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Home My WebLink About2013 Greater Point McIntyre AreaLisburne Oil Pool Page 1 ASR for Apr ’13 – Mar’14 Prudhoe Bay Unit Lisburne Oil Pool 2014 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2014 is submitted to the Alaska Oil and Gas Conservation Commission in accordance with 20 AAC 25.517. It covers the period between April 1, 2013 and March 31, 2014. Reservoir Management Summary Production and injection volumes for the 12 -month period ending March 31, 2014 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 on-going in the central Alapah (NK- 25), the southern periphery Wahoo (04-350) and the mid-field Wahoo (L5-13 & 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 was one production log obtained from Lisburne wells during the reporting period, L4-31. Neutron logs for April 1, 2013 thru March 31, 2014 are shown in Table 3 Lisburne Oil Pool Page 2 ASR for Apr ’13 – Mar’14 Future Development Plans and Review of Plan of Operations and Development L5 Gas Cap Water Injection 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, 2014 the cumulative volume of seawater injected in L5-29 was 16,835 mbbls. The L5-29 pilot injection to date has demonstrated positive results with confirmed/likely injection water breakthrough occurring in three offset producer wells (L5-28, L5-33 & L5-36). Pressure response has also been observed in offset wells. Three pressure fall-off (PFO) tests have been conducted in the L5-29 gas cap water injection well. 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. Offset well annuli pressures are reported monthly to the commis sion 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 1,271 mbbls of seawater as of March 31, 2014. 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. As of March 31, 2014 the cumulative volume of seawater injected in both these wells was 1,045 mbbls. No confirmed offset producer well response has been observed to date. 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 and has injected 692 mbbls of seawater as of March 31, 2014. Off set producer well pressure response has been observed but no confirmed water breakthroug h has occurred during the reporting period. Lisburne Oil Pool Page 3 ASR for Apr ’13 – Mar’14 Development Drilling No wells were drilled & completed into the Lisburne formation 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 4 ASR for Apr ’13 – Mar’14 Tables & Figures Oil + NGL Gas Water Oil + NGL Gas Water Monthly Cum Monthly Cum Date mstbo mmscf mbw mstbo mmscf mbw mmscf mmscf mbw mbw 4/1/2013 181 3,806 110 172,918 1,846,705 53,814 4,982 1,831,280 611 22,435 5/1/2013 221 4,141 133 173,139 1,850,846 53,947 3,958 1,835,238 181 22,615 6/1/2013 204 3,617 132 173,343 1,854,462 54,079 3,702 1,838,940 526 23,141 7/1/2013 206 3,800 127 173,549 1,858,262 54,207 3,947 1,842,887 286 23,426 8/1/2013 174 3,526 104 173,723 1,861,788 54,311 3,130 1,846,016 193 23,620 9/1/2013 189 3,763 110 173,912 1,865,551 54,421 4,152 1,850,169 494 24,113 10/1/2013 189 3,770 114 174,100 1,869,321 54,535 5,035 1,855,204 656 24,769 11/1/2013 157 2,987 110 174,257 1,872,308 54,645 4,935 1,860,138 761 25,530 12/1/2013 172 2,864 114 174,429 1,875,172 54,759 4,721 1,864,859 731 26,262 1/1/2014 174 3,186 99 174,603 1,878,359 54,858 5,037 1,869,896 783 27,045 2/1/2014 223 4,775 175 174,826 1,883,134 55,033 4,979 1,874,875 740 27,785 3/1/2014 261 5,047 253 175,087 1,888,181 55,286 5,570 1,880,445 912 28,697 Table 1 - Lisburne Monthly Production& Injection Volumes Monthly