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Home My WebLink About2014 Schrader Bluff Oil PoolCONFIDENTIAL 2014 Annual Reservoir Surveillance Report Schrader Bluff Pool Nikaitchuq Field P a g e 1 Table of Contents 1. 2014 Development Activity Summary ............................................................................................................................ 2 Table 1. 2014 Well Placement Schedule for Nikaitchuq Field. ....................................................................................... 2 Table 2. 2014 Workover Schedule for Nikaitchuq Field Wells. ....................................................................................... 2 Table 3. Total planned well count for Nikaitchuq Development. ................................................................................... 3 Figure 1. Nikaitchuq development Map showing the completed well paths and its reservoir units up to Dec 2014. .. 4 Figure 2. Nikaitchuq Field production and events summary. ......................................................................................... 5 2. Reservoir Pressure Surveys at the Nikaitchuq Schrader Bluff Pool ................................................................................ 6 Figure 3a Intake BHP measurements in year 2014 for active wells at OPP.. ................................................................. 6 Figure 3b. Intake BHP measurements in year 2014 for active wells at SID. ................................................................... 7 Figure 4 2014 Pressure map of Nikaitchuq. ................................................................................................................... 8 3. Pool Allocation Factors and Issues in 2014 ..................................................................................................................... 9 4. Reservoir Management Summary .................................................................................................................................. 9 Figure 5. Nikaitchuq map showing wells with Resman tracers and DTS Fibers. ........................................................... 10 4.1. 2014 Fall PFO and DTS Data Acquisition Campaign .................................................................................................. 11 Table 4. PFO/DTS Survey Well Data During Fall 2014 Campaign. ................................................................................. 11 Figure 6. OI11-01 Pressure & Injection Rate Data from Fall 2014 PFO/DTS Survey. .................................................... 12 Figure 7. OI07-04 Pressure & Injection Rate Data from Fall 2014 PFO/DTS Survey. .................................................... 12 Figure 8. OI11-01 Inflow zone contributions from 2014 DTS Transient model. ........................................................... 13 4.2. Tracer Surveys and Injection Monitoring Conducted in 2014 .................................................................................. 14 Figure 9. Completion configuration for the SP33-W3 well. .......................................................................................... 14 Figure 10. SP33-W3 well trajectory showing the physical locations of the tracers along the well bore. .................... 15 Figure 11. SP33-W3 well trajectory, showing the June 2014 restart flow distribution results ................................... 15 Figure 12. SP10-FN5 well trajectory, showing May 2013 restart flow distribution results ......................................... 16 Figure 13. SP16-FN3 well trajectory, showing the October 2012restart flow distribution results .............................. 16 5. Voidage Balance by Month of Produced Fluids and Injected Fluids on a Standard and Reservoir Volume Basis with Yearly and Cumulative Volumes ........................................................................................................................................... 17 Table 5. 2014 Nikaitchuq field monthly production/injection volumes and voidage replacement ratios .................. 