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Home My WebLink About2014 Greater Point McIntyre AreaLisburne Oil Pool Page 1 ASR for Apr ’14 – Mar’15 Prudhoe Bay Unit Lisburne Oil Pool 2015 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2015 is submitted to the Alaska Oil and Gas Conservation Commission in accordance with 20 AAC 25.517. It covers the period between April 1, 2014 and March 31, 2015. Reservoir Management Summary Production and injection volumes for the 12 -month period ending March 31, 2015 are summarized in Table 1. Oil production volumes include allocated crude oil, condensate and NGL production. 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 were six production and two injection logs obtained from Lisburne wells during the reporting period. Production and Neutron logs for April 1, 2014 through March 31, 2015 are shown in Table 3. Lisburne Oil Pool Page 2 ASR for Apr ’14 – Mar’15 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, 2015, the cumulative volume of seawater injected in L5-29 was 20,755 mbbls. The L5-29 pilot injection to date has demonstrated positive results with 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 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 grass roots injection well, 04-350, was completed on the southern periphery of the Wahoo Formation in November 2011 and has injected 2,462 mbbls of seawater as of March 31, 2015. 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, 2015 the cumulative volume of seawater injected in both these wells was 2,926 mbbls. No confirmed offset producer well response has been observed to date. In addition, a pilot water injection project into the Alap ah 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 2,526 mbbls of seawater as of March 31, 2015. Offset producer well pressure response has been observed and watercut increased, but no confirmed seawater breakthrough has occurred during the reporting period. Lisburne Oil Pool Page 3 ASR for Apr ’14 – Mar’15 Development Drilling No wells were drilled and completed into the Lisburne Formation during the reporting period. Support Facilities Lisburne will continue to share North Slope infrastructure with the Poin t 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 liquid s 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 ’14 – Mar’15 Tables & Figures Oil + NGL Gas Water Oil + NGL Gas Water Monthly Cum Monthly Cum Date mstbo mmscf mbw mstbo mmscf mbw mmscf bscf mbw mbw 4/1/2014 238.72 4,212 217 175,325 1,892,393 55,503 4,631 1,885,076 874 29,580 5/1/2014 199.86 3,369 209 175,525 1,895,761 55,712 4,542 1,889,618 883 30,463 6/1/2014 33.79 649 24 175,559 1,896,410 55,736 670 1,890,288 831 31,294 7/1/2014 194.64 4,174 105 175,754 1,900,584 55,841 4,811 1,895,099 763 32,057 8/1/2014 189.70 3,743 173 175,943 1,904,327 56,014 4,806 1,899,904 888 32,945 9/1/2014 162.68 3,869 137 176,106 1,908,196 56,151 5,003 1,904,908 703 33,648 10/1/2014 22.19 633 23 176,128 1,908,830 56,174 1,752 1,906,660 787 34,436 11/1/2014 81.00 1,501 97 176,209 1,910,330 56,271 4,287 1,910,947 813 35,249 12/1/2014 134.44 2,650 185 176,344 1,912,981 56,456 5,648 1,916,595 846 36,095 1/1/2015 167.76 3,026 201 176,511 1,916,007 56,657 6,055 1,922,650 494 36,589 2/1/2015 144.53 2,660 165 176,656 1,918,667 56,821 4,901 1,927,551 421 37,010 3/1/2015 166.17 2,877 175 176,822 1,921,544 56,996 4,798 1,932,349 523 37,533 Table 1 - Lisburne Monthly Production& Injection Volumes Monthly Production Cumulative Production Gas Injection Water Injection Table 2 - Lisburne Pressure data April 1, 2014 to March 31, 2015 Well Name Survey Date Pressure (psi) (Datum = 8900' SS) L5-08 4/23/2014 3072 L5-16A 4/24/2014 3393 L1-01 5/27/2014 3001 L2-21A 6/4/2014 1626 L2-16 6/5/2014 2595 L5-17A 6/6/2014 3431 L5-23 6/6/2014 3555 L3-31 6/8/2014 2253 L5-04 6/8/2014 3163 L3-18 6/9/2014 2674 L3-30 6/10/2014 2896 L2-06 6/22/2014 1770 L1-02 6/23/2014 3390 L1-31 6/24/2014 3271 L4-10 6/24/2014 1933 LGI-04 7/28/2014 3453 L4-12 7/29/2014 3244 L3-24 10/8/2014 3377 L4-15 10/8/2014 2895 NK-26 10/30/2014 4812 L3-19 11/16/2014 2779 L3-05 2/20/2015 3369 L1-15A 3/3/2015 3216 Lisburne Oil Pool Page 5 ASR for Apr ’14 – Mar’15 Table 3 - Lisburne Logging Comments/Interpretation Production logs obtained for the following wells: L1-21 L5-08 L5-13 (Injection profile log) L5-15 (Injection profile log) L5-16A L5-24 L5-28 L5-36 PNL/CNL logs were gathered for the following wells: L3-19 Note: all these PNL/CNL logs were obtained across the Ivishak formation for gas cap monitoring. Niakuk Oil Pool Page 1 ASR for Apr ’14 – Mar ‘15 Prudhoe Bay Unit Niakuk Oil Pool 2015 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, 2014 through March 31, 2015. 