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Home My WebLink About2006 Kenai Gas FieldM Marathon MARATHON Oil Company Alaska A. Team P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 March 2, 2007 DECEIVED MAR 0 2 2007 Alaska Oil & Gas Cons. Commmissidn Commissioners: John Norman, Dan Seamount, Cathy Foerster Anchorage Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Suite 100 Anchorage, AK 99501-3539 Re: Storage Injection Order 7 2907 -Annual Gas Storage Performance Evaluation LCX)LQ Dear Commissioners: Marathon Oil Company (Marathon) respectfully submits the attached information to fulfill the requirements of Rule 5 of Storage injection Order #7, dated April 19, 2006. Rule 5 requires, in part: "An annual report evaluating the performance of the storage injection operation must be provided to the Commission no later than March 15. The report shall include material balance calculations of the gas production and injection volumes and a summary of well performance data to provide assurance of continued reservoir confinement of the gas storage volumes." After almost 46 years of continuous production, the Sterling Pool 6 continues to exhibit a tank a like behavior. Marathon has not observed and has no information indicating any change to this behavior as a result of gas injection and storage operations which began on May 8, 2006. Marathon has conducted gas storage operations in compliance with the rules and conditions of SIO #7. All required data other than form 10-413 as explained below, have been submitted to the AOGCC. From the time of first injection through the period ending January 31, 2007, the total volume of gas injected into Pool 6 was 1,529,155 mcf. The total volume of stored gas withdrawn was 306,768 mcf. The total volume of native gas withdrawn was 2,760,912 mcf. The maximum calculated reservoir bottomhole pressure during the injection cycle was 172.2 psia, far below the maximum of 300 PSI permitted under Rule 4 of SIO -7. Attached please find Exhibit #1, a summary of the results of a recent update to the Sterling Pool 6 reservoir model, which is submitted to satisfy the annual performance evaluation requirements for material balance calculations, The reservoir pressures used in the model were shut-in tubing pressures obtained from our SCADA system which were converted to bottom hole pressures at mid -perforation. The pressures were obtained prior to and subsequent to the first injection cycle. (Shut in periods April 10, 2006 & Oct 14th, 2006) Modeling work shows an expected direct response to injection and withdrawals from the reservoir. Each observed shut in well pressure correlated very well with the model prediction. The observed static pressures gathered before and after the 2006 injection cycle do vary somewhat from the expected P/Z line (Exhibit 1 L) both values being lower than the values predicted on the P/Z line. The reason for this variation can be explained by examining the pressure distributions predicted by the simulation model (Exhibit 1 M). As can be seen in this exhibit the model suggests more pressure variation within the pool during April than during October. This is consistent with the observed departures from the P/Z values in Exhibit 1 L. The calculated pressure on October 14th, 2006 is approximately 5 psi below the model predication. In summary, the model predication is consistent with observed pressures and injection/withdrawal volumes. Exhibit #2 is a plot showing the performance of the injection well (KU 31-07X) during the first injection phase. Exhibit #3 is a table showing monthly injection and withdrawal volumes and allocated balances between Native and Stored gas. Exhibit #4 is the original P/Z plot contained in the application for gas storage for your reference. Although Form 10-413 appears