17 6. Reservoir Studies ........................................................................................................................................................... 17 Attachment 1 Nikaitchuq Field - Drilling Schedule as at March 2015……………………………………………………………………..18 Attachment 2 Voidage Replacement (VRR) Charts for the active Injector wells during the year 2014…………………… .19 Attachment 3 Nikaitchuq Field water cut trends: History Match vs. Real Time Data 2014 ....................................... 31 P a g e 2 1. 2014 Development Activity Summary Development activities performed during year 2014 added a total of nine (9) wells (3 new oil producers, 3 new water injectors, and 3 dual lateral additions to existing single oil producers) to the existing well inventory for Nikaitchuq development (See Table 1 & Figure 1). In addition, well intervention/workover (WO) activities were conducted on nine (9) wells (5 Oliktok Point (OPP) oil producers, 2 Spy Island (SID) oil producers, one water source well and one SID water disposal well). The wells and WO completion dates are shown in Table 2. Table 1. 2014 Well Placement Schedule for Nikaitchuq Field. Well Name Type Placement Date Drilling Path SI11-FN6 Water Injector 2/23/2014 Spy Island OP03-05 L1 Dual Lateral Oil Producer 3/16/2014 Oliktok Point SP24-SE1 L1 Dual Lateral Oil Producer 4/3/2014 Spy Island OP18-08 L1 Dual Lateral Oil Producer 4/13/2014 Oliktok Point OP16-03 L1 Dual Lateral Oil Producer 5/12/2014 Oliktok Point SI17-SE2 Water Injector 6/5/2014 Spy Island SP12-SE3 L1 Dual Lateral Oil Producer 7/17/2014 Spy Island SP21-NW1 L1 Dual Lateral Oil Producer 11/6/2014 Spy Island SI26-NE2 Water Injector 12/17/2014 Spy Island Table 2. 2014 Workover Schedule for Nikaitchuq Field Wells. Well Name Type WO completion Date Pad OP08-04 Dual Lateral Oil Producer 4/19/2014 Oliktok Point SP05-FN7 Single Lateral Oil Producer 5/11/2014 Spy Island OP05-06 Dual Lateral Oil Producer 5/19/2014 Oliktok Point OP23-WW02 Water Service Well 6/6/2014 Oliktok Point OP16-03 L1 Dual Lateral Oil Producer 6/30/2014 Oliktok Point SP08-N7 Single Lateral Oil Producer 7/22/2014 Spy Island SD37-DSP 1 Water Disposal 9/13/2014 Spy Island OP18-08 L1 Dual Lateral Oil Producer 11/21/2014 Oliktok Point OP14-S03 L1 Dual Lateral Oil Producer 11/28/2014 Oliktok Point At the end of 2014, the number of OPP wells with dual laterals w as eight (OP08-04 L1, OP24-S3L1, OP05-06L1, OP10-09L1, OP09-S1L1, OP03-05L1, OP18-08L1 & OP16-03L1) and five wells from Spy Island drilling site (SP36- W5L1, SP08-N7L1, SP24-SEL1, SP12-SE3 L1 & SP21-NW1 L1). The planned activity in 2009 had a total well count of 51. The well pattern and summary of the activity up to the end of year 2014 was 42 wells (including the dual lateral well paths) and it can be summarized in Table 3 as follows: P a g e 3 Table 3. Total planned well count for Nikaitchuq Development . Planned Activity (2009) Activity up to date (December 2014) OPP SID Total OPP SID Total Well Type Injector 8 12 20 8 11 19 Producer 11 15 26 11 14 25 Disposal 1 1 2 1 1 2 Water Source 3 0 3 3 0 3 Total 23 28 51** 23 19 42 Dual Lateral Well Paths 8 5 13 *OPP = Oliktok point development path (onshore) *SID = Spy Island Development path (offshore) SID Ext = Spy Island Western development extension wells ** The well OP-12 was drop from the drilling program Oil production at Nikaitchuq field has responded positively to waterflood. This is confirmed by the change of slope in several wells from sharply declining oil production during primary depletion to slightly inclining after waterflood response kicks in. The positive waterflood response to date indicates that waterflood technology chosen as the main oil recovery strategy for this field continues to be working well. Figure 2 shows Nikaitchuq field’s oil production and water injection history from January 2012 through year 2014. P a g e 4 Figure 1. Nikaitchuq development Map showing the completed well paths and its reservoir units up to Dec 