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Home My WebLink About2012 Greater Point McIntyre AreaZE BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 June 13, 2013 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7t' Ave, Suite 100 Anchorage, AK 99501 Re: Prudhoe Bay Unit GPMA Annual Reservoir Reports April 1, 2012 — March 31, 2013 Dear Chair Foerster: BP Exploration Alaska (BPXA) as operator of the Prudhoe Bay Unit submits herewith the Annual Reservoir Surveillance Reports for Greater Point McIntyre Area (GPMA) Oil Pools covering the time period from April 1, 2012 through March 31, 2013. These Annual Reservoir Reports were prepared in accordance with the latest conservation orders for each pool. We look forward to a further discussion and review of the data contained herein at the GPMA Field Review Presentation that is scheduled for June 25, 2013 at 2:00 pm in the BP Building, Conference Room 146. If you have any questions regarding the reports or the upcoming presentation please contact Eko Apolianto at 564-4569 or through email at eko.apolianto@bp.com. Respectfully, Katrina Cooper Head of Base Management Alaska Reservoir Development, BPXA 564-4212 cc: Mr. John Schultz, ConocoPhillips Alaska, Inc. Mr. Gerry Smith, ExxonMobil Alaska, Production Inc. Mr. Paul Ayers, Chevron USA Ms. Kyle Smith, Division of Oil and Gas Mr. Dave Roby, Alaska Oil and Gas Conservation Commission Mr. Jeff Spatz, BPXA Ms. Judy Buono, BPXA Ms. Susan Kent, BPXA Mr. R. L. Skillern, BPXA r s m Prudhoe Bay Unit Lisburne Oil Pool 2013 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2013 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with 20 AAC 25.517. It covers the period between April 1, 2012 and March 31, 2013. Reservoir Management Summary Production and injection volumes for the 12 -month period ending March 31, 2013 are summarized in Table 1. Oil production volumes include allocated crude oil, condensate and NGL production. Current well locations are shown in Figure 1. Oil recovery from the Lisburne reservoir continues under gas cap expansion supported by gas injection at LGI pad and water injection at L5-29. In the Central area, pressure support is supplemented by weak aquifer influx. Pilot seawater injection projects have been initiated in the central Alapah (NK - 25), the southern periphery Wahoo (04-350) and the mid -field Wahoo (1-5-13 & L5-15) areas. Reservoir Pressure Surveys within the Pool A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Results and Analysis of Production Logging Surveys There were two production logs obtained from Lisburne wells during the reporting period, L1-09 and L1-21. Neutron logs for April 1, 2012 thru March 31, 2013 are shown in Table 3 Lisburne Oil Pool Page 1 ASR for Apr '12 — Mar' 13 Future Development Plans and Review of Plan of Operations and Development L5 Gas Cap Water Infection Surveillance The L5 GCWI pilot project commenced injection in July of 2008. The initial injection rate was 2 mbd, and over time has been gradually increased to approximately 17 mbd. As of March 31, 2013 the cumulative volume of seawater injected in L5-29 was 12,593 mbbls. The L5-29 pilot injection to date has demonstrated positive results with confirmed injection water breakthrough occurring in one offset producer well (1-5-36). Pressure response has been observed in offset wells. Three pressure fall-off (PFO) tests have been conducted in the 1-5-29. The PFO analyses show a constant pressure boundary, and skin values of between -3.6 and -3.8. Based on these results, it is inferred that no fracture extension is occurring. Pressure fall-off testing will continue to monitor injection well behavior. Offset well annuli pressures are reported monthly to the commission by the BP North Slope Well Integrity Engineer via the Monthly Injection Report sent to the AOGCC. Waterflooding Pilot Projects A review of the Lisburne development plan identified water injection as a mechanism to provide additional pressure support in the Lisburne reservoirs. A new grass roots injection well, 04-350, was completed on the southern periphery of the Wahoo formation in November 2011 and has injected 270 mbbls of seawater as of March 31, 2013. No breakthrough has been observed in the offset producers and pressure monitoring continues. Another pilot water injection project has been undertaken in the mid -field area. Wahoo production wells L5-15 and L5-13 were converted to seawater injection service in March 2013. In addition, a pilot water injection project into the Alapah formation has been initiated from the Niakuk Heald Point pad. Alapah producer NK -25 was converted to seawater injection service in March 2013. Lisburne Oil Pool T)aCYP ') ASIS for Apr '12 — Mar' 13 Development Drilling No wells were drilled during the reporting period. Support Facilities Lisburne will continue to share North Slope infrastructure with the Point McIntyre and Niakuk fields. Six wells from the IPA can produce to the LPC as part of the L2 Re-route Project: L2 -03A, L2 -07A, L2 -08A, L2 -11A, L2 -13A and L2 -18A. Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs, will continue to be allocated to the Lisburne Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. There is a test separator at each Lisburne Drill Site. Gas Sales The timing of Lisburne gas sales is dependent upon market demand and the availability of a transportation system. Prior to initiation of gas sales, Lisburne produced gas (other than gas extracted as NGLs and blended with crude oil for shipment to market) will be used or consumed for Unit Operations, or injected back into the Lisburne formation. Lisburne Oil Pool Page 3 ASR for Apr '12 — Mar' 13 Tables & Figures Table 2 - Lisburne Pressure data April 1, 2012 to March 31, 2013 Well Name Table 1 - Lisburne Monthly Production& Injection Volumes Pressure (psi). (Datum = 8900 SS) 1-2-1413 5/10/2012 Monthly Production Cumulative Production I Gas Injection Water Injection L1-09 ,Oil + NGLI Gas Water Oil + NGL Gas Water I Monthly Cum Monthly I Cum Date mstbo mmscf mbw mstbo mmscf mbw I mmscf mmscf mbw mbw 4/1/2012 231 3,667 185 170,792 1,806,085 52,299 5,171 1,779,969 520 16,719 5/1/2012 159 2,538 100 170,951 1,808,623 52,399 4,038 1,784,007 588 17,307 6/1/2012 177 2,593 117 171,128 1,811,216 52,516 3,435 1,787,442 506 17,813 7/1/2012 120 2,965 35 171,247 1,814,181 52,551 1,961 1,789,403 461 18,273 8/1/2012 148 3,237 115 171,396 1,817,417 52,665 4,103 1,793,506 105 18,378 9/1/2012 186 2,743 226 171,581 1,820,160 52,892 4,153 1,797,658 399 18,777 10/1/2012 183 3,764 134 171,764 1,823,924 53,025 5.420 1,803,078 553 19,330 11/1/2012 197 3,878 133 171,962 1,827,802 53,158 5,733 1,808,811 572 19,902 12/1/2012 214 4,089 157 172,176 1,831,891 53,315 5,336 1,814,146 516 20,418 1/1/2013 203 3,788 135 172,379 1,835,679 53,450 5,242 1,819,388 404 20,822 2/1/2013 136 2,621 1171 172,515,1-,838,3001 53,5671 2,269 1,821,657 426 21,248 3/1/20131 2221 4,598 1371 172,737 1,842,898 53,7041 4,641 1,826,298 576 21,824 Table 2 - Lisburne Pressure data April 1, 2012 to March 31, 2013 Well Name Survey Date Pressure (psi). (Datum = 8900 SS) 1-2-1413 5/10/2012 2246 Ll -21 5/28/2012 2799 L1-09 5/30/2012 3075 L5-36 8/9/2012 3628 L5-23 8/20/2012 3415 1-5-12 8/22/2012 3197 L3-12 8/31/2012 3124 L1-01 11/16/2012 2871 1-4-03 11/16/2012 1970 Ll -14 11/17/2012 3406 1-3-22 11/23/2012 2913 NK -25 12/9/2012 2246 NK -26 12/9/2012 2185 1-4-30 12/13/2012 1978 L5-33 12/22/2012 3626 1-3-15 12/25/2012 2405 Lisburne Oil Pool Page 4 ASR for Apr '12 - Mar' 13 Table 3 - Lisburne Logging Production logs obtained for the following wells: L1-09 L1-21 PNL/CNL logs were gathered for the following wells: L1-02 L2-16 L2-24 L2-32 L3-11 L3-12 L5-05 Note: all these PNUCNL logs were obtained across the Ivishak formation for gas cap monitoring. Lisburne Oil Pool Page 5 ASR for Apr '12 — Mar' 13 <-5 Cr 3, -3 2a Updated: 5J2013 Cu entVUW statin v� _;O 2s Q,5 110 E � UrT.IA:-IA =o DNO.YXr Droajo--_r U bb as Key • Full time producer G Cycle producer • Shut-in Injector • P &+HJT&.A 3 t 013 • .rte O r w4 4 i Cr 3, -3 2a Updated: 5J2013 Cu entVUW statin v� _;O 2s Q,5 110 E � UrT.IA:-IA =o DNO.YXr Droajo--_r U bb as Key • Full time producer G Cycle producer • Shut-in Injector • P &+HJT&.A Cr 3, -3 2a Updated: 5J2013 Cu entVUW statin v� _;O 2s Q,5 110 E � UrT.IA:-IA =o DNO.YXr Droajo--_r U bb as PIA Prudhoe Bay Unit Niakuk Oil Pool 2013 Annual Reservoir Surveillance Report This Annual Reservoir Report has been prepared for submission to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order No. 329 for the Niakuk Oil Pool, as detailed in Administrative Approval No. 329.05, and pursuant to 20 AAC 25.517. This report summarizes the period from April 1, 2012 through March 31, 2013. a. Progress of Enhanced Recove Project Implementation and Reservoir Management Summary The Niakuk waterflood was started in April 1995, in conjunction with the commissioning of permanent facilities at Heald Point, using water from the Initial Participating Area Seawater Treatment Plant. Produced water from the LPC was used between August