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Home My WebLink About200-180 1 May 12, 2020 Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Conservation Order 559A (Rule 12) and Conservation Order 341I – Commingled production from the Put River Pool and Prudhoe Oil Pool in well 15-41B. Dear Chair Price, As required by the Alaska Oil and Gas Conservation Commission’s Conservation Order 559A; Rule 12 (vi), BP Exploration (Alaska) Inc. (BPXA) is providing this summary report documenting the results and effectiveness of commingled production allocation in well 15-41B within 9 months of its commencement. Over the course of the six-month commingled test period (August 18, 2019 through February 18, 2020), BPXA has fulfilled the Commission’s requirements to obtain a Production Profile, Static Bottom Hole Pressure Survey, Geochemical Samples and Well Tests. Results include production allocated to the Put River and Prudhoe Oil Pools, supported by analyses of geochemical tests, production logs, and regular well tests. Please call Don Brown at 564-4675 (cell: 982-9861) if you have any questions or wish to discuss further. Sincerely, Katrina Garner Area Manager, PBU Attachment 1: 15-41B WellBore Schematic-Old and New Attachment 2: Halliburton Production Log Analysis for 15-41B: Feb 19, 2020 Attachment 3: Stratum Reservoir Report No. 19-2531; December 2019 (CONFIDENTIAL) Attachment 4: Stratum Reservoir Report No. 20-2575; February 2020 (CONFIDENTIAL) Attachment 5: Stratum Reservoir Report No. 20-2605; May 2020 (CONFIDENTIAL) 2 History of 15-41B 15-41 was originally a conventional Zone 1 well completed in the northwestern area of DS 15 in November 1994. Initial oil rates peaked at 1500 bopd and held a steady decline throughout the lifetime of the well. Gas production forced the well to cycle/swing beginning in August 1997 through 2001. This well was sidetracked in March of 2001 as 15-41A but the hole was lost during completion. The well was then coil sidetracked to its current location 15-41B in October 2001. The parent wellbore was drilled through two Put River Oil zones, the Western and Central Lobes, the Sag River, then Zones 4 to 1 of the Ivishak. This 15-41B Zone 1A well underperformed for most of its early life producing only ~357 MBO black oil through 2004. Initial production was 1700 BOPD with a GOR of 7,000. By June of 2002, the well reached marginal GOR after only eight months of production. The well then became a cycle well with gas rate consistently just below ~20 MMSCFD. Adperfs were attempted in May 2003, but coiled tubing logging tools were unable to enter the 2-3/8” liner top, despite slickline and e-line tools being able to pass. Unfortunately, the proposed perforations are not e-line accessible, so the well continued to cycle. In 2004, the well was converted to a Put River appraisal well and a plug was set to shut off all Ivishak production. The well had a packer at 10,198’ MD from a previous workover, which is between the upper (Western) and lower (Central) Put River lobes. This packer was used to help separately test the upper and lower Put lobes (the packer appeared to function normally prior to a workover in January 2001). The following are results from the Put River initial production: - The lower Put River was perforated from 10,225’ to 10,260’ on November 3, 2004. This lower lobe did not flow. - Following a CT hydrate cleanout, an IBP was set at 10,212’ on Dec 2004. The upper Put River was perforated from 10,137’ to 10,192’ on December 13, 2004 and flowed with average rates of 95 bopd with 3.6 mmcfd. - Downhole pressure gauges were set on January 2, 2005. MEOH was pumped down the tubing to remove a hydrate plug prior to setting the gauges. Slickline rigged up on February 11 to retrieve the gauges and encountered hydrates with a sample bailer at 732’. Methanol was pumped down the tubing along with an IA HOT to clear the hydrates. A subsequent SL bailer run encountered hydrates at 2,280’. - A coil cleanout was completed on 3/4/05. Gauges were pulled on 3/6/05. - Pressure increased ~1psi/day from Feb 18 - Mar 4. - 3 ASRC tests were performed in April 2004. Since the 2004 tests the well remained shut in until July of 2018. At this time, the team revisited this well and decided to pursue the Put River production by commingling with the Ivishak. The well was then put on production and tested using PBGL from an adjacent well. Put River GeoChem end-member samples were collected. In 2019, the plugs isolating the Put intervals were removed and the well was placed on commingled production based on the commingled rules of CO341I and CO559A. The purpose of commingling in this well for current service is to use the Ivishak gas to help lift the Put River fluids and assist in keeping the well warm to avoid potential hydrate issues. This commingling is also a way the Ivishak and Put River resources could be maximized from the wellbore. 3 Completion Diagram: At the beginning of this project, the WellBore Schematic (WBS) used to plan this commingled testing showed the 2-3/8” liner landing inside the tubing tail. This WBS is shown in Attachment 1 and is labeled as Old WBS. The lower Put River perfs on this diagram are located just above the liner top. This is important to note as the first downhole choke was set just above the liner top based on this schematic. Results of early production will be discussed in the results section and will be referenced to this particular plug setting depth. The first indication that the WBS was incorrect was discovered during the Halliburton production log run. During these log runs, it was found by the wireline crew that the liner top was not where the WBS said it was based on the X-Y caliper and GR readings. This team discovered that there was more distance between the liner top and the bottom perf of the lower set of Put River perfs. Based on these findings and discussions, the WBS was investigated. This investigation led to