2014. green = producer, blue = injector, yellow = Dual lateral producer, purple = N Sand Appraisal well. P a g e 5 Figure 2. Nikaitchuq Field production and events summary. P a g e 6 2. Reservoir Pressure Surveys at the Nikaitchuq Schrader Bluff Pool Similar to previous years reservoir pressure monitoring activities, during 2014 reservoir pressures were monitored by controlling intake BHPs as shown in Figures 3a & 3b for OPP and SID, respectively. These plots show how intake pressures have been gradually stepped down while monitoring signs of sand production, rising watercuts (WC) and gas-oil ratios (GOR) and balancing voidage across all sectors in the field. Reservoir pressures were measured in new wells prior to placing them in service in 2014. Also, planned and unplanned downtime opportunities in 2014 made it possible to measure reservoir pressures during pressure fall off (PFO) and distributed temperature surveys (DTS) campaigns in the Fall of 2014. The reservoir pressure measurements in the foregoing campaigns were used to generate the Nikaitchuq reservoir pressure map in 2014 shown in Figure 4. Figure 3a. Intake BHP measurements in year 2014 for active wells at OPP. P a g e 7 Figure 3b. Intake BHP measurements in year 2014 for active wells at SID. On the injector side, wellhead pressures were capped at an equivalent of 0.60 psi/ft to avoid injection at pressures that can fracture the reservoir. P a g e 8 Figure 4. 2014 Pressure map of Nikaitchuq Field. 160 01600 160016 0 0 1 6 0 0 16 0 0 16 0 0 1600 1 6 0 0 1 6 0 0 1 6 0 0 16 0 0 1 6 0 0 160 0 1 6 0 0 1600 16 0 0 16 0 0 80016 0 0 1600800 800 800 160016008008 0 0 24002400240024002400240016001600160016001600160 0 1600 800 8 0 0 80 01600 160 0 1 6 0 0 1 6 0 0 160 0 80 0 8 0 0 80 0 16 0 0 8 0 0 80 0 800 800 160016 0 0 16 0 0 16 0 0800 800 800 800 8 0 0800 80 0 800 1 6 0 0 80 0 16 0 0 160 0 80 0 80 0 80 016001600 16 0 0 16 0 01600 8 0 0 80 0 240 0 160016 0 0 16 0 0 1600 16 0 0160 0 16 0 0 Olitok Point SP05-FN7 SP10-FN5 SP30-W1 SI26-NW2 OI06-05 OI07-04 OI11-01 OI13-03 OI15-S4 OI24-08 OP03-P05 OP04-07 OP05-06 OP08-04 OP09-S1 OP10-09 OP12-01 OP14-S3 OP16-03 OP17-02 OP18-08 OP21-WW1 SI20-N4 SI25-N2 SI29-S2 SP18-N5 SP23-N3 SP27-N1 Spy Island OI20-07 OP-I2 SI11-FN6 SI17-SE2 SI19-FN2 SI32-W2 SI35-W4 SP08-N7 SP12-SE3 SP16-FN3 SP21-NW1 SP22-FN1 SP24-SE1 SP31-W7 SP33-W3 SP36-W5 SI14-N6 SI13-FN4 492000 494000 496000 498000 500000 502000 504000 506000 508000 510000 512000 514000 516000 518000 520000 522000 524000 492000 494000 496000 498000 500000 502000 504000 506000 508000 510000 512000 514000 516000 518000 520000 522000 524000603500060375006040000604250060450006047500605000060525006055000605750060600006062500606500060675006070000607250060750006077500 6035000603750060400006042500604500060475006050000605250060550006057500606000060625006065000606750060700006072500607500060775000 500 1000 1500 2000 2500ftUS 1:20000 400 800 1200 1600 2000 2400 Pressure [psi] Nikaitchuq Pressure Map Year End 2014 Nikaitchuq Field: Pressure Map Date 24/02/2015 Signature Eni Alaska Dev. Team P a g e 9 3. Pool Allocation Factors and Issues in 2014 Production from all wells producing from the Schrader Bluff pool is commingled at the surface into a common production line. Theoretical production for individual wells from the pool is calculated on a daily basis by using well test allocation. Daily theoretical production for a well was calculated using the last valid well test and the amount of time a well was on production for a given day. For example, if we had a valid well test on the first of the month and another on the fifth of the month, the allocation factor for that well will be calculated on the first through the fourth of the month using the test on the first. Consequently, the allocation factor will be recalculated on the fifth using the new valid test measured on the fifth. On monthly level, our AVOCET Manager Production software sums up the allocated volumes for each period between valid well tests. (Minutes on production/1440 minutes/day)*Daily Rate (stb/d) well test=Theoretical Daily Production The daily allocation factor for the field is calculated by dividing the actual total production for the day by the sum of the theoretical daily production for each individual well. Daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average daily allocation factor for 2014 was 1.05. This confirms that our well allocation method is reasonably accurate. The slight discrepancy is attributable to pressure differences between the production and test headers. 