of 2000 and May 2004. Conversion to seawater injection was completed in September, 2004, and seawater injection continues throughout this reporting period. All producing segments (1, 2, and 3/5) are receiving pressure support from water injection. There are 5 active injectors in the Niakuk Pool with an average total injection rate of approximately 22 mbd for the reporting period. The current injection strategy is to maintain balanced voidage replacement in each segment. Reservoir Management Segment 1 NK -10 is the only injector in this segment and it supports four producers (NK - 07A, NK -27, NK -61A and 1-5-34). The producers in this segment appear to be in good communication with the injector. Brightwater was injected into NK -10 in October 2008 to improve sweep and to date no response has been observed. Production from the segment averaged 575 BOPD for the reporting period with a watercut of about 87%. Water injection in NK -10 averaged approximately 4.0 mbd for the period. Water injection volumes replaced reservoir voidage through the end of 1997 and since then over injection has increased reservoir pressure. The number of production and injection wells at the start and end of the reporting period was the same. Producer NK -07A is shut-in for Tubing by Inner Annulus (T x IA) integrity. Plans are to maintain voidage replacement and keep reservoir pressure at the current level. No conversions of producers to injectors are currently planned. Segment 3/5 At the beginning of the reporting period, there were four producers (NK -08A, NK -09, NK -12C, and NK -29), three active injectors (NK -13, NK -15, and NK - 28), one inactive injector (NK -17), one abandoned well (NK -14A), and one suspended well (NK -11A) in the Segment 3/5 area. During the reporting period NK -15 was shut-in for T x IA communication, and diagnostic wellwork is under evaluation. NK -12A developed T x IA communication at the production packer. Work is in progress to design a barite/sand mixture to restore integrity. Water injection rate for the segment averaged 7.2 mbd for the reporting period. Production and pressure data suggests good communication between injectors and producers. Oil production for the segment averaged 883 BOPD for the reporting period with an average watercut of 88%. Production from this segment began in February 1995 from NK -09 under primary depletion. Reservoir pressure dropped approximately 500 psi during this period but stabilized and increased back to original pressure after water injection startup in May 1997. Plans are to maintain voidage replacement and keep reservoir pressure at the current level. NK -13 and NK -28 were converted to injection service on 4/3/02 and 8/13/01 respectively, to improve both sweep efficiency and voidage replacement. Segment 2 Segment 2 contained 4 active producers (NK -20A, NK -21, NK -42 and NK -43), 3 shut-in producers (NK -22A, NK -19A and NK -62A), 2 active injectors (NK -18, and NK -23) and one inactive injector (NK -16) at the start of the reporting period. Injector NK -16 is shut-in for breakthrough and to optimize recovery in the lower zones in NK -21. NK -19A corrosion quill repair was completed and a single perforation was added in a high perm interval to obtain limited communication to it's offset injector. This did not result in restoring sustained Niakuk Oil Pool Page 2 ASR for Apr 12 — Mar '13 production and a wellwork program is pending to stimulate the perforation. NK -22A was returned to production after recovering multiple fish, and installing a patch across gas lift mandrel #3. Like all other segments in the field, the reservoir management strategy in this segment is to replace the voidage created by hydrocarbon production with water injection. NK -23 was converted to an injector in July of 1995 and had remained on injection supporting the majority of the oil producers in the segment. In July 2007, tubing was replaced in NK -23 which improved the segment's injection efficiency and overall oil production. Over injection continued during the reporting period in NK -18 to attempt to restore the area to original pressure. All producers in Segment 2 have exhibited waterflood response from one or more injectors, but production, pressure, and tracer data clearly show the effects of compartmentalization within the reservoir due to faulting and/or stratigraphy. Average oil production from the segment was 1332 BOPD with 91% watercut. Water injection in Segment 2 averaged10.7 mbd during the reporting period. b. Voida a Balance of Produced