reviews of previously run logs, the tubing tally and the liner tally. From that information, it was noted that the 2-3/8” liner top was not inside the tubing tail and was actually landed inside the 7” liner from the parent wellbore. The revised WBS is seen as Updated WBS March 5, 2020 in Attachment 1. Halliburton’s analysist used both WBS’s in their log interpretations and was QC’d by BP’s petrophysicist. Both agree on a scenario as explained in the results section. Results Obtained from Commingled Test During the first 6 months of commingled testing, one production profile was collected using Halliburton’s Production Logging Tool, 6 Geo-Chemical samples were collected, and 32 welltests were gathered to assess performance of the Put River and Ivishak commingling performance. Halliburton interpreted the oil/water and gas splits between the pools. These were completely independent from the oil Geo-Chemical analysis performed by Stratum Reservoir’s analysis. Neither were privy to the other’s analysis or results. Please note that references to the Ivishak, Prudhoe, or Zone 3 (“Zone 3” in the PL analysis is used in reference to 3 sections of analysis and is not related to the Ivishak Zone 3 interval) are meant to represent the same oil. The Halliburton Production Log report is included in the Appendix labeled as Appendix 2. Well Test Discussion: An initial production test on this well started in July of 2018 with the main purpose to collect a Put River GeoChem end-member. A portable test separator was used on the well for the collection of these end-members as well as collecting a production data point. The well would not flow on its own so well 15-34 was used for poor boy gas lift. Results of these well tests are presented in Table 1. 4 Table 1 – 15-41B July, 2018 Portable Well Tests while on Gas Lift from Well 15-34 Prior to initial commingled production in August of 2019, plugs isolating the Ivishak and Put River were removed and a downhole choke was set at 10,245’ at the top of the 2-3/8” liner. This choke was set with an orifice to limit Ivishak gas to ~6 mmscfd. As seen in Table 2 (15-41 Commingled Well Tests), oil and gas rates started out very high and gas rates continued to climb over the next month. At that time, the team felt the high oil rates were flush production from the Ivishak and due to the high oil and gas rates, the orifice in the downhole choke washed out quickly. It was also decided after these initial results to move this choke down into the 2-3/8” liner before running the production log. Moving this choke into the 2-3/8” liner would hopefully provide a better representation of each Put River interval while commingled with the Ivishak with the upcoming production log. The downhole choke was pulled and set deeper in the liner October 7, 2019 and from the well tests, gas rates decreased significantly and oil rates lowered to expected Put River rates based on 2018 results. Run Date Hrs Total Fluid Rate (bpd) Oil Rate (bpd) Water Rate (bpd) Form Gas Rate (mscfd) Gas Lift (mscfd) Gas Lift Press (psi) Form GOR (scf/ stbo) WC Pct (%)Test Type 7/20/2018 8 159 157 3 4,300 2,000 1,568 27,476 1.7 7-PORT TEST SEP 7/20/2018 8 159 157 3 4,300 2,000 27,476 1.7 4-GAS LIFT 7/21/2018 8 135 132 3 2,000 2,000 1,631 15,117 2 7-PORT TEST SEP 7/21/2018 8 135 132 3 2,000 3,000 15,117 2 4-GAS LIFT 7/22/2018 8 153 152 0 2,400 3,000 1,482 15,758 0.3 7-PORT TEST SEP 7/22/2018 8 153 152 0 2,400 3,000 15,758 0.3 4-GAS LIFT 7/23/2018 8 149 149 0 2,600 3,000 1,367 17,438 0.1 7-PORT TEST SEP 7/23/2018 8 149 149 0 2,600 3,000 17,426 0.1 4-GAS LIFT 7/24/2018 8 115 115 0 3,100 3,000 1,246 27,003 0.3 7-PORT TEST SEP 7/25/2018 8 126 126 0 2,200 3,000 1,482 17,530 0.1 7-PORT TEST SEP 5 Table 2 – 15-41B Commingled Production GeoChemical Samples: GeoChemical (GeoChem) samples were scheduled for every month. Six samples were collected from August through February as seen in Table 3. However, the month of November was missed by miscommunication and January was missed waiting for weather to cooperate while waiting for the production log. The initial Ivishak GeoChem end member was chosen as 15-17, a near-by and Ivishak only well. This sample was collected in November of 2018. For improved data analysis, a second Ivishak GeoChem end member was collected in well 15-45. The bottom-hole location of this well is closer in proximity to 15-41B than 15-17. 15-45 was not on production in November of 2018. Run Date Hrs Total Fluid Rate (bpd) Oil Rate (bpd) Water Rate (bpd) Form Gas Rate (mscfd) Gas Lift (mscfd) Gas Lift Press (psi) Form GOR (scf/ stbo) WC Pct (%)Test Type 8/18/2019 20 886 862 24 13,520 15,680 2.7 1-NAT FLOW 8/18/2019 18 1,070 1,045 26 4,456 4,265 2.4 7-PORT TEST SEP 8/19/2019 18 922 913 10 5,134 5,626 1 7-PORT TEST SEP 8/19/2019 18 985 958 27 15,022 15,680 2.7 1-NAT FLOW 9/10/2019 15 462 446 16 18,791 42,126 3.5 1-NAT FLOW 9/20/2019 0 665 450 215 19,084 42,418 32.4 1-NAT FLOW 9/21/2019 10 408 396 12 18,678 47,222 2.9 1-NAT FLOW 9/27/2019 8 394 382 12 19,073 49,900 2.9 1-NAT FLOW 10/5/2019 8 382 368 14 19,279 52,373 3.7 1-NAT FLOW 10/9/2019 4 130 130 0 6,361 48,913 0 1-NAT FLOW 10/14/2019 16 92 62 30 5,605 90,212 32.9 1-NAT FLOW 10/14/2019 16 92 62 30 5,605 90,211 32.9 1-NAT FLOW 10/14/2019 18 97 66 31 5,780 87,300 31.7 1-NAT FLOW 10/14/2019 18 106 103 3 2,100 20,408 3.2 7-PORT TEST SEP 10/15/2019 18 108 105 3 2,107 20,033 3.2 1-NAT FLOW 11/2/2019 12 86 72 14 5,669 78,493 16.2 1-NAT FLOW 11/8/2019 12 140 136 4 5,449 40,040 2.9 1-NAT FLOW 11/15/2019 13 141 137 4 5,623 41,086 2.6 1-NAT FLOW 12/3/2019 12 122 120 2 5,911 49,260 1.7 1-NAT FLOW 12/16/2019 21 150 128 22 6,362 49,623 14.5 1-NAT FLOW 1/7/2020 20 159 136 23 6,290 46,337 14.4 1-NAT FLOW 1/19/2020 8 128 119 9 6,225 52,434 7 1-NAT FLOW 1/30/2020 8 157 151 6 5,542 36,822 3.8 1-NAT FLOW 2/6/2020 8 156 150 6 6,917 46,050 4.1 1-NAT FLOW 2/19/2020 6 127 115 12 6,133 53,421 9.5 1-NAT FLOW 2/21/2020 12 125 111 14 6,210 55,749 11 1-NAT