4. Reservoir Management Summary The Nikaitchuq OA reservoir development is focused on two major areas; replenishing reservoir energy by replacing the voidage created by fluid production with water injection, productivity improvement through workover activities and adding a second laterals to wells with single laterals. Reservoir energy is monitored by monitoring surface and bottom-hole pressures. In addition to surface meters measuring tubing pressures, Nikaitchuq oil producers are equipped with downhole gauges which allow real- time bottom-hole pressures to be monitored. Additionally, Resman tracer system pairs (oil and water tracers) are deployed in two OPP producers (OP17-02 & OP05-06) and four SID producers (SP33-W3, SP16-FN3, SP36- W5 & SP10-FN5) to help assess oil flow distribution along the wellbores and determine locations of water production. Three OPP injectors (OI06-05, OI07-04 & OI11-01) and two SID injectors (SI14-N6 & SI20-N4) are equipped with DTS fiber optics which allows us to determine the level of injectivity along the horizontal injection intervals of the injectors. Figure 5 is Nikaitchuq field map showing the producers with Resman tr acers and injectors with DTS fibers. P a g e 10 Red – Water Injectors with DTS Green with black dots – Oil Producers with Resman tracers Figure 5. Nikaitchuq map showing wells with Resman tracers and DTS Fibers. P a g e 11 4.1. 2014 Fall PFO and DTS Data Acquisition Campaign Pressure and temperature data acquisition campaigns were conducted during Fall of 2014. During these campaigns, pressure fall off (PFO) and distributed temperature survey (DTS) data were collected. Good data were collected during the campaign and Table 4 below shows the injectors surveyed, duration of data acquisition and reservoir pressures at the start and end of the PFO. In future, we plan to conduct an additional Spring PFO/DTS campaign to complement the Fall program. In addition to the Spring and Fall PFO/DTS campaign, we plan to capture more shut-in reservoir pressure measurements during planned shutdowns. Table 4. PFO/DTS Survey Well Data During Fall 2014 Campaign . PFO Start & End Dates Duration hours Reservoir Pressure @ start & End of PFO - psi PFO Rate psi/hr Injector Start End Start End OI11-01 8/28/2014 8/30/2014 48 2450 2275 3.65 OI07-04 11/2/2014 11/4/2014 48 2100 1965 2.81 OI06-05 11/6/2014 11/8/2014 48 2123 2026 2.02 SI14-N6 11/16/2014 11/18/2014 48 2776 2613 3.40 SI20-N4 11/21/2014 11/23/2014 48 2134 1965 3.52 As shown in Table 4 above, the duration of the PFOs was 48 hours for all the injectors. In order to accomplish valid analysis of the PFO and DTS surveys, data 48 hours before and after the PFO durations are also collected for analysis. Figures 6 and 7 show the acquired PFO profiles from before, during and after PFO for OI11-01 and OI07-04 during the campaign. Figure 8 shows DTS interpretation for OI11-01. P a g e 12 Figure 6. OI11-01 Pressure & Injection Rate Data from Fall 2014 PFO/DTS Survey. Figure 7. OI07-04 Pressure & Injection Rate Data from Fall 2014 PFO/DTS Survey. P a g e 13 Figure 8. OI11-01 Inflow zone contributions from 2014 DTS Transient model. P a g e 14 4.2. Tracer Surveys and Injection Monitoring Conducted in 2014 Resman tracer system pairs (oil and water tracers) were deployed in SP33-W3, SP16-FN3, SP10-FN5 and SP36- W5 to assess oil flow distribution along the wellbores and to determine locations of water production. In 2014, water and oil samples from the wells were collected for Resman steady state and re-start