and Injected Fluids Tables 1 and 2 detail hydrocarbon production, water injection and resultant voidage data by month for the reporting period. c. Analysis of Reservoir Pressure Surveys Within the Pool Table 3 shows results from the 2012/2013 reservoir pressure surveys. The pressures in Segment 2 and Segments 1, 3, and 5 are generally managed to the original reservoir pressure of approximately 4500 psi. Notable exceptions over the previous reporting period are NK -43 at 4048 psi and NK - 18 at 4198. d. Results of Production Lagging, Tracer and Well Surveys One static production log was run in NK -43 during the reporting period to look for crossflow; none was found. No tracer surveys were performed during this reporting period. Numerous surface pressure falloffs were done during the reporting period to monitor reservoir pressure. Niakuk Oil Pool Page 3 ASR for Apr 12 — Mar `13 e. Special Monitoring NK -43 is a commingled producer which produces from both the Kuparuk and Sag River Reservoirs. The AOGCC approved co -mingled production in NK -43 with production allocated to each reservoir via geo-chemical analysis in Conservation Order 3296 on December 7, 2006. Three oil samples were taken from NK -43, during the reporting period, for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk Reservoirs. The geochemical analysis indicated that the Kuparuk (Combined Niakuk PA) is contributing 95.5% to 100% of the oil production from NK -43 consistent with the increase in water production. If. Future Development Plans Permanent production facilities at Niakuk were commissioned in March 1995. There have been 29 development wells drilled into the Niakuk Oil Pool through the end of the reporting period. Reservoir management activity in the Niakuk pool includes: 1) selective perforating and profile modifications to manage conformance of the waterflood, 2) production and injection profile logging to determine current production and injection zones for potential profile modifications, material balance calculations, and effective full field modeling, 3) pressure surveys to monitor flood performance and 4) analysis of production, GOR, and WOR trends to highlight poorer performing wells for possible intervention activity. Niakuk Oil Pool Page 4 ASR for Apr '12 - Mar 13 Tables and Figures Note: Monthly Production/I njectionNoidage/Pressure data (Tables 1 & 2) do not include the production results from NK -38A well drilled to Ivishak (Raven) formation or injection from the NK -65A injector which supports NK -38A. They are subject to a separate Raven Oil Pool Annual Reservoir Report. Niakuk Oil Pool Page 5 Table 1 - Niakuk Monthly Production & Injection Summary Produced Produced Produced Injected Injected Injected Cum Prod Cum Prod Oil Gas Water Gas Water MI Oil Gas mrvb mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr -12 30 109 90 769 0 692 0 91,966 81,662 May -12 31 54 56 440 0 716 0 92,020 81,718 Jun -12 30 73 63 591 0 421 0 92,093 81,781 Jul -12 31 22 35 229 0 526 0 92,115 81,816 Aug -12 31 80 88 923 0 172 0 92,195 81,904 Sep -12 30 731 71 820 01 524 0 92,268 81,975 Oct -12 31 60 64 396 01 709 0 92,329 82,039 Nov -12 30 100 93 830 0 825 0 92,428 82,132 Dec -12 31 112 104 972 0 851 0 92,541 82,236 Jan -13 31 117 90 966 0 971 0 92,657 82,326 Feb -13 28 110 138 977 0 855 0 92,7671 82,464 Mar -13 31 111 120 951 0 782 0 92,8781 82,584 0 8,124 0 2,364 Year 365 1,020 1,012 8,8641 01 8,043 0 Note: Monthly Production/I njectionNoidage/Pressure data (Tables 1 & 2) do not include the production results from NK -38A well drilled to Ivishak (Raven) formation or injection from the NK -65A injector which supports NK -38A. They are subject to a separate Raven Oil Pool Annual Reservoir Report. Niakuk Oil Pool Page 5 Table 2 - Niakuk Monthly Voidage Balance Produced Produced I Produced I Injected lni-e-c-t-e—dT Injected I Net Res. Oil Gas Water Gas Water MI Voidage mrvb mrvb mrvb mrvb mrvb mrvb mrvb Apr -12 30 141 10 776 0 699 0 229 May -12 31 70 13 444 0 723 0 -196 Jun -12 30 95 9 597 0 425 0 275 Jul -12 31 28 14 231 0 531 0 -259 Aug -12 31 105 22 932 0 174 0 885 Sep -12 30 95 14 828 0 529 0 408 Oct -12 31 78 15 400 0 716 0 -222 Nov -12 30 129 16 838 0 833 0 151 Dec -12 31 146 18 982 0 860 0 286 Jan -13 31 1521 6 976 0 980 0 154 Feb -13 28 143 42 987 0 863 0 308 Mar -13 31 144 30 961 0 790 0 344 0 0 0 0 0 0 0 0 Year 365 1,326 209 8,952 0 8,124 0 2,364 Note: Negative Net Reservoir Voidage indicates IWR>1 Note: Monthly Production/I njectionNoidage/Pressure data (Tables 1 & 2) do not include the