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, 2/4, and 3/5) are receiving pressure support from water injection. There are 4 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 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 142 bopd for the reporting period with a watercut of about 91%. Water injection in NK-10 averaged approximately 3.2 mbd for the period. Water injection volumes replaced reservoir voidage through the end of 1997 and since then over injection has increased reservoir pressure. Plans are to maintain voidage replacement and keep reservoir pressure at the current level. At the beginning of the reporting period, there were two active producers (NK-27 and L5-34), two inactive producers (NK-07A and NK-61A), and one active injector (NK-10). At the end of the reporting period, there was one active Niakuk Oil Pool Page 2 ASR for Apr ’14 – Mar ‘15 producer (NK-61A), three inactive producers (NK-07A, NK-27 and L5-34) and one active injector (NK-10). No conversions of producers to injectors are currently planned. Segment 3/5 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. 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. Due to facility shut downs over the reporting period we over injected into segment 3/5.Plans are to maintain a voidage replacement ratio of 1 and keep reservoir pressure at the current level. Water injection rate for the segment averaged 9.8 mbd for the reporting period. Production and pressure data suggests good communication between injectors and producers. Oil production for the segment averaged 446 bopd for the reporting period with an average watercut of 93%. At the beginning of the reporting period, there were three active producers (NK- 08A, NK-09 and NK-29), one inactive producer (NK-12C), one active injector (NK-13), two inactive injectors (NK-15 and NK-28), one abandoned well (NK- 14A), and one suspended well (NK -11A). At the end of the reporting period, there were three active producers (NK-08A, NK-09 and NK-29), one inactive producer (NK-12C), two active injectors (NK-13 and NK-28), one inactive injector (NK-15), one abandoned well (NK-14A), and one suspended well (NK-11A). No conversions of producers to injectors are currently planned. Segment 2/4 Like the other segments in the Niakuk 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. All producers in Segment 2/4 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 435 bopd with 95% watercut. Water injection in Segment 2/4 averaged 9 mbd during the reporting period. At the beginning of the reporting period there were three active producers (NK- 22A, NK-42 and NK-43), four shut-in producers (NK-19A, NK-20A, NK-21 and NK-62A), two active injectors (NK-18, and NK-23), and one inactive injector (NK- Niakuk Oil Pool Page 3 ASR for Apr ’14 – Mar ‘15 16). At the end of the reporting period there were three active producers (NK-21, NK-42 and NK-43), four shut-in producers (NK-19A, NK-20A, NK-22A and NK- 62A), one active injector (NK-23), and two inactive injectors (NK-16 and NK-18). No conversions of producers to injectors are currently planned. 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 2014/2015 reservoir pressure surveys. The pressures in Segments 2/4, 1, and 3/ 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 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 production allocation splits between the Sag River and Kuparuk reservoirs. Production allocation splits from the previous geochemical analysis were used for allocation. This analysis shows that 100% of oil production in NK -43 is from the Kuparuk. 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 Niakuk Oil Pool Page 4 ASR for Apr ’14 – Mar ‘15 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 perform ance 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 ’14 – Mar ‘15 Tables and Figures 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 mstb mmscf mstb mmscf mstb mmscf mstb mmscf Apr-14 30 42 47 566 0 608 0 93,763 83,657 May-14 31 54 54 563 0 588 0 93,818 83,711 Jun-14 30 4 3 36 0 556 0 93,821 83,714 Jul-14 31 37 37 515 0 599 0 93,859 83,751 Aug-14 31 45 47 654 0 744 0 93,904 83,798 Sep-14 30 49 51 671 0 499 0 93,952 83,849 Oct-14 31 6 4 79 0 865 0 93,958 83,853 Nov-14 30 0.1 0.2 3 0 611 0 93,958 83,853 Dec-14 31 33 25 634 0 632 0 93,991 83,878 Jan-15 31 36 19 655 0 706 0 94,027 83,898 Feb-15 28 32 20 589 0 839 0 94,059 83,917 Mar-15 31 35 26 607 0 808 0 94,094 83,944 Apr-11 Year 365 372 334 5,571 0 8,054 0 Table 2 - Niakuk 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-14 30 54 13 571 0 614 0 24 May-14 31 70 11 568 0 594 0 56 Jun-14 30 5 0 36 0 561 0 -520 Jul-14 31 48 8 521 0 605 0 -28 Aug-14 31 58 11 661 0 752 0 -21 Sep-14 30 63 12 677 0 504 0 249 Oct-14 31 8 0 80 0 873 0 -786 Nov-14 30 0 0 3 0 617 0 -613 Dec-14 31 43 2 641 0 638 0 47 Jan-15 31 47 -4 661 0 713 0 -9 Feb-15 28 42 -2 594 0 847 0 -213 Mar-15 31 45 2 613 0 816 0 -156 Apr-11 Year 365 484 53 5,627 0 8,135 0 -1,972 Note: Negative Net Reservoir Voidage indicates IWR>1 Note: Monthly Production/Injection/Voidage/Pressure data (Tables 1 & 2) do not include the production results from NK-38A well drilled to the 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 6 ASR for Apr ’14 – Mar ‘15 Table 3 – 2013 – 2014 Pressure Survey Data Well Name Survey Date Pressure (psi) (Datum = 9200' SS) L5-34 6/22/2014 3842 NK-09 6/15/2014 4383 NK-10 7/13/2014 4431 NK-13 7/13/2014 4441 NK-22A 7/9/2014 4571 NK-23 7/13/2014 4501 NK-27 6/25/2014 4253 Table 3 - Niakuk Pressure data April 1, 2014 to March 31, 2015 Point McIntyre Oil Pool Page 1 ASR for Apr ’14 – Mar ‘15 Prudhoe Bay Unit Pt. McIntyre Oil Pool 2015 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2015 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, 2014 and March 31, 2015. A. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) Enhanced Recovery Projects During the 12 month period from April 2014 – March 2015, a total of 8.1 BCF of MI (miscible injectant) was injected into P2-09 (2.0 BCF), P2-16 (2.2 BCF), P2-28 (2.2 BCF), and P2-29 (1.7 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, 2015 are summarized in Table 1. Total Pt. McIntyre hydrocarbon liquid production (oil plus NGL) averaged 16.3 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 ’15 – Mar ‘15 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 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) There were three production logs and one injection log obtained from Pt McIntyre wells during the reporting period. Production and injection logs for April 1, 2014 thru March 31, 2015 are shown in Table 4. 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 during 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 ’15 – Mar ‘15 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 minim ize 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 A laska 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 ’15 – Mar ‘15 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 ’15 – Mar ‘15 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-14 30 498 4,814 2,729 3,641 2,771 1,062 450,493 1,215,947 May-14 31 523 5,961 2,657 3,754 2,566 1,172 451,016 1,221,908 Jun-14 30 200 2,240 1,161 1,890 2,223 1,162 451,216 1,224,149 Jul-14 31 486 5,376 2,349 4,185 2,829 606 451,702 1,229,524 Aug-14 31 489 5,510 2,414 3,984 3,203 213 452,191 1,235,035 Sep-14 30 474 6,219 2,230 4,162 3,016 0 452,665 1,241,254 Oct-14 31 177 3,267 571 2,123 2,151 0 452,842 1,244,521 Nov-14 30 547 6,223 2,644 3,712 2,978 704 453,389 1,250,744 Dec-14 31 534 7,570 2,893 4,286 3,289 860 453,923 1,258,313 Jan-15 31 533 8,148 2,789 4,581 2,991 979 454,456 1,266,461 Feb-15 28 470 6,961 2,579 3,992 2,816 624 454,925 1,273,422 Mar-15 31 512 7,274 2,933 4,491 3,281 762 455,437 1,280,696 Apr-11 0 0 0 0 0 0 0 0 0 Year 365 5,441 69,563 27,947 44,800 34,115 8,145 0 0 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-14 30 692 3,027 2,770 2,484 2,812 659 534 May-14 31 727 3,796 2,697 2,561 2,605 727 1,327 Jun-14 30 278 1,425 1,178 1,289 2,256 720 -1,384 Jul-14 31 676 3,416 2,384 2,856 2,872 375 373 Aug-14 31 680 3,506 2,450 2,718 3,251 132 535 Sep-14 30 659 3,998 2,263 2,840 3,062 0 1,018 Oct-14 31 246 2,138 580 1,449 2,184 0 -669 Nov-14 30 761 3,963 2,683 2,533 3,023 437 1,414 Dec-14 31 743 4,888 2,936 2,924 3,338 533 1,771 Jan-15 31 742 5,283 2,831 3,126 3,035 607 2,087 Feb-15 28 653 4,506 2,617 2,724 2,858 387 1,808 Mar-15 31 712 4,698 2,977 3,065 3,330 473 1,519 Year 365 7,569 44,644 28,366 30,569 34,626 5,050 10,333 Note: Negative Net Reservoir Voidage indicates IWR>1 Point McIntyre Oil Pool Page 6 ASR for Apr ’15 – Mar ‘15 Table 3 - Pt. McIntyre Pressure data April 1, 2014 to March 31, 2015 Well Name Survey Date Pressure (psi) (Datum = 8800' SS) P2-17 4/13/2014 4182 P2-40 4/17/2014 4153 P1-24 4/21/2014 4178 P2-07 5/7/2014 4061 P2-52 5/18/2014 4151 P2-43 5/29/2014 4048 P2-21 6/8/2014 4032 P1-18A 6/9/2014 4029 P2-13 6/23/2014 3962 P2-45B 7/14/2014 4388 P2-19A 7/20/2014 4108 P2-45B 7/23/2014 4362 P2-59A 2/2/2015 4095 P2-37A 3/19/2015 4152 P1-14 3/20/2015 3952 Point McIntyre Oil Pool Page 7 ASR for Apr ’15 – Mar ‘15 Table 4 – Pt McIntyre Logging Comments/Interpretation Production logs obtained for the following wells: P1-04 P2-16 (Injection profile log) P2-51A P2-53 Note: No gas cap monitoring logs were obtained Point McIntyre Oil Pool Page 8 ASR for Apr ’15 – Mar ‘15 Figure 1 Pt. McIntyre Well Location Map Unit Boundary Point McIntyre Oil Pool Page 9 ASR for Apr ’15 – Mar ‘15 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 Raven Oil Pool Page 1 ASR for Apr ‟14 – Mar „15 Prudhoe Bay Unit Raven Oil Pool 2015 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, 2014 through March 31, 2015. 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, 2015 , seawater was used in NK -65A to provide injection support for the Ivishak reservoir at an average rate of 6.1 mbd . Raven Oil Pool Page 2 ASR for Apr ‟14 – Mar „15 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 0.17 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 3,564 psi, in NK38A, was taken in June of 2014, 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 ‟14 – Mar „15 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 sample was taken from NK-43 during the reporting period for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk reservoirs. Production allocation splits from the previous geochemical analysis were used for allocation. This analysis shows that 100% of oil production in NK-43 is from the Kuparuk. 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 ‟14 – Mar „15 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-14 30 9 63 99 0 199 0 3,036 16,060 May-14 31 12 67 92 0 198 0 3,048 16,127 Jun-14 30 1 3 8 0 190 0 3,048 16,130 Jul-14 31 7 53 118 0 169 0 3,055 16,183 Aug-14 31 6 78 105 0 186 0 3,061 16,261 Sep-14 30 5 57 92 0 121 0 3,066 16,319 Oct-14 31 2 11 17 0 176 0 3,068 16,330 Nov-14 30 0 0 0 0 199 0 3,068 16,330 Dec-14 31 5 79 168 0 205 0 3,072 16,409 Jan-15 31 4 77 129 0 199 0 3,077 16,485 Feb-15 28 3 50 97 0 13 0 3,080 16,535 Mar-15 31 5 53 111 0 196 0 3,085 16,589 Apr-11 0 0 0 0 0 0 0 0 Year 365 58 592 1,036 0 2,051 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-14 30 14 41 100 0 201 0 -47 May-14 31 19 42 93 0 200 0 -48 Jun-14 30 1 2 8 0 192 0 -181 Jul-14 31 10 35 119 0 171 0 -6 Aug-14 31 9 55 106 0 188 0 -18 Sep-14 30 8 40 93 0 122 0 19 Oct-14 31 2 7 18 0 178 0 -151 Nov-14 30 0 0 0 0 201 0 -201 Dec-14 31 7 56 170 0 207 0 27 Jan-15 31 7 55 130 0 201 0 -9 Feb-15 28 5 35 98 0 13 0 125 Mar-15 31 7 37 112 0 198 0 -42 Apr-11 Year 365 89 405 1,046 0 2,072 0 -531 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 ‟14 – Mar „15 Table 3 – Raven Ivishak Pressure Survey Data Since March 2005 Sw Name Test Date Pres Surv 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 NK-65A 7/13/2013 4429 9850 4429 NK-38A 12/26/2013 3549 9850 3549 NK-38A 6/26/2014 3564 9850 3564 NK-65A 7/13/2014 4674 9850 4674 NK-43 3/12/2015 4057 9850 4057