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Home My WebLink About2010 Kenai Gas FieldMarch 11, 2011 RECEIVED LIAR 15 2111 AWska Oil & Gas Cans. Comwam aRC,hOfB� Commissioners: John Norman, Dan Seamount, Cathy Foerster Alaska Oil and Gas Conservation Commission 333 W. 7t' Avenue Suite 100 Anchorage, AK 99501-3539 Re: Storage Injection Order 7 2010 Annual Gas Storage Performance Evaluation Dear Commissioners: Alaska Asset Team P.O. Box 198168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565.3076 Marathon Alaska Production LLC (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 48 years of continuous production, the Sterling Pool 6 continues to exhibit tank - like behavior. Marathon has noticed a pressure discrepancy between the predicted pressure by the reservoir simulation model and the observed pressures measured at the wells. The data collected does not indicate that there has been any loss of resource. We will continue to monitor the wells and are investigating the reason for the pressure anomaly. 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. For the annual period ending December 31, 2010, the total volume of gas injected into Pool 6 was 714,358 mscf. The total volume of stored gas withdrawn was 3,244,444 mscf. The total volume of native gas withdrawn was 3,683,360 mscf. The maximum calculated reservoir bottom -hole pressure during the 2010 injection cycle was 238 psia (KU 31-7X, January 2010) 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. Additionally, the field was shut in on May 5, 2010 and October 23, 2010 to obtain the pressures. Modeling work shows an expected direct response to injection and withdrawals from the reservoir prior to 2009. Each observed shut-in well pressure prior to 2009 correlated well with the model prediction. However, the observed pressures are higher than the predicted pressures by the simulation model in 2009 and 2010. We have run several static pressure - temperature logs on various wells in order to investigate the potential of water encroachment. The static pressure -temperature logs have verified that the surface pressures converted to bottom hole pressure are valid. There is still no evidence that indicates there has been any loss of resource. We will continue to monitor the pressure discrepancy seen in 2009 and 2010. The observed static pressures gathered continue to differ from the expected P/Z line (Exhibit 4). The reason for this variation can be explained by examining the pressure distributions predicted by the simulation model (Exhibit IN) and the reasons listed on page three. There is an aerial as well as temporal variation of pressure in the reservoir. This implies depending upon the location of the specific wells chosen for pressure measurements and the time of the year when the pressures are measured, the average measured pressure could be higher or lower than P/Z line. This is consistent with the observed departures from the PIZ values in Exhibit 4. Exhibit #2 is a plot showing the performance of the injection wells (KU 31-07X and 23X-06) during 2010. Exhibit #3 is a table showing monthly injection and withdrawal volumes plus allocated balances between Native and Stored gas. Exhibit #4 is the original P/Z plot contained in the application for gas storage. Exhibit #5 