Production Cumulative Production Gas Injection Water Injection Table 2 - Lisburne Pressure data April 1, 2013 to March 31, 2014 Well Name Survey Date Pressure (psi) (Datum = 8900' SS) L2-32 5/13/13 3334 L5-31 5/30/13 3520 L3-02 6/17/13 3137 L4-14 6/18/13 3024 L4-31 6/18/13 3523 L5-26 6/25/13 3514 L5-05 7/27/13 3177 NK-26 9/4/13 2348 L5-32 9/25/13 3501 L1-14 12/10/13 3439 L3-05 12/20/13 3266 L3-19 12/20/13 2688 Lisburne Oil Pool Page 5 ASR for Apr ’13 – Mar’14 Table 3 - Lisburne Logging Comments/Interpretation Production logs obtained for the following wells: L4-31 PNL/CNL logs were gathered for the following wells: L2-13A L2-16 L2-21A Note: all these PNL/CNL logs were obtained across the Ivishak formation for gas cap monitoring. Lisburne Oil Pool Page 6 ASR for Apr ’13 – Mar’14 Figure 1-Lisburne Location and Status Map Niakuk Oil Pool Page 1 ASR for Apr ’13 – Mar ‘14 Prudhoe Bay Unit Niakuk Oil Pool 2014 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 Nia kuk 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, 2013 through March 31, 2014. a. Progress of Enhanced Recovery 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 s eawater injection continues throughout this reporting period. All producing segments (1, 2, and 3/5) are receiving pressure support f rom water injection. There are 4 active injectors in the Niakuk Pool with an average total injection rate of approximately 24 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 L5-34). 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 564 BOPD for the reporting period with a watercut of about 88%. Water injection in NK-10 averaged approximately 5.0 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 injectors at the start and end of the producing period remained the same, whereas the number of producing wells dropped by one. Producer NK-07A is shut-in for Tubing by Inner Annulus (T x IA) integrity, and producer NK-61A is shut-in for watercut. Plans are to maintain voidage replacement and keep reservoir pressure at the current level. No conversions of producers to injectors are currently planned. Niakuk Oil Pool Page 2 ASR for Apr ’13 – Mar ‘14 Segment 3/5 At the beginning of the reporting period, there were three active producers (NK-08A, NK-09. and NK-29), two active injectors (NK-13 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. The producer NK-12C has been repaired, and will be BOL once the IBP is pulled from the well. Injector NK-15 is shut-in for T x IA communication, and diagnostic wellwork is under evaluation. Injector NK-28 will be patched to fix a very small leak. It will then be POI. Water injection rate for the segment averaged 5.8 mbd for the reporting period. Production and pressure data suggests good communication between injectors and producers. Oil production for the segment averaged 556 BOPD for the reporting period with an average watercut of 91%. 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 5 active producers (NK-20A, NK-21, NK-22A, NK-42 and NK-43), 2 shut-in producers (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. The wellwork to surge NK-19A’s perfs was unsuccessful. The plan forward on this well is under conside ration. NK-62A is shut-in for watercut. NK-21 and NK-43 are shut-in for watercut due to water handling pump going down at the LPC. Injector NK-18 has recently been shut-in so as not to over-pressurize NK-21’s area. Niakuk Oil Pool Page 3 ASR for Apr ’13 – Mar ‘14 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 r eservoir due to faulting and/or