to be required by statute, the form has not been submitted because it appears applicable only to enhanced recovery projects rather than gas storage projects. Additional guidance is requested regarding the applicability and necessity of Form 10-413 for this gas storage project. If you have any questions, please do not hesitate to contact me at (713) 296-3302 or domartens @ marathonoil.com. ,Sincerely, Dave Martens SUBSURFACE MANAGER Enclosures Hand Delivered cc: Greg Noble, BLM William Van Dyke, DOG (bele, Marathon File Exhibit #1 (IA - 1J) Comparisons of Observed Pressures vs. Expected Pressures from Eclipse Model • Well 34-31 • Well 34-32 • Well 13-6 • KDU-5 • Well 14-32 • Well 33-7 • Well 23X-6 • Well21-6RD • Well43-6RD • Well 14X-6 For each of the wells listed above, two plots are presented showing historical observed shut-in pressures against those predicted by the Eclipse simulation model. The upper plot encompasses the entire historical life of the Pool 6 reservoir. The lower plot shows the same data beginning in the Year 2000. As can be seen for each of the wells there is in general good agreement between the pressures predicted by the simulation model and those observed at the individual wells. There do appear to be some minor differences for the historical pressures during 2000- 2005 when plotted on an expanded scale. This is a result the fact that the simulation model uses average monthly production rates and assumes that a well produces each and every day during a month at a particular rate. Therefore, during months where an individual well has production, the simulation model will tend to under predict the pressure at that well because the model assumes the well is producing rather than shut-in. As can be seen on the plots, there is very good agreement between the simulation model and the pressures observed during the 2006 injection cycle season. f, Exhibit IA: Well 34-31 -WBPP-34JI rs.O(NRFR5T 0 +,F Observed static pressures i PJ4]I rs. OATE (NRPRES) OB] P]4]I rs. OATE (NRPRE3 QOB] Observed shut-in pressure during 2006 injection cycle 2000 loon i a a i M d M M O 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 DAT E 9 Exhibit 1B: Well 34-32 D 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 DAT E PJ6DATE(NFPFES_ — PD4n1 9O Ytvs. DATEMNFREB I)0 I)DBB + } Observed static pressures i Observed shut-in pressure during 2006 injection cycle zDDD I M D 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 DAT E M 1000 4 I M D 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 DAT E Exhibit 1C: Weil 13-6 -BYBP:ID E vf. WE(SAST J) •- PIM vf.WE(NRPRES)CBS yy Observed static pressures P134 DATE (NRPRES I)OBS T T o Observed shut-in pressure during 2006 injection cycle 2000 -- a n 1000 a m rl a m 3 ♦ a 0 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 i/1/90 1/1/95 1/1/00 1/1/05 DAT E f Exhibit 1D: Well KDU-5 -WBP: KOUd rs. OATE QRST T) ♦♦PKOLLSrs.ONE(NFPFES)OBS yy Jy. Observed static pressures PADLLS rs. OATE (NNPPES1) OBS T T Observed shut-in pressure during 2006 injection cycle 2000 a 1000 i 0 Y a 0 Y d l� 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 OAT E Exhibit 1E: Well 14-32 -WBP:14J]vs. OATE (lPSi J) i! P14J3rs.0ATE(NFPBE5J0B5 11 T T Observed static pressures _. P14J3 vs. GATE (N XPX ES I)OBS n Observed shut-in pressure during 2006 injection cycle 2000 M P 4 1000 I a 0 1/1/85 1/1/70 1/1/75 1/1/80 1/1/85 t/1/90 1/1/95 1/1/06 1/1/05 OAT 1 Exhibit 1F: Well 33-7 - WBP 11] vs. GATE (VSi l) ♦♦ PBS]v,.DATE(NNPNEB)OBB PBS)vs. GATE (NNPp ES_I)OBS ++ Observed static pressures O n Observed shut-in pressure during 2006 injection cycle 2000 0 1/1/65 1/1/70 1/1/75 1/1/80 1/1/65 1/1/90 1/1/95 1/1/00 1/1/05 DAT E f FExhibit 1G: Well 23X-6 -WBP�SMB ra. OPTE (USTJJ •• P3�LOra.OATEMRPRE4J005 + Observed static pressures �n P_Bra.O (RRPRESI)OBS -i i Observed shut-in pressure during 2006 injection cycle 2000 0 1 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 OAT E +000 M a n N a 0 1 1/1/65 1/1/70 1/1/75 1/1/80 1/1/85 1/1/90 1/1/95 1/1/00 1/1/05 OAT E r FExhihit 1H: Well 21-6RD I-Exhibit 1I: Well 43-6RD 1 Exhibit 1J: Well 14X-6 -'. P�aar:�U.rEM.PaEs_i)oPs * * Observed static pressures n n Observed shut-in pressure during 2006 injection cycle 1D00 \ 5 \ n 1000 - -- - 0 1/1/65 1/1/70 1/1/75 1/1/80 t/1/65 1/1/90 1/1/95 1/1/DO 1/1/05 DATE p Exhibit 1K: Static h,.