is a plot showing monthly averaged production rates, injection rates and field average pressure. Although Form 10-413 appears to be required by statute, the form has not been submitted because we interpret it to be 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: 713-296-3477 or steve.huddleston(a-)marathonoil.com Sincerely, Steven H leston SUBSURFACE MANAGER MARATHON OIL COMPANY Enclosures Via Certified Mail cc: Greg Noble, BLM Kevin Banks, Alaska DNR, Dept of Oil & Gas Lyndon (bele, Marathon File K Exhibit #1 (1 A — 1 L) Comparisons of Observed Pressures vs. Expected Pressures from Eclipse Model • KDU-5 • Well 43-06RD • Well 34-32 • Well 34-31 • Well 33-07 • Well 33-06 • Well 31-07X • Well 23X-06 • Well 21-06RD • Well 14X-06 • Well 14-32 • Well 13-06 • Well 22-6X 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 2006. As can be seen for each of the wells, there is in general, a good agreement between the pressures predicted by the simulation model and those observed at the individual wells prior to 2009. There do appear to be some minor differences for the historical pressures during 2006-2008 when plotted on an expanded scale. The minor variation could be attributed to the following reasons: 1) Simulation uses average monthly production rates rather than daily rates. 2) Some of the observed pressures are obtained from SCADA, which are less accurate as compared to test gauges used for semi-annual pressure measurements. There appears to be a greater pressure difference between the pressures predicted by the simulation model and the observed pressures in each of the wells for 2009 and 2010. The pressure variation could be attributed to the following reasons: 1) Simulation model incapable of handling high injection volumes 2) Potentially attached to an aquifer or leakage from another zone, although there has not been any evidence indicating this over the past 48 years. Conclusions • Eclipse Model was updated to include production and injection volumes through December 2010 • The pressures predicted by the Eclipse model were compared to pressures observed in the various wells in 2010 • The pressures observed in the various wells compared favorably with those predicted by the simulation model prior to 2009. The observed pressures beginning in 2009 were higher than predicted by the reservoir simulation model. • Storage Unit did not exceed maximum allowable pressure of 300 psis • We are investigating to determine the cause(s) of the observed pressure variation seen in 2009 and 2010. • Because the observed pressures are higher than the model pressures, we believe that there is no evidence to suggest any loss of hydrocarbon containment. 0 Sterling Exhibits 0 Pool 6 - S107 0 March 2011 . • �ertr ooserveo �r-i45rory> ... sacro strnmad Can trww antes -SBF& 56rvtleU (a%1 W.RY afIt RIAJI 2000 0 Cn 1000 Q j ! 0 1/1960 1/1965 1/1970 1/1975 1/15 Date --- Simulated SBHP -Eclipse Observed SBHP through 2010 Well Gas Production Rate 400 iM 0 200 VI n a� cn cn v 100 .'7 -seFw SYtwi.ea ('mt tram �Bttrtcsri S p 4E4 I 6 � 111985 1/1990 1/1995 112000 Date Exhibit 1A: Well KDU-5 1/20101 T 14 r� C) X 12 Q 0 10 U cr, 8 aD 0 6 a c� 4 d In a 2 CD 0 • SBHP observed (History) saw s�uscea (�o+irau zmiraxl7 -serve smmiaea tam wau ami arsq 300- 200— Cr) 00 200 # - ------ - - - - ---- 100 C ? - - -- 4 0 1/1960 111965 1/1970 1/1975 1M <. Date Simulated SBHP - Eclipse p Q Observed SBHP through 2010 Well Gas Production Rate 400 nol U 200 s2 AR (n v 1/1985 111990 1/1 a h 1/2005 1/20101 C Dote Exhibit 113: Well 43-06RD 16 14 r� C Q X 12 Q 10 c� r✓� 8 u, a 6 0 U 4 0 Ln a 2 t7 0 �HHt ense a (History) ..__......... SBFm SerahYetl (2t1Ft RtN! 3?t4REAi) -Selm Sm�dnfetl (2011fdN "'RUN} 0 2000 1000 CL -seem sk«aeeea (zm eRenu �IM1TRUNJ 0 111960 1/1965 1/1970 Simulated SBHP - Eclipse 4 Observed SBHP through 201C Well Gas Production Rate 400 300 0 200 Fn A f i 1/1975 1/1980 111985 111990 1/1995 1/2000 1/2005 1/2010 Date 9 Date Exhibit 1C: Well 34-32 i[: 14 (� _) 12 X Q d 10 c� 8 a, a 6 0 U 4 Ln a 2 CD 0 lole Pressure (34-31) --saa� s�we� czo„ Ruv ao„ RLNj -SBFT SMmie[etl Cp„ RUN 2[tl1 RUNj cn 1000 Q N -D i I � � I N I 0 1/1960 1/1965 1/1970 Simulated SBHP - Eclipse 00 Observed SBHP through 2010 Well Gas Production Rate 400 K44, U 200 Fn v cn cn v 100 C t i IE j i E � E 1/1975 1/1980 1/1985 1/1990 111995 1/2000 1/2005 1 Date Date Exhibit 1 D: Well 34-31 16 14 r� C O 12 x d r 10 c� cn 15 8 a) a 6 0 U 4 0 a a 2 0 ■ ■ sertr oosery a (rusrory) SeF®Shrviated (2O11RW M11RtN) _.___...SB11p SerrbLetl (X11 t RLN X11—so 2000 ----SBYIP SYnt9MC1 IR--1R11NJ ( cn 1000 Q i N i L ( r U7 { Cf) n i ■ ■ i 1/1960 1/1965 1/1970 1/1975 1/1980 1/1985 1/1990 1/1995 1/2000 1/2005 112010 Date Simulated SBHP - Eclipse 1-3 13 Observed SBHP through 2010 Well Gas Production Rate 400 -�- .... r 1 r r-- 16 300 200 Cn as Cn cn v L n 100 0 Date Exhibit 1E: Well 33-07 - . �tsrtr ooserveo �rtis[ory� -SBFD 9nI&etl (201tRUN 201tRLN) --SSFP SMWetetl (20tt RIJN ZOt1RlAV) 3� 2000 }..... (201 tRIlN 2p1tRUNj t }{} k ( 1 !i i t 1 i t 1 t! { 1000 ---- — ---.-.--.-.. - - . -- — — -- --- -- —. Q � 1 [ Ut r i { { { 0- 111960 1/1965 1/1970 1/1975 1/1980 1/1985 1/1990 1/1995 1/2000 1/2005 112010 Date Simulated SBHP - Eclipse o a Observed SBHP through 2010 Well Gas Production Rate 400 -- - > - I— 16 300 U 200 Fn Q a_ 100 9 Date Exhibit 1F: Well 33-06 14 a O X 12 Q 0 10 c� cn 8 n, Of 6 a c� 4 2 0 atn �rrl ---sena ser.�s,ea ao„aur zm,Rup __._.._saw srmietee Cza„aW zo„a,aa -saw sin��erea ta,,,aun, 2o„wma i 2000- 1000 000 1000 CL 0 1/1960 1/1965 ill Simulated SBHP - Eclipse Observed SBHP through 2010 Well Gas Production Rate 400 300 200 Fn n 1/1980 1/1985 1/1990 1/1995 1/2000 1 Date ■ et Date Exhibit 1G: Well 31-07X 1120101 T 14 i 0 X 12 Q 10 U CJ7 8 n, CD ry 6 0 U 4 0 a a 2 CD 0 MAMON .... ..S�1P 54n�latetl (2QttRW �Ot1RW} -----S pSh ,d (MI tRW 2Qt tRW) 2000 1000 Q -SBW SniulefcH (2R1tRW 2011RW) 0 Simulated SBHP - Eclipse 00 Observed SBHP through 2010 Well Gas Production Rate 400 300 0 200 Fn Q cn rn a� 100 0 Date Date Exhibit 1H: Well 23X-06 0 10 U C!1 8 aD Q 6 0 c� 4 0 a 2 CD L11 rve❑ frnsmryl � -sato s.�aCmttatw iflttrdlt) 2000 1000 0 --- Simulated SBHP - Eclipse p Observed SBHP through 2010 —Well Gas Production Rate EMI 300 0 200 Date A Date Exhibit 11: Well 21-06RD 2 CD 0 ■ ■ ocnr uuservea Fn —yj .---SSFP SImIrt� RMFM 2MIRLN) g -SRFP Sirxle! t(2EtIt RtM 2O1tRLN) 2000 _a 1000 Q 0 1/1960 1/1965 1/1970 1/1975 1/1980 1/1985 1/1990 1/1995 1/2000 1/2005 112010 Simulated SBHP - Eclipse pa Observed SBHP through 2010 Well Gas Production Rate 400 M 200 cn a.a rn En a� 100 X Date Date Exhibit 1J: Well 14X-06 16 14 r, C Q 12 x a r 10 c� c� 8 u, a 6 0 v 4 a a 2 0 . ■ atlrlr oosery a �Hlscory) SBF&s4nid—(.11RUN 20tI ) p S ddld (MI I RUN 2(YI I RLN) 2000 1000 Q L D U) C (D E 0 111960 1/1965 1/1970 111975 1/1980 Date Simulated SBHP - Eclipse 00 Observed SBHP through 2010 Well Gas Production Rate 400 300 200 v� Q cn cn as 100 IC £E E E1 4 111985 1/1990 1/1995 1/2000 112005 1/2010 HN, Date Exhibit 1K: Well 14-32 2 CD A • ■ ooser a (rnscory) __... -SBIIP SniMetl CXH tRLFJ 2011RuN) p---s91P 5ienileKetl (2011RW 2011 RIM 2000 1000 Q Q) L -�S ("tf x iRLN} 0 T- 1/1960 1 /1965 1/1 1 j€! 4 1/1975 1/1980 1/1985 1/1990 1/1995 1/2000 1/2005 1/2010 Date Simulated SBHP - Eclipse n a Observed SBHP through 2010 Well Gas Production Rate 400 300 U 200 Fn CI v IM. M Date Exhibit 1 L: Well 13-06 2 CD V . ■ observe isto -ser+v SvniJatcd (2011 RLIN 201SRw 2000 1000 Q 0 1/1960 1/1965 1/1970 Simulated SBHP - Eclipse Observed SBHP through 201 C Well Gas Production Rate 400 300 200 Cn 1/1975 1/1980 1/1985 1/1990 1/1995 1 Date 1/2005 1/20101 CI- 100 A Date Exhibit 1 L: Well 22-6X T 14 r� C Q X 12 �r 0 10 c� 8 aD a C� 6 0 v 4 0 a a 2 CD Pool 6 Shut -In Surface Pressures Date 5/5/2010 Wells had been S/I approx. 48 hrs. Well Test Gauge Psig Test Gauge Psia MidPerf SSTVD Mid point perf TVD MidPerf MD Zones Perfd Calc'd MidPerf (TVD) BHP psia COMMENTS KU 14-32 A 191.00 205.73 4520 4607 5316 C-1 225.73 Calibrated gauge placed on well. KU 21-6RD 190.00 204.73 4482 4562 5280 C-1 224.42 Calibrated gauge placed on well. KU 34-32L 185.00 199.73 4485 4580 5239 C-1 219.01 BHP calculated based upon surface pressures. Static PT measured 218.5 psia. KU 13-61L 187.00 201.73 4476 4570 5223 C-1 221.17 Calibrated gauge placed on well. KU 14X-06 AN 189.00 203.73 4403 4498 4498 C -1,C-2 223.04 BHP calculated based upon surface pressures KU 23X-06 189.00 203.73 4393 4486 4868 C-1 222.98 BHP calculated based upon surface pressures KU 43-6RD AN 189.00 203.73 4416 4503 5362 C-1 223.06 Calibrated gauge placed on well. KU 22-6X 189.00 203.73 4537 223.22 Calibrated gauge placed on well. KDU 5L 188.00 202.73 4490 4578 5162 C-1 222.30 Calibrated gauge placed on well. KU 33-6AN 190.00 204.73 4525.5 C-1 224.44 BHP calculated based upon surface pressures KU 33-7 199.00 213.73 4442 4532 5050 C-1 234.33 Calibrated gauge placed on well. KU 34-31 188.00 202.73 4653 4741 4743 C-1 223.03 Calibrated gauge placed on well. KU 44-30L 202.00 216.73 4767 238.60 Calibrated gauge placed on well. KU 31-7X 190.00 204.73 4359 4446 5350 C -1,C-2 223.57 Calibrated gauge placed on well. Pool 6 Shut -In Surface Pressures Date 10/23/2010 Wells had been S/1 approx. 48 hrs. Well Test Gauge Psig es Gauge Psia MidPerf Mid point SSTVD perfTVD MidPerf MD Zones Perfd Calc'd MidPerf (TVD) BHP psia COMMENTS KU 14-32 A 173.00 187.73 4520 4607 5316 C-1 205.46 BHP calculated based upon surface pressures KU 21-6RD 4482 4562 5280 C-1 KU 34-32L 177.00 191.731 4485 4580 5239 C-1 210.22 Calibrated gauge placed on well. KU 13-61L 173.00 187.73 4476 4570 5223 C-1 205.78 BHP calculated based upon surface pressures KU 14X-06 AN 174.00 188.73 4403 4498 4498 C -1,C-2 206.58 BHP calculated based upon surface pressures KU 23X-06 173.00 187.73 4393 4486 4868 C-1 205.43 BHP calculated based upon surface pressures KU 43-6RD AN 176.00 190.73 4416 4503 5362 C-1 208.79 Calibrated gauge placed on well. KU 22-6X 172.00 186.731 4537 204.54 BHP calculated based upon surface pressures KDU 5L 175.00 189.731 4490 4578 5162 C-1 208.01 BHP calculated based upon surface pressures KU 33-6AN 178.00 192.73 4525.5 C-1 211.25 Calibrated gauge placed on well. KU 33-7 187.00 201.73 4442 4532 5050 C-1 Calibrated gauge placed on well. Static PT on 11 - 221.14 1-10 measured BHP of 220 psia. KU 34-31 177.00 191.73 4653 4741 4743 C-1 Calibrated gauge placed on well. Static PT on 11 - 210.90 19-10 measured BHP of 206 psia. KU 44-30L i 1 4767 KU 31-7X 1 178.00 1 192.731 4359 4446 5350 C -1,C-2 210.74 BHP calculated based upon surface pressures Exhibit 1M: Static Reservoir Pressures gathered in 2010 Pressure distribution as per Eclipse Model on May 1, 2010 160 190 220 250 280 Exhibit 1 N: Reservoir pressure distribution predicted by Eclipse simulation model Pressure distribution as per Eclipse Model on November 1, 2010 160 190 220 250 Exhibit 1N: Reservoir pressure distribution predicted by Eclipse simulation model 280 MARATHON 20,000 18,000 16,000 14,000 12,000 a w U E 10,000 m is a 8,000 6,000 4,000 2,000 20,000 18,000 16,000 14,000 12,000 -o U E 10,000 d is 8,000 6,000 4,000 2,000 y = 80 439x - 15213 R2 = 0.9107 I 0 50 100 150 200 250 300 350 400 Tubing Pressure (psig) Exhibit # 2: Performance of injection wells during 2010 iuMN Jan -04 Feb -M Mar -W Apr -W May-0� Jun-0� Jul -04 Aug-0� Sep-0� Oct -Of Nov -Of Dec -0E Jan -1( Feb -1( Mar -1C Apr -1 C May -1C Jun -1C Jul -1C Aug -IC Sep -1C Oct -1 C Nov -10 Dec -1 C 2009 Total 2010 Total Total Total Allocation Ratio *Native *Stored Gas Gas Native Stored Gas Gas Iniected Withdrawn Gas Gas Withrirawn Withrirnwn 1 529,145 168,141 70% 30% 117,699 50,442 610,275 57,840 70% 30% 40,488 17,352 i 889,015 85,728 70% 30% 60,010 25,718 i 1,418,148 19,208 70% 30% 13,446 5,762 1,326,519 0 60% 40% - - 1,278,925 0 60% 40% - - 1,268,657 0 60% 40% - - 1,143,616 0 60% 40% - - 925,063 61,756 60% 40% 37,054 24,702 718,191 5,655 60% 40% 3,393 2,262 132,383 426,155 60% 40% 255,693 170,462 232,435 363,782 60% 40% 218,269 145,513 86,156 424,986 60% 40% 254,992 169,994 100,523 266,910 60% 40% 160,146 106,764 20,025 432,777 60% 40% 259,666 173,111 0 1,143,288 60% 40% 685,973 457,315 26,534 189,512 50% 50% 94,756 94,756 76,247 124,199 50% 50% 62,100 62,100 371,521 32,750 50% 50% 16,375 16,375 33,282 329,282 50% 50% 164,641 164,641 0 903,271 50% 50% 451,636 451,636 0 929,929 50% 50% 464,965 464,965 0 949,205 50% 50% 474,603 474,603 70 1,275,074 50% 50% 637,537 637,537 10,472,372 1,188,265 746,052 442,213 714,358 71001,183 3,727,388 1 3,273,795 Exhibit 3: Monthly injection and withdrawal volumes 300 250 200 N 150 a 100 50 P/Z for Pool - 6 ♦ 2006 A 2007 ■ 2008 ■ 2009 • 2010 Linear (Eclipse P/Z) • Official P/Z ■ . Eclipse Model P/Z A A 5.100E+08 5.200E+08 5.300E+08 5.400E+08 Cum withdrawl (MSCF) Exhibit # 4: P/Z Plot 5.500E+08 5.600E+08 5.700E+08 -FGPR vs. DATE (2011RLN) FOR vs. DATE (2011 RLA1) -FPR vs -DATE (2011RENJ) 50000 40000 30000 Q L� U U 7; 20000 C� L� 0 10000 0 DATE Black — Monthly averaged gas injection rates Red — Monthly averaged gas production rates Blue — Monthly averaged field pressures Exhibit # 5: Monthly averaged rates and pressure F 220 210 200 190 180 Q 170 d Fr CL 160 150 140