production results from NK -38A well drilled to Ivishak (Raven) formation or injection from the NK -65A injector which supports NK -38A. They are subject to a separate Raven Oil Pool Annual Reservoir Report. Niakuk Oil Pool Page 5 Table 3 - 2012 - 2013 Pressure Survey Data Table 3 - Niakuk Pressure data April 1, 2012 to March 31, 2013 Well Name Survey Date Pressure (psi) (Datum = 9200' SS) NK -13 6/4/2012 4620 NK -28 6/4/2012 4681 NK -23 6/27/2012 4576 NK -18 6/27/2012 4198 NK -10 6/27/2012 4529 NK -20A 7/9/2012 4614 NK -27 7/13/2012 4317 NK -15 8/7/2012 4607 NK -43 10/23/2012 4048 NK -23 1 10/26/2012 4448 NK -22A 1 11/18/2012[ 4634 Niakuk Oil Pool Page 6 ASR for Apr 12 — Mar 13 n CD Prudhoe Bay Unit Pt. McIntyre Oil Pool 2013 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2013 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 317B for the Pt. McIntyre Oil Pool. This report summarizes surveillance data and analysis and other information as required by Rule 15 of Conservation Order 31713. It covers the period between April 1, 2012 and March 31, 2013. A. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) Enhanced Recovery Projects During the 12 month period from April 2012 — March 2013, a total of 11.6 BCF of MI (miscible injectant) was injected into P1-16 (1.7 BCF), P1-25 (.02 BCF), P2-09 (3.3 BCF), P2-16 (5.6 BCF), and P2-46 (.9 BCF). Ten of the 15 waterflood/EOR patterns have had MI injection to date. Reservoir Management Summary Production and injection volumes for the 12 -month period ending March 31, 2013 are summarized in Table 1. Total Pt. McIntyre hydrocarbon liquid production (oil plus NGL) averaged 17.2 mbd. Current well locations are shown in Figure 1. The dominant oil recovery mechanisms in the Pt. McIntyre field are waterflooding and miscible gas injection in the down -structure area north of the Terrace Fault and gravity drainage in the up -structure area referred to as the Gravity Drainage (GD) Area. Gas injection commenced in the gas cap with field startup to replace voidage and promote gravity drainage. The waterflood was in continuous operation during the reporting period with 16 wells on water injection. Point McIntyre Oil Pool Page 1 ASR for Apr '12 — Mar `13 B. Voidage Balance by Month of Produced and Injected Fluids (Rule 15 b) Monthly production and injection surface volumes are summarized in Table 1. A voidage balance of produced fluids and injected fluids for the report period is shown in Table 2. As summarized in these analyses, monthly voidage is targeted to be balanced with injection. C. Analysis of Reservoir Pressure Surveys within the Pool (Rule 15 c) Reservoir pressure monitoring is performed in accordance with Rule 12 of Conservation Order 31713. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. D. Results and Analysis of Production & Injection Logging Surveys (Rule 15 d) Interpreted results of production and injection logs are reported in Tables 4 and 5. Surveys were obtained using conventional cased -hole production logging tools including spinner, temperature, pressure, and fluid identification. E. Results of Any Special Monitoring (Rule 15 e) An RST log was run in P2 -01A on 7-13-12 ;results are contained in Table 6. F. Future Development Plans and Review of Plan of Operations and Development (Rule 15 f & g) Production Pt. McIntyre production is processed at the LPC and until November 12th 2011 was also processed at the GC -1 Gathering Center facilities. Currently the 36" three phase line connecting PM2 with GC -1 is shut-in due to the integrity status of the line and production is limited by both gas and water handling limits at the LPC facilities. Production from some areas of the field is also limited by injection well capacity and reservoir management constraints. Development Drilling P2-39 and P2 -51A were completed and placed on production in May of 2012. P2 -51A is a sidetrack of P2-51 due to high watercut. P2-39 is a replacement well for a surface casing leak in P2-32, and is a grass roots well. Point McIntyre Oil Pool Page 2 ASIR for Apr '12 — Mar'13 There currently are a total of 26 well penetrations drilled from DS-PM1 including sidetracked, P&A and suspended wells. There are a total of 76 well penetrations drilled from DS-PM2. An additional water/MI injector (P1-25) is located at the West Dock staging area. Pipelines Figure 2 shows the existing pipeline configuration together with the miscible injectant distribution pipelines from LPC and CGF to the Pt. McIntyre drill sites. Lisburne Production Center (LPC) During