m m ~1 wlu ~ - BI~ O~ ,. '::. 'J ".~':~',~ . · - ~ntolnl~.~ ':"..':.~.;:. ~la ut 2:~ P.~, A.S.T., N~ :.~:i.:~ADSTN~e~I~ .. During the period of publlcutlen ..vember 15, 1982 ut the Purcl~s- · ..._... ~. ~ ,. ~.: .... ;, ........ .;.;,. ..- .... ' - · NOTICE OF PROPOSED LAND EXCHAIM~E. ":'ii .... ', .:~'¥';.-"'-" '.'. U.F. FISH AND WILDLIFE SE RVICE :, ..,,.~;.'~i'.: ,;:% :. ,!~".~.',','~ ' .' ' '. ,'.':'.' .' '. :. i'" .. ' ..'.' '. ' ·, ·. · '"' :" "~." ..... '.':~ ' ,~:' This notice advises the public that the Service Is negutlutlng a. ;"'" small· land exchange on Upper Ugeshlk Lake within the Alaska ~' Peninsula National Wildlife. Refuge. A maximum of five acres of land Is Involved. A draft report Is available for review. Comments t are requested by November 22, 1982. For further Information con- tact Dr. Gall S. Baker, U.S. Fish and.Wildlife Service, 101t EaSt "Pub: Oct. 27: Nov; 3,10,1982,:~t'i(~'h~,~?,i!..',T:~,:'' Or. N0..70181-0053-83 STATE OF ALASKA .... ' ......... NOTICE OF PUBLIC HEARING ~: ~.; '. -''~ ,*': ..,;;;",i;: ;" ' : STATE OF ALASKA ..... Alaska Oil and Gas CoaMrvatlon Commlsdon , :: '.~. ',;:;;'2 ..;' · y.~,~.~ .... ~;,~.,.:..f....-~-.- .... ~ The al~llcolloa of ARCO ~LASKA, INC., on behutf of the ......... Prudhoe Bay Unit Working Interest Owner~, ..... -,', recovery by miscible enric~l hydrocarbon gas Injection and ...... (2) al~roval as a qualified tertiary recovery ..... "."' poses d the Crude OII Wi~II Profit Tax Actd 19B0. ,.,,. ~ ~.~..,... -*--Notice Is hereby liven thor ARCO ALASKA, INC. has r~luested ~-~e 'Alaska Oil and G4~ Coeservutlan C, ommlulon, by letter -~.Au~ust 31, 19~2, to hold a public hearing to provide tt~ Prudhoe ,...Bay Unit OwneB ~10lN~Ortunlty to enter testimony into ~ Nbll¢ .-. record and answ~' ~stions cla3ceming the Flow Stution 3 Injec- tion Prole~. This project Involves the alternating Injection of w~ter and miscible enrlctN~l mturol ~ (WAG) Into a IX~tlon of the S4~lleroc~lt Reservoir In the Prudll~e Bay Field. The al~llcoflt requests alN3rmml d (I) the Flow Station ;3 Injection Project as re- quired by Section ~0 AAC 25.400 and (2) approval as a auallfled tertiary recovery M'olect a¢cerding to ParagraPhs IAi, (B), and lC) of IRC Sectlon 4~"J~;1(¢){2). .. The hearing will N held ut 9:00 AM on Friday, November 19, 19~2 In theQuo¢lront Room, Captain Cook Hotel, Alaska. All Interested per~ons and parties are Invited to give testl- ;. many. , . .. , · '~" .... Is/ Han'Y W. K~gler, Commissioner . - : .... Alaska OII and Gas Conservation -'Commission .,~-. ' -~ub: November 3,1982 Aa-08 5522 STATE OF ALASKA NOTICE ' WANTED-- LISTINGS OF - CITY OF ST/RARYS · . .. St. MerYs, AtoJka ADVERTISEMENT FOR BIDS :?" DOCK EXTENSION PORT OF ST. MARYS at ST. MARYS, ALASKA.?. ifructlon of a clock extoflslon ut the Perf of SI. Meryl~ Alaska,: 2. Site Preaoroflo~, 3. Pulling & S~lv~ge of Exlsflng 40' Long Hoesch 1:)4 Steel Sheet Plies, . 4. Unclassified Excoyatlon, Ri- moral & Disposal, 5. Fabricate Tieback Wnsherl From Owner-Furnished tory-Lead, 6. Procost & Install Reln~)r(~d- Concrete Tietmck Ancher Pi]- ness From Owner. Furnished Cement and Reinforcing-. Steel, 7. Fabricate 40' Long Steel Sheet Pile Compromise Plies From Owner-Furnished Rombes RZ-10 & Hoesch 134 Steel Sheet Piles, AGO 10031796 PRUDHOE BAY ,UNIT FLOW STATION 3 I NJ,ECTI,O.N PROJECT ,APPLICATION FOR APPROVAL AS :AQUALIFIED. TERTIARY RECOVERY PROJECT FOR PURPOSES OF THE CRUDE .OIL WINDFALL PROFIT TAX ACT OF 1980 AUGUST, '1982 ~'~Uc4, ~ ...... ,. AGO 10023760 PRUDHOE BAY UNIT FLOW STATION 3 INDECTION PRODECT APPLICATION FOR APPROVAL AS A (}UALIFIED TERTIARY RECOVERY PRO3ECT FOR PURPOSES OF THE CRUDE OIL WINDFALL PROFIT TAX ACT OF 1980 August, 1982 AGO 10023761 TABLEOF CONTENTS INTRODUCTION PART ONE - BACKGROUND AND FACTUAL INFORMATION Geographical Location of Unit and History of Unit Operations Description of Tertiary Processes Considered for the Unit Description of Tertiary Process Utilized, Location of Project, and History of Operations in Project Area Geologic and Reservoir Characteristics of Project Area PART TWO - PRODECT DESIGN, OPERATION AND EXPECTED PERFORMANCE Project Overview Facility Design Source and Distribution of Miscible Fluids Source and Distribution of Injected Water Project Investment Costs Project Implementation and Operation Sequence of Project Implementation Project Operation Project Surveillance Reservoir Analysis and Expected Project Performance Analysis of Expected Project Performance Estimated Project Revenue and Expenses Discussion of Implementation Timing PAGE NO. 15 18 22 22 26 26 29 31 33 33 35 37 4O 41 47 48 AGO 10023762 TABLE OF CONTENTS PART THREE - WINDFALL PROFIT TAX QUALIFICATION REQUIREMENTS Qualified Tertiary Recovery Method Sound Engineering Principles More Than An Insignificant Increase in Recovery Project Beginning Date After May 1979 Adequate Delineation of Project Area SUMMARY TECHNICAL REFERENCES EXHIBITS PAGE NO. 52 53 57 58 58 6O AGO 10023763 I Exhibit No. 10 11 12 13 14 15 16 lY 18 19 20 21 22 23 24 25 26 27 28 29 3O 31 32 33 34 35 36 37 38 39 4O 41 LIST OF EXHIBITS Description List of Prudhoe Bay Unit Working Interest Owners Letter Designating the AOGCC as the Jurisdictional Agency Prudhoe Bay Unit Map Prudhoe Oil Pool - Conservation Order 145 Prudhoe Bay Field Major Waterflood Areas Prudhoe Oil Pool - Conservation Order 165 Prudhoe Oil Pool - Conservation Order 174 Prudhoe Bay Field Production Facilities Prudhoe Bay Unit Map Showing Flow Station 3 Injection Project (FS3IP) Flow Station 3 Injection Project Surface Delineation Drill Sites Serving FS3IP Wells Sample Log Showing Vertical Delineation of FS3IP Method for Determining Heavy Oil/Tar Zone Location Project Wells Drilled as of August 15, 1982 Production History of FS3IP Structure Map of FS3IP Area Type Log Showing Sadlerochit Zonation and Shale Complexes Isopach of Shale Near the Base of the X-Ray Zone Isopach of Upper Tango Shale Isopach of Lower Tango Shale Location Map of N-5 and E-W Cross Sections North-South Cross Section of Project Area East-West Cross Section of Project Area Oil-Water Contact Contour Map in Project Area Heavy Oil/Tar Isopach Map in Project Area Gross Light Oil Isopach Map in Project Area Facilities Overview Map for Miscible Gas Injection Simplified Process Flow Diagram for FS3IP Process Module Detailed Process Flow Diagram for FS3IP Process Module Typical Miscible Injectant Composition Slim Tube Displacement Results for Estimating Minimum Miscibility Pressure Investment Costs 'for the FS3IP in 1982 Dollars ARCO's 3-D Strip Model Grid Oil Recovery Projections as a Function of Miscible Gas Slug Size Oil Rate Projections for 160 Acre Waterflood and 80 Acre Pattern Waterflood Comparison of Water Production for Early and Late Life WAG Injection Scenarios Sohio's 3-D Strip Model Grid Exxon's 3-D Pattern Grid Incremental O&M and Injectant Costs for ~$3IP Availability of Miscible Gas Injection per year for FSJIP Miscible Fluid Displacement Definitions AGO 10023764 INTRODUCTION By this application, ARCO Alaska, Inc., (hereinafter referred to as "ARCO") respectfully requests that the Alaska 0il and Gas Conservation Commission, in its capacity as a designated jurisdictional agency within the meaning of I.R.C. § 4993(d)(5)(A)(i), approve the proposed miscible fluid displacement tertiary recovery project at Flow Station 3 of the Prudhoe Bay Unit (hereinafter referred to as the "Flow Station 3 Injection Project"), as meeting the requirements of subparagraphs (A), (B) and (C) of I.R.C. § 4993(0) ARCO, as operator of the Flow Station 3 Injection Project is submitting this application on behalf of all the interest owners in the Prudhoe Bay Unit. The names of the Working Interest Owners are listed in Exhibit 1. The Alaska Oil and Gas Conservation Commission (hereinafter referred to as "AOGCC") has been designated by Governor Hammond in accordance with I,R.C. § 4993(d)(5)(A)(i) as the jurisdictional agency responsible for approving tertiary recovery projects located on nonfederal lands in the State of Alaska for purposes of the Crude Oil Windfall Profit Tax Act of 1980 (herinafter referred to as WPT Act). Attached as Exhibit 2 is a copy of the designation letter from Governor Hammond. ARCO speci- fically requests that the AOGCC approve the Flow Station 3 Injection Project as meeting the requirements that: AGO 10023766 (A) the project involves the application (in accordance with sound eng£neering principles) of I or more tertiary recovery methods which can reasonably be expected to result in more than an insignificant increase in the amount of etude oil which will ultimately be recovered, (B) the project beginning date is after May 1979, and (C) the portion of the property to be affected by the project is adequately delineated. Part One of this Application, BACKGROUND AND FACTUAL INFORMATION, contains background information on the Prudhoe Bay Unit, a descrip- tion of tertiary recovery processes considered for the Prudhoe Bay Sadleroohit Reservoir, and a discussion of the Project Area and its geologic and reservoir characteristics. Part Two, PRODECT DESIGN, OPERATION AND EXPECTED PERFORMANCE, contains a description of the overall development plan for the Project, a descrip- tion of the facilities involved, a discussion of the planned implementa- tion and operation of the Project and a reservoir analysis of expected Project performance. Part Three, WINDFALL PROFIT TAX QUALIFICATION REQUIREMENTS, discusses in' detail why the Flow Station 3 Injection Project is a qualified tertiary recovery project for purposes of the Crude Oil Windfall Profit Tax Act of 1980. 2 AGO 10023767 Additional information concerning this project is provided in "Prudhoe Bay Unit Flow Station 3 Injection Project - Application for Additional Recovery by Miscible Enriched Field Gas Injection" which is being sub- mitted concurrently with this Application. AGO 10023768 PART ONE - BACKGROUND AND FACTUAL INFORMATION Geographical Location of Unit and History of Unit Operations The Prudhoe Bay Sadleroohit (Permo-Triassio) Reservoir, located in the North Slope Borough of Alaska, was discovered in February 1968 with the drilling of Prudhoe Bay State #1. Subsequent drilling confirmed the Sadleroohit Reservoir to be a major oil and gas pool with approximately 22 billion barrels of oil and 26 trillion cubic feet of gas in place. To ensure greater ultimate recovery of oil and gas, to prevent waste and to protect the correlative rights of interest owners, the Prudhoe Bay Field was unitized on April 1, 1977. As shown on Exhibit 3, the Unit is located within Townships 10, 11, and 12 North and Ranges 10, 11, 12, 13, 14, 15 and 16 East. The Unit is divided iinto two Operating Areas with Sohio Alaska Petroleum Company operating the Western portion and ARCO Alaska, Inc. operating the Eastern portion. A Plan of Development and Operations for the Prudhoe Bay Permo-Triassio Reservoir was presented to the Alaska Oil and Gas Conservation Commission at a public hearing in May 1977. The plan called for timely development of the field on 160 acre spacing and expansion of production facilities to support an ultimate oil offtake of 1.5 million barrels per day. Possible long term reservoir management options were also discussed and included: 1) development of the field on closer spacing; Z) injection of produced water; 7) injection of external source water; and 4) installa- tion of low pressure separation and artificial lift facilities. It was stressed that the long term options were not fixed and would be better defined as knowledge of the reservoir and its performance increased. AGO 10023770 Pool rules consistent with the Plan were issued via Conservation Order No. 145 (Exhibit 4) on Dune 1, 1977 and the Unit Agreement along with the Plan of Development and Operations was approved by the Commissioner of Natural Resources on Dune 2, 1977. In May 1980, the Unit Owners presented a status of the Field development to the AOGCC and proposed amendment of Rules 6, 9, 10, and 11 of Conserva- tion Order No. 145 regarding reservoir surveillance. Also, plans for injecting produced and Beaufort Sea water into the Sadlerochit formation were addressed. These plans entalled commencement of produced water injection when sufficient water volumes were available and of source .water injection in mid 1984. Analysis using sophisticated reservoir simulation models indicated that the overall recovery from the Field could be increased by an additional 4-7% OOIP if waterflooding was implemented in certain areas of the Field. The primary areas which were seen to benefit from waterflooding included the Flow Station 2 area, the northwest fault block area, and the peripheral wedge zone (Exhibit 5). As a result of this hearing, Conservation Order 145 was amended with the issuance of Conservation Order 165 (Exhibit 6). The Unit owners submitted to the AOGCC an Application for Additional Recovery by Waterflood in December 1980. The Commission approved the Application in March 1981. In Dune 1981, the Unit Operators requested that the AOGCC amend Rule 2, Well Spacing, of Conservation Order No..'i45. The proposed changes included deletion of the rule requiring a minimum distance of 2,000 feet between wellbores and amendment of the allowable wellbore distance to the AGO 10023771 Unit boundary from 1,000 feet to 500 feet. Reservoir simuiation studies indicated that cioser weli spacing would increase the uItimate recovery of oil. This request was approved in Duly I98i with the issuance of Conservation Order 174 (Exhibit 7). At Field startup in 1977, 104 oil wells and facilities designed to support production of 1.2 million barrels oil per day were available. As of Duly 1982, 394 additional wells have been drilled and production facilities have been expanded to maintain an offtake of 1.5 million barrels per day. Through Dune 1982, 2.345 billion barrels of oil had been produced. Exhibit 8 depicts the production facilities currently available. Wells have been drilled from 31 Drill Pads which are connected to 6 separation centers (Gathering Centers 1, 2, and 3 in the Western ~perating Area and Flow Stations 1, 2, and 3 in the Eastern Operating Area). The oil from these facilities is transported to Alyeska Pump Station #1, the beginning of the Trans-Alaska Pipeline System' (TAPS). All produced gas is routed from the separation centers to the Central Compressor Plant (CCP). Current annual average CCP gas handling capacity is 2.25 BCF/D. Most of this gas is compressed from about 600 psi to 4500 psi and is then routed to the North and West Gas Injection Pads where it is reinjected into the Sadlerochit gas cap. The remainder of the gas, except a small portion which is flared, is piped after the first stage of compression to the Field Fuel Cas Unit (FFGU) where it is conditioned for field and pipeline fuel use. In the process of conditioning the gas, low AGO 10023772 molecular weight hydrocarbon liquids are recovered. Currently, all of these flash drum liquids are sent to Flow Station 1 via a pipeline from the FFGU to Drill Site 2. A portion of these liquids is stabilized in the crude oil and is shipped to TAPS. Water production from the field has been minimal as expected. Except for the water produced at Flow Station 1, all water is currently being injected into the Tertiary and Cretaceous sands through disposal wells located at each separation center. Since Duly 1979, the produced water at Flow Station 1 has been reinjected into the Sadlerochit formation as part of a long term water injectivity test at Drill Site 5-17. Facilities for pr~oduced water injection into the Sadlerochit at Flow Stations 2 and 3 are installed and injection is planned to begin later this year. As a result of the harsh Arctic environment and the remote location of the Prudhoe Bay Field, development of the Field ha~ entailed significantly higher capital expenditures than are required in a typical oil field. As of year end 1981, capital expenditures for the Field have totaled $6.4 billion. The current planned development through 1987 will require additional expenditures of approximately $9.8 billion. In addition, the operating and maintenance costs at Prudhoe Bay are much higher than that found in onshore fields in the continental U.S. Knowledge of the Sadlerochit Reservoir's geology, drive mechanisms, and production trends has significantly increased since Field start-up. This has enabled the Unit owners to examine and 5egin implementation of the AGO 10023773 long term development alternatives discussed in the 1977 Plan of Develop- ment and Operations for the Prudhoe Bay Permo-Triassic Reservoir. With this expanded knowledge of the Sadlerochit Reservoir, the Unit owners have considered enhanced oil recovery (EOR) methods as another option for long term development of the Prudhoe Bay Field. AGO 1002377z,. Description of Tert£ar¥ Processes Considered for the Unit The planned execution of primary and secondary operations at Prudhoe Bay is projected to yield an ultimate recovery of 9-10 billion barrels of oil, leaving more than 10 billion barrels of oil untapped in the Sadlero- chit Reservoir. With such a large volume of oil at stake, the Unit owners recognized the potential of increasing recovery through the application of tertiary recovery methods. Hence, screening studies were conducted to better define the applicability of the leading enhanced recovery methods at Prudhoe Bay. The processes considered fal! into four categories: 1) miscible gas displacement processes, 2) surfaotant flooding, 3) enhanced waterflood techniques, and 4) thermal processes. The following discussion summarizes the findings of these studies. .Miscible gas displacement processes involve the in~eotion of a gaseous mixture which is usually not miscible with crude oil initially but develops into a miscible solvent-oil bank through the exchange of hydro- carbon components between the gaseous mixture and crude oil within the reservoir. Because of the miscible transitions from oil to oil-solvent to the gaseous mixture, entrapment of oil within the pore throats by capillary forces does not occur, and the miscible bank effectively displaces nearly all of the oil from the fraction of the reservoir contacted. A drawback to the process is that the miscible injeotant's density is usually lower than that of the reservoir oil leading to gravity segregation of the fluids. Another drawback is that the in~ectant's viscosity is always lower than that of reservoir oil with the result that conditions are AGO 10023775 conducive for viscous fingering of injectant through the oii. To help control the gravity segregation and fingering problems, water is often injected alternately with the gas (WAG process). Two main categories of miscible gas processes exist~ 1) high pressure lean gas (vaporizing) drive and 2) enriched gas (condensing) drive. High pressure lean gas drive involves the injection of methane or carbon dioxide gas at high pressures. This forms a miscible bank through evaporation of mainly intermediate hydrocarbon components (C2-C6) from the oil into the solvent. The effective use of this process requires a volatile oil with high concentrations of C2-C6 components in combination with high reservoir pressures. Where these conditions cannot be met, enriched gas processes can sometimes be applied. In enriched gas processes, a gas such as methane, field gas or CO2 is enriched with intermediate hydrocarbon components and is injected into the reservoir. The enriched gas forms a miscible bank as the intermediates from the gas are absorbed into the oil. High pressure gas processes are not applicable at Prudhoe Bay since Sadlerochit crude is relatively low in intermediates and the critical pressure at which methane and Sadlerochit oil become miscible is over 2500 psi higher than the pressure levels existing in the reservoir. It is possible, however, to enrich field gas to intermediate hydrocarbon concentrations of 30-40% and obtain a miscible injectant at reasonable reservoir pressures. Another possibility is to extract CO2 from field 10 AGO 10023776 gas and combine it with 25-30% intermediates to achieve miscibility with Sadlerochit crude at expected reservoir conditions. Currently, a limited amount of these intermediate hydrocarbons can be recovered at existing Prudhoe Bay production facilities, and these fluids could be used to form a miscible enriched field gas. In a surfactant flood, the composition of the injected fluids is designed to reduce oil-water interracial tension through the formation of oil- water-surfactant microemulsions, thereby mobilizing more oil than by waterflooding. A typical process might involve the injection of a surfactant bank followed by a larger bank of thickened water or brine. Polymers are usually added to both the surfactant solution and to the drive water to reduce the mobility of the injectants. With this process, a larger portion of the reservoir could be contacted than with miscible gas injection. Since the surfactant systems that are currently available are not effective over large ranges of salinity or temperature, the planned injection of low temperature Beaufort Sea water into the Sadlero- chit will introduce temperature and salinity gradients that will seriously hinder the use of currently available surfactants at Prudhoe Bay. Therefore, development of new surfactant chemicals is a prerequisite to surfactant flooding. Also, the manufacturing and delivery costs of surfactant and polymer chemicals at the remote location of Prudhoe Bay must be considered. 11 AGO 10023777 The use of thermal processes improves recovery by reducing the oil viscosity and by expansion and distillation of the crude. Two therma! methods were analyzed for possible application at Prudhoe Bay. The first involves injection of steam into the reservoir to change the flow charac- teristics of the oil. In the second process, in situ combustion, oil in the reser¥oir is ignited and combustion is Sustained through air injection. Neither process appears applicable at Prudhoe Bay. Steam injection was e~iminated from consideration because the high pressure and depth of the Sadlerochit Reservoir would reduce process effectiveness, as compared with use ~n low pressure shallow reservoirs. In situ combustion is not economically feasible since high air in~ection pressures (approximately 5000-6000 psi) and very close well spacing (.possibly as small as 10 to 20 acres) are required for efficient combustion process. Other enhanced waterflood techniques attempt to improve sweep efficiency and/or reduce the residual oil left in the reservoir over what would be possible with conventional waterflooding. Three such techniques, carbon- ated waterflooding, polymer waterflooding, and caustic waterflooding were considered in the screening studies. The injection of water saturated with CO2 improves recovery through the diffusion of CO2 from the saturated water into the contacted reservoir oil. This swells the oil and reduces its viscosity, thus improving reservoir sweep and reducing the amount of oil trapped. Addition of polymer to flood water increases the viscosity of the water and imprbves the mobility ratio between the oil and flood water, thereby improving volumetric sweep efficiency. 12 AGO 10023778 , Caustic waterfIooding involves the injection of water in which sodium hydroxide or other pH increas£ng chemica~s have been added. Reduction of interfacia~ tension results from the in situ generation of surfactants through chemica~ reactions between the high pH water and organic acids in the oil. Residua~ oi~ saturations in the swept regions are reduced as a resuit of the generated surfactants. Successful caustic f~ooding is very dependent upon suitab~e reservoir oi~ and rock characteristics. Reservoir simuIation studies have shown that carbonated waterfIooding is a less efficient EOR technique than miscibie dispiacement processes. SimuIation has shown that With the alternating injection of water and an injectant containing C02, carbonation of the water wiii occur naturally and carbonated waterfiooding ben~fits wili accrue aiong with the miscibie displacement benefits. Poiymer WaterfIooding may be appiied at Prudhoe .! Bay to improve the water/oiI mobiliity ratio and to reduce siumping of injected water in thick sand intervals. However, since a favorable mobility ratio exists between water and Sadlerochit crude, the use of polymers as a mobiiity control agent wouId yield Iimited benefits. At present, poIymers which wouid be effective at the high Sadierochit temperatures are not eommerciaiiy avaiIabIe. FinaiIy, with both poIymer and caustic waterfIooding, the Iogistics of suppiying Iarge quantities of chemicals to this remote Arctic location may entaiI prohibitive costs. In summary, the miseibie gas dispIaeement process is the most technicaiIy feasibie enhanced recovery technique which can be applied at Prudhoe Bay i3 AGO 10023779 at this t£me. This process has been used by the industry for several years which reduces the risk of its implementation. Since the miscible gas injectant is available on location, enriched field gas injection can be easily implemented. Practical surfactant, caustic, and polymer flooding systems that can be used in the Sadlerochit Reservoir have not been developed. 14 AGO 10023780 Description of Tertiary Process Utilized, Location of Pro~ect, and ~istor¥ of Operations in Rro~ect Area The screening studies discussed in the previous section indicate that miscible enriched field gas injection has the potential to significantly increase ultimate oil recovery. A distinct advantage of this process is that miscible gas injectant is available on site at Prudhoe Bay. Produced separator gas can be enriched with intermediate hydrocarbons from the Field Fuel Gas Unit and from the gas scrubbers at the Flow Stations or Gathering Centers. This EOR technique is compatible with existing field facilities and implementation is expected to recover additional oil, provide operating experience, and allow analysis of the potential to utilize miscible gas processes on a wider scale. The Project will utilize miscible enriched field gas injection along with the alternating injection of water (WAG process). The W^G technique is expected to retard miscible gas overriding and viscous fingering and help maintain pressures above minimum miscibility conditions. The choice of the Project Area was based on the following criteria: 1) The area should be relatively low in gas saturation so that contamination of the injectant is not a problem. 2) The area should be relatively high in pressure such that misci- bility can be maintained. 15 AGO 1002~781 3) The area should be one in which sufficient volumes of miscible gas and water could be made available within the near term for injection. Based upon the above requirements, the southwestern portion of the Eastern Operating Area was chosen as a good candidate for the miscible gas injection project. Specifically, the area chosen encompasses all or portions of Sections 10, 11, 13, 14, 15, 23, and 24 in Township 10 N, Range 14 E, and Sections 18 and 19 in Townships 10 N, Range' 15 E (Exhibit 9). With the choice of this area, Flow Station 3 (FS-3) was the logical centralized point for processing and injection of miscible fluids, and the tertiary project became referred to as the Flow Station 3 Injection Project. Additional equipment is necessary at Flow Station 3 to gather interme- diate hydrocarbons. In addition, provisio~ has been made for transferring the intermediate hydrocarbons from the Field Fuel Gas Unit to Flow Station 3. This processing equipment is expected to provide enough miscible gas injectant such that more than a 10% pore volume slug can be injected. As part of the Project analysis, reservoir models of the area were constructed and simulation studies showed that the increased recovery potential is indeed significant. A modified inverted nine spot development is planned for the Area as depicted in Exhibit 10. Wells will be drilled on 80 acre spacing and the Project will affect all or portions'of Drill Sites 1, 6, 12, 13, and 14 (Exhibit 11). Injaction of miscible enriched field gas and water into 11 16 AGO 10023782 WAG injectors is expected to increase the oil recovery from 42 producers. The actual number of producers in the Project Area may change as a result of further performance evaluation. Moreover, water will be injected into seven northern water injectors to help confine the miscible gas within the Project Area, to prevent contamination of the miscible fluid by encroaching gas tongues, and to help maintain the Project Area pressure above minimum miscibility conditions. The Project boundaries are defined by the water injectors to the north, by the outermost producing wells in the patterns to the east and west, and by the down dip development limit in the south (hereinafter referred to as the "Project Area"). The Project Area covers approximately 3650 acres. The Project vertically encompasses the light oil column of the Sadlero- ohitl that is, the interval from the top of the Sadleroohit formation to the top of the heavy oil/tar zone. This delineation is illustrated by the sample log shown in Exhibit '12, and Exhibit 13 describes the method by which the location of the heavy oil/tar zone contact is determined. The heavy oil/tar zone will not be affected by the miscible gas injection because the oil is nearly immobile at reservoir conditions and its high viscosity would result in very limited injection into the zone. Production from the Project Area began in March 1979 when Well 6-6 came on stream. Total production during the WPT base level period (October 1, 1978 to March 31, 1979) within the Project Area was 119,143 STB. Forty- four of the sixty planned Project wells are currently drilled as shown in Exhibit 14. As of Dune 1982, 37,098,000 bbls of oil, 2,805,000 bbls of water, and 28,918,000 MCF gas have been produced. Exhibit 15 shows the production history of the Project Area. AGO 10023783 17 Geologic and Reservoir Characteristics of Pro~ect Area The Sadlerochit formation consists of a deltaic sequence of sandstones, conglomerates, and shales which were deposited by a southward flowing river system. The reservoir thickness averages 575' with a +25' variation in the Project Area. The formation gently dips to the south at a 1-2 degree angle resulting in the top of the Sadlerochit varying from 8650' TVD SS in the north to 8925' TVD SS in the south. As shown on the'structure map, Exhibit 16, the Project Area is cut by two major and several smaller faults. These are east-west trending, high angle, normal faults with throws between 20' and 100'. These faults are not sealing, although permeability across the faults may be lowered slightly. In a small area of the south central portion of the Project, the Sadlerochit may be in communication with the lower 20 feet of the Sag River formation. The much lower permeability in the Sag River formation, typically 2-6 md or two orders of magnitude less than the Sadlerochit, will tend to limit fluid movement between the formations. If Project surveillance indicates that fluid migration is a problem, appropriate steps will be taken to minimize adverse consequences. A stratigraphic zonation of the Sadlerochit, commonly referred to as the Shale Mapping Team Zonation, divides the formation into five main zones. These are named the Zulu, X-Ray, Victor, Tango, and Romeo in order increasing of depth. This zonation is illustrated by the type log in Exhibit 17 in which the major shale complexes are also noted. The top two 18 AGO 10023784 stratigraphic zones, Zulu and X-Ray, are composed of fine to medium grained sandstones with interbeds of thin, mostly discontinuous, siltstones and shales. The sandstone was deposited largely by braided streams while the shales and siltstones are a consequence of the infilling of abandoned braided stream channels. A shale at ~he base of the X-Ray is found in a large portion of the Project Area as shown in Exhibit 18; however, faulting breaks the continuity of this shale. The Victor, deposited during the highest energy level of the river system, is composed of a conglomerate section in the upper half grading to a coarse grained sandstone in the lower half. This zone lies below the water-oil contact in the southern portion of the Project Area. The Tango zone consists of clean massive sandstones separated by major shale interbeds. The sandstones were deposited in the main river channels of the delta and the shales were deposited in quieter bay areas. This zone lies below the water-oil contact throughout the Area. A shale at the base of the Tango is present throughout the Project Area as shown in the shale isopach in Exhibit 19. A thinner, less continuous shale lies near the top of the Tango'as indicated in Exhibit 20. As mentioned earlier, faulting disrupts the continuity of these shales. At the base of the Sadlerochit formation is the Romeo zone. This strati- graphic zone consists of a sequence of fine to very fine grained sandstones interbedded with shales primarily deposited in a marine environment. This zone represents the initial stage of delta development. Since the Romeo zone is below both the water-oil contact and the Tango shales 19 AGO 10023785 throughout the entire Project Area, this zone is expected to have little or no effect on the miscible gas project. North-South (Exhibit 22) and East-West (Exhibit 23) cross-sections have been assembled to provide a view of the shaIe continuity, fauiting, zonation, and structure of the Area. Exhibit 2I is a iocation map showing the weIIs that are inciuded in the cross-sections. As shown in these exhibits, discontinuous shaies are numerous in the Zulu and X-Ray zones. These shaies shouid heip to retard the gravity segregation of the injected fIuids. The water/oii contact Iies between 8980' TVD SS and 9069' TVD SS as indicated in Exhibit 24. DirectIy overlying the aquifer is a heavy oiI/tar zone consisting of highly viscous crude, ranging in thickness from 2I' to 63' (Exhibit 25). As discussed eariier, due to the low mobility of the crude, injectivity into this zone is very low and WAG injection wiii not affect the heavy oiI/tar zone. Thus, fuIi verticaI deiineation of the Project is provided by the gross Iight oil isopaeh contained in Exhibit 26. No original gas cap is present in this peripheral section of the reservoir. However, production in the Project Area has liberated gas from solution such that localized pockets of gas exist near the wellbores of the older producing wells. The average gas saturation is expected to be less than the critical gas saturation of around 3-4%. 2O AGO 10023786 Geologic and reservoir data pertaining to the Project is listed below. · Original oil in place: 4#2 MMSTB · Total pore volume: 1023 MMRVB · Hydrocarbon pore volume: 610 MMRVB · Average porosity: 22.3% · Average initial water saturation: 40.4% · Average current gas saturation: 2-3.5% · Wettability: intermediate · Gravity of oi1: 25.5o AP1 · Average reservoir temperature: 200° F · Average reservoir pressure ~ 1-1-82 (reference elevation 8800 feet SS): 3975 psi · Initial bubble point pressure @ gas/oil contact: 4335 psi · Initial oil formation volume factor: 1.378 RVB/STB · Solution gas oil ratio at original pressure: 745 SCF/STB · Oil viscosity at original reservoir conditions: .89 op · Dead oil viscosity at 60° F: 56.8 cp · Average permeability: +300 md 21 AGO 10023787 PART TWO - PRODECT DESIGN, OPERATION, AND EXPECTED PERFORMANCE .Project Overview The proposed Flow Station 3 Injection Project consists of an enriched miscible gas process applied to portions of Drill Sites 1, 6, 12, 13, and 14 of the Prudhoe Bay Unit. As mentioned in Part One, this particular area of the Field was chosen for three reasons. First, the area is not overlain by the gas cap and has a low gas saturation in the oil column. Second, because of the late development of Drill Sites 13 and 14 and resultant low withdrawals, the reservoir pressure is relatively high. Both of these' characteristics enhance the development of miscibility since less contamination (or "dilution) of the enriched gas by the leaner free gas will occur and a minimum amount of pre-conditioning to raise reservoir pressure will be required. Third, miscible gas and water can be made available for injection in the area within the near time frame. The injection pattern chosen for the Project ls an inverted'nine spot pattern developed on 80 acre well spacing. This pattern development leads to improved volumetric sweep and tends to provide a uniform and rapid pressure response in the Project Area. The inverted nine spot pattern was primarily selected for miscible'gas injection because of its flexibility in conversion to other pattern configurations should condi-' tions warrant after Project start-up. This flexibility is highly desirable due to the geological uncertainties discussed in Part One. Alternate configurations which may be developed from the inverted nine 22 AGO 10023789 spot include a line drive pattern capable of being oriented in four different directions to overcome adverse directional permeability and a five spot pattern. Initial development with the inverted nine spot is also preferred for its 3 to i producer to injector ratio. This will allow more versatility in maintaining the balance of injection and withdrawals required to sustain reservoir pressure within any particular pattern. Thus, the Project design includes flexibility for controlling flood performance. The Flow Station 3 Injection Project requires the injection of water as well as miscible gas. Produced water will be alternately injected with the enriched gas lnto the WAG injectors to provide pressure mainten- ance and to reduce the "channelling" tendency of the lower viscosity gas (often referred to as mobility control). Water will also be injected in the upstructure water injectors to help maintain miscibility pressure, confine the mlscible gas, and shut off gas cap gas that may tongue along the top of the Sadleroohit. As illustrated in Exhibit 10, the Project Area will consist of eleven inverted nine spot patterns which will be bounded to the north by seven upstructure water injectors. Each pattern will be serviced by a WAG injector and will encompass approximately 320 acres. The seven water injection wells will be located approximately one mile downstructure of the original gas-oil contact and, as previously discussed, will aid in isolating the Project Area from the Main Field Area. The well development plan will therefore include the seven water injectors, eleven WAG injec- tors, and forty-two producers. 23 AGO 10023790 The Flow Station 3 Injection Project makes use of existing and previously planned facilities and pipelines for production, produced water injection, source water injection, and artificial lift. In addition, new facilities and pipelines will be required to gather, process, transport, and inject the miscible fluid. Other facilities will also be needed to provide sufficient volumes of water for the Project prior to the initiation of source waterflooding. These additional facilities are designed to supply approximately 40 MMSCF/D of enriched gas and will generally encompass the following aspects: 1) Transfer of flash drum liquids from the Field Fuel Gas Unit (FFGU) to Flow St'ation 3. 2) Gathering of additional low molecular weight hydrocarbon liquids (scrubber liquids) from the separators at Flow Station 3. 3) Combination of rich hydrocarbon gas, flash drum liquids, and scrubber liquids to form a miscible gas mixture. 4) Delivery of the enriched methane gas to Drill Site 13 at 4000 psi. 5) Production of supplemental produced water from the Sadlerochit aquifer at Drill Site 14. 6) Transfer of produced water to Drill Site 13 prio'r to start-up of the source waterflood. AGO 10023791 The current timetable for Project implementation provides for the initia- tion of produced water injection into the upstructure water injectors in the fourth quarter of 1982. All the additional facilities necessary for supporting the Flow Station 3 Injection Project are scheduled to be operational for the start of miscible gas injection in early 1983. Miscible gas injection is expected to continue until more than a 10% PV slug has been injected into the Project Area. Based on present estimates, this will require approximately ten years. 25 AGO 10023792 Facilit¥ Design The WAG process which will be employed in the Flow Station 3 Injection Project requires a substantial investment in facilities and pipelines to process, blend, and inject miscible fluid and water. Design and construc- tion of these facilities and pipelines is compatible with previously planned facilities and capable of being installed without impacting other projects. The additional facilities are needed for two purposes; namely, for creating a miscible gas injectant and for providing adequate water injection volumes. Source and Distribution of Miscible Fluids A new process module, the Flow Station 3 Injection Module, will become operational in early 1983. This module will be located at Flow Station 3 and will house the major process equipment necessary for the mixing and injection of the miscible fluid at Drill Site 13. The major pieces of process equipment that will be included in this module are as follows: two gas injection compressors with electric motor drivers, inlet and interstage gas coolers, hydrocarbon scrubber liquid pumps, an injection liquid drum, an injection liquid pump, surge drums, knock-out drums, and a triethylene glycol (TEG) column. Basically this equipment will receive hydrocarbon liquids from the existing Field Fuel Gas Unit where they will be combined with heavier molecular weight hydrocarbon liquids recovered from the existing Flow Station 3 residue gas and intermediate pressure 26 AGO 10023793 scrubbers. The miscible gas injectant will be formed by pressuring this liquid mixture to 4100 psig and combining it with a gas stream compressed to the same pressure. As shown in Exhibit 27, the liquids obtained from the flash drum at the FFGU will be transported to Drill Site 2 and then will be routed through a new uninsulated 12" diameter pipeline to Flow Station 3. The liquids will then be heated and combined with the other liquids in the injection liquid drum at 1250 psig (Exhibits 28 and 29). During process upsets, the flash drum liquids from the FFGU will be diverted to a high pressure separation train at Flow Station 3. Exhibits 27 and 28 detail the additional components of the Flow Station 3 Injection Module process flow design. As depicted in the Exhibits, the injection liquid drum serves as the common collection point for enriching fluids which are obtained from the FFGU and Flow Station 3. Residue gas scrubber liquids from Flow Station 3 are dehydrated and collected in a new residue gas liquid surge drum which operates at 620 psig. This liquid is pumped to the injection liquid drum which operates at 1250 psig. Intermediate pressure suction scrubber liquid from Flow Station 3 is dehydrated and collected in a new intermediate pressure surge drum operating at 65 psig. This liquid is pumped to the injection liquid drum also. Intermediate pressure compressor gas (Iow in methane content) from Flow Station 3 is cooled and the resultant gas/liquid stream flows to a new low pressure knock-out drum operating at 635 psig where gas and liquid 27 AGO 1002379~, are separated. This liquid is dehydrated and pumped to the injection liquid drum. The gas stream continues through a TEC column where it is dehydrated to a water dew point of -40° F. Additional dehydrated Flow Station 3 residue gas may then be combined at this point, if necessary, to provide the total desired gas volume. The gas is compressed from 650 to 4100 psig by two electric motor-driven, reciprocating, two-stage compressors housed in the new module. First and second stage knock-out drums collect any liquids and interstage cooling is also provided. Each compressor is rated at 15 MMSCF/D, providing a nominal total of 30 MMSCF/D of high pressure gas. Liquids from the injection liquid drum are pumped to 4100 psig with the injection liquid pump and combined with the gas. The resultant liquid fluid stream is supercritical and exhibits single phase behavior. The injection fluid is then piped to Drill Site 13 through a 10" diameter flowline and is distributed to the WAG injectors through 8" diameter manifolds and 6" diameter well lines. In order to minimize the cost of miscible gas facilities and flowlines, all WAG injectors will be drilled and operated from Drill Site 13. Metering at each WAG well will ensure the proper distribution of enriched gas to individual patterns within the Project Area. The Project has been carefully designed to ensure that the enriched gas is miscible when injected in the Sadlerochit Crude. The design basis 28 AGO 10023795 for the process described in Exhibits 27 through 29 will provide approxi- mately 40 MMSCF/D of hydrocarbon fluid with a typical composition as · shown in Exhibit 30. An in-line gas chromatograph will be installed in the injection fluid line to monitor gas composition. The composition of the gas injectant will be maintained such that the gas is miscible with the oil at the prevailing average reservoir pressures. An analysis of minimum miscibility pressure as a function of fluid composition is outlined in Exhibit 31. Additional measurement and sampling devices will be utilized to monitor the injectant as well as the different component fluid streams which form the fluid. Source and Distribution of Injected Water The Flow Station 3 Injection Project requires both produced and source water injection to maintain reservoir pressure and provide mobility control for the WAG process. Although the equipment necessary for the separation, treatment, and injection of produced water is contained in existing or currently planned facilities, it is anticipated that addi- tional produced water above projected Flow Station 3 volumes will be required to support the Project in the 1983-1984 time frame. Therefore, to provide supplemental water up to four Drill Site 14 wells will be perforated in the Sadlerochit aquifer and artificially lifted with high pressure gas supplied by three new 1200 hp Solar Saturn turbine compres- sors. Beginning in December 1982, the three compressors will provide 40 to 4# MMSCF/D of gas lift gas capable of producing from 40 to 60 MSTB/D of additional water. A 12" diameter flow line branching to 4" diameter 29 AGO 10023796 tie lines will transport the gas to the source wells from which the water will be produced through the existing Flow Station 3 separation facilities. In early 1984, a large 35,000 hp gas lift compressor will be operational as part of the planned artificial lift development of the Prudhoe Bay field. This compressor will permit the high water cut wells in the Flow Station 3 area to be produced such that adequate volumes of water will be available for the Project without requiring the additional water production from Drill Site 14. Throughout the Project life, the WAG wells will inject the higher tempera- ture produced water to help prevent the formation of hydrates with the miscible gas. The upstructure water injector~ will also initially use produced water untii source water from the Beaufort Sea becomes avaiiabie in mid 1984. The pianned increase in produced water handling capacity at Fiow Station 3 wiiI be sufficient to support the process, as i20 MBWPD of injection capacity will be available in 1983 and 240 MBWPD of injection capacity will be provided by 1985. Since frequent mixing in surface facilities of Beaufort Sea and produced water is not desirable due to differing mineral contents, separate pipe- lines and manifolds will be utilized to distribute the two waters concur- rently to Drill Site 13. Two lines, one 14" and the other .12" in diameter, will transfer produced and source water from Flow Station 3 to Drill Site 13. The individual injection wells will be connected to the manifold system via 6" and 8" diameter tie lines. Unlike the WAG injection wells, 30 AGO 10023797 not all of the upstructure water injectors will be drilled from Drill Site 13. Two of the upstructure water injectors will be drilled from Drill Site 12, three from Drill Site 13, and two from Drill Site 1#. As part of the original waterflood design, facilities are available to provide freeze protection for the water distribution system if a process shut-down should occur. This freeze protection system includes the capability of displacing methanol or another non-freezing liquid through the transfer lines, well lines, and injection well tubing strings. This concept has been extended to furnish additional protection against possible hydrate formation in the WAG injectors by allowing the well tubing string to be displaced with methanol at the start of each alterna- ting cycle of injection. Project Investment Costs The anticipated well and facility costs for the Flow Station 3 Injection Project are estimated to be 110 MM$ in constant 1982 dollars. Since the most recent Prudhoe Bay Unit Five Year Plan has adopted 80 acre development for the peripheral waterflood areas, the expenditures involved in the Flow Station 3 Injection Project relate only to those facilities that are incremental to an 80 acre spaced waterflood in the Eastern Operating Area. Included in the Project investment costs are the Flow · Station 3 Injection Module, Solar Compressor Mo.dule, flash drum liquid and miscible gas pipelines, and incremental drilling and completion costs associated with surveillance wells and the supplemental produced water 31 AGO 10023798 wells. The magnitude of the investment associated with these facilities reflects the significantly higher costs incurred for Prudhoe Bay develop- ment over a routine oilfield operation. As mentioned in Part One, the geographical location of the field, some 350 miles above the Arctic Circle, increases transportation costs, introduces longer lead times, and results in premium labor costs. Exhibit 32 contains a more detailed breakdown of these investment costs. In summary, the facilities required for the Flow Station 3 Injection Project are well designed and compatible with other existing and planned Prudhoe Bay facilities. These facilities are capable of providing approximately #0 MMSCF/D of an enriched fluid with gas compositions such that miscibility will be maintained within the reservoir during the P~oject life. 32 AGO 10023799 ~roject Implementation and Operation Implementation of the Flow Station 3 Injection Project is moving forward as expeditiously as possible. As was previously discussed, all facilities necessary to support the Project are scheduled to be operational in early 1983. Drilling is currently underway in the Project Area, and it is anticipated that infill well development will be concluded by mid 1983. Sequence of Pro~ect Implementation Some conditioning of 'the Project Area prior to miscible gas injection is presently planned. As was mentioned in the Project Overview section, the conditioning will consist of upstructure water injection which is designed to block off any gas cap tongues advancing into the Project'Area and to create a safety margin between average pressure and minimum miscibility pressure of the enriched gas. This injection is scheduled to commence in one or two of the upstructure injectors when produced water volumes resulting from normal Flow Station separation become significant (i.e., greater than approximately 10 MSTB/D). Based on current projections~ it is anticipated that this will occur in the fourth quarter of 1982. In December 1982 the Solar compressors will be operational to gas lift the four Drill Site 14 wells completed in the Sadlerochit aquifer which will provide an additional 40 to 60 MSTB/D of produced water. This supplemental water will be used to expand the existing injection into the upstructure Project Area. 33 AGO 10023800 Miscible gas injection is planned to begin in 3anuary 1983. At start-up, the 40 MMSCF/D of enriched gas available is expected to be injected into two or three of the WAG injectors for a period of one to three months. After this period, produced water will be injected into these initial wells, thus beginning the normal water-alternating-gas process, and another set of WAG injectors will commence taking miscible gas. It is anticipated that several periods or sequences will be required before all of the WAG injectors have received miscible gas. The injection sequence may begin with produced water rather than miscible gas should the pre-production of the WAG wells demonstrate that localized areas of higher than expected gas saturation exist. Prior to implementation of the source waterflood in mid 1984, approximately 65 to 100 MSTB/D of produced water will be available for use as needed in the upstructure and WAG injectors. This total produced water volume consists of 40 to 60 MSTB/D from the Drill Site 14 wells and a projected 25 to 40 MSTB/D from normal Flow Station 3 production separation. The seven upstructure water injectors can be converted from a produced water to a source water supply after waterflood start-up and will be capable of injecting 25 to 30 MSTB/D of Beaufort Sea water per well. Ultimately, approximately 90 MSTB/D of produced water may be required in the WAG injectors. The drilling program for the Flow Station 3 Injection Project has been optimized to: 1) assure that all drilling necessary to accommodate 34 AGO 10023801 miscible gas injection is concluded in a time frame compatible with facilities construction, and 2) develop the Project Area without signifi- cantly impacting planned expansion in other portions of the Field. Forty-eight of the sixty planned wells to be employed ultimately in the process will be available before miscible gas injection begins in Oanuary 1983. These wells include all eleven WAG injectors, five of the seven upstructure water injectors, and thirty-two producers. The remaining twelve wells, namely two additional upstructure water injectors and ten infill producers, will be completed by Oune 1983. The six month differ- ence between the start of miscible gas injection and the end of well development will have no effect on the performance or operation of the Project. The ten producers to be drilled will finish the inverted nine spot configuration before production response to injection is expected. Similarly, the two remaining upstructure water injectors to be drilled at Drill Site 12 will be primarily needed to maintain reservoir pressure in the northeast portion of the Project Area and the sequenced WAG injector start-up will allow sufficient time for conditioning of the affected pattern prior to miscible gas injection. Project Operation Since the Flow Station 3 Injection Project will employ a water-alternating- gas process in conjunction with facilities which will continuously supply enriched gas, routine operation will involve having part of the WAG wells AGO 10023802 on a miscible gas injection cycle while the rest are injecting water. Although the actual length of each enriched gas cycle will be determined by operational experience and reservoir performance, it is currently estimated that miscible fluid will be injected in one to three month periods. The subsequent duration and rate of water injection following the gas cycle will be adjusted to maintain the pressure in each pattern above the minimum miscibility pressure. In addition, the upstructure water injectors can be used to balance injection and production in the Project Area. With an overall average design rate of approximately 40 MMSCF/D of miscible gas, this process will continue until more than a 10% PV slug of enriched gas has been injected. As discussed above, produced water will be used in all of the WAG injec- tors. Produced water, because of its high temperature of 140° F, will help prevent hydrates from forming between the gas and water phases. Initially, as a further safeguard against hydrate formation, methanol will be displaced into the WAG wells prior to each change in injected fluid. Both the miscible gas and water injection rates to each WAG well will be metered and monitored to optimize the performance of the Project. The producing rates for each pattern element will also be monitored and the offtake will be controlled as closely as possible to achieve a balance between pattern injection and production. Since the injectivity of a WAG well is believed to exceed the productivity of a producer, the inverted nine spot pattern with its three to one producer/injector ratio will 36 AGO 10023803 facilitate maintaining an offtake equal to injection. Additional well capacity can also be obtained by providing priority to the Project producers when future low pressure separation and artificial lift systems are installed at Flow Station 3. Conversely, if Project performance should become constrained by injectivity rather than productivity, the nine spot pattern can be converted with slight modification to a five spot pattern which will increase the total number of injection wells within the Project Area. The timing of miscible gas breakthrough at the' producing wells will also be monitored to determine pattern sweep efficiency. If premature gas breakthrough becomes a severe problem, operational flexibility will exist to modify the original Project design. Available options include convert- ing the nine spot pattern to a multiple line drive configuration to overcome strong directional permeability trends, or changing injector/ producer completions and increasing the WAG ratio to decrease stratifica- tion effects. Pro~eet Surveillance Since one of the objectives of the Flow Station 3 Injection Project is to provide a better understanding of key factors affecting tertiary recovery processes in the Sadlerochit, an extensive reservoir surveillance program is planned to monitor and optimize the enriched gas drive process. The existing field wide surveillance program will be supplemented by the use of observation wells, cores, additional and more frequent well surveys, 37 AGO 1002380Z~ By Project start-up, five wells in the Project Area will have been cored through the Sadlerochit oil column. A detailed analysis of these cores will provide valuable data on lithology, permeability, porosity, fluid saturations, and relative permeabilities for use in further reservoir studies and performance evaluations. Additional monitoring of the Project will include the running of injec- tion or production profiles on each well during the first year with subsequent surveys being performed on a rotating basis so that a new profile is obtained on each well periodically. These profiles will be used to ensure that injection or production is not being dominated by a single interval. Bottomhole pressures will be obtained in each inverted nine spot pattern well to ensure that!the reservoir pressure is main- tained above minimum miscibility conditions. In summarizing the Unit's Project implementation and operational plans, very little pre-conditioning of the Project Area appears to be necessary. Provision for early upstructure water injection has been planned, however, to provide a safety margin between reservoir and minimum miscibility pressures. The major co-owners have worked together to design the Project to fit the reservoir characteristics of the Sadlerochit formation and be compatible with the overall planned development of the Field. A large degree-of operational flexibility has been incorporated into the Project design, and a detailed surveillance plan has been established which will facilitate optimization and provide needed performance informa- tion. 39 AGO 10023805 and possibly chemical and radioactive tracers to follow actual water and miscible gas movement in the reservoir. Two non-perforated observation wells located close to one of the WAG injectors will be utilized for early flood surveillance. The wells will be completed with non-conductive casing to allow~the use of induction logging tools to observe water bank movement. The propagation of the enriched gas front past the observation wells will also be monitored with neutron logging devices. Current plans involve running these logs repeatedly during the first year of injection (or until the fluid banks stabilize) and at least once per year thereafter. The observation well logging program will provide a time-lapse description of changes in water and gas (and hence oil) saturations versus.depth. From these measurements the effectiveness of the tertiary process in forming a miscible zone and in mobilizing oil will be evaluated. Consideration is also being given to testing the effect of miscible gas injection rate on vertical sweep. In addition, the effects of reservoir stratification and gravity segregation will be observed. The logging measurements will provide essential data in analyzing the overall effectiveness of the tertiary recovery process in the Sadlerochit. Following gas breakthrough, neutron logs will be run periodically in the producing wells to evaluate coning and vertical sweep. Gas samples will also be taken from the producers at this time to determine process efficiency and to ascertain if enriched gas breakthrough has occurred. AGO 10023806 Reservoir Analysis and Expected Project Performance As was discussed in Part One, the selection of an enriched gas miscible displacement process for use in the Flow Station 3 Injection Project was based on screening studies of several potentia! oi! recovery techniques. The primary advantages which made the application of the enriched gas drive process attractive were twofold. First, the present availability of the injectant on site at Prudhoe Bay enhanced the viability of employ- lng the process because transportation costs would be eliminated and a minimum amount of additional facilities would be required. Second, miscible gas injection using an enriched methane stream was a well established process which possessed a sufficient amount of technical expertise to allow timely field implementation (Technical References 1-6 overview the enriched gas process, References 7-13 describe the WAG technique). Since miscible gas injection has not been p~eviously undertaken in the Sadlerochit formation, the Project design and anticipated performance were based on extensive numerical reservoir simulations of the process by the Unit Owners, Results of these studies have indicated that the displacement of a 10% PV slug of miscible gas will recover an additional 5,5% of the original oil in place over conventional pattern waterflooding developed on 80 acre spacing, This corresponds to a 24 MHSTB increase in ultimate recovery from the Project AreJ, 4O AGO 10023807 Analysis of Expected Pro~ect Performance ARCO, as Operator of the Project, undertook a large scale reservoir model study to: 1) determine the recovery benefits associated with miscible gas injection, 2) determine Project sensitivities, and 3) develop a plan of implementation. The model employed was a sequential, semi- implicit four-component miscible simulator which is formulated to repre- sent gas, oil, water, and solvent systems (Technical Reference 14). A three dimensional reservoir description of a symmetrical strip element of the Project Area was utilized for the study. As shown in Exhibit 33, the strip was extended north into the gas cap and south to the aquifer to correctly incorporate pressure boundary effects. The model was matched to existing actual Project Area primary performance and to the predicted future pressure performance of the area generated with ARCO's full field three dimensional simulator. A final calibration of the miscible simu- lator was then obtained by matching the hydrocarbon miscible WAG process performance predicted by a two dimensional, fully compositional model. To supplement the three dimensional strip model study, additional simula- tion was performed with small area models to quantify gas overriding, determine coning behavior, and investigate well completion philosophy. A total of six major cases encompassing three different reservoir producing mechanisms were studied with the Project Area model. The first case involved the prediction of natural depletion performance utilizing the current 160 acre well spacing, while the remaining five scenarios modelled frontal displacement processes employing an inverted nine spot pattern with 80 acre well development. The pattern development cases 41 AGO 10023808 that were simulated consisted of a conventional waterflood and a WAG miscible displacement process with a 10, 15, and 25% PV slug of enriched gas being injected. The final scenario modelled involved deferral of Project implementation and will be discussed later. In the miscible gas cases studied, the WAG process began in early 1983 and the Area was converted to waterflooding at the completion of slug placement, which occurred in 1993 for the 10% PV slug, 1998 for the 15% PV slug, and 2008 for the 25% PV slug. All simulator runs were terminated in the year 2008 which corresponds to the currently estimated full Field oil rim depletion date. The projected ultimate recovery in the Project Area from natural deple- tion, waterflood, and miscible gas simulations is tabularized as follows: Ultimate Ultimate Case Recovery, % Recovery, MMSTB Natural Depletion Pattern Waterflood Miscible WAG -10% PV Slug 27.7 122 42.2 187 47.7 211 As demonstrated above, the WAG injection of a 10% PV slug of enriched gas provides a 5.5% (OOIP) increase in recovery over the pattern waterflood. However, extended enriched gas injection potentially leads to higher recoveries as shown on Exhibit 34. Injection for 25 years provides about an 11% increase in recovery over the pattern waterflood. Thus it appears that extended miscible gas injection may be attractive; however, the ultimate Project life must be based on the evaluation of actual Project performance, availability of injectant, and future economic conditions. 42 AGO 10023809 Exhibit 35 illustrates the estimated oil rate performance of the Flow Station 3 Injection Project for the pattern waterflood and the 10% PV WAG cases. Analysis of the Exhibit shows that the increase in rate attribu- table to the WAG process is anticipated to occur during the time at which the entire Field is estimated to be on decline~ that is, in late 1986 and beyond. As was previously mentioned, simulations with the ARCO model comparing early gas injection versus gas injection following waterflooding were performed as a sensitivity to Project timing even though the current facilities would be incapable of supplying sufficient injectant in this time frame. The "deferred" case simulated wa~er injection from 1983.25 to 1998 followed by a 10% PV WAG injection completed by 2008. Given the current understanding of Field life and within the accuracy of the simulator employed, no difference in recovery was observed between the 10% PV WAG case initiated in 1983 and the hypothetical deferred case begun in 1998. Although ultimate recovery for the two scenarios was virtually identical, the overall process efficiency of the deferred case was lower. A higher percentage of the solvent injected in the deferred case was left in the reservoir at abandonment, and as demonstrated in Exhibit 36, the cumulative amount of water produced at any point in the recovery process was higher for the late life WAG scenario. Also, delaying miscible gas injection would reduce the possibility of being able t6 continue injection in order to achieve the higher recoveries associated with higher injectant volumes (Exhibit 34). 43 AGO 10023810 Both Exxon and ARCO conducted laboratory linear flow core floods on Sadlerochit formation samples to substantiate the model studies. The results have shown that the same low residual oil saturation of approxi- mately 2% or less is obtained regardless of the order in which water and miscible gas are flowed through the core leading to the overall conclusion that no loss in recovery results from initiating a miscible gas displace- ment prior to waterflooding. A review of the available literature on other laboratory investigations (Iechnical References 15-21) supports this conclusion for intermediate wettability systems such as exists at Prudhoe Bay. 'Sohio and Exxon, as major co-owners, also independently performed reservoir studies to verify the projected recovery benefits and anticipa- ted production performance of the miscible gas process. The simulation work conducted by Sohio employed the Interoomp COMP II compositional simulator which is designed to model three-phase, multi-component flow in hydrocarbon reservoirs. The three phases represented in the composi- tional model are 1 hydrocarbon liquid phase, 1 hydrocarbon gaseous phase, and 1 water phase. The simulator calculates volumetric and phase behavior of the reservoir fluid mixtures by means of an extended version of the Redlioh-Kwong equation of state. For the oases modelled, the reservoir fluids were described with eight components which included carbon dioxide, methane, and slx heavier hydrocarbons. AGO 10023811 A three dimensional strip representative of the Project Area which included portions of both the gas cap and aquifer was modelled (Exhibit 37). The pressure performance of the upstructure area under the gas cap in the strip model was matched to the predicted behavior generated by the Sohio full Field simulator. Project performance with 80 acre well development was simulated for both waterfloodin§ and WAG injection. Sohio's model study yielded a waterflood recovery for the Project Area of 39.1% of the original oil in place and a 47.4% recovery for a 15% PV slug WAG injection scenario. The 8.3% incremental recovery was very similar to that obtained by ARCO's model studies discussed previously. The numerical reservoir simulation performed by Exxon also employed a fully compositional model. This model used an eleven component descrip- tion of the displacement including water, methane, carbon dioxide, and eight heavier than methane hydrocarbon components. Water, gas, and oil were treated as separate phases and the components were distributed between the phases in accordance with phase behavior and solubility principles. The effects of components mixing to attain miscibility between gas and oil phases were included. A three dimensional reservoir description of portions of three 320 acre inverted nine spot patterns was used for the study (Exhibit 38). A base waterflood case and four cases in which enriched gas was injected were run. The enriched gas WAG injection cases yielded higher recoveries, with the increment over waterflooding ranging up to 8.0% (OOIP) for a AGO 10023812 case in which a 15.3% PV slug of miscible gas was injected. The 15.3% PV slug was the largest injectant volume studied by Exxon. AIthough siightly differing assumptions and constraints were integrated into the simulations performed by the three major Working Interest Owners, a comparison of the common, 15% PV enriched gas slug WAG case demonstrates a close agreement between the studies on projected process efficiency. As has been detailed, the incremental recovery resulting from the 15% PV'miscible gas slug was predicted to be 8.2% by ARCO, 8.3% by Sohio, and 8.0% by Exxon. 46 AGO 10023813 Estimated ProjeCt Revenue and Expenses It is estimated that the Project will generate $380 MM in gross revenues. These revenues represent the uninflated, and undiscounted worth of the 24 MMSTB of incremental oil before Federal excise and income tax as well as state tax. This incremental oil is estimated to be recoverable with the 10% PV enriched gas slug over the pattern waterflood. These revenues are based on a constant oil price of $18.19/barrel (May 1982 average wellhead price for Alaska royalty oil) and a 1/8 royalty deduction. The expected incremental costs for operation and maintenance of the project over the normal pattern waterflood, as well as injectant expense, are detailed in Exhibit 39. 47 A$O 10023814 Discussion of Implementation Timing As was discussed in the section on History of Unit Operations in Part One of this Application, both the "Plan of Development and Operations for the Prudhoe Bay Permo-Triassic Reservoir" and the "Application for Additional Recovery by Waterflood" have presented to the AOGCC the benefits of employing waterflooding to increase recovery from the Sadlerochit forma- tion. Since the Flow Station 3 Injection Project will be implemented prior to the initiation of the major source waterflood, a discussion of the reasons associated with this timing is included for completeness. In general, a 1983 start-up of the Project will result in maximum miscible fluid injection and thus maximum recovery potential~ will take advantage of favorable reservoir and facility conditions which reduce Project cost and risk~ and will provide valuable information for future possible applications. As was outlined in the Facilities Design section, the feedstock necessary to enrich the hydrocarbon gas stream may presently be obtained with minor revisions to existing facilities. However, it should be noted that the availability of the enriching feedstocks is time dependent and, therefore, a limited supply of miscible gas injectant exists.. Exhibit 40 provides an estimate of the availability of miscible gas from 1983-1998. As shown in this exhibit, the injectant availability declines rapidly in the 1990's. This trend which is expected to continue through the end of the Field life is caused by the following factors: 1) the volumes of both 48 AGO 10023815 the scrubber liquids and rich hydrocarbon gas obtained from Flow Station 3 are dictated by oil throughput rates, and as such will decrease as production from the Field declines; and 2) similarly, the source of flash drum liquids received from the FFGU is dependent on the need for fuel gas in the Field, inlet gas composition, and operational parameters set by both distribution system constraints and BTU value requirements. Since the inlet gas composition will become leaner with time, the hydrocarbon liquid yield will decrease in the future. Thus, an early start-up of the miscible gas project is necessary in order to take advantage of readily available enriching fluids. An early initiation of the Flow Station 3 Injection Project will also capitalize on a favorable set of reservoir conditions which simplifies implementation of the miscible displacement process by minimizing potential complicating reservoir factors. Since the portion of the reservoir upstructure of the Project Area will continue under a gravi'ty drainage mechanism (and hence will decline in. pressure), the efficient placement of boundary injection and maintenance of miscibility will be more easily achieved the earlier the process is begun. As was previously discussed in the Project Overview section, a timely implementation of the process also minimizes problems caused by gas tonguing. Beginning the miscible process prior to the creation of a significant free gas satura- tion eliminates {he risk of contaminating the injected enriched gas with the leaner solution and gas~ca~ gas (and thus potentially losing misci- bility) and avoids problems associated with the injection of large volumes of water necessary to decrease the free gas saturation. Thus, 49 AGO 10023816 these favorable reservoir conditions reduce the risk and cost of imple- mentation. An additional reservoir benefit provided by an expeditious implementation of the process results from the potential to maximize oil recovery from the Project Area within the currently limited time frames of injectant availability and Project life. As was detailed in the previous section, reservoir simulation studies have suggested that additional recovery may be obtained by extending the total miscible gas volume injected past the 10% PV slug. The flexibility to maximize oil recovery is enhanced by an early start-up of the Project since a longer period of miscible gas displacement may be supported with the present facilities before the anticipated decline occurs in design rates. In addi'tion, early start-up ensures that the oil rim life of the Field does not impact the operating life of the FS-3 Injection Project. Thus, ultimate recovery from the Project Area becomes a function of the actual process performance and economics rather than being constrained by injectant availability or overall oil rim life. Implementing the Project in the 1983 timeframe will also provide valuable reservoir and operating knowledge for use in evaluating whether other tertiary .projects can be applied for increasing the ultimate recovery from the Prudhoe Bay Field. Considering the inherent reservoir and operational complexities associated with an enhanced recovery process, it is desirable to obtain some actual Field performance data to aid in designing other future possible applications. 50 AGO 10023817 Finally, during the course of evaluating miscible gas recovery potential within the Flow Station 3 area, it became apparent that deferring imple- mentation until completion of the waterflood could render the Flow Station 3 Injection Project uneconomic. As opposed to the current design, it is estimated that a substantially greater investment in additional facilities would be required to supply the enriching feedstock after 1990. Since initiating miscible gas injection immediately following infill drilling will minimize the need for remedial well work, maximize the efficient use of flowlines and facilities operating lives, and result in an overall reduction in operating difficulties associated with aging equipment, it is anticipated that operating and maintenance costs for a late life Project would be significantly higher than the current values, The economics of a late Project start-up would also be additionally burdened by higher injeotant costs since a greater amount of the solvent would be left in the reservoir at Project abandonment as discussed previously in connection with the reservoir simulation model results. For the above reasons, the Unit Owners believe that implementation of the Flow Station 3 Injection Project in Danuary 1983 is warranted. 51 AGO 100Z3818 PART THREE - WINDFALL PROFIT TAX QUALIFICATION REQUIREMENTS For purposes of the Crude 0il Windfall Profit Tax Act of 1980 an enhanced oil recovery project is a "qualified tertiary recovery project" if the operator submits a certification to the Secretary stating that a designated jurisdictional agency has approved the project as meeting the requirements in I.R.C. § 4993(o)(2) that: (A) the project involves the application (in accordance with sound engineering principles) ~f 1 or more tertiary recovery methods which can reasonably be expected to result in more than an insignificant increase in the amount of crude oil which will ultimately be recovered, (B) the project beginning date is after May 1979, and (C) the portion of the property to be affected by the project is adequately delineated. The AOGCC has been designated by Governor Hammond in accordance wi'th the I.R.C. § 4993(d)(5)(A)(i) as the jurisdictional agency responsible for approving tertiary recovery projects located on nonfederal lands in the State of Alaska for purposes of the WPT Act. As will be discussed in the following paragraphs, the Flow Station 3 Injection Project meets the requirements of subparagraph (A), (B) and (C) of I.R.C. § 4993(o)(2) and should therefore be approved by the AOGCC as meeting those requirements. 52 AGO 10023820 i iI Qualified Tertiary Recovery Method The Flow Station 3 Injection Project involves the application of a WPT Act qualified tertiary recovery method. The term "tertiary recovery method" is defined in the WPT Act as: (A) any method which is described in subparagraph (1) through (9) of section 212.78(c) of the Dune 1979 energy regulations, or (B) any other method to provide tertiary enhanced recovery which is approved by the Secretary for purposes of this chapter. I.R.C. § 4993(d)(1) The term "Dune 1979 energy regulations" which is used in the above definition is defined in I.R.C. § 4996(b)(8)(C) as Department of Energy regulations which existed on Dune 1, 1979 including final action taken pursuant thereto before Dune 1, 1979, and including action taken before, on, or after such date with respect to incremental production from qualified tertiary enhanced recovery projects. The enriched gas WAG injection method which is planned for use in the Flow Station 3 Injection Project is a miscible fluid displacement method. Miscible fluid displacement is listed as a tertiary recovery method in subparagraph (1) of the section 212.78(c) of the Dune 1979 energy regu- lations. This definition of miscible fluid displacement was amended on August 30, 1979. These amendments added a pore volume requirement to the miscible fluid definition and also changed "gas or alcohol" to "fluid". The Dune 1979 definition of miscible fluid displacement and the August 30, 1979 amendments thereto are in Exhibit #1. 53 AGO 10023821 The Flow Station 3 enriched gas WAG injection process meets all the requirements in the Dune 1979 definition of miscible fluid displacement and also the requirements added by the August 30, 1979 amendments. Enriched natural gas will be injected into the oil reservoir at pressure levels such that the gas and the reservoir oil will be miscible. The injected gas measured at reservoir temperature and pressure is reasonably expected to be more than 10% of the reservoir pore volume being served by the injection wells. The process involves the alternating injection of water and gas which is specifically recognized in the energy regulations. Sound Engineering Principles The Flow Station 3 Injection Project has been planned and will be imple- mented and operated in accordance with sound engineering principles. The planning and implementation of the Project has been under the direct supervision of qualified and experienced reservoir engineers. Miscible fluid displacement using enriched hydrocarbon gas was selected as the best method to use at this time for this portion of the reservoir after a comparative examination of various methods based on formation type, injectant availability, and process costs. The various other methods which were examined for potential use in the Project were discussed in Part One of this Application. The Project was planned after a thorough examination of the Sadlerochit formation underlying the Project Area including its geological character- istics, permeability, reservoir pressure, current and projected well 5# A(~O 10023822 productivity, statistical data relating to actual and projected well performances, and viscosity, pressure build-up and sweep efficiency analyses. The Project applies the miscible fluid displacement method in a manner which is generally recognized and accepted in the professional literature of engineering as likely to increase the amount of crude oil that can be economically recovered from the Project Area. The legislative history to the WPT Act indicates that as a general rule sound engineering principles require implementation of secondary recovery processes prior to the undertaking of more enhanced recovery methods. However, if producers can illustrate reservoir or oil peculiarities and other adequate reasons for absence of secondary methods, the sound engineering requirement will be considered to have been satisfied. Sufficient reasons have been shown in this Application why it is in accordance with sound engineering principles to implement a tertiary recovery project in this Project Area prior to a secondary waterflood project. These reasons were discussed in detail in Part Two and by way of summary are as follows: 1. The implementation of this Project as soon as possible provides an opportunity to maximize oil recovery from within the Project Area by extending injection of miscible gas past the 10% pore volume slug, if economically feasible, as indicated in Exhibit 34. 2. A start-up of miscible gas injection prior to a secondary waterflood reduces operational complications caused by fluid migration and gas tonguing. 55 AGO 10023823 3. The feedstock necessary for enriching the gas to make it miscible may not be economically available if the Project is not implemented until after waterflooding. 4. Any substantial deferment of the Flow Station 3 Project could render the Project uneconomic because of higher risk from reservoir contamination by solution and gas cap gas in latter years and higher investment, operating, and injeetant costs. The remote and harsh Arctic environment, which makes Prudhoe Bay development peculiar, additionally burdens the implementation of a tertiary recovery process when compared to a routine oil field operation in the continental U.S. 5. Valuable reservoir and operating knowledge for use in evaluating other potential tertiary projects at the Prudhoe Bay Field will be gained from the implementation of the Flow Station 3 Injection Project. A successful WAG project at Flow Station 3 will encourage the implementation of projects in other areas of the reservoir. Start-up of the Project before secondary is neces- sary to provide information early enough that other projects may be designed and implemented in the Unit during the time frame in which other miscible fluid sources can be developed economically .. for injection. 56 AGO 1002382z, 6. Laboratory core results indicate no difference in oil recovery regardless of whether miscible gas is injected before or after water injection. However, initiation of the Project at this time will capitalize on existing favorable conditions and reduce the risk of the less favorable conditions associated with deferral. Deferral could potentially lead to lower recoveries which could preclude the Project. More Than An Insignificant Increase in Recovery It is reasonable to expect that the Project will result in more than an insignificant .increase in the amount of crude oil which will ultimately be recovered from the Project Area. There is estimated to be 442 MMSTB of original oil in place in the Project Area. It is estimated that 122 MMSTB of this original oil in place would be recovered if only primary operations were undertaken (27.7% OOIP). An additional 65 MMSTB is estimated to be recovered if an 80 acre pattern waterflood was conducted (42.2% OOIP). The implementation of the Flow Station 3 Injection Project is estimated to recover at least 89 MMSTB of additional oil over primary recovery and at least 24 million additional barrels over recovery from an 80 acre pattern waterflood, providing an increase in ultimate recovery of 20.0% (OOIP) over primary and 5.5% (OOIP) over 80 acre pattern water- . flooding. This corresponds to an increase of 12.8% in the recoverable primary and secondary reserves. A recovery of 24 million additional barrels of oil is clearly more than an insignificant increase in the ultimate recovery of crude oil. 57 AGO 10023825 Project Beginnin9 Date After MaX 1979 A project will qualify under the WPT Act only if its "project beginning date" is after May 1979. The term "project beginning date" is defined in I.R.C. § 4993(d)(2) as the latter of the date on which the injection of liquids, gases or other matter begins or the date on which the project is certified. Either of these two dates for the Flow Station 3 Injection Project will be after May 1979 because the Project has not yet been certified and injection has not yet commenced. Adequate Delineation of Project Area If a tertiary recovery project is expected to increase the ultimate recovery C~f crude oil from only a portion of a D.O.E. property, that portion is required to be treated as a separate property for incremental tertiary oil purposes (I.R.C. § 4993(d)(3)). The Flow Station 3 Injec- tion Project which is currently planned will affect only a portion of the Prudhoe Bay Unit which is one D.O.E. property. As discussed previously~ the area which will be affected involves 11 injection patterns and encompasses approximately 3650 acres. The boundaries of the Project Area are defined by the outer producing wells of the nine spot patterns to the east and west~ by the limit of development drilling to the south, and by the seven water injection .wells to the north. The Project will affect the entire light oil column of the portion of the Sadlerochit Reservoir which lies within the surface boundaries of the Project; The 58 AGO 10023826 area which will be affected by this Project is delineated on Exhibits 10 and 12. A reasonable allocation will be applied to production from any peripheral well determined to be producing oil from outside the Project Area which is unaffected by the tertiary method. The portion of the Prudhoe Bay Unit which will be affected by the Project has been adequately delineated in this Application and will be treated as a separate property for purposes of calculating the WPT base level for the Project and the amount of incremental tertiary oil removed each month from the property. AGO 10023827 SUMMARY In this Application, ARCO has presented sufficient facts and information to demonstrate that the miscible fluid displacement project which is planned for Flow Station 3 at the Prudhoe Bay Unit meets the requirements of I.R.C. § 4993(c)(2)(A), (B) and (C). Specifically, we have demonstrated that: a) The Project involves the application of an enriched gas miscible fluid displacement method which is a qualified tertiary recovery method as that term is defined in I.R.C. § 4993(d)(1). I b) The Project has been planned and will be implemented and opera- ted in accordance with sound engineering principles. c) The Project is reasonably expected to increase the ultimate recovery of crude oil from the Project Area by 24 million barrels, an amount which is clearly more than an insignificant increase. d)' The Project beginning date will be after May 1979. e) The port'ion of the Prudhoe Bay Unit which will be affected by this Project has been adequately delineated in this Application. 60 AGO 10023829 Based on the foregoing facts and information,. ARCO respectfully requests that the AOGCC, in its capacity as a designated jurisdictional agency, issue an order approving the Flow Station 3 Injection Project as meeting the requirements of subparagraphs (A), (B) and (C) of I.R.C. § 4993(0)(2). 61 AGO 10023830 TECHNICAL REFERENCES · ® Griffith, O. D. and Lyca, L. G.: "Performance of South Swan Hills Miscible Flood," paper SPE 8835 presented at First Or. SRE/DOE Symposium on EOR at Tulsa, Oklahoma, April 20-23, 1980. Benham, A. L., Dowden, W. E. and Kunzman, W. O.: "Miscible Fluid "Trans. AIME (1960) 219, Displacement--Prediction of Miscibility, , 229. · Arnold, C. W., Stone, H. L. and Luff el, D. L.: "Displacement of Oil "Trans. AIME (1960) 219, 305. by Rich Gas Banks, , . Ballard, 3. R., Smith, L. R.: "Reservoir Engineering Design of a Low-Pressure Rich Gas Miscible Slug Flood," 3. Pet. Teoh. (May 1972) 599-605. · Griffith, D. D. and Horne, A. L.: "South Swan Hills Solvent Flood," Procedures 9th World Petroleum Congress 1975, Panel Discussion 14(3). . Herbeck, E. F., Heintz, R. C., and Hastings, O. R.: "Fundamentals of Tertiary 0il Recovery Part 3 - Enriched Gas Miscible Process," Petroleum Engineer (March 1976) 84-88. Spivak, A.: "Gravity Segregation in Two-Phase Displacement Processes," Soo. Pet. Eng. O. (Dec 1974) 619-632. 8. Warner, H. R., Or.: "An Evaluation of Miscible CO2 Flooding in Waterflooded Sandstone Reservoirs," D. Pet. Teoh., (Oct. 1977) 1339-13#7. 9. Youngren, Gary K. and Charlson, Gary S.: "History Match Analysis of the Little Creek CO2 Pilot Test," paper SPE 8200 presented at the 54th Annual Fall Meeting, SPE/AIME, Las Vegas, Sept. 23-26, 1979. 10. Caudel, B. H. and Dyes, A. B.: "Improving Miscible Displacement by Gas Water Injection," Trans., AIME (1958) 213, 281-18#. 11. Blackwell, R. 3., Terry, W. M., Rayne, O. R., Lindley, D. C. and Henderson, D. R.: "Recovery of 0il by Displacement with Water-Solvent "Trans. AIME (1960) 219, 293-300. Mixtures, , 12. Shelton, O. L. and Schneider, F. N.: "The Effects of Water Injec- tion on Miscible Flooding Methods Using Hydrocarbons and Carbon Dioxide," Soo. Pet. Eng. O. (Dune 1975) 217. 13. Brannan, G. and Whitington, H. M., Or.: "Enriched Miscible Flooding - A Case History of the Levelland Unit Secondary Miscible Rroject," paper SPE 5826 presented at the 51st Annual Fall Conf. of SPE, New Orleans, Oct. 3-6, 1962. 62 AGO 10023832 TECHNICAL REFERENCES 14. Todd, M. R. and Longstaff, W. 3.: "The Development, Testing, and Applioation of a Numerioal Simulator for Predicting Miscible Flood Performanoe," D. Pet. Teeh. (Duly 1972) 8?4 ff. 15. Raimondi, P., Toroaso, M. A. and Henderson, D. H.: "The Effect of Interstitial Water on the Mixing of Hydrooarbons During a Miscible Displaoement Prooess,": Mineral Industries Experi- ment Station Circular No. 61, The Pennsylvania State U., (Maroh 1964) 49-55; Trans. 16. Ra£mondi, P. and Torcaso, M. A.: "Distribution of the 0il Phase Obtained Upon Imbibation of Water," Soo. Pet. Eng. 3. (March 1964) 49-55~ Trans., AIME, 231. 17. Thomas, G. H., Countryman, G. R. and Fatt, I.: "Miscible Displaoement in a Multiphase System," Soo. Pet. Eng. D. (Sept. 1963). 18. Stalkup, F. I.: "Displaoement of 0il by Solvent at High Water Saturation," Soc. Pet. Eng. D. (Deo. 1970) 337-348: Trans. AIME, 249. 19. Kane, A. V.: "Performance Review of a Large Scale C02-WAG Projeot SACROC Unit - Kelly Snyder Field" paper SPE 7091 presented at the 1978 SPE Symposium on Improved 0il Reoovery, Apr. 16-19. 20. Grave, D. D. and Blevin, T. R.: "SACROC T.ertiary CO2 Pilot Pro,eot" paper SPE 7090 presented at the 1978 SPE Symposium on Improved 0il Reoovery, Apr. 16-19. 21. Shelton, D. L. and Schneider, F. N.: "The Effects of Water Injeotion on Misoible Flooding Methods Using Hydrooarbons and Carbon Dioxide," Soc. Pet. Eng.. 3. (Dune 1975) 217. 63 AGO 10023833 EXHIBITS AGO 10023835 EXHIBIT 1 PRUDHOE BAY UNIT WORKING INTEREST OWNERS Amerada Hess Corporation ARCO Alaska, Inc. Chevron U.S.A., Inc. Exxon Corporation Getty 0il Company The Louisiana Land and Exploration Company Marathon Oil Company Mobil Oil Corporation Sohio Alaska PetrOleum Company Phillips Petroleum Company Petro-Lewis Corporation AGO 10023836 .;'FI ] O- 2 7- ~0 TAX C¢::.:!iiEE The !;onorable :.t. :4ichael Blumenthal Secretary of the Treasury =.eat and Pennsylvania Avenue. Washington, D.C. 20220 ARCO Oii and Gas Com?.-,ny E&P and P'/L 'i'a~:~s- Datt~s OF.T:-'~ ~ ~,,. 0 ' I~;~. UCH~NAN HAZELVf~CD' FRE~TO?i.' . . EGAN }~CTLEY SCRI~NSR Dear Mr. S~czekary: .. ; ?ursuant to the requirements of Section 4993 (d) (5)(A) of the recently enacted Crude Oil Windfall' Profits Tax Ac~ c 1980, I have appointed the Alaska Oil and Gas Conservation Co.wmission (AOGCC) as the ,jurisdictional agency over ap- plications involving tertiary recovery projects .on lands in Alaska not under federal jurisdiction. The AOGCC ~,'ill revie'~: and take suitable action on any application'for a · _ = the tertiary recovery project within the stipulations o._ Crude Oil WiD. dfall Profits Tax Act of 1980, and applicable regulations. · This notifi'cation fulfills the responsib:lities of the Governor of Alaska to provide a ~,'ritten 'submittal of ac~cncy designation in accordance with Section 4993 (d) (.5)(A) of the Act. ' .. Acknowledc. ement of receipt of this letter is requested. Sincerely, Jay S. llanunond Governor c.c: 1.1ol.,le .Il. Hamilton, Chairman/Commissioner Alaska Oil and Gas Conservation Cor,=mission The Ilonorable ¥;illiam P. Clements, Governor o~ Texas Interstate Oil Compact Co~mission .. ... Wi!liam I.:. Hopkins Alaska Oil and Gas Association· · · · . . · The Honorable Robert E LeRe$che, Com,mizsioner Department of Natural Resources AGO 10023837 · Tool 2 M-C M-C A-E A-r M-P SOfllO M-P M-P'-C · M-P A-E SOHIO ~HIO ~OHIO M--P SOHIO ~OHI0 A. H,- G~T'rY A-E SOHIO I SOHIO A-E t A:E · PRUDHOE BAY UNIT .BOUNDARY A-E SOHIO A-E A-E A-E EXHIBIT 3 PRUDHOE BAY UNIT UNIT OUTLINF Sit,arid wthXirl T. lO-12N. R. 10-~6E. L~i~t Ikridlan MOrH~ ~O1~ of HOikO LEAS~ LEGEND A-F -- ARCO-EXXDN M-C -- M~ - CH£VI~N M-P -- IdOML- PNK. LIPS M-P-C -- M~I k - P~ L LU;~ --CHEVIK~ & I~, e~ M -- AMER,M)A HE'~'q, et M &H.*M'TTY -- MI~,D~ H~SSoG~'TY I -+' .... ~o .... ;- .... ~--- I I I I -+, AlE I A-E A- E SOHIO , A-E I I I - ' '"~':-'~,o~---- SOHIO I A'-E. A-E A-E SOHIO 89 SOHIO A-E A-E ~, A-E A-E A.H.It al M-P SOHIO SOHIO SOHIO A-E t03 ~ ,U 14)i · ' "' 106 " SOfllO ' ' M -P-C SOHIO I I "109A" "' ' I A-E A-E SOHIO , ,. .,.., ~,.-n '~';';'" '~:"?"! ''?':' ,.., / .. :?. , ~'o-,~ '"" ' ':" ,:"': t)';" ' u' ' I OD N O O ii' EXHIBZT ,4 (, Departrm~nt of Natural Resources Division of Oil and Gas Ccz~e_~ation Alaska Oil and Gas Consar%~tion C~rmi~ee " 3001 Porcupine Drive Anchorage, Alaska 99501 Re: The request of Atlantic Richfield ) Coupany and BP Alaska Inc. t~ ) present tastL~ony to detezmine ) · new pool rules and amend existing ) rules for the Prudhoe Oil Pool. ). ) Cons~ticn Order No. 145 Pru~ Bay Field June 1, 1977 · · ,.. 1." 'The ~ef~renced c=~p. anies app. lie~.by'~ letter received March 30, 1977, for a hearing to .adopt new cz am~'~d e~s~tng pool rules.' 3, Notice of public hearing was published in the Anchorage Daily News on April 2, 1977. · . A public hearing was held in the Ramada Inn, Anchorage, Alaska on May 5 and 6, 1977. ' The hearing record was continued until the close of business on May 16, 1977. Additional data was received.. Rules per~g to the P~3_~_hoe Oil Pool have been included in Conservation Order Nos. 98-B, 130, and 137. .. Administrative approvals 98-B. 3, 9 $-B. 6, 98-B. 7, and 9 $-B. B written pursuant to Conservation Order No. 98-B, Rule 8 are currently in effect. · Wai%~rs per~g to blowout prevention practic~~ written. pursuant to Conser~mtion Order No. 137, Rule 2 '-are currently ,in effect. · The applicants prOPOse to raise and lower the vertical pool 1/mits of the Prudhoe Oil Pool to include the "Put River Sandstone" and Ivishak Shale respectively.. J No drill stem tests or production tests have been conducted in the "Put River Sandstone" or the Ivishak Shale , No analysis of fluid fram the "Put River Sandstone" or the Ivishak Shale are presently available to t_he Cmnnit~e. · . . AGO 10023839 CONS~_~TICN OED~-R NO. 145 Page 2 June 1, 1977 ~ The areal =x%~nt of the Pru~/hoe Oil P°°l as defined on March 12, 1971, · Ln Conservation Order No. 98-B, is co~iderab!y larger ~han t-he area nc~ proven t~ be produ~ive by ~he drilling of' addit/ona! wells since Most producing w~lls ~n the Prudhc~ Oil Pco! are deviated holes to min/mize the number of drilling pads. · 9. The applicants propose to elimj_nat~ reference to acreage _spacing re- quiran~_n~s but rec~aest that at least 2000 feet be rn~n*~ned between the pay opened in the well bore in a] ~ w~ll~ in the Prudhc~ Oil Pool. 10. The applicants propose that a distance of !000 feet be maintained between r_ha .pay .cpened in any well and the bouna~y of the Prudhoe . . · regulation and opera~ of thru regervoir. 12. Perfo~r=nnce must be'accurately observed and quickly analyzed for a timely asses~_nt of reservoir behavior. 13. Perfc~nance during t. he first two years wi!! be 'used to design the water fi~g prcject~ and ~ be vital in fo~malat_ing and imple- men ~ting furze: opera~ plans. ' · 14. A reservoir surve~ ] ]ance program can provide for mmnitoring both reservoir and production da~a. 15. M~nt_hly production tests will mc~it~r changes in w~L1 produc--~ivity, gas-ci! and oi!-wmtar ratios, and provide basic da~a for reservoir . 16. The reservoir is ccmpiex with many discontinuous intarbedded sb~es. 17. The reservoir is underlain by a heavy oil or t~r zone of %retying thickness. · 18. Scr~ areas of the raservo~ 6ontain many faults.. 19. The reservoir pressure data will provide inf°~ation on well flow efficiency, reservoir permaabi!ity, reservoir ~disccntinuities, and the need for a pressure m~ntanance pr .c~ram. 20. The use of .specialized transient pressure tmst].ng tmchniques' such as pulse 'testing, vertical peazmaabi!ity tests, and interference tests may prove useful. 21. Specific wells may be selected which are located outside the main area of the Sadleroc.h/t oil colunn to monitor the pressure in the ~ gas cap, the' aquifer, the Eileen a~ea, and the Sag River gas cap. 22. The aFp!ic~nts have agreed t~ a ccmr~pn datum plane of 8800 feet subsea for all pressure surveys. AGO 10023840 CONSER¥~TiON ORDW-R ~ 145 Page 3 J=ne 1, 1977 23. Changes in the gas-oil fluid contact movement in the reservoir with response to production would provide information on shale continuity, effective v~r~cal perm =eabi!ity, displacement .~fficiency of oil by gas and define areas of poor natural recove~-y. 24. Preliminary studies indicate that early run open hole or cased hole neutron logs may provide a suit~B!e base log for monitoring the movemant of the gas-oil contact by ~ison with a later cased hole neutron log run in the sam~ 25. Open hole neutron logs have ~eady been r%~n ca the majority of walls. 26. Cased hole neutron logs have ~lveady been run in a and will continue to be run in selected wells until .this technique . "i'-,-27-.. Monitoring .the mov~t of ~a.6i!-wat~r =~tact ~hO~d halp to detezmLne the extant of water infi'Ux ~rcrn the aquifer, idenf~,=y areas of peripheral, water influx and allow dete_!nination of the ... water displacament efficiency. 28. Monitoring the oil-water contact should provide infoL~atica to ha!p define locations where water injection would be beneficial. 29. A program is now in progress to evalua~ the capability of monitoring the oil-water contact with cae of three d/~ferent methocis, such as the Thermal Decay Tools (T.D.T.) or the Neutron Lifetime Log (N.L.L.) , the Carbon-OxTgen Log an~ the Sam~ Ray Lo~. 30. The ca,u~bility of these m~th0~s to monitor the changing oil-water contact has not been demonstrated as . 31. The contribution of each ~ the xrarious perforated in~ in each producing well may be detannined through dc~nhole spinner flow meter surveys. 32. A reliable assessment of the rate of the production fr=n' the various lithologic subdivisions within the reservoir will assist in the detar- ruination of the effectiveness of the well 'cOmPletions to dr~n the reservoir. : 33. Numarous 'computer reservoir simulation mo~el studies of the Sadlerochit Formation have been made by the State and the working in%e~est cwners. In these studies the offtake rates of oil and gas and the injection -rates of gas and water have been varied. 34. The Trans-A!aska Pipeline will have an initial capacity of 1.2 million barrels per day and should be ready to accept oil near mid !977.- ... 35. The a.~plicants have submitted a Plan of Operations whi=h includes proposed average annual off take rates of 1.5 million barrels per day for oil plus condensate production and 2.7 billion cubic feet per day for gas. AGO 10023841 CONS~'--RI~TION OP~--~R NO. 145 Page 4 June 1, 1977 36. Production facilities to surpport an average oil offtake of 1.2 million ba_-reis ~.day will be installed by the last quarter of 1977. Addi- tions are plar~ned during ]378 and 1979 to suppo~ an average oil off take rate of 1.5 million barrels per day plus condensate prcdu~ion, when pipeline capacity is available. 37. Gas sales in large volumes from the Prudhoe Bay Field will not be possible until a gas conditioning plant, and a large gas sales pipeline are constru~ed. 38. The ccr~.ietion of a large gas sales pipe~n~e and plant t~ c~n~ticn gas is estimated at appr 'oximately five yea~s fram st~t of oil production. Un'ii a large ga~" sales pipe]'~ne, is available, all '~cduced gas, except that used as" fuel in the-field and ~small loca~ gas sales, wil]~ be r~nj~-ted 'into f_he gas ...cap.. .. 40. Gas will be used to supply the opera~g re<~r~nents of the Prudhoe Bay Field, the first four pump stations of the Trane-Alaska Pipeline and other minor local fuel needs. 41. To meet pipeline sale .cual/ty it will be necessary t~ remove carbon dioxide ~ram the gas. . . 42. Water 'prcduc~on will be mill init/~]~v and will 'be di .sposed of by injection into sands of Cretaceous age. 4'3. When ~tar production becames significant, the a.rp!icants p_~n tm file a secon~ recovery application for th~ injection cf ~ water into the Pruf~oe Oil Pool. 44. Injection of prcducad water into the Pruclhoe Oil Pool could begin within two years after start of oil prcductian. 45. The applicants wi!! proceed with design and impl~ta~on studies concurrently with injectivity taste and reservoir data gathering to '~hortan the imp~entat_ion ~ for a source water.' inject_ion "46. The Sadlercchit Formation aquifer exhibits the best reservo~ qualities near the .Prudhoe Bay Field area and pr .cgressive!y deteriorates away fram the field. CCIWCLUSIONS: To avoid confusion it would be desLrable to conso!idata the outstanding Pool rules effecting the Prudhoe Oil Pool into one order. Conservation Orders Nos. 98-B, 130, and Rule 2 of Conservation Order Nc. 137 should be canceled and the relevant porT_ions included in Conservation Order No. 145. AGO 10023842 Page 5 June 1, 1977 2~ . Adm/nistrative Approvals 98-B. 3, 98-B. 6, 98-B. 7, and 98-B. 8 should r end_in in e_._ect and will be applicable un ~ti! stable production the field is .attained or until the t/me period, stipulated expires. Waivers per~~g to bio,out preventers written pursuant to Conservation C~rder No. 137, Rule 2 should r~n in effect. . 5~ There are insufficient data to juse~fy raising cr lowering the vertical limits of the Prudhoe Oil Pool, as pr .cposed by the applicants, to correspond with the vertical limits .of the Prudhoe Bay (Permo- Triassic) ReservoLr as described in the Prudh~ Bay Unit Agreement. The areal enchant of the Prudhoe Oil Pool ~hould be identical to the initial participating area of the Pruclhoe Bay Unit which is described as the Prudhoe Bay (P~Triassic) Reservoir in the Unit Agr~t. facilitate present.and future additional recovery operations and enable the'unit operators to develop the-'prcductive capacity to meet'the · planned throughput of the Trans-Alaska Pipe] ~ ne. . A distance of 2000 feet between the pay opened in the w~ll bore in. ' all wells in the Prudhce Oil Pool should maintain an adequate drainage area, not unnecessarily restrict bottamhole e~get locations and protect col-relative right~ iand prevent, waste. A distance o~ 1000 feet between the pay opened in any well and the boundary of the Prucihoe Oil Pool will protect correlative rights. To gather the data i necessary for proper regulation and operation of the reservoir, a rigorous surveillance program of rese_r~Dir parf~ce should be accurata!y observed and assessed especially during the first two years of operation. The surveillance program should ~]-~o provide guide!/~es far a long t~ key'wel! surveillance progr~ 10. A surveillance program should include monitoring the_ rese_~ir pressures, gas-oil and oi!-w~ter contact m~v~ts, production tests, gas-oil and water-oil ratios, and produc=ivity profiles of individual w~3~. -11. A ~as-oi! 'contact movement m~ni=~ prc~ram/ ba~ed 'on 'a c==.=r, ison of open hole neutron base logs to be later comp. ared with neutron lc~s run in the sam~ wells should be a t~a~mpted. '12. The data obtained during the first two years could lead to a key well program of periodic surveys that may adequata!y monitor t_he gas-oil contact movements. 13. Monitoring the movement of the oil-water contact is desirable to evaluate the water influx in the reservoir and the .applicability of w~tar injection systems. Three methods ~re potentially applicable as means of m~nitmring the mov~_nt of the oil-water contact. These methods are the The~ Decay Tools or the Neutron LifetL~e Log, the Carbon-Ox%;gen I~ and the Ganma Ray Log. The pr .ogram to evaluate =he relative capability of these AGO 10023843 : C~NSE.~v~TION ORD_rR NO. 145 Page 6 June !, 1977 lcgs mhould be ccntLnued and -~,hould tony ~ethcd be d_=n~?_~trata~2 caFable of adequ, ately monitoring the changLng ~,~=_er sa~arati~ns in t_he reservoir, a key well pr ~cc/ram should be set up. 14. ~ole spinner flc~ meter surv .eys tm detemmine w~!l prc~uctivity profiles should help det=rn~ine the effectiveness of cc~p. le~o~ and provide information on reservo~ drainage. To provide the necessary productive, fy prc.=?_~le data a base line survey should be !nih on each well with later folic~ up, sur~eys c~n each 15. The injection of produced wa~ into the Sands of Cretaceous age will n_ct ccn~ta ~res~. water .sources ~ endanger other natural resources. .1 '6. Studies of t~e a '.q~."'fer have i~dicata~-that it prubab!y will not offer ~ 'much 'preSsure 17. Reservoir studies-have shown that both produced w~ter injection and source water injection into th~ P~oe Oil Pool should increase oil 18. Reservoir stuslies have. shown that large scale source ~atar injec~ion will probably be necessary t~ maximize 'oil recovery. 19. The ?~nned reinjecUion of gas into the Sadlerockit gas cap prior to large gas sales will help to maJ_ntain reservoir pressure and will not adversely affect u!tLmate recovery. , 20. The Plan of Opera, ohs proposed by_ the applicants which average annual cfftake rates of 1.5 m/ilion barrels per day fur oil plus condensate prcduction and 2.7 bill_ion cubic feet per day for gas are consistent with sound ccnservmticn practices based cn currently available data. 21., After field and local fuel recf~4r~ts and the rem~ cf carbon dioxide and liquids frmn the prcducad gas, it is es~-imatmd t_hat a ga~ prcducticn rate of 2.7 bLlli0n s-tanciard Cubic fe~_t per day will yield 2.0 billion standard cubic feet per day of pipeline quality gas. '22. Prcducticn history will be D~eded to locate ~ater injection wells and to refine reservoir resale! studies. 23. .The cfftake rates approved by the Ccrmittee at t_his ~ must be estmb!ished without the benefit of production histcu-y. Therefore, these offtake rates may be ~hanged as prcducticn data and additional reservoir data are obt~_4ned and analyzed. AGO 10023844 CONSZ_RVATIQN ORD~--R NO. 145 Page 7 June 1, 1977 NOW, THER_~RE, IT IS ORDERZI) THAT ~he rules hereLnaftar, set fo_~.h apply to ~dle following des~-r_ibed area referred to in this drder as the affected area: T. ION., R. 12E., Sections 1, 2, 3, 4, 10, 11, 12 T. 10N., R. 13E., T. 1ON., E. 14E., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, L1, 12, 13, 14, 15, 15, 24 .' 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, . . 24, 25, 26, 36 . . . ~ . .: 5, 6, 7, 8, 17, 18, 19, 20, 29,.30, 31 1, 2, 3, 4, 9, 10, ~, 12, 13, 14, 15, 24, 25 T. liN., E. 14E., T.'~ liN., R. 15E., T. LIN., R. 16E., 30, 31, 32 15, 16, 17, 18, 19, 20, 21, 22, 25, 26, 27, 28, 29, 30, .32, 33,' 34, 35, 36 23, 24, 25, 26, 27, 28, 33,' 34, 35, 36 T. 12N., R. 13E., ' ' "31 '32 33 34 19, 26, 27, 28, 29, .30, , , , , 35, 36 - · T 12N., R. 14E., 25, 26, 27, 28, 29, 31, 32, 33, 34, 35, 36 T. 12N., R. 15E., 27, 28, 29, 30, 31, 32, 33, 34 '. AGO 100238%5 CON--~.~ION ORDER NO. 145 Pace $ June 1, 1377 Rule ! Pool bef~nition The Prudhoe Oil Pool is defLned as the ac~-m~laticns of oil ~hat are c~on to and which correlate with the accumulations found Ln the Atlantic Ridnfie!d - Humble Prudhoe Bay State No. 1 w~!l between the depths of 8,3~0 and 8,680 feet. Rule 2 Well Spacin~ In the affected area, no pay sha3~ be opened i~ a well closer than 2000 feet to any pay opened in another w~ll in the P~dhoe Oil Pool cr be nearer than 1000 feet to the boundary of t_he affected area. · ~ie-~-casing ~nd Cemen'~ting ~equ/rsm~nts :~ .. (a) .Casing and cemen~g programs ~hail provide ad -equate prct~_-ticn of all fresh waters and productive farma~cns and protsc~cn f_rcm any pressure that may be encountered, including. ~xta_~ freezaback within ~he permafrost. (b) For proper anchorage and tm prevent an uncontrolled f!cw, a conductor casing shall be set at least 75 feet belc~ the surface and sufficient cement shall ~be used to fill the annu!u~ behind the pipe to the' surface. . (c) For proper anchorage, to prevent uncontrolled f!cw and to protect the well frc~ the effects cf pe_~n~/Dst thaw, a string of surface casing shall be set at least 500 feet be!c~ the base of the perma- fro~ section but not belc~ 2,700 feet ~niess a greater depth is approved by the Ccn~nittee u-pon showing that no potenti ~!!y prc~uctiv~ pay exists above the .proposed casing setting dsp~h, ~nd suffici~t cement sba] ~ be used to ff~] the a~nu!us behind ~he pipe to t_he surface. The surface casing shall have minimum post-yield strain of-0.9% in tension and 1.26% in ~essicn... .. (d) If the surface casing does not meet 'the ~ain re?~r~o_nts in (c) above, the integrity of the well sha] ~ be protact_=d from the effec~ of permafrost thaw by runn/ng an i~_ner string of cesing ~lso set at least 500 feet beicw the base of the permafrost section and pr .oper!y c~nented except that the ~'o casing strings shall not be · bonded together within the permafrost' seCaion. This inner string of casing shall not be utilized as production casing. (e) Or. her means for maintaining the integrity cf the well from the effects cf permafrost thaw may be approved by, the Ccr~niTtee .upon a.~plication. (f) Prcduc~.icn casing shall be landed t~hrough the ccr~_ !eticn zone and c~_nt shall cover and extend to at least 500 feet abov~ each hydro- carbon-hearing fonna%ion which is pot=-n~ial!y prcduc~ive. In t~e alternative, the casing string may be set and ad .equata!y csmenta~ at AGO 100238z~6 CC/q__c-~Kg~TI~N ORDER NO. 145 Page 9 June 1, 1977 at an zn~_w~d_a~e point and a ] ~ her landed %hrouc. h ~he camp. !e*_~on zone. If such a liner is run, the casing and !/n:~ shall overlap by at !eaSt 100 feet and the armular space behind the ~liner shall be filled wizh c~ant to at least 100 feet above the casing shoe, ar the top. of the liner shall be squeezed with sufficient c~_nt to provide at least 100 feet of c~ment between the liner and casing. Cement must c~ver and extend at least 500 feet above each hydrocarbon- bearing fonmation which is potentia3~y p.roductive. (g) Casing and liner, after being c~manted, shall be satisfactorily tested to not less than 50% of minimum in~al yield pressure or 1,500 pounds per square inch, whichever,is less. (h) No well shall be ?~odu.ced through the annulus between the tubing · And-the casing' unless a-cement sheath exten~.fr~~e top of the "' pay to the shoe of the next aha..l!.~r c~.sing., string. '.. · · (a) The use of blowout Prevention equipment sha~l be in accordance wi~h good established practice and all equi~t .shall be in good operating condition at all tin~s. All blowout prevention equi~ent shall be adequately protected to ensure re!labile operat/on under the existing w~ather conditions. All blowout prevention equi.~uent sb~ be checked for satisfac~ operation during each ~ip. (b) Before drilling below the c~nductar string, each well sha!~ have instmlled at least one remotely controlled annular type blc~mut preventer and flc~ diverter systsm. The annular preventer installed on the conductor casing shall he utilized to penmit the diversion cf hydrocarbons and other fluids. This lc~ pressure, high capacity divert~r system shall be insured to provide at lem_~t the equiva!~nt of a 6-inch 1/ne with at least tw~ ]~nas ventJ_ng in ~ferent d/rections to insure downwind diversion and shall be designed to avoid freeze-up. These lines shall be equipped with full-openir~ butterfly type v-~lves or other v~lves approved by the Comuittee. 'A schematic diagram, list of .equipTant, and operational procedure far .the divertar system shall be s~tted with the application Pezmit to Drill ar Deepen (Form 10-401) for approval. The above requ. irements may be w-~ived far subsequent wells drilled fr~m a multiple drill site. (c) Before drilling below the surface casing all wells shall have three remota!y controlled blowout preventers, including one equipped with pipe rams, one with blind rams and one annular type. The blowout preventers and associated equi.=m~nt shall have 3000 psi workin~ pressure and 6000 psi test pressure.. (d) Before drilling into =he Prudhoe Oil Pool, the bio-out preventers and associated equi.m.~=._nt, required in (c) above shall have 5000 psi working pressure ra~ng and 10,000 psi test pressure rating. AGO 10023847 CON~.~--vT~TICN ORDER NO. 145 ~ac~ !0 J=ne 1, 1977 (e) %~ne associated eqfuipme_nt shall Lnc!ude a dri!!!n?.spoc! wi~h ~-d_~~ t_~_~ee_-in~h ~ide outlets (if not ~n +Jne blc~cut prev~-.tar bcd-:'), a minL?_-n t~_~ee-_ inch choke manifold, cr .equiv~nt, mx~2 a .... -. . The drilling string will contain fu!!- .cp~-J_-.g v~!ves above and Lnr~=diataly be!ow the kelly during all cLrcaiatLng .c?erations with the kelly. Two ~nergency valves with ro*~_,' subs for ail c~nneCgons in use will be conveniently located cn the drilling floor. One valve will be an inside blowout preventer of ~he _=pring-!caded .type.. The second valve %.il! be of the manual!y-crk=_rated ball t~e, ~ any o~her type which will perform the same f~_-%c?4on. % (f) Ail ram-t~e blowout preventers., kelly valves, ~n=__~mncy %~ives and choke manifolds shall be tasted to re~'~ed wor~ .pressure -~alled or c_hanged and at least cnce. each w~ek theraftar. . . .'' pr-ev~_nters 'shall be .'tested tm 50% reccr~nd_~t workJ~.-g pressure ~%en ' . insna!!ed and once each week t~ereafr~. !=_st results shall be recorded on written daily records-kept at ~%e w~!!. Rule 5 Aut~.~atic Shut-in .Equi~nent Upon ccr~_-!etion, each well shall be .equi~d with a suiemble s~fety valve installed belc~ the base of the perr~cst which will autcratical!y shut in the well J_f an uncontrolled fic.~ occurs. Rule 6 Pressure S.u?veys .. (a) Prior to Lnitia! sustained well prcduc~_icn, a s~atic bct~-c~hcie pressure survey sha] ] be taken on each well. CD) Be~.~en 90 and 100 days after ccn~?_nc~r~_nt of sustained pco! produce, ion, the applicants shall perform an initial key well bcttaTincie ~_nsi~t pressure sL?vey on one specific well cn each prc~ucLng pad cr dh-ill sits. Another survey of the same ~ shall be conducted each 90 days (c) Within the first six months follo~d~.g the Lnitial sustained well profusion, the applicants shall conduct a transient pressure survey on each well. (d) A seni-annuai transient pressure survey ~m_!l be ccnduc~=d cn one well in ea=h gOVernments! section frc~ w'nidn oil is being produced. This is in addition to the pressure surveys ccndu~--=d in (b) and (c) above. (e) A !onu~-tarm key well pressure survey %ii! be formulated and impl~~ in apprcximate!y two years from the sta~-t cf production based evaluation cf data sukr~itted under (a), (b), (c), ~_nd (d) above. (f) Data frcm the above m~ntioned su~;eys =_hall be filed wa_th t_he Carol%tee by the fifteenth day of the month fcllc.,~n.? ~.he r~-~.~-h Ln which each surx, ev is taken. Form No. 10-412, Ras~_~/clr Pressure Rm~-~t, shall be utilized for all surveys with attac~_~-~_n~ for cctv. !ere ad~iticr--=! data. Da~_a sulu~,itted shall include but is nc= !L-.i~=d t~ rate, pressure, %L~e, depths, t~n~rat~e, and o~-.er ~!1 ~nditi~-.s necessary for AGO 10023848 Pa~e 11 June 1, 1977 cc~?lete analysis for each survey being conducted. The pool pressure datun plane shall be SS00 feet subsea. Bo~cr~ho!e transient pressures obtained by a 24 hour bui!d~ or multiple flow rate test %~11 be acc~pv~h!e. · (g) Results and data fr~ any spec~ resarvDir pressure mcnitmring techni~es, tests or surveys shall also be sukm~t~ed as prescribed in Cf) above. (h) By admini~ative order the Onnnittee shall speci~=y additional pressure surveys if the survey prcgr~ designated in ~his rule is found to be inadequate. ' Rule 7 Gas-Oil. Ratio ~ests . · u~n~s thereafter, a gas-.oil ratio test shall be'.".taken on' each prcd. ucing we~i'. "T~e'~est'sh~_7 ~be-of at leaS~'. .' t2 '. 'hours duration and shall be made at the producing 'rate at which the opera,or ordinarily produces the well. The test results shall be reported cn gas-oil ratio test form P-9 within fi~.=te~n days after c~mpletion of the sur~ey. The ~ttee sb_~ b~ nct~ed at least five days prior tm each test. The ven~Jung or flying of gas is prob~-~ited except as may be authorized by t_he Carmittae in cases of ~mergency ar .operational necessi~y. ,k~3.e .9 Gas-Oil Contact ~n~.tcring . Open hole and cased hole neutron logs shall be run in selected W~!!s to conf~ gas-oil contact m~v~t unless this technique is prcvefi Lrmur~le or an altemnative approach is recommended and accepted by t_ha Ccnnaittee. The wells selected for this neutron log survey together wi~h a surmary cf %ha' survey analyses shall be zubmit~ to ~he ~ttae by January 1, 1378, and each six months thereafter. The Cznn~ttse may also specify additional wells to. be surveyed s~ho~d they decide the survey-pr.ogram' being fo!l~we~ is inadequate. · The cased hole neutron logs run shall be filed with the CaTmi~e by the fifteenth day .of the month following the month in which the logs w~re run. Other methods of monitoring the gas-oil contact mov~nent may be approved if t_h~y show to be more effective. A long term key well gas-oil contact movement monitoring program may be formulated and imp. l~ted in approx/mate!y two years from s~.?~ of pro-' duc~ion if a w~rk~-ble techn'ique is found. AGO 100238~9 CO~_~E.~--v~TIOJ ORD~ bO. 145 Pa~e 12 J~.ne i, 1977 Rule !0 Oil-~-?ater Ccnta~ ~nitorin= (a) A repo~ on ~he evaluation program to de-:a~--nine the ci!-~ter contact m~itoring capabi!i~y of the The_~nal Decay Tools cr the Neut---on L~ Get/me Lo~, the ~Carbon-Oxygen Log and the Gamma Ray Log sb~l be ~tted r~ the C~mittee_ by Janua_~y !, 1978. If the capability of m~nitmrir~ the change in oil-~,~tar c_~n~ct move- ment can be d~nonstrated by one cr more of these mat_hods, a key ~ progr, am shall be set up by the applicants s~bject tm the approval of the Ca~mittea. .:- .. '." - -(a)' - A spinner flc~ meter' ~rvey sha~ be run in each,well during the fLrst six months the we!!'is cn p~cduction. Cb) A follc~ up. s~-vey shall be perfo~ cna rotating basis so that a new prcduction profile is obtained on ea=h well periodically. Ncnscheduied su_~veys sb~] ] be run in wells whi~ .~i~nce an ab~t change in ~ater cut, gas-oJ~ ratio, or prcducr_ivity. · (C) The ccrr~iete spj_~ner survey data and results shall be recorded and flied with the Ccnrnittee by the !5%h 'day of the m~nth fo!!c~ng the month in which each survey is taken. (d) By administrative order the Cgnn~t~--~e_ shall speci~=y additional surveys should 'they deta:mine the surveys suhnittad under (a), (b) and (c) above are inadequate. Rule 12 Changing the Affected Area By adminisUrative .approval the Ccnr~ttee may adjust the des~ipt_ion of the a~fected area to confarn tm fxrcure changes in the initial .participating . .. Rule i3 Orders Cancelled Ccnsarvmtion Orders Nos. 95-B, 130, and Rule 2 cf Conservation Or=dar No. 137 are hereby cancelled. Po=~_ions cf conservation Orders Nos. 98-B and 137 are made part cf this crder and the hearing records cf these crders are also made part of the hearing record of tb~ order. Rule 14' AmDrova!s Radesic~mt_=d A~min/s~ative Approvals made pursuant tm CO 98-B, Rule 8 and the waivers made p~suant to Conservation Order No. 137, Rule 2 reTs_in in effect and will new be_ 'authorized by this order. · AGO 10023850 Page 13 June ~, 1977 Rule 15 Pool Off-Take Rates The m~v~im~ annual average oil offtake rate is 1.5 ~l!ion ba_~re!s .Der day plus condensate prcducticn. The m~w/mu~ amnual average gas ~. ~=~~ rata is 2.7 billion standard cubic feet per day, w~_~'n c~n~mo., lares an annual average gas pipe!in~ delivery sales rate of 2.0 billion standard cubic feet per day of pipeline quality gas when trea ~ting and tran .s~tion facilities are available. Daily offtake r~tes in excess of these amounts are pexmitted only as required to sustain these annual ay ~erage rates. The annual average offtake rates as specified shall not be exceeded ~it~hout the prior written approval of the Cc~mittee. Annual average offtake rates mean the daily average rata calculatad by dividing the total volume produced in a calendar y~ar by the number of days. in the year. H_c_~...ever, in the first calendar., y~.ar that large gas · zDfftike-rates are initiates; fol.~ow-ing the"~letion of a large gas · -'sales pipeline, th~ annual average '~fft~ke rata..for gas shall be de~ed · · by dividing-the, total-v~lume Of gas-produced in' that calendar year. by .the n~rber of days r~naining in the year following initial delivery to the large gas sales pipeline. · . ~ at Ancharage, .Alaska, and dated June 1, 1977. Alaska O~ and Gas Conservation Carmi~ Concurrence: Alaska ~il~ and Gas Conservation C~rmi~tee ~k'ska Oil and Ga ~servation Cczm'dt. tee · AGO 10023851 ', 'MAJOR R~2E · W FAULT-BLOC MAIN FIk~D AREA R~2E RI3E PRUDHOE OIL POOL WATERFLOOD AREAS RI4E SOHIO Jl ARCO OPERATING Il OPERATING AREA RI§E · -"' .~..."'..iu~i~l~;':i~:h"":" ........... ::':::P.L..:'.:. !~:::::'" . .' '.~j:... I00 FOOT ' ' ":':i.'.'.'.. OIL COLUMN ~?. BOUNDARY-;,,' EXTENT OF ORIGINAL GAS CAP ZONE 2 RI4E RfSE .' RI6E RICE STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISS. ION 3001 Porcupine Driv~ ' Anchorage, Alaska 99501 Re: The ALASKA OIL AND GAS ) CONSERVATION COMMISSION, ) upon its own motion, to hear) plans of the Prudhoe Bay ) Unit operators for water in?) ' jection, to present the ) results .of recent model ) studies, and to consider ) _changes to certain rules of ) "~-Conservation Order No.. 145 .. . .. Conservation Or'der No. 165 Prudhoe Bay Field Prudhoe Oil Pool '"Jun-e 6,- 1980. · IT APPEARING THAT: · .. 1. The Alaska Oil and Gas Conservation Commission, upon its own motion, called for a public hearing to hear water injection plans of the Prudhoe Bay Unit operators, to present the results of the Commission's mode/'study of the Prudhoe Oil Pool'and ~o consider changes to Rules 6, 9, 10, and 11 of Conservation Order No. 145. 2. Notice of public hearing was published in the Anchorage Daily News on March 21, 1980 · 3. A public hearing was held in. the Municipality of'Anch6rage Assembly Room, Anchorage, Alaska on May 7 and 8, 1980. · · . . · · . · .. FINDINGS:. .... . .. . .. 1. During the period from June 1977. through April 1980 the following down-hole surveys were run: ' 898 reservoir " pressures, 407 productivity profiles,-285 gas-oil contact logs and 110 water-oil contact logs. 2. The operators have requested an additional 15 d~ys in which to file the data required' in Rules 6, 9, 10, and 11 because of the time required to handle the increased volume of data. · 3.. The operators have requested that the frequency of pressure surveys' be reduced. .. 4. The operators have recommended key wells for repetitive ' pressure surveys and gas-oil contact monitoring. · · · . · , · .. · ~ AGO 10023853 Conservation O~er No. 165 FINDINGS: (cont.) 5. Neutron logs which have been run in the same well at various time intervals have proven effective %n monitoring movement of the ~as-oi! contact. , 6. A capable method for oil-water contact monitoring has not been demonstrated. .~. 7. Spinner and tracer surveys have yielded comparable results in determining production profiles in most wells and tracer surveys have been found to ba more accurate at low producing ra~es. · CONCLUS IONS: .A~ additional '15-'days'in--which'.td file the data r~quired'in Rules .:6,. 9, 19, and 11 as. requested by the operators is 'reasonable and will not be a hardship on the commission· · · · Sufficient pressure surveys have been run so that the frequency of the surveys can be reduced if the same density is maintained. . . · Key well programs for long. term monitoring of the ' pre.ssure cha~ges and the gas-oil contact movement sho~!d be initiated. .. The key well programs recommended by the operators are acceptable. .. · NOW, THEREFORE, IT IS ORDERED TEAT the following rules of .Conservation Order No. 145 are changed to read as follows: .R. ule 6 Pressure S. urv.ey.~ ' A key well program for oil-Hater contact monitoring is inappropriate at this time but investigation of a monitoring feel'should continue. . . . , . . Tracer surveys should be permitted as an al'ternate 'method to spinner surveys in determining productivity profiles. " · . . · . · · (a) Prior to initial sustained production, a Static bottomho!e pressure survey shall be taken on each well. · (b) Within the first six months following the initial sustained production from each well, a transient pressure survey shall .be taken. · · AGO 10023854 Conservation Ot(" ~.r No. 165 · (c) One specific well on each producing pad or drill site shall be designated as a key well. Semi-annual bottomhole transieft pressure surveys shall be conducted on each key well and the following wells are currently designated as key wells: Western Operating Area Sohio Alaska Petroleum Company Operator Prudhoe Bay Unit Well Numbers A-5 B-2 ¢-2 .. D-6 F-4 G-3 ~ N-7 Q-3 Eastern Operating Area Atlantic Richfield Company Operator ' · . Prudhoe Bay Unit well Numbers -- j , DS 1-4 DS 2-1 DS 3-7 DS 4-5 DS 5-11 .' DS 6-4 DS 7-6 ' · ,- · . .... ' ,'DS 9-6 .DS 12-3 , · DS 13-4. · · - · DS 14-5 (d) An annual transient pressure survey shall be conducted · on one well in each governmental section from which oil is being produced. The surveys required in either (b) or (c) of this rule can be used to fulfill this requirement. .. · · (e) Dat~ from the surveys required in (a), (b), (c) and (d) of this rule shall be filed with the Commission by the last .day of the month following the month.in which each survey is taken. Form No. 10-412, Reservoir Pressure Report, 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 pressure datum plane shall be 8800 feet subsea. Bottomho!e · transient pressures obtained by a 24 hour buildup or multiple flow rate test will be acceptable. (f) Results and data from any special reservoir pressure monitoring techniques, tests or .surveys shell'.also be submitted as prescribed in (e) of this rule.' ',.,. · (g) When new pads or drill sites are developed, the 'operator shall designate a key well for each and, upon commission approval, these wells will become part of the key wall program in (c) of ". this rule. .. .(h) By administrative order the Commission may require additional pressure surveys or modify the key wells designated in (c) of this rule · . AGO 10023855 Conservation Or~ No. 165 ~ Rule 9 Gas-Oil Contact Monit. orin.c (a) Prior to initial sustained production, a cased or open hole neutron, l. og sha'!l be run.in each wall.. (b) Semi-annual neutron log surveys shall' be run in the following wells designated as key wells: Western Operating Area Sohio Alaska Petroleum Company Operator Eastern Operating Area Atlantic Richfield Company Operator Prudhoe Bay Unit Well Numbers A-4 C-.8 D-4 F-3 J-5 N-6 Q-2 Prudhoe Bay Unit Well Numbers DS 1-8 ' DS 2-1 DS 4-7 DS 5-5 -DS 5-7 'DS 5-12 DS 6-3 DS 7-!1 DS 7-14 DS 9-4 - (c) An annual report shall be submitted to the Commission by July 1 of each year which shall include a summary of the wells surveyed, .an analysis of the surv.eysr and an analysis of the gas-oil contac~t behavi.or. · (d) The neutron logs run on any well and those required in (a) and (b) of this rule ~hall be filed with the Commission by the last day of the month foilowihg the month in which the logs were run. ' (e) The operators may at anytime designate additions or changes to the key wells and, if approved by the Commission, they would become part of the key well program under (b) of this rule. · (f) By administrative order, the Commission may require additional wells to be logged or modify the key wells designated in (b) of this rule. " ... ~.'"' ... "" · · · Rule 10 Oil-Water Contact Monitoring (a) The operators shall continue an evaluation program to determine the oil-water contact monitoring capability of various -. cased hole logs. An annual report shall be submitted to the Commission by July 1 of each year on the evaluation program. '(b) Ail cased hole logs run for this purpose shall .be filed with ~he' Commission by the last day of the month following the month in which each log was run .... . . .. -. AGO 10023856 Conservation O~ r No. 165 (c) If the capability of monitoring the change in the oil-water contact movement can be demonstrated by a cased hole loggin.c method, a key well program shall be set up by the opera- tors subject to the approval of the Commiss'ion. Rule !1 Productivity Profiles (a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. (b) Follow up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys sha}l be run in wells which experience an abrupt-change in water cu.t, .gas-oil ratio, or pro- ductivity. · . '--_(C) The co.m. pl.e.t.e spinner flow meter or ~racar survey data · ' --and-results-.shall be recorded--and f'iled' With'the Commission by ' - "the last day of the month following-~hel, mon:h ih which each -~sur=ey 'i-s taken..-... (d) By administrative order the Commission may specify additional surveys other than the surveys submitted under (a), (b), and (c) of this rule. DONE 'at Anchorage, Alaska and dated June 6, 1950. 5~5yl %~. Hamil Chairman/Commi ss loner ':'. Alaska O.il and Gas Conservation commission Lonnle C. Sml=h /. Commissioner Alaska 0il and Gas Conservation Commission ~arry W. Kug~e: : / .. Commissioner - ~ " ', Alaska Oil and Gas Conservation Commission -5- AGO 10023857 EXHIBIT ? STATE OF ALASKA ALISKA OIL AND GAS CONSERVATION COMMISSION 300! Porcupine Drive ~ - Anchorage, Alaska 9950"1: Re: THE APPLICATION OF ARCO ) ALASKA, INC. and SOHIO ) ALASKA PETROLEUM COMPANY) requesting the amendment) of Rule 2 of Conserva- ) tion Order No. 145,- ) which pertains to well ) spacing in the Prudhoe. Oil-Pool,. Prudhoe. Bay .- ) .. · ' "Ff~ld'. -- ·. . . - . Conservation Order No. 174 Prudhoe Bay Field Prudhoe Oil Pool IT APPEARING THAT: · . ARCO Alaska, Inc. and Sohio Alaska Petroleum Company, operators of the Prudhoe Bay Unit, by letter dated June 15, 1981, requested the. Alaska Oil and Gas Con- servation Commission to amend Rule 2 of Conservation Order No. 145 which sets out well spacing requirements for the Prudhoe Oil Pool. · Notice of public hearing was published in the Anchorage Times on June 19, 1981. · The notice of public hearing indicated only ARCO Alaska, Inc. to be the applicant when in fact Sohio, Alaska Petroleum Company was a joint applicant. 4. There were no protests to the application. FINDINGS: o. · Rule 2 of ConserVation Order No. 145 states "In the affected area, no'pay shall be opened in a well closer than· 2'000 feet 'to any pay opened in another well in the Prudhoe Oil Pool or be nearer than 1000 feet to the boundary of the affected area." e · The Prudhoe Oil Pool, as defined in Conservation Order No. 145, exists in an area that is part of the Prudhoe Bay Unit. -' , Based on current' data, the Prudhoe Oil Pool is com- pletely within the Prudhoe Bay Unit and correlative rights of all owners are protected. " AGO 10023858 Conservation Or~ Page 2 · ~ · Evidence indicates that a closer spacing c, wells could result in increased recoveries in ;.;a~__f!ood areas wh~re multiple sand intervals of:contrasting perme- ability are separated by shales'. Evidence indicates that a closer spacing of wells could also result in increased recoveries in areas which are cut by major faults. Evidence further indicates, that a closer spacing of wells in the areas of a thicker oil column could in- crease recoveries. ~ The flexibility to vary well spacing at this stage of pool dave!opment will faGilitate-the best q~se of rigs by-minimizing ri9 moves.. " · Since s~atewide rules-'al!ows a well to be drilled nc closa'r than 500 feet tca unit boundary, the operators of a unit' should 'have the same minimum distance re- striction at the boundary of the affected area. · NOW, THEREFORE, it is ordered that: Rule 2 cf Conservation 'Order No. !45 is hereby amended ~o read as fo!lows: RULE 2 Well Spacing. . There shall be no restrictions as to well soac4~ except that no pay shall be opened in a well cicser than 500 feet to the boundary of the affected area. DONE at Anchorage,. Alaska and.. dated July !, 198!. · ' ";;i c:.h,".a.~J .rm:~ n/Commi s s i o n er 'Alaska"Oil and Gas Conservation Commission Harry W. KugL~r / Commissioner Alaska Oil and Gss Conservation Commission AGO 10023859 'l ~ M-C A E T~ -1 MC -- T4 M-C A-E A-E A-E M-i-C ~ 50 4.9 A-E A-E CHEVRON M-P-C ,, -- 8'! -- M-P M-P-C , lO SOHIO M .-P-C SOHIO SOHIO '"I SOHIO SOHIO SOHIO SOHIO M-P SOHIO M-P-C A-E A.H ,et al Tr.-83 -- 84 -- 85 86 SOHIO T ' SOHIO A-E A-F' 43 42 -- SOilO SOHIO 5.9 -- ~60 SOHIO SOHIO -- 7,5 A, H.- GETTY , A-E A. H, et al 104 103 -- SOHIO --74 SOHIO A-E SOHIO SOHIO EXHIBIT 9 PRUDHOE BAY UNIT LOCATION OF FLOW STATION INdECTION PROdECT PRUDHOE BAY UNiT UNIT OUTLINE Situated Jlthln T IO-IZN R IO-16E Umiol Meridion North Slope of ~,laska LEASE LEGEND A [ - ARCO [XXON ~-~ - ~OSIL- PHILLIPS ~HIO PETR CO A H, et ol ~A H~SS, et ol A H -GETTY - ~[RADA H~5S GETTY A S B ARCO SOHIO BPA fXP . FLE'~ PRUDHOE BAY UNIT BOUNDARY A - E . -E SOHtO ' ¥ ....~c .....T''-~--- ~ .... '"' ........ A- E SOHIO SOiH IO I [ '1 I , I , ' _~L ' - - -{- - - - 2!9 .... + .... 3~) ......... 3"t ........ 3~2 - - - I I I ,, I £ - 4- .... 4',o .... ;- .... 3', I I SOHIO SO~410 I, I I I I I I I -J- .... 3"3 '~- -- - k-- -Tr,-34 .... I -t-- --- ~ ,'L' ._~. ;_ :,~:.., ~ ......... SOHIO A'-E A-E 72 7.1 A-E 70 A-E A-E A-E SOHIO A- E A-E · 98 I SOHIO 109A ,, I 109 SOHIO SOHIO " I I Tr.-111 1 I I ~:,,~ I UNIT BOUNDARy-I-..... T CENTRAL P R U D HOE co~R. BAY ~C-2 A UNIT ~j GC-1 ALYESKA PUI~ STATION NO. I BOUNDARY FIELD FUE"L ( 18 X ,14 3 ALYESKA 3 PIPELINE--i- 0 I 2 ;5 4 5 6 SCALE IN MILES EXHIBIT-8 PRUDHOE BAY FIELD PRODUCTION FAC IL TTIES 200482020 I AGO 10023861 SHUBLIK FM. SADLEROCHIT FM. HEAVY OIL / TAR ZONE OIL/WATER CONTACT FLOW SAMPLE LOG EXHIBIT PRUDHOE BAY UNIT STATION :3 INdECTION PROdECT SHOWING VERTICAL _DELINEATION_OF .PROJECT_ 8800 ego0 9000 9100 9200 ---- "1 _mmmm .... i m .mmmm__ _. ...... · '~ ~m~.., --'-~ .... i II-.-.~" 1I! III IlI,uN; III !11 i l I!.~.,~- ill .... .... llk~'-' Ill I!1 i '~,- 111 ill rf,~ ~-. I11 !11 ~ !11 ill '~.~ II1 ill ---~- :.'-7- .... .~.------", -----"-- · .~,~,,,,,l~ '~":~1 ' ' ' · I --~:- -- · ~,-~r~'.~.l~' ill'. 'i · ,,~"-'..~ III III ":'"'" '" '!! ~'~ II! I "~x .~'";r,h~r'' Ill ill 8863 Z z w rr'. w 9034 9085 0 0 0 g FLOW EXHIBIT IO PRUDHOE BAY UN TT STATION 5 INJECTION PROJECT PROJECT DEL INEATION LEGEND ® PROJECT PRODUCERS · WAG INJECTORS · WATER INJECTORS o DEVELOPMENT WELLS OUTSIDE PROJECT AREA SCALE: I" = 4000' 0 0 0 0 0 0 0 0 0 0 I I0 'aBIi '--~ 12 ? I 0 0 · ·· ~ 0 0 0 0 0 0 · · · · 0 0 '~~T ' v · ~ 0~ ~¢ · ~ ~ 0 · · · · 0 21 Z2 25 ~~/ 19 ~ ~NdECT~ON PRoJEcT AREA o I ,. R I4E R I 5E 0 1',,3 (~ Z FLOW DRILL E×H iB iT I I PRUDHOE BAY UN TT STATTON 5 ~NJECTTON PROJECT S TTES SERVTNg PROJECT WELLS LEGEND 0 PRODUCERS WAG INJECTORS A WATER INJECTORS DRILL SITE BOUNDARIES FLOWSTATION BOUNDARIES SCALE: I" = 4000' R I4E RI 5E EXHIBIT 13 PRUDHOE BAY UNIT DESCRIPTION OF HEAVY OIL/TAR ZONE AND METHOD OF PICKING ZONE The heavy oil/tar zone is a deposit of low gravity oil directly overlying the oil/water contact. Where a well is cored the zone is recognized by a dark brown or black color and has a marked increase in residual oil saturation compared to the Overlying light oil ~one. In an uncored well there is an often coincident marked increase in the · L~a.t. er!Pg 8. resis_t_ivit~ '~response C. ompar, ed' to.-.t..he 'In'ddctlon'. .,resistivity _response. The increased :LL-8 in the-.HO/T, zone compared'tO, the light oil zone above i~ is caused by the. imcre, ased res~duat~oil saturation (assuming that"the'conductive phase'is mud filt'~'~{~' in both cases). AGO 10023865 Z o ~ 14-18 014-G 16 21 ~ 14-S 14-9B~[ 14-30~ ~ 13-32 ~'"' '" ~3-29 xx FS-5 INJECTION P 06-14 0 6-4 14-14 13-17 ~1~-11 ~6-i2 ~ 13-30 ~-ls 0 6-13 06-8 0 1-14 0 1-2 13-18 Nx6-9 ~,~ 1~ ~ 13-20 V~- ~__~ ~ ~2-19 ..... .... ~ 12r12 1-18 13-22 13-4 0 13-S 13-11 13-G ~13-10 13-7 12-1S 13-27 ~13-9 13-16 12-17 ) ~F13-21 12-4 ,~.~T RIVER -10-15 ~ , 12-18 12-9 0 12-3 2-8 1£-8A I ~' 12-S 12- 16 · : ~o-~s · 12-~0 ~F~2-'7 12-11 20 13-8 PUT RIVER 24-10-14 12-8 R14E R1SE LEGEND · EXISTINg OIL PRODUCER 0 PROPOSED OIL PRODUCER V EXISTING NAG INJECTOR ~ PROPOSED NAG INJECTOR & EXISTING NATER INJECTOR PROPOSED NATER INJECTOR SUSPENDED OR ABANDONED NELL © PROPOSED SOURCE WATER WELL · EXISTING SOURCE WATER WELL NOTE: NELL LOCATIONS AT TOP OF SADLEROCHIT FORMATION SCALE: 1"=2000' PRC AS EXHIBIT 14 RUDHOE BAY UN IT FLOW STATION 5 NJECTZON PROJECT J ECT WELLS DR ILLED OF AUGUST 15, 1982 AGO 10023866 ; 2003520801 40000, Flow Exhibit 15 Prudhoe Bay Unit Station 5 In/ection Proiect Production History $5000 $0000- 25000- ;20000 15000 fO000 5000 0 , ! ! , , , -' ............... -~ ...... c ....... ' ................. ' ......................................... , ................ ' i : [ : : ........ :: ....... i:: ....... %i-i; ..... i- ........ :: ................ , 1, : , \:/\ .,. , ' .[: /.: .-",:: .'./ ........ ! ...... ]-'-,---:~ .... ,! ......... ', ........ ,i ..... -\-'.../%":'- ...... ?':-: ........ :, ........ ! ........ :, ........ ~-' ..... ,: ......... \ ........ : ...... L/: ........ ,~ ........ : ........ : ........ : ........ : ........ : ........ ....... '--. ~ .......... ~vero~e Doily Production -: ......................... ' ................. : .... Oil Rote , , ........ " .... lJ~ '- ~ ........ GOD Rote , ~ =:.. = ~ ........ :--B .... -: ........ r ........ : ........ , ........ :- , , , , ~. , , ii;' i ' ' ' ' ' ' ......................................... '. ........ , ........ .',a~ ......., ......... , ........ ¢ ........ , ........ ~ ~ '~ =~' .-,1= ~ ~ ~ ~" , , ' ,' f I I ~I ~ I I I979 1979,5 f980 1980.5 1981 1981.5 1982 1982. Time, Years .... , EXH!BIT t--~ PR. UDHOE~ BAY UNIT" FLOW STATION 3 INJECTION PROJECT ¢0 ~o cO 0 0 ,-~ SHUBLIK FM. SAI:X. EROCHIT FM. BASE SADLEROCHIT 9172' 9405 ,-- Shale · -- I~~:- ZULU -- _ - ×RAY , II' ~ l~I VICT~ I -~ I I I~'.,! lll/ _ TAN~ ..... ++-..~ -~-+~+.+ ,+. FLOW TOP EXHIBIT- 16 PRUDHOE BAY UNIT STATION 3 INdECTiON PROdECT SADLEROCHIT STRUCTURE 8550 -....___ 8600 - / 0 0 0 9200 9~00 IN, /- 'ROJ lEA 9OO~ Scale -. 1" = 4000' Contour Interval : 25' EXHIBIT-18 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT ISOPACH OF SHALE NEAR BASE XRAY 0 0 0 x X x x x x x X X X X X INJECTION PROJECT AREA Scale: 1"=4000' Contour Interval = 25' 0 EXHIBIT-~9 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PRO,JECT ISOPACH OF UPPER TANGO SHALE 0 0 X X X × X X X X / X X F S 3 INJECTION PROJEI Scale- 1":4000' Contour 'Interval = 25' EXHIBIT- 2o PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT ISOPACH OF LOWER TANGO SHALE /0 ~0~ ~0 0 /0 X \ X 0 ROJEC lO .~c_21~: 1"=4000' Contour Interval = 25' EXHIBIT 21 LOCATION I~P t 2 MILES 6600 34900 7~x X X 33T00 33600 2 O0 2~300 X X 40500 X 39700 X 48900 39000 X X 46300 44100 X X 46700 X 6400 254OO 17000 8600 15400 X 27~X00 7700 15200 26300 X X X X X X X X 14700 200 I I I O0 18600 27300 24800 24300 X X X 32000 28200 17300 X 17200 X X X X 31700 31800 31900 X ~( A x x x x 29800 28800 11200 16000 45900 x 6.500 26900 7000 x x x 36200 57600 59800 46000 x 29900 x x x x x x ~ x /~' XTO0 ~XXX) X X 16400 ~.oo ~oo .~ . ~ x ~ ~ . ~ .~.OOx ~ x / L_ 7600 42800 40000 40300 15700 27000 16900 26800 X 20~00 45600 X X X X X X 5~eoo ~ x x x 4~5oo $2800 X t ~ X X \ '~ ~ ~ --'~x' ;36~00 37000 X A~.-~_ ~,,r..~.~ '~x~'-- ~A~v~A ' ~,~--o1~.~ . 41400 · I 4500 ,~ 39100 40100 \ ! ~'x~°° x x 505oo ~7~oo x x . / s64oo /x x x ~.._ / .,. /. ~5oo ~'~__l .~" '~, .~ 60lOOX 58600 40900 48600 50800 --.~.r ~, ~' X X X X ' ~,~Boo ~, 4~.od x x A' \ ZS 15oo x x x x 7oo x 49800 x 3 INJECTION PROJECT AREA N APl WELL ,NUMBER ~-.11400 BOTTOM HOLE WELL LOCATION-- ,,~, X AGO 10023873 0 GR ORIGINAL GAS ! OIL CONTACT ZULU 'XRAY VICTOR TANGO 4-4-++ ROMEO 20460 6-16 O GR 150 4-+ 4-4-4-+++ 4-4-4-++4- 20458 6-14 0 GR 150 TA._..R C.~O NT A.~ 4-4-4-4-4-4-+4-+ APPROXIMATE PROJECT AREA S 20456 6-1Z 20201 6-6 2O538 15-12 4-4-4-4-4-4- +4-4-4-4-+-I 0 GR zuLu TANGo 4-4-4-++~4-++ 4-+4-+4-~++4-4-+4-4- RoMEo SUBSEA -- -8500' 4-+++ I00' 50'/VIE;RT. EXAG. 12~1 I HORIZ. SCALE APPROX. · 0 t~O' 12~)0' 0 GR 150 PRUDHOE BAY UNIT 'FLOW STATION 3'INJECTION PROJECT CROSS SECTION A-A' ---8700' -- - 8800' -- -91OO' -- -9400' AGO 10023874 EXHIBIT -- 24 PRUDHOE BAY UNIT FLOW STATION 3 INdECTION PROJECT OIL WA TEll CONTACT '90~0 ~20 90 TION PROJEC Scale · 1" = 4000' Contour Interval = VARIABLE EXHIBIT- 25 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT HEAVY OIL~TAR ISOPACH ~> 0 0 0 L~ Scale · 1" = 4000' Contour Interval = VARIABLE EXHIBIT- 26 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT GRoss SADLEROCHIT LIGHT OIL THICKNESS' 0 0 0:) 125 375 PROJECT Scale · 1" = 4000' Contour Interval = 25' FLOW EXHIBIT 27 PRUDHOE BAY UN IT STATION 3 INJECTION FAC IL ITIES OVERVIEW MISCIBLE GAS PROJECT FOR INJECTION FIELD FUEL GAS UN IT PRUDH~ BAY FFGU' DS- 13' FS-3' FAC ILITIES LOCATION FLASH DRUM LIQUID SOURCE MISCIBLE GAS INJECTION SITE PROCESS MODULE- CENTRAL IZED FACILITIES FOR PROCESSING/ COf4~RESSION OF MISCIBLE FLUID. LEGEND EXISTING PIPELINE NEW P IPEL INE APPROX. SCALE' I" = I MILE lO"FLASH DRUM LIQUID LINE DRILL FLOW STATION ;5 % DR ILL SITE SITE 2 \\ 12'FLASH DRUM \ LIQUID LINE \ I0' MISCIBLE FLUID INJECTION LINE 13 EXH lB IT 28 PRUDHOE BAY UNIT FLOW STATION 5 INJECTION PROJECT PROCESS FLOW DIAGRAM PROCE SS MODULE ~,GAS FROM FS-5, ~ ~, IP COMPRESSORL-~ D I SCHARGE >FLASH DRUM LIOUIDS FROM FFGU FS-5 I I ! I I R.G. + SCR. R.G. LIOUID I SURGE DRUM FS-5 I I I I I ' IP SCF~. AGO 10023881 TEG LOW PRESSURE I Ic°LUMN K. O. DRUM TO F S- 5'T' ~1~ HYDROCARBON L IOUID PUN~ I IP L IOUID SURGE DRUM R.G. LIQUID PUMP IP LIQUID PUMP LEGEND, NEW EXISTING INJ. INJECTION COMPRESSOR LIQUIDI DRUM LIQUID INJECTION PUMP >TO DS-15 EXHIBIT 30 TYPICAL MISCIBLE INDECTANT COMPOSITION Component NR COz C1 Cz C3 i-Cg n-C~ i-C5 n-C5 C6 C7 C8 C9 ClO Mole % 0.13 12.41 #2.50 12.77 13.59 2 49 6176 1.86 3.07 1 97 1]10 0.79 0.15 100.00 AGO 10023884 Exhfbff $1 {" Prudhoe Boy Uni! Flow $tafion 5 ln~ecfion Project C~pillary Tube Displocerneni Resulf$ i - . . '.' ....... 't' . · ~'..'" I ..... ~ . ~ . ._ ._ · · '_ ; ; ; .. ., .......... ~ ........ '.-- ...... ~. ....... ~/ ......... i ......'-..~ ..... '., ......... : .......... ; ....... '.- .....'~ ..................... ~ ....... ~. ........ . ....... · , ~_~ · ; ~ · ; · . . ; · . ~ ,..i...../i...: : : :~ ; : ; : '. : ; : t : : : : I ; ; ; : ; : ; ; ....................................... ~ ................................................................................................ : , I .' ........................... 7: .................. ~-";' ................................................................................. /: : · ........... "' ........... J' ...... ~' ......... ~ ....... 4-.,,t ............................ ~ ................... ~ .......... , ..................... . ......... -- ........... . ....... : · /: · : d : : - ; ; , -* : : : : :~ : : : : * : · . : . : .0 . : : , : / : · : : : :% : : : : : : . ........... i .......... 57 · '-5 .......... i ..... [] ......... ? .......... i ........ i .......... '.. .......... .:- .......... ? .......... i .......... i .......... .-. .......... i .......... : · : .. ~: : : : : : : : : : : : ./... : · ,: · : · : : ; · : . : : : ~ , : ! : ! : : : ~ : ! : .......... '- ............ : .......... i .... -/---'- ........ ? .......... '- .......... : .......... -' ........ -.; .......... ! .......... ~ .......... ? ......... -..: ......... '- .......... , :. , ~e_qen~ .................... 4.. .................. ~..., ...... : ....... 4. ................... ~ ............................. .. : .*m : :' · 40~. ~ef~one Di~l~cln? RuM · . ,4 * . , . .......... ,; .......... .......... , ...... [] ~ ....... , .................... , ......... , ........... f55 ?.%~.~.%~.%:Y.-~.~::-~ [~.~. ......... , ......... · : : : ! : : i ;! : : : : : e : ; ; ; : : .......... i ............................... i ...................................... .......... .......... ......... + .................................................. .* : : : ; ** : : . 3400 3500 J*~O0 .~700 J~'O0 J~O0 ~00 4100 4200 This Exhibit shows results of capillary tube displacement experiments performed with Sadlerochit crude and two enriched methane displacing fluids at 200OF. The methane compositions of the displacing fluids were 40 ahd, 44 mole %. This plot of recovery versus pressure shows a sharp change in slope when the minimum miscibility pressure (MMP) has been reached, indicating that no further recovery benefit arises from increased pressure. The MMP's for the 40 and 44 mole % methane dis- placing fluids are 3615 psi and 3735 psi, respectively. AGO 10023885 EXHIBIT 32 PRUDHOE BAY UNIT FLOW STATION 3 IN3ECTION PRO3ECT PRO3ECT INVESTMENT COSTS Description FS-3 Injection Project Process Module - Includes process equipment, engineering, transportation, construction, and instal- lation. Cost, HMS 6O Pipelines - Includes flash drum liquid line from DS-2 to FS-3, miscible gas line from FS-3 to DS-13, miscible gas manifolding, well lines to the WAG injectors, and extra pipe necess- sary to swap SWI"from DS-14 to DS-Z3. 27 Gas Lift Facilities - Includes engineering, equipment, materials, transportation and installation of a Solar gas lift compressor module at FS-3 and 4 gas lift well lines for water production at DSZl4. 13 Drilling & Completion Costs - Includes drilling two observation wells and recompletion of 4 DS-14 wells to water produc- tion. 10 Total Cost - 110 AGO 10023886 Exhibif $$ Prudhoe Boy Flow 5teflon 3 InletS;on Pro]eof ARCO $-D MODEL GRID GOC GOC IFO C 0 NORTH ~ Legend Producer Water Inleclor WAG Inlector SOUTH Exhibit ,54 Prudhoe Boy UnTf Flow Siafion $ lnjecfion Projecf Retofionship of lncremenfal Recovery fo Miscible Gas Slug Size !2 0 10 0 ...... , 0 15 20 25 Pore Volume Slug AGO 10023888 Exhibit 55 Prudhoe Bay Unit Flow Station 5 Injecfion Project Oil Rate Projections )> o 0 52 46 4O 36 i i i ~ .i i i · i I i i i _ ~ ..e ..... - - --i .................. · ...... · i Legend _WAG - IOL~ P,V. Inlec_llon _ Walerflood - 80 Acre $~aci_n~ mm m~m mm mmm m~ ~mm mm Imm ~mmm ~mm ~=m ~ ~mmm m i ! e ! ........ ..i ......... , ......... i i ' e , i , 1982 1984 1986 f988 1990 1992 1994 1996 Time, Yeor's 1998 2000 2002 2004 2006 20( 0 0 0 700- 650- 600- 550- 5oo- 450- 400- 350- 500- 250- 2OO- ~50~ 100- 50- Exhibit 56 Prudhoe Bay Unit 'Flow Station 5 Injection Prelect Cumulative Wafer Production as a Function of %Oii Recovery: Early and Late WAG Starfups i i i i i i i i i i e · - r .......... I. ........... · ........... , ........... · ...................... · ' ' ........... · ........... i .......... - ' i ~ t * i i i i , i , ' , ' i ' o , , , ' , . . ........... · ........... " ........... · ........... i ........... · ........... i ........... · ........... $ .................. eden ' ' ' ' ........... I '"' I---, ........... J ........... , ........ 1'': ......... ''''* ........ WAGInleollonfrom 1998-2008 I : ! ', / ! ': .' I ........ I · , ! ', I WAG Inlecllon from 1983.25-1993.25 I. .... : ................ ~ ........... ~/ ........... ........... ! -"-.:' ..... ':' ..... :"=-- r": ........ i i / i i i * i . .i ...... ....... .._..i ........... · ....................... · ....................... · .......... ~- i i I . , , , :/ : / '. i i i i i ........... '. ....................... ' ........... t ........... · .................... //~ ..... / ....... ~. ........... ' i, · I i ! , , , / , : / , , . . , , / '. ,/ ; , , : , : _.: ................... ~_: ....................... , : , , , ,/ : ~ ; : . : , : . : j/ ; /- : , , . ........... ; ....................... : ......... /'~,- ........ } ....... ~:-- ........... ; ........... , , ~" ; ~ , : ' · ~-- ~" .......... 1 ........... ........... I ........... · ........... 1 ...................... 1' i ' I ' ........... : ........... : ....................... ,'. ........... ,,,,-,~ ....... ,'. ....................... ,'. ........... : ........... i~ i il , ~"-i ~ I ~ ...................................... : . ........... r ........... ;' 5 I0 15 20 25 30 35 40 45 50 Recovery, 5DQLIBIT 37 P~DHOE BAY FLOW EL%TION 3 ~ION SOHIO STRIP MODEL (20 X 3 X 14) Oil Prcducer ~AG Injector Water Injector AGO 10023891 EXHIBIT 38 PRUD}~3E BAY UNIT FLOW STATION 3 I~ION PROJECT EXXON ' S 3-D MOD~ GRID ~x UPDIP o o o ~J c~ ,4) H 440' PRODUCER IN.JtCTOR LAYER I'HICI~IESSES IOO Plodel PV Z:)]. ! I~B 14o,de I O01P 59.8 14caJel IIT'Va 120.6 HRB 'PY In Hydrocarbo. bearing rock EXHIBIT 39 PRUDHOE BAY UNIT FLOW STATION 3 INDECTION PRODECT INCREMENTAL PRODECT OPERATING, MAINTENANCE, AND INDECTANT COSTS Description O&M and Wireline work for 2 observation wells Additional O&M and Wireline work for 42 producers Additional O&M and Wireline work for 11 WAG Injectors F5-3 Injection Project Process Module O&M Pipeline O&M Gas Lift Costs (2 years only) Miscible gas injectant Cost per year MS 1,958 1st year, 398 next 4 years 5,796 1st 2 years 2,352 thereafter Cumulative Cost After 10 Years MS 3,550 31,752 693 1st year 3,960 363 thereafter 4,511 45,110 133 1,330 600 1,200 13,790 137,900 Exhibit 40 Prudhoe Bay Unit Flow Station 5 Infection Prelect Estimated Miscible Gas Availability 40~ 55- $0- 25- , 20 -- 980 1985 1990 1995 2000 Time, Years AGO 10023894 EXHIBIT Definition of Miscible Fluid Displacement Oune 1979 D.O.E. Regulations - Miscible fluid displacement, i.e., an oil displacement process in which gas or alcohol is injected into an oil reservoir, at pressure levels such that the injected gas or alcohol and reservoir oil are miscible. The process may include the concurrent, alternating, or subsequent injection.of water. The injected gas may be natural gas, enriched natural gas, a liquefied petroleum gas slug driven by natural gas, carbon dioxide, nitrogen, or flue gas. Gas cycling, i.e., gas injection into gas condensate reservoirs, is not a miscible fluid displacement technique nor a tertiary enhanced recovery technique within the meaning of this section. August 30, 1979 Amendments (Effective October 1, 1979) - "Miscible fluid displacement" means an oil displacement process in which fluid is injected into an oil reservoir at pressure levels such that the injected fluid and reservoir oil are miscible. The process may include the concurrent, alternating, or subsequent injection of water. The injected fluid measured at reservoir temperature and pressure must, with reasonable expectations, be more than 10 percent of the reservoir pore volume being served by the injection well or wells. Gas cycling, i.e., gas injection into gas condensate reservoirs, is not a miscible fluid displacement technique nor a tertiary enhanced recovery technique. AGO 10023895 PRUDHOE BAY UNIT FLOW STATION 3' INJECTION PRO, JECT APPLICATION FOR ADDITIONAL RECOVERY BY MISCIBLE ENRICHED HYDROCARBON ~GAS INJECTION AUGUST, 1982 AGO 10060610 PRUDHOE BAY UNIT FLO~' STATION 3 IN3ECTION PRO3ECT APPLICATION FOR ADDITIONAL RECOVERY BY MISCIBLE ENRICHED HYDROCARBON GAS IN3ECTION August, 1982 AGO 10060611 Purpose ARCO Alaska, Inc. requests approval by the Alaska 0il and Gas Conservation Commission (AOGCC) of the Flow Station 3 Injection Project which will involve the injection of miscible enriched field gas into the Permo-Triassic (Sadlerochit) Reservoir. In accordance with Article 5, Section 400, of the AOGCC Regulations, Duly 1981, the information required by 20 AAC 25.400.(B).(1-9) is submitted in this Application. ..Project Scope The Flow Station 3 Injection Project will use the enhanced oil recovery technique of miscible gas displacement to increase the recoverable reserves in all or portions of Drill Sites 1, 6, 12, 13, and 14 in the Eastern Operating Area of the Prudhoe Bay Unit. This technique~ which has been employed by the oil industry for several years, involves the injection of an enriched hydrocarbon gas into the oil zone alternating with the injection of water (WAG process). The injected gas forms a miscible bank with the reservoir oil through the exchange of hydrocarbon components and effectively sweeps nearly all of the oil which is contacted to the producing wells. The injected water helps maintain reservoir pressure, retard gravity segregation of the gas, and control gas channeling. The Project was designed to fulfill the following objectives: AGO 1006061Z 1. Increase recoverable reserves above that which can be obtained through waterflood£ng. 2. Provide additional oil rate during the mid to late 1980's, a period when the Field is expected to be on decline. 3. Obtain information regarding the effectiveness of a miscible gas WAG process in the Sadlerochit Reservoir such that the use of this technique on a wider scale can be evaluated. 4. Provide design information for possible future applications. Miscible gas injection is planned to begin in Danuary 1983 at a rate of approximately 40 MMSCFD. Prior to the availability of Beaufort Sea water, an estimated 65-100 MBPD of produced water will be injected along with the enriched hydrocarbon gas in a WAG mode of operation. WAG injection will continue until more than a 10% PV slug of miscible gas has been injected into the Project Area. Implementation of this Project is expected to increase the recovery by at least 5.5% OOIP above that which is attainable through waterflooding and by at least 20.0% OOIP above that which is attainable through natural depletion. This relates to an incremental recovery of 24 MMSTBO over waterflooding and 89 MMSTBO over primary depletion. 2 AGO 10060613 Content The following specifically addresses subsections (B). 1-9 of AOGCC Regulation 20 AAC 25.400. 20 AAC 25.400.(B).(1): Operator ARCO Alaska, Inc. P.O. Box 360 Anchorage, Alaska 99510 Attention: G. L. Downey 20 AAC 25.400.(B).(2): Plat,of Project Area and Offsetting Acreage As illustrated in Exhibit 1, the Project will be located in the south- western portion of the Eastern Operating Area of the Prudhoe Bay Unit. The Project encompasses approximately 3650 acres and is estimated to contain 442 MMSTB of light oil. The Project includes all or portions of sections 10, 11, 13, 14, 15, 23, and 24 in Township 10 N, Range 14 E, and Sections 18 and 19 in Township 10 N, Range 15 E. As illustrated in Exhibit 2, the Project Area will consist of eleven inverted nine spot patterns and will be bounded to the north by seven upstructure water injectors. The area as presently envisioned will be developed'on 80 acre spacing and will include seven water injectors~ eleven WAG injectors, and forty-two producers. In addition, two observation wells will be located AGO 10060614 close to one of the WAG injectors to monitor early flood performance. Exhibit 2 also indicates the surface boundary of the Project and the locations of all existing production and injection wells, abandoned or suspended wells and scheduled future wells. Flexibility exists to convert the Project Area to five spot patterns or line drive patterns if warranted by actual performance considerations. Offsetting the Prudhoe Bay Unit to the west is the Kuparuk River Unit operated by ARCO Alaska, Inc. 20 AAC 25.200.(B).(3): Current Zone of Completion All existing and possible future development wells shown in Exhibit 2 are completed in the Permo-Triassic (Sadleroohit) formation of the Prudhoe oil pool. A type log of the Sadleroohit formation is provided in Exhibit 3. 20 AAC 25.400.(B).(4): Zone Affected by Injection The light oil column of the Permo-Triassic (Sadlerochit) sandstone formation identified on the type log, Exhibit 4, is the target producing formation of the Prudhoe oil pool to be affected by miscible enriched field gas injection. Within the Project Area the top of the Sadlerochit varies in depth from 8650' TVD SS in the north to 8925' TVD SS in the south (Exhibit 5). The light oil column varies in thickness from 75 feet in the south to 300 feet in the north as depicted in Exhibit 6. AGO 10060615 20 AAC 25.400.(B).(5): Logs of Existing Injection Wells Waiver of this requirement is requested since all well logs have been submitted to the AOGCC in accordance with Conservation Order 145. 20 AAC 25.400.(B).(6): In~ection Well Casin9 Program and Testin9 A. Casing Program Wells drilled specifically for water or miscible gas injection service will be cased in a manner consistent with current production wells. B. Casing Tests Ail current and future casing strings have been and will continue to be tested in accordance with AOGCC Regulation 20 AAC 25.030 as a minimum. Waiver of further submittal of information for this section is requested since well completion data including casing, cementing, and test programs are submitted for each well on the State of Alaska 0il and Gas Conservation Commission Form 10-#07, "Well Completion or Reoompletion Report and Log" in accordance with AOGCC Regulation 20 AAC 25.030 Casing and Cementing. 20 AAC 25.400.(B).(7): In~ection Fluid The miscible gas injectant required for the project will be obtained by enriching FS-3 separator off-gas with intermediate hydrocarbons recovered 5 AGO 10060616 from the Field Fuel Gas Unit (FFGU) and from additional processing equipment located at FS-3. These facilities are designed to supply approximately 40 MMSCF/D of miscible enriched field gas with a methane content of approximately 42.5 mole percent. The minimum miscibility pressure of this injectant is estimated to be approximately 3700 psi. Produced Sadlerochit water will be injected alternately with the enriched gas in the WAG injectors. Prior to implementation of the source waterflood in mid 1984, approximately 65-100 MSTB/D of produced Sadlerochit water will be available for use in the upstructure and WAG injectors. In mid 1984, Beaufort Sea water will be available for injection into the seven upstructure water injectors. These injectors may require up to 105 MBPD of this source water. 20 AAC 25.400.(B).(8): Tabulation of Production Tests Waiver of this requirement is requested since semi-annual well test data are submitted in accordance with Conservation Order 145. The last report was submitted as of 3uly 1, 1982 on State of Alaska Oil and Gas Conservation Commission Form 10-409, "Well Status Report and Gas-Oil Ratio Tests." 20 AAC 25.400.(B).(9): Plan and Rate of Development The following discussion is a summary of the planned development and operation of the Pr°jeot. A more thorough description of the Project is 6 AGO 10060617 provided in "Prudhoe Bay Unit Flow Station 3 Injection Project - Applica- tion for Approval as a 0ualified Tertiary Recovery Project for Purposes of the Crude 0il Windfall Profit Tax Act of 1980", which has been sub- mitted concurrently with this Application. Pro~ect Development The drilling program for the Flow Station 3 Injection Project has been optimized to: 1) assure that all drilling necessary to accommodate miscible gas injection is concluded in a time frame compatible with facilities construction, and 2) develop the Project Area without signifi- cantly impacting planned expansion in other portions of the Field. Forty-eight of the currently planned sixty wells are expected to be available before miscible gas injection begins in 3anuary 1983. These wells include all eleven WAG injectors, five of the seven upstructure water injectors, and thirty-two producers. The remaining twelve wells, namely two additional upstructure w9ter injectors and ten infill producers, will be completed by Dune 1983. The six month difference between the start of miscible gas injection and the end of well development will have no significant effect on the performance or operation of the Project. As shown in Exhibit 2, the Project wells will be drilled from Drill Sites 1, 6, 12, 13, and 14. All WAG injectors will be drilled and operated from Drill Site 13 to minimize the cost of miscible gas facili- ties and flowlines. The upstructure water injectors will be drilled from 7 AGO 10060618 the peripheral Drill Sites 12, 13, and 14. These injectors will be used to help maintain the pressure level in the Rroject Area above minimum miscibility conditions and to prevent the development of gas tongues into the Project Area. Pro~ect Operation Water injection is scheduled to commence in one or two of the upstructure injectors when produced water volumes resulting from normal Flow Station separation become significant (i.e., greater than approximately 10 MSTB/D). Based on current projections, it is anticipated that this will occur in late 1982. In December 1982, three turbine compressors will be operational to gas lift an additional 40 to 60 MSTB/D of produced water from Drill Site 14 wells with perforations in the Sadlerochit aquifer. This supplemental water will be used to expand the existing injection into the upstructure Project Area. Miscible gas injection is planned to begin in 3anuary 1983. At start-up, approximately 40 MMSCF/D of enriched gas will be injected into two or three of the WAG injectors for a period of One to three months. After this period, produced water will be injected into these initial wells, thus beginning the normal water-alternating-gas (WAG) process, and another set of WAG injectors will commence taking miscible gas. It is anticipated that several periods or sequences will be required before all of the WAG injectors have received miscible gas. However, should condi- tions warrant, water may be injected prior to miscible gas injection to AGO 10060619 precondition the reservoir. The Project will continue until a volume of miscible gas equal to at least 10% of the Project pore volume is injected. It is anticipated that ten years will be required to inject this volume. Operational considerations will dictate the WAG ratios and the cycle lengths for water and gas injection. Prior to implementation of the source waterflood in mid 1984, approximately 65 to 100 MSTB/D of produced water will be available for use as needed in the upstructure and WAG injectors. This total produced water volume consists of 40 to 60 MSTB/D from the Drill Site 14 wells and a projected 25 to 40 MSTB/D from normal Flow Station 3 production separation. The seven upstructure water injectors will be converted to a source water supply after waterflood start-up and an estimated 105 MSTB/D of Beaufort Sea water may be needed for injection in these upstructure injectors. Ultimately, approximately 90 MSTB/D of produced water may be required in the WAG injectors. Facilities A new process module, the Flow Station 3 Injection Module, will be operational in Oanuary 1983. This module will be located at Flow Station 3 and will house the major process equipment necessary for the recovery and injection of the miscible fluid at Drill Site 13. Intermediate hydrocarbon liquids will be routed from the FFGU to the module and will be combined with additional intermediates obtained through processing of AGO 10060620 FS-3 separator off-gas. This enriching material will be recombined with a relatively rich separator off-gas stream at 4100 psig resulting in a supercritical single phase fluid. The process is designed to provide approximately 40 MMSCF/D of miscible gas for injection at Drill Site 13. An in-line gas chromatograph will be installed in the injection fluid line to monitor gas composition and to ensure that the gas injectant will be miscible with the oil at reservoir conditions. It is anticipated that additional produced water above projected Flow Station 3 volumes will be required to support the Project in the 1983-1984 time frame. Therefore, to provide supplemental water, four Drill Site 14 wells will be perforated in the Sadlerochit aquifer and artificially lifted with high pressure gas supplied by three new 1200 hp Solar Saturn turbine compressors. Beginning in December 1982 and continuing until early 1984, the three compressors will provide 40 to 44 MMSCF/D of gas lift gas capable of producing from 40 to 60 MSTB/D of additional water. This supplemental water will be treated, pumped, and transported to DS 13 and DS 14 for injection by existing FS-3 PWI facilities. Project Surveillance Since one of the objectives of the Flow Station 3 Injection Project is to provide a better understanding of key factors affecting tertiary recovery processes in the Sadleroohit, an extensive reservoir surveillance program is planned to monitor and optimize the enriched gas drive process. The AGO 10060621 10 existing Field wide surveillance program will be supplemented by the use of observation wells, cores, additional and more frequent well surveys, and possibly chemical and radioactive tracers to follow actual water and miscible gas movement in the reservoir. Two non-perforated observation wells located close to one of the WAG injectors will be utilized for early flood surveillance. These wells will be completed with non-conductive casing to allow the use of induction logging tools to observe water bank movement. The propagation of the enriched gas front past the observation wells will also be monitored with neutron logging devices. Current plans involve running these logs repeatedly during the first year o~ injection (or until the fluid banks s~abilize) and at least once per year thereafter. The observation well loQging program will provide a time-lapse description of changes in , water and gas (and hence oil) saturations versus depth. From these measurements the effectiveness of the tertiary process in forming a miscible zone and in mobilizing oil will be evaluated. Consideration is also being given to testing the effect of miscible gas injection rate on vertical sweep. In addition, the effects of reservoir stratification and gravity segregation will be observed. Following gas breakthrough, neutron logs will be run periodically in the producing wells to evaluate coning and vertical sweep. Gas samples will also be taken from the producers at this time to determine process efficiency and to ascertain if enriched gas breakthrough has occurred. ll AGO 10060622 At Project start up, five wells in the Project Area will have been cored through the 5adlerochit oil column. A detailed analysis of these cores will provide valuable data on lithology, permeability, porosity, fluid saturations~ and relative permeabilities for use in further reservoir studies and performance evaluations. Additional monitoring of the Project will include the running of injec- tion or production profiles on each well during the first year with subsequent surveys being performed on a rotating basis so that a new profile is obtained on each well periodically. These profiles will be used to ensure that injection or production is not being dominated by a single interval. Bottomhole pressures will be obtained in each inverted nine spot pattern to ensure that average reservoir pressure is maintained above minimum miscibility pressure. 12 AGO 10060623 I EXHIBIT I.,L ~ CATION OF FLOW STATION ,__ ~,co ,.i INdECTION PROdECT · T M-C M-C ~'r. -17 ' .-c .... ;-~' .... ~---- ~ ' T~-I 2 M-C - ' A-E A-E M-P M-P SOHIO A-E KUPARUK, RIVER UNLIT A-E M-P-C ·M-P SOHIO SOHIO SOHIO 50 4-9 ..~ ~ ,~ A-E CHEVRON M-P SOHIO M-P-C M-P-C M-P-C A-E H,' M-P M-P-C 'Ir. - ! 3 , SOHIO SOHIO ~E ,, A-E PRUDHOE BAY UNIT .BOUNDARY ., A-E A-E SOHIO A-E A-E SOHIO A-E A-E I ! A-E I A~-E SOHIO ? -:,--~ .... + ....~o .... I I I / I ' i ' i + .... ,'o .... ~ .... ~ - - ~ I I ArE A-E / PRUDHOE BAY UNiT UNIT OUTLINE Situated milflin T. IO-IZN, R. IO-16E. Umiat Meridian North Slope of 4iaaka LEASE LEGEND A-E -- A~CO -EXXON M-C - ~L - CHEVRON M-P --I~L- PHILLIPS M-P-C -- M~IL- t~dl L LIPS -CHEVRON so,liD -- ~(~4i0 P~TR CO &H., ~ eJ -- AMER,&DA HESS, ®t e~ &.H.-C~TT'Y --~MIrR&D& HI=SS-GETTY &-S-B - &RCO-$OHIO-BI~A EXP FEET SOHIO SOHIO A.H., et al A.H.- GETTY A-E SOHIO A-E' SOHIO I SOHIO ?4 A-E SOHIO A. H. el al I -- 103 -- SOHIO I 106 A-E A~E ,~ A-E SOHIO A'-E. A-E A-E 7,1 70 SOHIO Id -P-C SOHIO SOHIO I "109A" ' j " I Tr.-111 ,, I 109 A-E J, , A-E A-E " I ,,, ,1 AGO i0060625 A-E Z o ~14-18 14-5 014-6 14-11 ~14-10 14-9B~ 14-12 14-29 14-28 14-8 14-7 ~13-23A ~14-26 14-30 13-2G 16 k~ 13-32 1S 14-9A 14-22 21 013-29 FS-5 INJECTION 22 i~t 6-14 14-14 13-17 ~6-12 6;-6 ~ 15-30 13-15 6-17 ~Ir13-25 6-4 G-11 13-1 6-13 13-18 I2 13-20 13-2 3 6-8 6-10 13-22 ~ 13-53 ~13-4 13-5 13-1G 013-11 13-6 13-13 13-12 PROJECT AREA 23 13- ~I 13-10 ~ 13-7 ~F13-9 12-1S 13-8 PUT RIVER 24-10-14 1-14 1-7 12-19 ~iI12-12 12-20 1-2 ~ 1-15 1-13 1-18 ~ 1-10 12-13 01-1 ~ 1-11 12-1 12-17 ~'13-21 PUT RIVER 12-4 ~18,-10-15 ~' 12-4A 12-9 12-18 12-3 17 ~I12-5 12-8B: 12-8A 12- 16 ~PUT RIVER ~ i9 iD-iS 12-11 12-10 ~12-7A ~12-7 19 2O ~12-8 LEGEND EXISTINQ OIL PRODUCER PROPOSED OIL PRODUCER EXISTINC NA~ INJECTOR PROPOSED NAC INJECTOR EXISTIN~ NATER INJECTOR PROPOSED NATER INJECTOR SUSPENDED OR ABANDONED NELL 0 PROPOSED SOURCE WATER WELL · EXISTING SOURCE WATER WELL NOTE: NELL LOCATIONS /~T TOP OF SADLEROCHIT FORMATION SCALE: 1"=2000' R14E RISE EXH IB IT 2 PRUDHOE BAY UNIT FLOW STATION 5 INJECTION PROJECT PROJECT, WELLS DR ILLED AS OF AUGUST 1,5, 1982 AGO 10060626 200~520802 FLOW EXHIBIT _~ PRUDHOE BAY UNIT STATION ;5 INJECTION PROJECT Sedlemchit zon(.ion end shale corn SHUBLIK FM. SADLEROCHIT FM. 9088 9172 9403 BASE SADLEROCHIT .~-- Shale IVlepping Te~m Units ~ ~"-- =~_~ ._.. 8863 · ~~ ~oo ---- ~ ZULU L . r ~ ........ ~-' ~' ~oo ~~ XRAY I - VlCT~ _ __ ~& 92II ~~' TANGO ~+~ 1 ~r ~ - ' ~EO ! EXHIBIT 4 PrUDHOE BAY UNIT FLOW STATION :3 INJECTION SAMPLE LOG - PROdECT SHOWING ZONE AFFECTED BY PROJECT o 88O0 SHUBLIK FM. SADLEROCHIT FM. HEAVY OIL / TAR ZONE 8900 9000 8863 >- Z 9034 OIL/WATER CONTACT 9085 9100 9aO0 EXHIBIT - 5 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT TOP SADLEROCHIT STRUCTURE ~-~ 0 0 O~ 0 o~ 9\0C / / 8550 ---_.. 865O B~ IECT 9OOo Scale · 1" = 4000' Contour Interval = 25' EXHIBIT- 6 PRUDHOE BAY UNIT FLOW STATION 3 INJECTION PROJECT GROSS SADLEROCHIT LIGHT OIL THICKNESS Scale' 1"= 4000' 575 ~o 125 0 0 ~0 0 0 I PROJECT 0 Contour Interval = 25'