stratigraphy. Average oil production from the segment was 1192 BOPD with 93% watercut. Water injection in Segment 2 averaged 13.5 mbd during the reporting period. b. Voidage 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 2013/2014 reservoir pressure surveys. The pressures in Segment 2 and Segments 1, 3, and 5 are generally managed with the original reservoir pressure of approximately 4500 psi as a target/maximum, and the bubble point pressure of 4200 psi as a minimum . The notable exception is L5-34, which has come in at this lower bottomhole pressure for the last decade. d. Results of Production Logging, Tracer and Well Surveys No production logs were run in this section during the reporting period. No tracer surveys were performed during this reporting period. Surface pressure falloffs were done on NK-10, NK-13, and NK-23 during the reporting period to monitor reservoir pressure. 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 329B on December 7, 2006. An oil sample was taken from NK-43 during the reporting period, for geochemical analysis to confirm Niakuk Oil Pool Page 4 ASR for Apr ’13 – Mar ‘14 production allocation splits between the Sag River and Kuparuk Rese rvoirs. The geochemical analysis indicated that the Kuparuk (Combined Niakuk PA) is contributing 100% of the oil production from NK-43, consistent with the increase in water production. f. 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 modification s 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 5 ASR for Apr ’13 – Mar ‘14 Tables and Figures Niakuk Oil Pool Page 6 ASR for Apr ’13 – Mar ‘14 Note: Monthly Production/Injection/Voidage/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. Table 3 – 2013 – 2014 Pressure Survey Data Sw Name Test Date Pres Tool DpthDatum Ss Pres Datum NK-13 7/13/13 483 9,200 4,531 NK-10 7/13/13 407 9,200 4,455 NK-23 7/14/13 352 9,200 4,400 L5-34 8/18/13 3,809 9,200 3,806 NK-22A 8/19/13 4,234 9,200 4,233 NK-27 8/19/13 4,226 9,200 4,226 NK-20A 8/21/13 4,242 9,200 4,242 NK-21 3/6/14 4,229 9,200 4,229 Niakuk pressures Apr 1, 2013 - Mar 31, 2014 Raven Oil Pool Page 1 ASR for Apr ‟12 – Mar „13 Prudhoe Bay Unit Raven Oil Pool 2014 Annual Reservoir Surveillance Report This Reservoir Report has been prepared for submission to the Alaska Oil and Gas Conservation Commission (“AOGCC”) 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, 2013 through March 31, 2014. 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 NK-43 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 W aterflood 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 31 st, 2014 , seawater was used in NK -65A to provide injection support for the Ivishak reservoir at an average rate of 5.0 mbd . Raven Oil Pool Page 2 ASR for Apr ‟12 – Mar „13 Reservoir Management Raven Pool 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 0.3 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 3,549 psi, in NK38A, was taken in December of 2013, 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 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 329B on December 7, 2006. One oil samples was taken from NK-43during 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% of the oil production from NK-43, consistent with the increase seen in water production . f. 