�servoir Pressures gathered before and alter 2006 injection cycle April 10, 2006 POOL 6 Shut -In surface pressures with 200psi test gauge Wells had been S/I approx. 72 hrs. Wells had been S/I approx. 48 hrs. 4565 Well Test Gauge Psi TOW SITP psig SITP psia MidPerf SSTVD MidPerf TVD MidPerf MD Zones Perfd ac MidPerf BHP psia a Datum 4565' SS COMMENTS 14-32V 117.0 Zones Perfd 131.65 4520 4607 5316 C-1 144.1 144.2 14-32AN 122.0 120.0 136.65 4520 4607 5316 C-1 149.5 149.7 21-6RDV 118.0 4607 132.65 4482 4562 5280 C-1 145.0 145.3 21-6RDAN 121.0 122.0 135.65 4482 4562 5280 C-1 148.3 148.6 34-31 88.0 94.0 102.65 4653 4741 4743 C-1 112.6 112.3 Probable water column on bottom 34-32L 120.0 140.0 134.65 4485 4580 5239 C-1 147.3 147.5 34-32LAN 121.0 121.0 135.65 4485 4580 5239 C-1 148.4 148.6 DU -51L 121.0 120.0 135.65 4490 4578 5162 C-1 148.4 148.6 DU-51LAN 122.0 136.65 4490 4578 5162 C-1 149.5 149.7 13-61L 167.0 167.2 4476 4570 5223 4490 4578 13-E1LAN 121.0 120.0 135.65 4476 4570 5223 C-1 148.3 148.6 1446V 5223 168.0 4403 4498 4498 1446AN 121.0 118.0 135.65 4403 4498 4498 C -1,C-2 148.1 148.6 23-X6RDV 121.0 121.0 135.65 4393 4486 4868 C-1 148.1 148.6 2346RDAN 121.0 4403 135.65 4393 4486 4868 C-1 148.1 148.6 31-7X 129.0 130.0 143.65 4359 44461 5350 C -1,C-2 156.7 157.3 Open in both zones, may be higher 31-7X 140.0 154.65 4359 4446 5 5 1 C-1 169.0 than wells with C-1 only open. 33-7S 31-7X 4442 4532 5050 1 5350 C -1,C-2 Well was flowing, not shut-in. 43-6RD Open in both zones, may be higher 120.0 134.65 4416 4503 5362 1 1 147.1 1 147.5 than wells with C-1 only open. 33-7S Z= 0.9844 AVG = 147.7 P/Z 148.0 Excludes highest & lowest values 150.4928 PVT Assumptions lWell was flowing, not shut-in. 43-61RD 143.0 157.65 4416 4503 SG = 0.56 172.2 Ppc = 672.8 MFT on KU 21-7X shows C-1=150 si CO2 = 0.01 AVG = T c = 344.9 Excludes highest & lowest values PVT Assumptions but C-2=225 psi, taken Mar 24,2006. H2S = 0 Z = 0.98337 SG = 0.56 N2= 0.483 IGasDens= 0.405617 Ibm/cu it MFT on KU 21-7X shows C-1=150 psi CO2 = 0.01 BHT = 100.0 1 Gas Grad= 0.002817psi/ft but C-2=225 psi, taken Mar 24,2006. H2S= October 14, 2006 POOL 6 Shut -In surfacepressures Wells had been S/I approx. 48 hrs. 4565 Well Test Gauge Psi TOW SITP psig SITP psia MidPerf SSTVD MidPerf TVD MidPerf MD Zones Perfd acUHF MidPerf BHP psla a Datum 4565' SS COMMENTS 14-32V 4520 4607 5316 C-1 14-32AN 4520 4607 5316 1 C-1 21-6RDV 4482 4562 5280 C-1 21-61RDAN 138.0 152.65 4482 4562 5280 C-1 167.0 167.2 34-31 140.0 154.65 4653 4741 4743 C-1 169.7 169.4 34-32L 140.0 154.65 4485 4580 5239 C-1 169.2 169.4 34-32LAN 4485 4580 5239 C-1 DU -51L 138.0 152.65 4490 4578 5162 C-1 167.0 167.2 DU-51LAN 4490 4578 5162 1 C-1 13-61L 139.0 153.65 44761 4570 5223 168.0 168.3 13-E1LAN 4476 4570 5223 C-1 14-X6V 4403 4498 4498 14 -MAN 141.0 155.65 4403 4498 4498 C -1,C-2 167.0 167.5 23-X6RDV 4393 4486 4868 C-1 23-X6RDAN 140.0 154.65 4393 4486 4868 C-1 169.0 169.6 31-7X 4359 4446 5350 C -1,C-2 Open in both zones, may be higher 31-7X 1 4359 4446 5350 than wells with C-1 only open. 33-7S 4442 4532 5050 lWell was flowing, not shut-in. 43-61RD 143.0 157.65 4416 4503 5362 1 172.2 1 172.7 Z= 0.981 AVG = 168.6 P/Z 168.9 1 172.195 Excludes highest & lowest values PVT Assumptions SG = 0.56 Ppc = MFT on KU 