tracer surveillance analysis. The main objectives of the tracer analyses were to gain qualitative insights into production contribution from the multiple segments of the long horizontal wells and to attempt to gain quantitative distribution of inflow contribution following a well startup. A typical completion configuration for SP33-W3 showing five oil and water tracer systems installed to cover five compartments of the lateral section of the well is shown in Figure 10. Figure 11 shows the physical locations of the tracers along SP33-W3 wellbore. Figure 12, 13 & 14 shows tracer analyses results for SP33-W3, SP10-FN5 and SP16-FN3, respectively depicting percentage contribution of their laterals to production. The foregoing interpretations are quick look interpretations from the service vendor, Resman. At the time of the SP10-FN5 Resman samples acquisition, there was a possibility that the tracer carriers were not wet by oil due to either sediment plugging or gas presence. However, analysis of the Steady State campaign in 2014 is showing some improvements in the areas previously deemed to be weakly contributing to production . Figure 9. Completion configuration for the SP33-W3 well. P a g e 15 Figure 10. SP33-W3 well trajectory showing the physical locations of the tracers along the well bore . The analyses were done in two steps: A steady state from September 2013 – June 2014 a re-start on June 2014. The results of those tests show an anomaly that could potentially indicate no flow upstream of 16,000 ft MD (Figure 9); this anomaly will be considered for further investigation as a part of the scope of study on the next intervention of this well which is going to be in 2016. Figure 11. SP33-W3 well trajectory, showing the June 2014 re-start flow distribution results based on flush-out modeling and the showing strong contribution and high pressure for the toe of the well. P a g e 16 Figure 12. SP10-FN5 well trajectory, showing May 2013 re-start flow distribution results indicating little or no flow from the toe, declining middle and increased heel flow contribution. Figure 13. SP16-FN3 well trajectory, showing Oct 2012 re-start flow distribution results and confirmed by 2013 – 2014 steady state indicating fairly equal flow distribution along the lateral. P a g e 17 5. Voidage Balance by Month of Produced Fluids and Injected Fluids on a Standard and Reservoir Volume Basis with Yearly and Cumulative Volumes A total of approximately 8.20 million (3.99 million from OPP and 4.21 million from SID) barrels of oil was produced from the Nikaitchuq field during the year 201 4 at an average daily production of 22,460 bopd. Injected volumes of water during year 2014 were about 9.87 million barrels at an average daily rate of 27,047 bwpd. Attachment 2 summarizes on a month by month bases production / injection volumes for all the nineteen (19) Nikaitchuq patterns or sectors and their voidage replacement ratios. Table 5 below summarizes the entire voidage replacement for the Nikaitchuq field in 2014. Table 5. 2014 Nikaitchuq field monthly production/injection volumes and voidage replacement ratios 6. Reservoir Studies The new reservoir model produced in 2013 was used throughout 2014. This model is incorporating significant amount of information that has been collected since development started (well performance and extensive well control data). The model has validated the development concept and field performance. WC trends have been captured and the data collected from 2014 is helping to validate the history match (HM). From reservoir management and waterflood performance point of view, the most relevant feedback is that fie ld watercut trends (through March 2014) are in line or more optimistic than modeled trends suggesting no significant by passing of oil and good conformance. Attachment 3 presents the individual well WC trends. MONTHLY SURFACE INJECTION VOIDAGE YEAR MONTH OIL MB GAS MMCF WATER MB OIL MRB GAS MRB WATER MRB OIL MB GAS MMCF WATER MB WATER_INJ MB PRODUCTION MRB INJECTION MRB