the 12 -month reporting period the LPC continued to provide produced water for injection at Point McIntyre. Additional produced water is provided from FS1 to LPC for injection at Pt. McIntyre. The LPC also provides up to 45 mmscfd of miscible injectant when the EOR compressor is on line. Brill Sitpc In March of 2004, the project to route some Pt. McIntyre production to GC -1 was completed. All wells at drillsite PM2 could be flowed to either the LPC (high pressure system) or to GC -1 (low pressure system). PM1 wells can only flow to the LPC. This project lowered wellhead pressures for the PM2 wells flowing to GC -1 by approximately 400 psi and utilized approximately 80 MB/D of available water handling capacity at GC -1. On November 12th 2011 the 36" line from PM2 to GC -1 was shut-in due to the integrity status of the line. Inspection and potential repair of the pipeline are being evaluated. Support Facilities Pt. McIntyre will continue to share North Slope infrastructure with the Lisburne Participating Area ("LPA") and the IPA to minimize duplication of facilities. Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs, will continue to be allocated to the Pt. McIntyre Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. There is a test separator at Drill Site PM1 and two test separators at Drill Site PM2. Point McIntyre Oil Pool Page 3 ASR for Apr '12 — Mar '13 Gas Sales The timing of Pt. McIntyre gas sales is dependent upon market demands and the availability of a transportation system. Prior to initiation of gas sales, Pt. McIntyre produced gas (other than gas extracted as NGLs and blended with crude oil for shipment to market) will be used or consumed for Unit Operations, or injected into the Pt. McIntyre or another formation underlying the Unit Area. Point McIntyre Oil Pool Page 4 ASR for Apr '12 — Mar `13 Tables and Figures Point McIntyre Oil Pool Page 5 A,' Table 1 - Pt McIntyre Monthly Production & Injection Summary Produced Produced Produced Injected Injected Injected Cum Prod Cum Prod Injected I Net Res. Oil Gas Water Gas Water MI Oil Gas MI Voidage mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr -12 30f 534 6,351 2,448 4,312 3,151 1,365 438,504 1,089,705 May -12 31 467 6,130 1,780 4,332 3,119 1,299 438,971 1,095,835 Jun -12 30 503 5,128 1,753 3,564 2,962 913 439,473 1,100, 963 Jul -12 31 385 2,902 1,830 3,155 2,847 742 439,858 1,103, 865 Aug -12 31 515 5,424 2,808 3,9721 3,611 259 440,373 1,109, 289 Sep -12 30 550 5,711 2,710 4,0201 3,022 1,072 440,923 1,115, 000 Oct -12 311 439 6,034 1,623 4,6211 3,073 1,073 441,362 1,121,034 Nov -12 30 504 6,323 2,259 4,082 3,410 815 441,866 1,127, 357 Dec -12 31 492 6,079 2,098 4,254 3,504 958 442,358 1,133, 436 Jan -13 31 539 6,573 2,404 4,517 3,463 1,096 442,897 1,140,009 Feb -13 28 384 3,466 1,839 3,027 3,066 991 443, 281 1,143, 476 Mar -13 31 457 5,228 2,135 4,6441 3,054 1,020 443,739 1,148, 704 633 -767 0 0 0 0 0 0 Year 3651 5,769 65,351 25,688 48,5001 38,282 11,604 38,856 Point McIntyre Oil Pool Page 5 A,' Table 2 - Pt McIntyre Monthly Voidage Balance Prod -mc -ed -1 Produced I Produced I Injected I Injected I Injected I Net Res. -61 -1 Water Gas Water MI Voidage mr%b I mrvb mrvb mrvb mrvb mrvb mm Apr -12 30 743 4,057 2,485 2,942 3,199 846 298 May -12 31 649 3,941 1,807 2,956 3,166 805 -531 Jun -12 30 699 3,239 1,779 2,432 3,006 566 -288 Jul -12 31 536 1,780 1,857 2,153 2,890 460 -1,329 Aug -12 31 716 3,434 2,851 2,710 3,665 161 465 Sep -12 30 765 3,612 2,751 2,743 3,067 665 653 Oct -12 31 611 3,889 1,647 3,153 3,119 665 -790 Nov -12 30 701 4,053 2,293 2,785 3,462 505 295 Dec -12 31 684 3,893 2,130 2,9U 3,557 594 -346 Jan -13 31 750 4,206 2,440 3,082 3,515 680 120 Feb -13 28 534 2,166 1,867 2,065 3,112 615 -1,225 Mar -13 31 636 3,330 2,167 3,169 3,099 633 -767 0 0 0 0 0 0 0 0 Year 365 8,025 41,600 26,073 33,094 38,856 7,195 -3,446 Note: Negatie Net Reserwir Voidage indicates IWR-1 Point McIntyre Oil Pool Page 5 A,' Table 3 - Pt. McIntyre Pressure data April 1, 2012 to March 31, 2013 Table 2 - Pt McIntyre Monthly Voida a Balance P2 -511A 4/21/2012 4161 P2-5013 Produced Produced Producedl Injected Injected Injected Net Res. 4290 P2-03 Oil Gas Water Gas Water MI Voida e 4122 P2-07 mrvb mrvb mrvb mrvb mrvb mrvb mrvb Apr -11 30 949 3,383 4,679 3,138 5,434 502 -62 May -1 1 31 817 2,502 4,521 1,613 5,850 551 -174 Jun -11 30 506 2,147 2,468 1,673 3,397 314 -264 Jul -11 31 252 992 930 816 3.088 135 -1865 Au -11 31 762 3,113 3,115 2,864 5,150 919 -1,943 Sep -11 30 1,058 4,146 4,739 2,789 5,315 674 1,163 Oct -11 31 871 3,832 3,849 3,049 5,215 724 -436 Nov -11 30 781 3,239 3,519 3,214 5,268 697 -1,641 Dec -11 31 782 3,411 3,146 3,144 5,268 766 -1,841 Jan -12 31 772 3,692 3,045 3,280 4,991 1,059 -1,822 Feb -12 29 752 3,341 2,934 2,914 4,234 913 -1,034 Mar -12 31 810 3,568 2,714 3,100 3,748 839 -596 Year 366 9,110 37,364 39,658 31,596 56,957 8,095 -10,515 Note: Negative Net Reservoir Voidage indicates 1WR>1 Table 3 - Pt. McIntyre Pressure data April 1, 2012 to March 31, 2013 Pressure (psi) Well Name Survey Date (Datum = 8900' SS) P2 -511A 4/21/2012 4161 P2-5013 6/25/2012 4355 P2-21 6/26/2012 4204 P2-17 7/6/2012 4290 P2-03 7/9/2012 4180 P 1-06 7/10/2012 4113 P 1-24 7/11/2012 4122 P2-07 7/11/2012 4179 P2-4513 7/13/2012 4403 132-48 7/16/2012 4413 P 1-20 7/17/2012 4113 P 1-13 7/18/2012 4155 P2-39 7/25/2012 4173 P2-40 7/27/2012 4197 132-49 8/1/2012 4175 132-59A 9/30/2012 4185 P2 -36A 3/15/2013 4270 Point McIntyre Oil Pool ASR for Apr 12 - Mar '13 Table 4 - 2012-2013 Production Profiles (none acquired in the April 2012 - March 2013) Table 5 — 2012-2013 Injection Profiles (none acquired in the April 2012 - March 2013) Table 6 - 2012-2013 Gas Cap Monitoring Surveys Well I Log Data P2 -01A 1 7/31/13 GOC Previous Previous Previous Type Depth Log Type GOC Log (SS) Date Log Depth RST Ambiguous 4/21/03 RST 8829' results i Change Point McIntyre Oil Pool Page 7 ASR for Apr '12 — Mar '13 Figure 1 Pt. McIntyre Well Location Map ,North Expansion Area 1Mile < + 1 ADL 3$994r Original PMPA Point McIntyre Oil Pool m All 389945 77 PMPA Expansion WBPA Contraction SE Expansion ADL 34827 ADL 34626 ASR for Apr '12 — Mar `13 Figure 2. Drill Site and Pipeline Configuration Point McIntyre Oil Pool Page 9 ASR for Apr '12 — Mar `13 c� Prudhoe Bay Unit Raven Oil Pool 2013 Annual Reservoir Surveillance Report This Reservoir Report has been prepared for submission to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 570 for the Raven Oil Pool and pursuant to 20 AAC 25.517. This report summarizes surveillance data and analysis and other information as required by Rule 10 of Conservation Order 570. It covers the period from April 1, 2012 through March 31, 2013. Raven is a small oil and gas field in the Permo-Triassic interval (Ivishak and Sag River) located beneath the Niakuk field (Kuparuk reservoir). Two oil wells, NK -38A (Ivishak producer) and NK -43 (commingled Kuparuk and Sag River producer), produce from the Raven field. NK -65A is the only injector in the Raven field and it provides injection support for the Ivishak producer, NK -38A. Production from the Raven field started in March 2001 with the completion of the Sag River in NK -43.. The Sag River was subsequently isolated with a cast iron bridge plug (CIBP) and the well was perforated in the Kuparuk reservoir and produced until 1/2/06 when the CIBP was removed and the Sag River commingled with the Kuparuk. Production from NK -38A began in March 2005 from the Ivishak reservoir. Water injection in NK -65A, providing pressure support in the Ivishak reservoir, started in October 2005. a. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary Waterflood at Raven began in October 2005, using water from the Initial Participating Area Seawater Treatment facilities. From the beginning of the reporting period until March 31St, 2013, seawater was used in NK -65A to provide injection support for the Ivishak reservoir at an average rate of 5.6 mbd. Raven Oil Pool Page 1 ASR for Apr 12 — Mar 13 Reservoir Management Raven Pnnl NK -65A is the only injector in the Raven field and it supports the Ivishak producer, NK -38A. The NK -38A producer exhibits good communication with the injector. Oil Production from the Raven pool averaged 0.4 mbd for the reporting period. The reservoir management plan is to replace the voidage created by hydrocarbon production with water injection and keep reservoir pressure at levels that will optimize oil production. Periods of increased offtake and high voidage replacement have been utilized over the reporting period to optimize production. No conversions of producers and injectors are currently planned. b. Voidage Balance of Produced and Injected Fluids Tables 1 and 2 detail the production, injection and calculated voidage by month for the reporting period. c. Analysis of Reservoir Pressure Surveys Within the Pool Static pressure surveys have been conducted on the wells in the field. Table 3 shows results of static reservoir pressure surveys conducted on the wells since March 2005. The most recent static reservoir pressure of 3,976 psi, in