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 4 ASR for Apr ‟12 – Mar „13 Tables and Figures Table 1 - Raven Monthly Production & Injection Summary Produced Produced Produced Injected Injected Injected Cum Prod Cum Prod Oil Gas Water Gas Water MI Oil Gas mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr-13 30 10 51 74 0 202 0 2,931 15,344 May-13 31 11 50 80 0 221 0 2,942 15,393 Jun-13 30 10 47 81 0 192 0 2,952 15,440 Jul-13 31 8 53 74 0 49 0 2,960 15,493 Aug-13 31 7 66 69 0 35 0 2,967 15,560 Sep-13 30 8 71 72 0 65 0 2,975 15,630 Oct-13 31 5 58 53 0 121 0 2,980 15,688 Nov-13 30 5 39 50 0 185 0 2,985 15,727 Dec-13 31 9 67 92 0 191 0 2,994 15,794 Jan-14 31 14 75 110 0 192 0 3,008 15,869 Feb-14 28 9 67 97 0 181 0 3,017 15,936 Mar-14 31 10 61 100 0 208 0 3,027 15,997 Apr-11 Year 365 106 705 952 0 1,842 0 0 Table 2 - Raven Monthly Voidage Balance Produced Produced Produced Injected Injected Injected Net Res. Oil Gas Water Gas Water MI Voidage mrvb mrvb mrvb mrvb mrvb mrvb mrvb Apr-13 30 15 31 75 0 204 0 -83 May-13 31 17 29 81 0 224 0 -96 Jun-13 30 15 28 81 0 194 0 -70 Jul-13 31 13 34 75 0 49 0 73 Aug-13 31 11 45 69 0 35 0 90 Sep-13 30 12 48 73 0 66 0 67 Oct-13 31 8 40 54 0 122 0 -20 Nov-13 30 7 26 51 0 187 0 -103 Dec-13 31 14 44 93 0 193 0 -42 Jan-14 31 22 46 111 0 194 0 -14 Feb-14 28 14 44 98 0 183 0 -27 Mar-14 31 15 39 101 0 210 0 -55 Apr-11 0 0 0 0 0 0 0 0 Year 365 163 455 962 0 1,861 0 -281 Note: Negative Net Reservoir Voidage indicates IWR>1 Note: Monthly Production/Injection/Voidage for the Ivishak formation. Raven Oil Pool Page 5 ASR for Apr ‟12 – Mar „13 Table 3 – Raven Ivishak Pressure Survey Data Since March 2005 Sw Name Test Date Pres Tool DpthDatum Ss Pres Datum NK-38A 3/29/05 4,973 9,850 4,973 NK-38A 8/1/05 4,231 9,850 4,237 NK-38A 8/7/05 4,271 9,850 4,273 NK-65A 8/9/05 4,517 9,850 4,463 NK-65A 8/15/05 4,311 9,850 4,295 NK-38A 12/24/05 4,206 9,850 4,210 NK-65A 5/24/06 4,395 9,850 4,414 NK-38A 7/26/06 4,155 9,850 4,155 NK-65A 7/26/06 4,315 9,850 4,400 NK-38A 1/23/07 4,097 9,850 4,104 NK-38A 7/6/07 3,729 9,850 3,758 NK-65A 8/16/07 4,643 9,850 4,827 NK-38A 8/24/07 4,341 9,850 4,370 NK-38A 10/30/07 4,343 9,850 4,379 NK-38A 6/9/08 3,459 9,850 3,543 NK-65A 8/17/08 4,289 9,850 4,379 NK-38A 9/2/08 3,463 9,850 3,507 NK-38A 4/29/09 3,493 9,850 3,537 NK-38A 5/18/09 3,881 9,850 3,928 NK-65A 8/8/09 191 9,850 4,525 NK-38A 8/31/09 4,123 9,850 4,165 NK-65A 6/5/10 200 9,850 4,534 NK-38A 7/6/10 4,090 9,850 4,090 NK-65A 6/4/11 4,472 9,850 4,468 NK-38A 6/6/11 4,402 9,850 4,402 NK-65A 6/27/12 163 9,850 4,497 NK-38A 7/14/12 3,976 9,850 3,976 NK-65A 7/13/13 95 9,850 4,429 NK-38A 12/26/13 3,548 9,850 3,549 Point McIntyre Oil Pool Page 1 ASR for Apr ’13 – Mar ‘14 Prudhoe Bay Unit Pt. McIntyre Oil Pool 2014 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2014 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 317B. It covers the period between April 1, 2013 and March 31, 2014. A. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) Enhanced Recovery Projects During the 12 month period from April 2013 – March 2014, a total of 11.6 BCF of MI (miscible injectant) was injected into P1-16 (3.9 BCF), P1-25 (2. 2 BCF), P2- 09 (0.04 BCF), P2-16 (4.1 BCF), and P2-46 (4.5 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, 2014 are summarized in Table 1. Total Pt. McIntyre hydrocarbon liquid production (oil plus NGL) averaged 18.6 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 15 wells on water injection. Point McIntyre Oil Pool Page 2 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 Tabl e 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 317B. 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) No special monitoring was performed during the reporting period. 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 No development drilling was performed du ring the reporting period. 