PRODUCTION MRB INJECTION MRB INSTANTANEOUS CUMULATIVE 2014 1 606.48 73.07 167.84 636.73 30.25 168.24 606.48 73.07 167.84 688.12 835.23 689.74 835.23 689.74 0.83 0.83 2014 2 535.81 57.65 149.09 562.54 12.11 149.44 1142.29 130.73 316.93 653.65 724.09 655.19 1559.31 1344.93 0.90 0.86 2014 3 612.32 65.68 83.94 642.86 24.35 84.14 1754.61 196.41 400.87 749.99 751.36 751.76 2310.67 2096.69 1.00 0.91 2014 4 632.47 63.52 108.23 664.02 16.19 108.48 2387.08 259.93 509.10 799.62 788.69 801.51 3099.37 2898.20 1.02 0.94 2014 5 675.61 64.99 94.52 709.32 12.89 94.74 3062.69 324.92 603.62 781.66 816.95 783.50 3916.32 3681.70 0.96 0.94 2014 6 706.17 78.01 99.81 741.40 16.75 100.05 3768.86 402.93 703.43 846.91 858.19 848.91 4774.51 4530.61 0.99 0.95 2014 7 703.47 78.13 103.07 738.56 15.54 103.31 4472.33 481.06 806.50 903.70 857.42 905.83 5631.93 5436.44 1.06 0.97 2014 8 710.17 72.43 113.74 745.60 14.25 114.01 5182.50 553.50 920.25 792.92 873.86 794.79 6505.79 6231.23 0.91 0.96 2014 9 752.60 82.61 138.86 790.14 18.68 139.18 5935.10 636.11 1059.10 835.36 948.01 837.33 7453.80 7068.56 0.88 0.95 2014 10 746.58 92.53 159.34 783.83 16.60 159.72 6681.68 728.64 1218.45 928.51 960.14 930.70 8413.94 7999.26 0.97 0.95 2014 11 729.67 95.74 163.51 766.07 31.72 163.89 7411.34 824.38 1381.96 919.41 961.68 921.57 9375.62 8920.83 0.96 0.95 2014 12 786.48 95.41 185.81 825.72 29.44 186.25 8197.83 919.78 1567.77 972.18 1041.41 974.47 10417.03 9895.30 0.94 0.95 MONTHLY SURFACE PRODUCTION VOIDAGE MONTHLY SUBSURFACE PRODUCTION VOIDAGE CUMULATIVE SURFACE PRODUCTION VOIDAGE INSTANTANEOUS MONTHLY SUBSURFACE PROD/INJ VOIDAGES CUMULATIVE SUBSURFACE PROD/INJ VOIDAGES VOIDAGE REPLACEMENT RATIOS P a g e 18 Attachment 1. Nikaitchuq Field - Drilling Schedule as at April 2015 P a g e 19 Attachment 2. Voidage Replacement (VRR) Charts for the active Injector wells during the year 2014. P a g e 20 P a g e 21 P a g e 22 P a g e 23 P a g e 24 P a g e 25 P a g e 26 P a g e 27 P a g e 28 P a g e 29 P a g e 30 P a g e 31 Attachment 3. Nikaitchuq Field water cut trends: History Match vs. Real Time Data 2014 P a g e 32 P a g e 33 P a g e 34 P a g e 35 P a g e 36 P a g e 37 P a g e 38 P a g e 39 P a g e 40 1 Guhl, Meredith D (CED) From:Roby, David S (CED) Sent:Wednesday, March 10, 2021 2:30 PM To:Guhl, Meredith D (CED) Subject:FW: Confidentiality of 2014 Annual Reservoir Surveillance Report It’s not confidential. Dave Roby 907‐793‐1232 CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907‐ 793‐1232 or dave.roby@alaska.gov. From: Province Robert <Robert.Province@enipetroleum.com> Sent: Tuesday, May 5, 2015 5:11 PM To: Roby, David S (DOA) <dave.roby@alaska.gov> Subject: RE: Confidentiality of 2014 Annual Reservoir Surveillance Report Dave, My apologies for putting confidential on Eni’s reservoir surveillance report. That was a complete oversight and error of mine. For some reason, I confused the report with another report due the DNR and assumed it to be confidential. Please accept this email as Eni’s request for the AOGCC to consider the 2014 Reservior Surveillance Report as public information and not confidential. Let me know if you need anything else from Eni. Thanks, Robert A. Province Manager, Land and Public Relations - Alaska Eni US Operating Co. Inc (907) 865-3350- Office (907) 947-3793 - Cell From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent: Monday, May 04, 2015 5:47 PM To: Province Robert Subject: Confidentiality of 2014 Annual Reservoir Surveillance Report Mr. Province, 2 In looking back at the annual reservoir surveillance reports submitted for the Nikaitchuq Schrader Bluff Oil Pool Eni has not previously requested that any portion of the report be held confidential by the AOGCC, but for the recently submitted report covering 2014 operations you’ve requested that the entire report be held confidential. Can you please explain why you wish for this report to be held confidential? Thank you, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.roby@alaska.gov. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations.