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Home My WebLink About2002 Northstar Oil Pool Annual Reservoir Performance Report Northstar Field Northstar Oil Pool January 2002 through December 2002 2 Table of Contents A. Progress of Enhanced Recovery Project B. Voidage Balance by Month of Produced Fluid and Injected Fluids C. Summary and Analysis of reservoir pressure surveys within the pool D. Results and Analysis of Production and Injection Log surveys, tracer surveys, observation well surveys and any other special monitoring. E. Review of pool production allocation factors and issues over the prior year F. Review of Annual Plan of Operations and Development and Future Development Plans G. Status of wells shut-in for 365 days or more Attachment 1: Map of well Locations Attachment 2: Northstar Field 2002 Overview Statistical Summary 3 A) Progress of Enhanced Recovery Project During 2002, 5 additional production wells were brought on line (NS07, NS08, NS09, NS14, NS15) and one existing well was converted from production to gas injection (NS27). Average oil production was 49,049 bopd and average gas injection was 176.4 mmscfd. Injection gas consisted of produced formation gas and imported make-up gas from Prudhoe Bay. The location of these wells and other wells that have been added to date are shown in Attachment 1. Production and injection statistics are summarized in Attachment 2. During 2002, gas compressor problems limited gas injection capacity resulting in a voidage balance shortfall of approximately 2.5 mmrb. Conversion of the NS27 well from production to injection took place in July to provide additional gas injection capacity. Completion of additional oil producers and gas injectors was delayed in November and December due to slow sea ice formation which extended the restricted drilling window into mid December. History matched reservoir simulator model results have been provided to the AOGCC as part of the Submission of Proposed Interim Tract Participation Factors for the Northstar Participating Area. Additional drilling and laboratory work are ongoing and will be used to continue to refine the reservoir simulator model. 4B) Voidage Balance by Month of Produced Fluid and Injected Fluids Note: MRB stands for thousand reservoir barrels MonthOil, MRBFree Gas, MRBWater, MRBTotal Voidage, MRB2002Cum, MRBCum since start-up, MRBFormation Gas, MRBImport Gas, MRBTotal Injection, MRB2002Cum, MRBCum since start-up, MRBNet Injection, MRB2002Cum, MRBCum since start-up, MRBJanuary-02 2,419 0 4 2,423 2,423 5,197 1,501 745 2,245 2,245 4,707 -178 -178 -490February-02 2,210 0 2 2,213 4,636 7,410 1,091 687 1,778 4,023 6,485 -435 -612 -925March-02 3,397 0 2 3,399 8,035 10,809 1,943 1,452 3,395 7,418 9,880 -5 -617 -929April-02 2,388 0 0 2,389 10,424 13,198 1,528 1,301 2,829 10,247 12,709 440 -177 -489May-02 2,368 75 1 2,444 12,868 15,642 1,507 770 2,278 12,524 14,987 -166 -343 -656June-02 3,994 300 4 4,298 17,166 19,940 2,905 764 3,668 16,193 18,655 -630 -973 -1,285July-02 3,874 679 10 4,563 21,729 24,503 3,236 1,183 4,419 20,612 23,074 -144 -1,117 -1,429August-02 4,035 1,000 18 5,054 26,783 29,557 3,645 1,109 4,754 25,366 27,828 -300 -1,417 -1,729September-02 2,965 451 15 3,430 30,213 32,987 2,388 1,006 3,394 28,760 31,222 -36 -1,453 -1,765October-02 4,062 999 36 5,097 35,310 38,085 3,713 909 4,622 33,382 35,844 -475 -1,928 -2,240November-02 3,669 1,148 30 4,848 40,158 42,932 3,593 865 4,458 37,841 40,303 -389 -2,317 -2,629December-02 3,749 1,459 37 5,245 45,403 48,177 3,952 1,095 5,047 42,888 45,350 -198 -2,515 -2,8272002 Totals 39,130 6,112 161 45,403 31,003 11,885 42,888 -2,515Produced Fluids Injected Fluids Net Injection 5 C) Summary and Analysis of reservoir pressure surveys within the pool Static bottom hole pressures collected in 2002 are summarized below. Well Date Extrapolated Pressure at - 11,100' TVDss Datum, psia Data Source NS09 17-Jan-02 5,188 Cidra Data NS14 18-Feb-02 5,170 Cidra Data NS08 20-Mar-02 5,190 Cidra Data NS15 4-May-02 5,186 Cidra Data NS08 6-May-02 5,186 Cidra Data NS09 7-May-02 5,184 Cidra Data NS13 7-May-02 5,187 Cidra Data NS14 19-Apr-02 5,182 Cidra Data NS07 10-May-02 5,177 RFT-B NS07 27-Jun-02 5,159 Cidra Data NS15 22-Jul-02 5,159 Cidra Data NS08 22-Jul-02 5,164 Cidra Data NS09 22-Jul-02 5,160 Cidra Data NS13 22-Jul-02 5,173 Cidra Data NS14 22-Jul-02 5,193 Cidra Data NS15 31-Oct-02 5,106 Cidra Data NS15 6-Nov-02 5,113 Cidra Data NS08 31-Oct-02 5,144 Cidra Data NS08 6-Nov-02 5,134 Cidra Data NS09 31-Oct-02 5,165 Cidra Data NS09 6-Nov-02 5,160 Cidra Data NS13 31-Oct-02 5,150 Cidra Data NS13 6-Nov-02 5,152 Cidra Data NS14 31-Oct-02 5,164 Cidra Data NS14 6-Nov-02 5,163 Cidra Data NS24 20-Dec-02 5,160 RFT-B NS18 31-Dec-02 5,121 RFT-B These pressures are graphically represented in the next figure that is a plot of pressure by well versus time. 6 Northstar 2002 SBHP Data by Well51005110512051305140515051605170518051905200Jan-02 Feb-02 Mar-02 Apr-02 May-02 Jun-02 Jul-02 Aug-02 Sep-02 Oct-02 Nov-02 Dec-02DateExtrapolated Pressure at 11,100' TVDss, psiaNS07NS08NS09NS13NS14NS15NS18NS24 7 These data indicate pressures have fallen slightly because of under-injection. The average of the 2002 static bottomhole pressures is 5163 psia. A complete listing of data from these surveys is shown in Attachment 2 on the AOGCC Reservoir Pressure Report form. 8 D) Results and Analysis of Production and Injection Log surveys, tracer surveys, observation well surveys and any other special monitoring. No surveys were obtained in 2002. There are plans to initiate a tracer study in 2003 and a production/injection survey campaign. 9 E) Review of pool production allocation factors and issues over the prior year Theoretical production is calculated for each Northstar producing well on a daily basis. A well’s theoretical production is calculated using average wellhead flowing pressure and hours on production as follows: ltheoreticaaof n whsi whfproduced QQP Phours =×           −× 124 Where: hoursproduced = hours on line Pwhf = average wellhead flowing pressure Pwhsi = shut-in wellhead pressure n = flow exponent Qaof = absolute open flow of well with Pwhf = 0 psi Qtheoretical = theoretical production The input parameters (n, Qaof and Pwhsi ) for each well are determined from well test data and systems analysis and are reviewed each time new test data becomes available. The actual total production for a day is divided by the summation of the theoretical production from each well to calculate a daily allocation factor. This allocation factor is then multiplied by each well’s theoretical production to calculate allocated production. Allocation factors for 2002 had an average value of 0.966 and a median of 0.952. 10 F) Review of Annual Plan of Operations and Development and Future Development Plans Northstar concluded 2002 with three injection wells (NS27, NS29 and NS31), six producing wells (NS07, NS08, NS09, NS13, NS14, and NS15) and one Class I disposal well (NS10) online. During 2002, the NS27 well was converted from production to injection and the NS09, NS08, NS14, NS15 and NS07 wells were brought on line. In addition to the wells that were completed and brought on line in 2002, one well was drilled and completed but not perforated (NS24), eight wells were drilled down to the top of the Sag River formation (NS06, NS12, NS16, NS18, NS17, NS20, NS19 and NS22) and the surface hole was drilled for one well (NS21). The plan for 2003 is to finish drilling and completing the NS06, NS12, NS16, NS18, NS21, NS20, NS19 and NS22 producing wells and the NS17 and NS23 injection wells. Additional potential activity includes the drilling of a sixth injection well and a second Class I disposal well. This drilling activity is summarized in the following table. 11 Northstar - Year End Wells Year Count Producers Injectors Class I Disposal 1 NS07 NS27 NS10 2 NS08 NS29 3 NS09 NS31 4 NS13 5 NS14 6 NS15 2002 1 NS07 NS27 NS10 2 NS08 NS29 (NS32)* 3 NS09 NS31 4 NS13 NS17 5 NS14 NS23 6 NS15 (NS25 or 35)* 7 NS24 8 NS18 9 NS22 10 NS06 11 NS12 12 NS16 13 NS19 14 NS20 2003 15 NS21 * - Possible Well MMS wells in bold Future Development Plans We also recognize the possibility that satellite hydrocarbon accumulations may exist within expected drilling reach from the island. These targets will be the subject of additional appraisal. 12 G) Status of Wells Shut-in for 365 days or More (20 AAC 25.115) There were no wells shut-in at the end of 2002. 13 Attachment 1: MAP OF NORTHSTAR WELL LOCATIONS Well Status 12/31/02 Bottomhole Locations Abandoned Disposal Well Gas Injector Not Complete Oil Producer Ivishak Boundary Lease Boundary Unit Boundary Township / Range Boundary Northstar Well Status for AOGCC Annual Performance Report E. M. Fueg 3/26/03 Projection Information Alaska State Plane Zone 4 Clarke 1866, NAD 1927R13ER12E R14ER14ET14N T13N R13ER13ER12ER13ER13ER14E ADL312799 Y0179 ADL312798 ADL312808 Y1645 Y0181 ADL312809 ADL355001 NS08 NS14 NS13 NS26 NS20 NS06 NS07 NS09 NS10 NS12 NS15 NS16 NS17 NS18 NS19 NS21 NS22 NS24 NS27 NS29 NS31 bp LEGEND T R A N S - A L A S K A PIP E LIN E 32 MILES 10 14 Attachment 2: NORTHSTAR FIELD 2002 OVERVIEW STATISTICAL SUMMARY WELL STATISTICS 2002 (12/31/01) Producers 6 Injectors 3 NOTES: (1) Well count data reflects ONLY those wells which contributed to production/injection during the respective year PRODUCTION/INJECTION STATISTICS Production 2,002 Cumulative: Start-Up through 12/31/02 Oil (BBL) 17,902,993 19,168,876 Gas (MCF) 47,615,650 50,301,716 Water (BBL) 152,461 159,547 Injection Water (BBL) into NS10 Disposal Well 935,119 1,225,233 Gas (MCF) 64,396,277 68,093,052 Balance Cum Production (MRB) 45,403 48,177 Cum Injection (MRB) 42,888 45,350 Over/Under (MRB) -2,515 -2,827 AVERAGE RATE DATA 2002 Production Oil, BOPD 49,049 Gas, MCF/D 130,454 Water, BWPD 418 Injection Water, BWPD 280 Gas, MCFPD 176,428 AVERAGE RESERVOIR PRESSURE Average of surveys obtained in 2002, psia 5,163