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. Point McIntyre Oil Pool Page 3 ASR for Apr ’12 – Mar ‘13 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. Drill Sites 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 utilize d 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 4 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 5 ASR for Apr ’12 – Mar ‘13 Tables and Figures Table 1 - Pt McIntyre Monthly Production & Injection Summary Produced Produced Produced Injected Injected Injected Cum Prod Cum Prod Oil Gas Water Gas Water MI Oil Gas mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr-13 30 490 5,441 2,445 3,668 3,116 1,155 444,229 1,154,145 May-13 31 471 4,705 2,619 4,206 3,451 1,219 444,700 1,158,850 Jun-13 30 453 4,431 2,298 3,801 3,726 1,050 445,153 1,163,282 Jul-13 31 574 4,473 2,889 3,784 3,312 987 445,727 1,167,755 Aug-13 31 486 3,961 2,117 3,851 3,016 1,124 446,213 1,171,716 Sep-13 30 566 5,113 2,298 3,965 2,737 1,837 446,779 1,176,829 Oct-13 31 586 6,058 2,714 3,858 2,718 1,811 447,365 1,182,887 Nov-13 30 571 6,097 2,754 4,010 2,888 1,061 447,936 1,188,984 Dec-13 31 554 6,211 2,602 4,141 2,804 1,415 448,490 1,195,195 Jan-14 31 522 6,164 2,470 4,389 2,984 1,439 449,011 1,201,359 Feb-14 28 456 4,612 2,292 3,647 2,693 866 449,468 1,205,971 Mar-14 31 528 5,162 2,647 3,984 3,025 810 449,996 1,211,133 Apr-11 Year 365 6,257 62,429 30,147 47,303 36,471 14,773 Table 2 - Pt McIntyre Monthly Voidage Balance Produced Produced Produced Injected Injected Injected Net Res. Oil Gas Water Gas Water MI Voidage mrvb mrvb mrvb mrvb mrvb mrvb mrvb Apr-13 30 682 3,458 2,482 2,503 3,163 716 240 May-13 31 655 2,966 2,658 2,870 3,503 756 -848 Jun-13 30 630 2,789 2,333 2,593 3,782 651 -1,275 Jul-13 31 798 2,755 2,933 2,582 3,362 612 -70 Aug-13 31 676 2,451 2,149 2,628 3,061 697 -1,110 Sep-13 30 788 3,195 2,333 2,706 2,778 1,139 -308 Oct-13 31 816 3,830 2,755 2,632 2,759 1,123 887 Nov-13 30 794 3,864 2,796 2,736 2,931 658 1,129 Dec-13 31 770 3,951 2,641 2,826 2,846 877 813 Jan-14 31 726 3,935 2,507 2,995 3,029 892 252 Feb-14 28 635 2,911 2,326 2,489 2,734 537 112 Mar-14 31 734 3,249 2,687 2,718 3,071 502 379 Apr-11 0 0 0 0 0 0 0 0 Year 365 8,703 39,354 30,599 32,277 37,018 9,160 201 Note: Negative Net Reservoir Voidage indicates IWR>1 Point McIntyre Oil Pool Page 6 ASR for Apr ’12 – Mar ‘13 Well Name Survey Date Pressure (psi) (Datum = 8900' SS) P1-13 4/12/2013 4105 P1-06 5/18/2013 4107 P1-20 6/18/2013 4000 P2-22A 6/23/2013 4356 P2-49 6/24/2013 4280 P2-21 6/25/2013 4252 P2-48 6/25/2013 4389 P2-03 6/26/2013 4170 P2-07 6/26/2013 4173 P2-40 6/26/2013 4192 P2-52 6/27/2013 4354 P2-45B 6/29/2013 4440 P1-24 7/7/2013 4187 P2-17 7/25/2013 4354 P2-36A 8/13/2013 4355 April 1, 2013 to March 31, 2014 Table 3 - Pt. McIntyre Pressure data Point McIntyre Oil Pool Page 7 ASR for Apr ’12 – Mar ‘13 Table 4 – 2013-2014 Production Profiles Point McIntyre Oil Pool Page 8 ASR for Apr ’12 – Mar ‘13 Table 5 – 2013-2014 Injection Profiles Point McIntyre Oil Pool Page 9 ASR for Apr ’12 – Mar ‘13 Table 6 – 2013-2014 Gas Cap Monitoring Surveys None acquired during the reporting period Point McIntyre Oil Pool Page 10 ASR for Apr ’12 – Mar ‘13 Figure 1 Pt. McIntyre Well Location Map Point McIntyre Oil Pool Page 11 ASR for Apr ’12 – Mar ‘13 PM2 Approximate Scale 0 1Miles Prudhoe Bay Existing Pipelines Pipelines for EOR PM1 LG1 L1 CCP CGF L2 L3 L5 NK L4 LPC Figure 2. Drill Site and Pipeline Configuration GC1* * GC1 location not to scale Figure 3