21-7X shows C-1=150 psi CO2 = 0.01 T c = but C-2=225 psi, taken Mar 24,2006. H2S= 0 Z = 0.981 N2 = 0.483 GasDens= • 0.461967 Ibm/cu ft BHT = 100.0 Gas Grad= 1 0.003208psi/ft r Exhibit 1L: Static Reservoir Pressures gathered before and atter 2006 injection cycle -ompared to Field P/Z Kenai Sterling Pool 6 300 ------- Y -4.3990E-06x+ 2.5051 E+03 R2 = 1.0000E+00 250 -- --- -- - - + Official PZ ® 10 -Apr -06 Ave Static Pressure 'i 200 ` ♦ 14 -Oct -06 Ave Static Pressure a ♦ OGIP 2 ® ------ Eclipse Model P/Z • 5/15/2005 a 150 .o - - - - Linear (Official PZ) v 100 --- _ - -- -- -- -- -- :4 rn 50 ` 5.10E+08 5.20E+08 5.30E+08 5.40E+08 5.50E+08 5.60E+08 5.70E+08 Cum Withdrawal (Mscf) DATE CUM PZ Pressure Z -factor Mcf psia psia 4/10/2006 526,436,677 150.5 148.0 0.983 10/14/2006 525,545,425 172.2 168.9 0.981 ( t Exhibit 1M: Reservoir pressure distribution predicted by Eclipse simulation model before and after 2006 inj ection cycle. Pressure distribution per Eclipse Model on 30 -April -2006 For all grid cells where Sg > 0.01 150,0 1600 1 MO 180'a 190,0 200,0 210.0 2209 230 G 2400 Pressure distribution per Eclipse Model on 31 -October -2006 For all grid cells where Sg > 0.01 140 0 15an 168o 1700 laaa Igoo 200,0 2100 220.0 2300 240 1, Conclusions • Eclipse Model was updated to include production and injection volumes through December 2007. • The pressures predicted by the Eclipse model were compared to pressures observed in the various wells in 2006. • The pressures observed in the various wells compared very favorably with those predicted by the simulation model. • Storage Unit did not exceed maximum allowable pressure of 300 psia. • There is no evidence of any containment issues. Exhibit #2 70000 0 50000 LL U 40000 O LL 30000 fA Q 20000 10000 l■' Exhibit #3 KU31-7X GAS INJECTION 2006 0 100 200 300 =1100 500 600 700 800 TUBING PRESSURE, PSIG ♦.,17-5:s'I • 711 - 7! 15 7116 - M1 rI -0:15 girls ?:?.1 5r11� - 9130 —Linear (S11 - :;IFS TOTAL TOTAL Allocation Ratio `Native 'Stored Schedule Native Stored Total GAS =. _- Native S:Ored Gas Gas Native ♦♦ A t A Year End date Month Year Beg Balance Beg Balance Beginning INJECTEDYrl--CF_�•%W4 ♦ �x S? thdrarn Withdrawn End B.alanse End Bala— KP ♦ 25,193.;1.: - 23.1;3.9.2 277.415 Cs - 90% 13% - - 23.1;3.932Zi471.:27 Jun -CC 23. 193,952 277,415 --3471,357 0 100 200 300 =1100 500 600 700 800 TUBING PRESSURE, PSIG ♦.,17-5:s'I • 711 - 7! 15 7116 - M1 rI -0:15 girls ?:?.1 5r11� - 9130 —Linear (S11 - :;IFS TOTAL TOTAL Allocation Ratio `Native 'Stored Schedule Native Stored Total GAS =. _- Native S:Ored Gas Gas Native Stored Total Year End date Month Year Beg Balance Beg Balance Beginning INJECTEDYrl--CF_�•%W4 Gas Gas S? thdrarn Withdrawn End B.alanse End Bala— cnd 5alsr :e May -D6 25,193.;1.: - 23.1;3.9.2 277.415 90% 13% - - 23.1;3.932Zi471.:27 Jun -CC 23. 193,952 277,415 --3471,357 500.273 - 93% 13% - 23.193932 777.39' _---1., Ju -o3 25,193,952 777.6g1 _3.971.843 238,033 77_ 93% 10% 701 74 _6,1;32.1 1.2F..°7: _ Aug -00 26. 193.1151 1.00.5.879 2-.254.00 48,568 243.83' 90% 10% 219.421 24,320 25.973 c35 1.X3£.45=. _ _..._- SeP-CB 25.;73.8-30 1.089,805 27.003.995 e5.3o5 X19,947 204.375 ;]% 13% 183.935 20,437 25,7828"n4 L-t6F.?'_ _7 1 Oc:-33 25,792.894 1.455,313 ?7255207 252.41a 93% 13% 233.474 25.942 ..55.23 L4.r.?': - -- ' Nov -33 25.558.420 1.45$.313 27.0 14738 0 711.4-3 93% 13% et'0.325 71.147 24.913.0;4 1.3eL 17' _.. Dec -05 24.913.094 1.387.171 26,303.285 0 837.7'6 931,16 13% 790.953 93.773 24,13.5.1-1 1,30C.32c :t 42, Jan -C7 24.135.141 1.300.394 25535,539 0 750.112 90% 10% 702.101 78.011 3433.64,3 1.2_1'.?3? ,1-.427 Totals 1,529,155 3.067.660 2,760,912 Exhibit # 4 Original P/Z Plot submitted at original filing POOL 6 P,Z CURVE 1033 5DI) 0 iplc.cllc'cll, X0'.0.000 20"",30c,'wr) -00.0�:,G 500'000.000 CUM GAS PRODUCTION, MCC