NK38A, was taken in July of 2012, and indicates a reservoir pressure similar to earlier years when the well has shorter shut-in periods. It has been shown that with extensive shut-in periods, pressure will continue to build in NK -38A. It is inferred from this response that baffling exists between the injector and producer. d. Results of Production Logging, Tracer and Well Surveys No logs were obtained in Raven during the reporting period. Raven Oil Pool Page 2 ASR for Apr '12 — Mar `13 e. Special Monitoring NK -43 is a commingled producer which produces from both the Kuparuk and Sag River Reservoirs. The AOGCC approved co -mingled production in NK -43 with production allocated to each reservoir via geo-chemical analysis in Conservation Order 3296 on December 7, 2006. Three oil samples were taken from NK -43, during the reporting period, for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk Reservoirs. The geochemical analysis showed that the Sag (Raven PA) is contributing 0 to 5% of the oil production from NK -43, consistent with the increase seen in water production. If. Future Development Plans No development wells were drilled in the Raven field during the reporting period. Reservoir management activity in the Raven pool includes: 1) imposing optimal drawdown on the reservoir to prevent water coning from underlying aquifer and gas coning from overlying gas cap 2) optimum injection rate selection to ensure sweep efficiency toward the producer, 3) pressure surveys to monitor flood performance and 4) analysis of production, GOR, and WOR trends to highlight poorer performing wells for possible intervention activity. Raven Oil Pool Page 3 ASR for Apr 12 — Mar 13 Tables and Figures Note: Monthly Production/InjectionNoidage for the Ivishak formation. Raven Oil Pool Page 4 ASR for Apr 12 — Mar `13 Table 1 - Raven Monthly Production & Injection Summary Produced Produced Produced I Produced Injected Injected Injected Cum Prod Cum Prod Oil Oil Gas Water Gas Water MI Oil Gas m rvb m rvb mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr -12 30 31 102 173 0 191 0 2,790 14,720 May -12 31 23 65 111 0 203 0 2,813 1 14,784 Jun -12 30 12 49 86 0 161 0 2,825 14,834 Jul -12 31 2 8 47 0 154 0 2,826 14,842 Aug -12 31 12 52 100 0 42 0 2,839 14,894 Sep -12 30 15 78 102 0 154 0 2,854 14,972 Oct -12 31 13 74 127 0 182 0 2,867 15,046 NoNF12 30 13 56 78 0 186 0 2,880 15,102 Dec -12 31 10 50 76 0 194 0 2,890.. 15,153 Jan -13 31 10 43 74 0 216 0 2,900 15,196 Feb -13 28 9 47 78 0 191 0 2,909 15,243 Mar -13 31 12 49 80 0 173 0 2,921 15,292 2,067 0 -286 Year 365 1621 674 1,131 01 2,0461 0 0 Note: Monthly Production/InjectionNoidage for the Ivishak formation. Raven Oil Pool Page 4 ASR for Apr 12 — Mar `13 Table 2 - Raven Monthly Voidage Balance Produced Produced Produced Injected Injected Injected Net Res. Oil Gas Water Gas Water MI Voidage m rvb m rvb m rvb m rvb m rvb m M m rvb Apr -12 301 481 54 175 0 193 0 84 May -12 31 35 32 112 0 205 0 -27 Jun -12 30 19 28 86 0 163 0 -30 Jul -12 31 2 5 48 0 155 0 -100 Aug -12 31 19 30 101 0 42 0 108 Sep -12 30 23 48 103 0 155 0 18 Oct -12 31 21 46 128 0 183 0 12 Now12 30 20 33 79 0 188 0 -56 Dec -12 31 16 31 77 0 196 0 -73 Jan -13 31 15 25 75 0 218 0 -104 Feb -13 28 14 29 78 01 193 0 -72 Mar -13 31 19 28 81 0 175 0 -47 0 0 0 0 0 0 0 0 Year 365 249 389 1,143 0 2,067 0 -286 Note: Negative Net Reservoir Voidage indicates IWR>1 Note: Monthly Production/InjectionNoidage for the Ivishak formation. Raven Oil Pool Page 4 ASR for Apr 12 — Mar `13 Table 3 — Raven Ivishak Pressure Survey Data Since March 2005 Sw Name Test Date Pres Sury Datum Ss Pres Datum NK -38A 3/29/2005 4973 9850 4973 NK -38A 8/1/2005 4237 9850 4237 NK -38A 8/7/2005 4273 9850 4273 NK -65A 8/9/2005 4463 9850 4463 NK -65A 8/15/2005 4295 9850 4295 NK -38A 12/24/2005 4210 9850 4210 NK -65A 5/24/2006 4414 9850 4414 NK -38A 7/26/2006 4155 9850 4155 NK -65A 7/26/2006 4400 9850 4400 NK -38A 1/23/2007 4104 9850 4104 NK -38A 7/6/2007 3758 9850 3758 NK -65A 8/16/2007 4827 9850 4827 NK -38A 8/24/2007 4370 9850 4370 NK -38A 10/30/2007 4379 9850 4379 NK -38A 6/9/2008 3543 9850 3543 NK -65A 8/17/2008 4379 9850 4379 NK -38A 9/2/2008 3507 9850 3507 NK -38A 4/29/2009 3537 9850 3537 NK -38A 5/18/2009 3928 9850 3928 NK -65A 8/8/2009 4525 9850 4525 NK -38A 8/31/2009 4165 9850 4165 NK -65A 6/5/2010 4534 9850 4534 NK -38A 7/6/2010 4090 9850 4090 NK -65A 6/4/2011 4468 9850 4468 NK -38A 6/6/2011 4402 9850 4402 NK -65A 6/27/2012 4497 9850 4497 NK -38A 7/14/2012 3976 9850 3976 Raven Oil Pool Page 5 ASR for Apr 12 — Mar `13