FLOW 3/11/2020 7 129 125 4 6,191 49,484 2.7 1-NAT FLOW 3/11/2020 8 108 105 3 6,190 59,089 2.7 1-NAT FLOW 3/19/2020 8 117 98 19 6,004 61,276 16.1 1-NAT FLOW 3/27/2020 8 131 116 15 6,393 55,092 11.4 1-NAT FLOW 4/11/2020 8 143 140 3 6,260 44,736 2.1 1-NAT FLOW 4/19/2020 8 133 115 18 6,415 55,697 13.5 1-NAT FLOW 6 Table 3 – 15-41B GeoChem Sample Collection The GeoChem samples were sent to Stratum Reservoir for analysis over a 3-period window and reports were returned to BP in December 2019, February 2020, and April 2020. These reports can be reviewed in Appendices 3, 4, and 5. Results from the December 2019 report were only for August and September samples with results shown below: Table 4 – December 2019 GeoChem Results End members used for this analysis were 15-17 for the Ivishak (the 15-45 sample had not been collected yet) and July 2018 sample for the Put River. Results from the February 2020 report used both the 15-17 and 15-45 Ivishak end-members along with the same Put River end-member used in the December results. It was determined that the 15-45 Ivishak sample was a better match than the 15-17. All samples collected to this date were re-run using these end-members. Results from this report are shown below: Note: the 8/19/19 BP077149 results above should be: 57% Put River; 43% Ivishak, the 49% Ivishak is a misprint. Table 5 – February 2020 GeoChem results (see Note under table) sample date shipped 1 8/19/2019 8/19/2019 2 9/27/2019 9/27/2019 3 10/14/2019 12/3/2019 4 12/17/2019 12/31/2019 5 2/6/2020 2/1/2020 6 2/11/2020 2/1/2020 GeoChem samples collected (15-41) since August 18, 2019 when commingling started 7 In summary of these results, it is seen the 15-45 Ivishak end member shifted ~10 to 20% of the oil in the August and September samples from the Put River to the Ivishak. There are two potential thoughts on this production shift. The 15-45 well’s proximity is a better match to the Ivishak production in 15-41 with condensate yield and other oil properties. Second, the August and September rates may have these splits as the Ivishak showed good flush production with both gas and oil rates. The initial placement of the downhole choke played a role in these rates at that time. It wasn’t until after moving the choke into the 2-3/8” liner that the Put River began to dominate more of the oil production while the Ivishak was choked back to be the source of lift gas as designed. The April 2020 report used the same end members as the previous sample with results below. These February results are the beginning of the well in a more steady state and a better representation of production compared to the earlier samples. The December sample has a lower percentage of Put River oil compared to the October and February samples, but this may be an anomolous data point for these last four samples. Table 6 – April 2020 GeoChem Results Production Log Analysis: The Production Log was run on this well on February 19, 2020. The log was run with no major issues. One detail of the logging to note, the tool could not enter the 2-3/8” liner because the gas velocity was too great. Because of this issue, getting an Ivishak only data point was not achieveable. With the lower Put River perfs in the tubing tail and the complicated completion at this depth, getting a lower Put River and Ivishak split is difficult. Halliburton gave 2 interpreations using the old WBS and the updated WBS. Results are shown below with a detailed explanation in Appendix 2. Table 7: Production Log interpretation based on old WBS The main interpretation in Table 7 is explained as the following from the Halliburton report: (the flow zone 2 in the table is not an actual perforation, but a catch-all zone to show all the other production, not attributed to flow zone 1 perforations). 8 Table 8: Production Log interpretation based on updated WBS The main interpretation in Table 8 is explained as the following from the Halliburton report: an alternate interpretation (the flow zone 3 in the table is not an actual perforation, but a catch-all zone to show all the other production, not attributed to flow zones 1 and 2 perforations). Based on Table 8, Oil Splits: Put River Oil = 44%; Ivishak = 56% Gas Splits: Put River Gas = 40% Ivishak = 60% Allocations used from August to Present: Initial allocations used for this well to split Ivishak and Put River oil was based on the oil production from the July 2018 well tests. Based on the Put River in those tests (seen in Table 1), the Put River was producting ~150 bopd. This rate then became the oil value for the Put River for the August and September well tests, the remaining oil was allocated to the Ivishak and percentage oil splits were given to each pool. The same methodology was used for gas splits using a base of 2.4 mmscfd and the remaining gas to the Ivishak . This process continued for the allocations for October and November allocations. In December and January, the allocations were reviewed using the GeoChem report from Stratum based on samples from August and September. However, it was decided to maintain the current allocation process due to the new downhole choke that was installed in mid-October which reduced both oil and gas rates. In February, a more scientific process for allocations was applied based on the February Stratum report. These GeoChem results were used to split the oil rate for Ivishak and Put River. Gas splits were then backed out using these oil rates and a condensate yield that is typical for the Ivishak, 7 bbl/mmscf, in this area and the yield of the Western Lobe, 40 bbl/mmscf. This methodology was used for February and March allocations. As a note, the Central Lobe never produced when first perforated in 2004. This evidence suggests it is not contributing and therefore, these assumptions are reasonable. A summary of the allocated production is shown here in Table 9 along with the GeoChem and PL production splits. As seen in the table, the production splits have changed over time. Allocations for August through December were based off of July, 2018 Put River production as a basis with the remaining production allocated to the Ivishak. At that time, there were no GeoChem results or PPROF to guide the allocations any better. As additional GeoChem results were reviewed along with production data and production profile log, allocations were adjusted to those results. 9 Table 9 – Allocated Production Data and GeoChem/PL results Looking forward and based off the GeoChem results and the production log, it seems reasonable to maintain a 70% / 30% oil split between the Put River and Ivishak Pools and to continue to back out gas rates based on these oil rates and condensate yield (April allocation completed with this process as seen in Table 9). It is important to note at this time that neither GeoChem or a production log can provide a Put River split between the Western and Central Lobes with any level of confidence. Static Pressure Collected as per CO 341G and CO 559A: 1. 15-41B Put River Static: survey date – 9/11/2018: 4127 psi at 8100’ SS Datum 2. 15-17 Ivishak Static: survey date – 1/19/2019; 3334 psi at 8800’ SS Datum 15-41B Put River only 2018 Well test (Gas Lift from well 15-34) Date Oil Water Gas Jul-18 150 3 2400 15-41B allocations with average oil rates 8/18 to 8/31/19 oil Rate water rate gas rate Oil split water split gas split Put River 150 5 2400 16%50%43% Ivishak 763 5 3167 84%50%57%GeoChem Split Summary Total 913 10 5567 Date Collection %Put River % Ivishak 9/1 to 9/30/19 oil Rate water rate gas rate Oil split water split gas split 27-Sep-19 57 43 Put 150 7 5135 36%50%27%19-Aug-19 69 31 Ivishak 270 7 13765 64%50%73%14-Oct-19 72 28 Total 420 14 18900 17-Dec-19 51 49 10/1 to 10/13/19 oil Rate water rate gas rate Oil split water split gas split 6-Feb-20 75 25 Put 105 7 5135 29%50%27%11-Feb-20 68 32 Ivishak 263 7 14144 71%50%73% Total 368 14 19279 Production Log Split with New WBS 10/14 to 10/31/19 oil Rate water rate gas rate Oil split water split gas split 19-Feb-20 44 56 Put 103 3 107 98%100%5% Ivishak 2 0 2000 2%0%95% Total 105 3 2107 11/01 to 11/30/19 oil Rate water rate gas rate Oil split water split gas split Put 130 2 545 95%50%10% Ivishak 7 2 5446 5%50%90% Total 137 4 5445 12/01 to 12/31/19 oil Rate water rate gas rate Oil split water split gas split Put 118 2 614 95%50%10% Ivishak 6 2 6137 5%50%90% Total 124 4 6137 1/1/20 to 1/31/20 oil Rate water rate gas rate Oil split water split gas split Put 129 11 629 95%50%10% Ivishak 7 12 6291 5%50%90% Total 136 23 6290 2/1/20 to 2/29/20 oil Rate water rate gas rate Oil split water split gas split Put 65 4 1187 51%50%18% Ivishak 63 4 5405 49%50%82% Total 128 8 6592 3/1/20 to 3/31/20 oil Rate water rate gas rate Oil split water split gas split Put 57 4 1039 51%50%18% Ivishak 55 4 4730 49%50%82% Total 112 10 5768 4/1/20 to 4/30/20 oil Rate water rate gas rate Oil split water split gas split Put 88.9 4 2222.5 70%50%36% Ivishak 38.1 4 3930.5 30%50%64% Total 127 11 6153 PBGL Rate 3000 10 Conclusions • GeoChem analysis appears to be best allocation for commingled oil splits. • Due to the wellbore completion, production logging results have low confidence as interpretation is difficult. • Setting a plug to isolate the Ivishak will probably not give true Put River production as the July 2018 test had issues with hydrates and required a near-by well for gas lift. Recommendations • Based on the current conditions of the well, GeoChem based analysis with a Put River/Ivishak oil split of 70% / 30% should be adopted as the most valid allocation method for the next 6 months, or until the next GeoChem analysis is completed. • Gas Splits to be calculated using yield of 7 bbls/mmscf for Ivishak and 40 bbls/mmscf for Put River. • Water splits will be 50% / 50% between the Pools as the water rate is minimal at 10 to 24 bbls • Collect GeoChem samples as per CO every 6 months and update allocations based on those results Old WBS Updated WBS March 5, 2020 BP Exploration Alaska Production Log Analysis BP Exploration Alaska Inc. Well: 15-41B Field: Prudhoe Bay North Slope, Alaska, USA Report Production Log Analysis Prepared For : BP Exploration Alaska Inc. Logging Date : Feb 19, 2020 Submitted by: Farrukh Hamza Phone: +1(281)871-3048 3000 N. Sam Houston Pkwy E., Houston TX 77032 Email: farrukh.hamza@halliburton.com HALLIBURTON DOES NOT GUARANTEE THE ACCURACY OF ANY INTERPRETATION OF THE LOG DATA, CONVERSION OF LOG DATA TO PHYSICAL ROCK PAR AMETERS OR RECOMMENDATIONS WHICH MAY BE GIVEN BY HALLIBURTON PERSONNEL OF WHICH APPEAR ON THE LOG OR IN ANY OTHER FORM. ANY USER OF SUCH DATA, INTERPRETATIONS, CONVERSIONS OF RECOMMENDATIONS AGREES THAT HALLIBURTON IS NOT RESPONSIBLE EXCEPT WHERE DUE TO GROSS NEGLIGENCE OR WI LLFUL MISCONDUCT, FOR ANY LOSS, DAMAGES, OR EXPENSES RESULTING FROM THE USE THEREOF BP Exploration Alaska Production Log Analysis TABLE OF CONTENTS 1.0 EXECUTIVE SUMMARY ....................................................................................................................... 2 2.0 BACKGROUND AND OBJECTIVES ..................................................................................................... 4 3.0 WELL INFORMATION AND DATA QUALITY ASSESSMENT ......................................................... 5 4.0 PRODUCTION LOG PROCESSING ...................................................................................................... 9 4.1 FLOWING SURVEY: MAIN INTERPRETATION ........................................................................................ 10 4.2 FLOWING SURVEY: ALTERNATE INTERPRETATION ............................................................................... 20 BP Exploration Alaska Production Log Analysis 1.0 EXECUTIVE SUMMARY Production logging (PL) was performed in Well 15-41B on February 19th, 2020 in flowing conditions with the objective of determining the flow profile. During the logging program, the PL tool string was “unable to drop into the 2-3/8” liner due to gas up-flow (as noted on the field log). The log was performed from 10,272’ to 10,000’. This means that only the top 2 perforated intervals were logged, and but they appeared to be behind the tubing with no obvious path to the tubing for any flow. It was concluded in discussions with BP that, the well schematic was slightly misleading, and the perforations (10137’-10192’, 10225’-10260’) were shot through tubing and casing. There are packers isolating these perforations from each other, and the rest of the well, but any production from each interval will have had the chance to mix with itself between casing and tubing before entering the tubing. The liner top packer at 10265’ appears to be off depth based on the caliper (Figure 1A). An updated well sketch was developed by BP, and provided for PL interpretation. In this schematic (Figure 1B), the changes are shown in red. The perforated intervals are better designated, and there are a couple packers that are in a different spot. The biggest change, though, is that the perforations from 10225’-10260’ can also enter from below the 3 ½” tubing tail. This tubing is not inside the 5” liner, and the 2 -3/8” liner does not come up past the top of 5” tubing. This results in the flow around the 3 ½” tubing tail to be quite complicated. An alternate interpretation is provided in this report. The flow from the bottom-most zone (“below 10260 feet zone”) is supposed to be a catch-all for all the zones below 10260’; but since the per forations from 10225’-10260’ can also enter from below the 3 ½” tubing tail, the zone from 10225’-10260’ (since it is not coming in at those depths) was removed, and attributed to the “below 10260 feet zone” (this version is the main interpretation presented in this report.). In the velocity match track of the ma in and alternate interpretations (Figures 12, and 16 respectively), at two depth intervals (around 10150’ and around 10230’), the available internal diameter information is not enough to match the flow velocity. Neither the measured caliper, nor the diamet er from the well sketch can provide this changing enlarged diameter (notice the tapered shape of the ILS measurements). The hypothesis is, because the flow from the top two zones is coming into the tubing in an “opposite pattern” to the tubing flow, this causes the spinners to rotate differently. The flow from 10225-10260 in the alternate interpretation (Figure 16) is attributed to “below 10260 feet zone” in the main interpretation (Figure 12). Due to the “opposite pattern” flow hypothesis causing spinners to rotate in the opposite direction, the spinner measurements under-measure the fluid flow around 10260’. Hence, the model is slightly ahead of the measured velocity (Figure 12 velocity track around 10260’). BP Exploration Alaska Production Log Analysis The interpreted well production at the time of production logging is similar to the reported surface production, for both main and alternate interpretations. The reported surface production rates at the time of logging are: 6100 MCF/D, 31 bbl/day water, and 175 bbl/day oil, while the flowing PL survey interpretation (numbers shown are converted to surface conditions) are presented below. Main interpretation (the flow zone 2 in the table below is not an actual perforation, but a catch-all zone to show all the other production, not attributed to flow zone 1 perforations) results are presented below. Alternate interpretation (the flow zone 3 in the table below is not an actual perforation, but a catch-all zone to show all the other production, not attributed to flow zones 1 and 2 perforations) results are presented below. No.From To STB/D %MSCF/D %STB/D % 1 10137 10192 36 25 1260 21 10 33 2 10265 10280 108 75 4668 79 21 67 144 5928 31 Flow Oil Rate Gas Rate Water Rate No.From To STB/D %MSCF/D %STB/D % 1 10137 10192 36 25 1260 21 10 33 2 10225 10260 27 19 1141 19 10 34 3 10265 10280 81 56 3542 60 10 33 144 5944 31 Flow Oil Rate Gas Rate Water Rate BP Exploration Alaska Production Log Analysis 2.0 BACKGROUND AND OBJECTIVES The objective for running the production log is to determine oil, gas and water splits for each logged producing interval. BP Exploration Alaska Production Log Analysis 3.0 WELL INFORMATION AND DATA QUALITY ASSESSMENT Well 15-41B is completed with a 2 3/8” production liner and a 3 ½” tubing. The production log could not reach the desired depths due to gas up -flow. The original wellbore schemat ic is presented in the Figure 1 A, while the updated wellbore schematic (used in this interpretation) is presented in Figure 1B. An updated well sketch was developed by BP, and provided for PL interpretation. In this schematic (Figure 1B), the changes are shown in red. The perforated intervals are better designated, and there are a couple packers that are in a different sp ot. The biggest change, though, is that the perforations from 10225’-10260’ can also enter from below the 3 ½” tubing tail. This tubing is not inside the 5” liner, and the 2 -3/8” liner does not come up past the top of 5” tubing. This results in the flow around the 3 ½” tubing tail to be quite complicated. The tool string diagram used for the PL logged is presented in Figure 2. The tool string consisted of the following production logging sensors: Gamma Ray – Casing Collar Locator – Pressure – Capacitance Water Holdup – Inline Spinner – Temperature – Continuous Flowmeter Spinner. The data quality is summarized below. TOOL USAGE LOG DESCRIPTION LOG QUALITY REMARKS WELL BORE PARAMETERS QP Well bore pressure Good TEMP Well bore temperature Good FLUID TYPE FDR Radioactive density tool uses radioactive source and detector to measure density and is a center sample device Good GHT Gas Holdup Tool provides an across wellbore gas/liquid holdup measurement in any flow regime Good CWH Uses capacitance to measure the differences between hydrocarbons and water Good FLUID VELOCITY CFS Continuous Flowmeter Spinner Good ILS Inline Spinner Good BP Exploration Alaska Production Log Analysis Figure 1A: Wellbore Schematic BP Exploration Alaska Production Log Analysis Figure 1B: Updated Wellbore Schematic BP Exploration Alaska Production Log Analysis Figure 2: Production Log Tool string BP Exploration Alaska Production Log Analysis 4.0 PRODUCTION LOG PROCESSING The production log data from the flowing were processed using Kappa’s Emeraude software. In Emeraude, the rate calculation is treated as a minimization problem and solved using non-linear regression. Unlike the conventional approach, non-linear regression offers full flexibility in the type and number of measurements that can be handled, as well as the possibility to include external constraints. In its general form, a minimization problem is one where we consider some function y = F(x), where both x and y are vectors, the goal being to determine x such that F(x) is as close as possible to some known value y*. We say that we are solving an inverse problem since we seek a function input from its known output. The function to minimize, called the objective function, is taken as the squared difference between 1 and the ratio of the entries y and y*. A comparison between the model and the data is shown in this report and allows the analyst or the reader to determine validity of the answer obtained. Potential sources of discrepancies include tool measurement errors, conflicts between the parameters or conditions that make the underlying empirical models (such as flow regimes) less applicable.  The flow regimes were det ermined, directly from the flow rates and holdups, according to the Dukler model.  Gas compressibility factor and viscosity were calculated from Beggs & Brill, and Lee et al. correlations.  Oil properties were derived from derived from Standing, Vasquez & Beggs, Beggs & Robinson correlations. The water density and viscosity were calculated using a salinity of 40,000 ppm. The Van- Wingen & Frick correlation was used. The Standing correlation was used to calculate the solution gas. A Solution Gas-Oil Ratio of 5625 scf/stb was used. Viscosity was calculated using the Beggs & Robinson correlation. The gas viscosity was calculated using the Lee Gonzales Eakin correlation. An oil API gravity of 41.5 was used. The following gas parameters were used. GasType Miscellaneous SPGG UNITY 0.74 GP-CO2 % 0 The following capacitance tool characteristics were used. HydroWater Normalized 1 (Downhole measurement) HydroHyd Normalized 0.03 (Downhole measurement) BP Exploration Alaska Production Log Analysis 4.1 FLOWING SURVEY: MAIN INTERPRETATION The table below and Figure 3 summarize the flow profile for the two inflow zones. Figure 4 summarizes the PVT parameters, well and fluid properties, and total flow rate for the two inflow zones, while Figure 5 summarizes the water, oil, gas flow rates, and associated velocity, holdup, and co rrelations for the two inflow zones. The raw data from the flowing survey are presented in Figures 6 and 7. Figure 6 has the data from conventional production logging sensor s. Figure 7 has the same data that was presented in Figure 6 with the addition of the station measurements. During processing and interpretation of the production log, two flow zones were created in the analysis software to analyze the inflow or outflow. During the logging program, the PL tool string was “unable to drop into the 2-3/8” liner due to gas up-flow (as noted on the field log). The log was performed from 10,272’ to 10,000’. This means that only the top 2 perforated intervals were logged. The interpreted well production at the time of production logging is similar to the reported surface production. The reported surface production rates at the time of logging are: 6100 MCF/D, 31 bbl/day water, and 175 bbl/day oil. Main interpretation (the flow zone 2 in the table below is not an actual perforation, but a catch-all zone to show all the other production, not attributed to flow zone 1 perforations) results at surface conditions are presented below. No.From To STB/D %MSCF/D %STB/D % 1 10137 10192 36 25 1260 21 10 33 2 10265 10280 108 75 4668 79 21 67 144 5928 31 Flow Oil Rate Gas Rate Water Rate BP Exploration Alaska Production Log Analysis Figure 3: Graphical representation of the flow profile at surface conditions for the main interpretation. Gas rates are presented in MSCF/D, while the oil and water rates are in STB/D. BP Exploration Alaska Production Log Analysis ` Figures 4 and 5: For the two inflow zones, (left) summary of PVT parameters, well and fluid properties, and total flow rate, and (right) summary of water, oil, gas flow rates, and associated velocity, holdup, and correlations, are presented. Inflow 1 Inflow 2 From , ft 10137 10265 To , ft 10192 10280 FVF 1.006 1.008 Viscosity, cp 0.760 0.712 Density, g/cc 1.02 1.02 FVF 1.115 1.118 Viscosity, cp 1.440 1.320 Density, g/cc 0.766 0.764 Pb, psia 11427 11578 FVF 0.018 0.018 Viscosity, cp 0.013 0.013 Density, g/cc 0.050 0.050 Temperature, °F 107 113 Pressure, psia 769 772 Diameter, in 3.312 3.204 Deviation, °10.52 11.02 Roughness 0 0 Rs, scf/stb 226 223 Rsw, scf/stb 5.52 5.41 V mixture, ft/min 1250 1070 Visc. Mixture , cp 0.023 0.021 Vpcf 0.89 0.89 Q total res., B/D 19222 15320 dQ res., B/D 4090 15320 % Qt 21 79 Water Oil+Gas Gas Well and Fluid Properties Total Flow Rate Inflow 1 Inflow 2 From , ft 10137 10265 To , ft 10192 10280 Qw total res., B/D 31 21 Qw total s.c., STB/D 31 21 dQw res., B/D 10 21 dQw s.c., STB/D 10 21 % Qw 33 67 Qo total res., B/D 161 121 Qo total s.c., STB/D 144 108 dQo res., B/D 40 121 dQo s.c., STB/D 36 108 % Qo 25 75 Qg total res., B/D 19030 15179 Qg total s.c., Mscf/D 5928 4668 dQg res., B/D 4039 15178 dQg s.c., Mscf/D 1260 4668 % Qg 21 79 Vsw, ft/min 2 1 Vso, ft/min 10 8 Vsg, ft/min 1240 1057 Vw, ft/min 358 237 Vo, ft/min 2434 2689 Vg, ft/min 1253 1067 Yw 0.006 0.006 Yo 0.004 0.003 Yg 0.99 0.991 Vslip, ft/min 0 0 Vslip W-O, ft/min 21 23 Regime Mist/Ann ular Mist/Ann ular Correl.Dukler Dukler Correl. W-O ABB - Deviated ABB - Deviated Oil Flow Rate Gas Flow Rate V Superficial Holdups Correlations V Average Water Flow Rate BP Exploration Alaska Production Log Analysis Raw Data - The figure below summarizes the input data recorded at the well site during flowing passes. - Each pass is shown with a fixed predefined color. Figure 6: Input data from the conventional production logging sensors. BP Exploration Alaska Production Log Analysis Figure 7: Input data from the conventional production logging sensors along with the station measurements. BP Exploration Alaska Production Log Analysis Pre- Processing Figure 8: All the passes have been used in the interpretation. On the z track, red zones are perforations, yellow and orange are the spinner calibration zones, blue are the inflow zones while grey are the rate calculation zones. BP Exploration Alaska Production Log Analysis Calibration of Spinner Data The Figure 9 below displays cross plot for the continuous flow spinner (CLS), using a calibration zone. The estimated slope is used for converting the continuous flow spinner response to flow velocities. Figure 9: Spinner cross plot for CFS calibration BP Exploration Alaska Production Log Analysis Pre-Processed Data and Defined Zones Starting from the pre-processed data, the perforations, the temperature gradient, apparent velocity, the production, injection and flowing (fluid flow but no in or out flux) zones can be established. The Figure 10 below summarizes the pre-processed data and the zoning o f the intervals. This specifies if the zone is producing, injecting or simply flowing. The coloring of the profile is only to visualize the range of each zone. Within each producing/injecting zone the production/injection rate is constant. However, several producing/injecting zones, with different rates, can be used to capture the variations in the production rate. Figure 10: Pre-processed data and defined zones are presented. BP Exploration Alaska Production Log Analysis Flow Profile Figure 11 below shows the flow profile at reservoir conditions, for each of the 2 flow zones. The quantitative production rates were determined by comparing the well flow model with all available data. The Figure 11 is provided to verify the agreement of the flow model with the data. In Figure 12, the data is represented by the red curves, while the calculated tool values are shown in green. The small fluctuations around the data are to be expected, since the tools h ave intrinsic errors. Large sustained discrepancies indicate problems with the data, conflicts between parameters or conditions that make the acquired data less representative or the underlying empirical models less applicable. The production rates at reservoir conditions are presented in the figure below: Figure 11: Flow profile at reservoir conditions BP Exploration Alaska Production Log Analysis Figure 12: Flow profile at reservoir conditions (main interpretation) BP Exploration Alaska Production Log Analysis 4.2 FLOWING SURVEY: ALTERNATE INTERPRETATION The table below and Figure 13 summarize the flow profile for the three inflow zones. During processing and interpretation of the production log, three flow zones were created in the analysis software to analyze the inflow or outflow. During the logging program, the PL tool string was “unable to drop into the 2-3/8” liner due to gas up-flow (as noted on the field log). The log was performed from 10,272’ to 10,000’. This means that only the top 2 perforated intervals were logged. An alternate interpretation is provided in this section of the report. The flow from the bottom-most zone (“below 10260 feet zone”) is supposed to be a catch-all for all the zones below 10260’; but since the perforations from 10225’-10260’ can also enter from below the 3 ½” tubing tail, the zone from 10225’-10260’ (since it is not coming in at those depths) was removed, and attributed to the “below 10260 feet zone” (this version is the main interpretation presented in this report.). The flow from 10225 -10260 in the alternate interpretation (Figure 16) is attributed to “below 10260 feet zone” in the main interpretation (Figure 12). The interpreted well production at the time of production logging is similar to the reported surface production, for both main and alternate interpretations. The reported surface production rates at the time of logging are: 6100 MCF/D, 31 bbl/day water, and 175 bbl/day oil. Alternate interpretation (the flow zone 3 in the table below is not an actual perforation, but a catch-all zone to show all the other production, not att ributed to flow zones 1 and 2 perforations) results at surface conditions are presented below. No.From To STB/D %MSCF/D %STB/D % 1 10137 10192 36 25 1260 21 10 33 2 10225 10260 27 19 1141 19 10 34 3 10265 10280 81 56 3542 60 10 33 144 5944 31 Flow Oil Rate Gas Rate Water Rate BP Exploration Alaska Production Log Analysis Figure 13: Graphical representation of the flow profile at surface conditions, for the alternate interpretation. Gas rates are presented in MSCF/D, while the oil and water rates are in STB/D. BP Exploration Alaska Production Log Analysis Figures 14 and 15: For the three inflow zones, (left) summary of PVT parameters, well and fluid properties, and total flow rate, and (right) summary of water, oil, gas flow rates, and associated velocity, holdup, and correlations, are presented. Inflow 1 Inflow 2 Inflow 3 From , ft 10137 10225 10265 To , ft 10192 10260 10280 FVF 1.006 1.008 1.007 Viscosity, cp 0.760 0.712 0.716 Density, g/cc 1.02 1.02 1.02 FVF 1.115 1.118 1.118 Viscosity, cp 1.440 1.320 1.327 Density, g/cc 0.766 0.764 0.764 Pb, psia 11427 11578 11565 FVF 0.018 0.018 0.018 Viscosity, cp 0.013 0.013 0.013 Density, g/cc 0.050 0.050 0.050 Temperature, °F 107 113 113 Pressure, psia 769 772 774 Diameter, in 3.312 3.204 3.169 Deviation, °10.52 11.02 10.65 Roughness 0 0 0 Rs, scf/stb 226 223 224 Rsw, scf/stb 5.52 5.41 5.43 V mixture, ft/min 1260 1070 823 Visc. Mixture , cp 0.023 0.021 0.020 Vpcf 0.89 0.89 0.88 Q total res., B/D 19271 15370 11566 dQ res., B/D 4090 3751 11569 % Qt 21 19 60 Well and Fluid Properties Total Flow Rate Water Oil+Gas Gas Inflow 1 Inflow 2 Inflow 3 From , ft 10137 10225 10265 To , ft 10192 10260 10280 Qw total res., B/D 31 21 10 Qw total s.c., STB/D 31 21 10 dQw res., B/D 10 11 10 dQw s.c., STB/D 10 10 10 % Qw 33 34 33 Qo total res., B/D 161 121 90 Qo total s.c., STB/D 144 108 81 dQo res., B/D 40 30 90 dQo s.c., STB/D 36 27 81 % Qo 25 19 56 Qg total res., B/D 19079 15229 11465 Qg total s.c., Mscf/D 5944 4684 3542 dQg res., B/D 4039 3710 11468 dQg s.c., Mscf/D 1260 1141 3542 % Qg 21 19 60 Vsw, ft/min 2 1 1 Vso, ft/min 10 8 6 Vsg, ft/min 1244 1061 816 Vw, ft/min 359 238 113 Vo, ft/min 2440 2698 2866 Vg, ft/min 1256 1071 823 Yw 0.006 0.006 0.006 Yo 0.004 0.003 0.002 Yg 0.99 0.991 0.991 Vslip, ft/min 0 0 0 Vslip W-O, ft/min 21 23 24 Regime Mist/Ann ular Mist/Ann ular Mist/Ann ular Correl.Dukler Dukler Dukler Correl. W-O ABB - Deviated ABB - Deviated ABB - Deviated V Average V Superficial Holdups Correlations Gas Flow Rate Oil Flow Rate Water Flow Rate BP Exploration Alaska Production Log Analysis Figure 16: Flow profile at reservoir conditions (alternate interpretation) Geochemical Allocation of Two Oils from the 15-41B Well, North Slope, Alaska Stratum Reservoir Project No. BH-102366 (OilTracers Report No. 19-2531) By Matthew M. Laughland, Ph.D. Prepared for BP Alaska December 2019 CONFIDENTIAL Stratum Reservoir 3141 Hood St., Suite 103 Dallas, TX 75219 Telephone: 214-732-7174 www.stratumreservoir.com email: matt.laughland@stratumreservoir.com BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 1 Table of Contents I. Introduction................................................................................................... 2 II. Conclusions................................................................................................... 2 Summary of the Report Structure……………….………………… 3 III. Background Information...................................................................……. 3 Allocation of Commingled Production ….........................................3 IV. Materials and Methods................................................................................. 5 V. References.................................................................................................... 7 VI. Tables............................................................................................................ 9 VII. Appendices…………………………………………………………………. 17 BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 2 I. INTRODUCTION Two samples of commingled oil that were both collected from the same well 15-41B, but on different dates (August 19, 2019 and September 27, 2019), were submitted for quantitative geochemical allocation. The samples of produced (commingled) oil are believed to have contributions of oil from two different zones or “end-member” oils, the Put River Formation and Ivishak Formation. The main objective of this study is to determine the percent contributions of Put River and Ivishak oil in the commingled samples. Two different samples of end-member oils for the Put River Fm. were collected on different dates (July 22, 2018 and July 24, 2018) from the same well (15-41B). Accordingly, a secondary objective of this study is to determine which of the two Put River oil samples yield the better allocation results. A single sample of Ivishak oil (collected on November 7, 2018) from the 15-17 well is used as the end-member oil from the Ivishak Fm. See Table 1. Table 1: Samples used in this study for oil allocation. Well Name Collection Date Sample ID Client ID Data File Sample Type 15-41B 27-Sep-19 BP077133 00600397-001 C G6191837.D Commingled oil 15-41B 19-Aug-19 BP077149 00600397-003 C G6191838.D Commingled oil 15-41B 22-Jul-18 BP072879 10004086-002 C G6191839.D Put River Fm. End-member 15-41B 24-Jul-18 BP072880 10004086-003 C G6191840.D Put River Fm. End-member 15-17 7-Nov-18 BP073589 10004092-001 C G6191841.D Ivishak Fm. End-member The objectives of this study are to: (1) Determine which of the Put River end-member oils yield the more reliable allocation result. (2) Determine the percent contribution of oil from the Put River Fm. and the Ivishak Fm. in the two commingled samples of produced oil from the 15-41B well using: a.) the preferred sample of end-member oil from the Put River Fm; and, b.) the single end member sample from the Ivishak Fm. The following results are based on the geochemical methods described in the “Background Information” section of this report, including: “Allocation of Commingled Oil.” II. CONCLUSIONS 1.) Allocation results using the Put River end-member collected on July 22, 2018 (and the single end-member oil from the Ivishak Fm.) yield the more reliable allocation solution. The July 24th Put River sample appears to be contaminated with a small amount of Ivishak oil and hence is a less suitable Put River end member than is the July 22nd sample. BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 3 2.) Allocation results for the commingled oil from the 15-41B well collected on September 27, 2018 show that 65% of the oil is derived from the Put River Fm. and 35% of the oil is derived from the Ivishak Fm. 3.) Allocation results for the commingled oil from the 15-41B well collected on August 19, 2019 show that 69% of the oil is derived from the Put River Fm. and 31% of the oil is derived from the Ivishak Fm. 4.) Allocation results achieve of Quality of Solution of “Very Good” to “Excellent”. (Note: OilUnmixer™ calculates the uncertainty in solution at the 80% confidence level as follows: Excellent <2.5%; Very Good 2.5-3.99%; Good 4-5.99%; Fair 6-6.99%; Poor 7-7.99%; No Solution >8%) Table 2: Allocation results for commingled oils from 15-41B well. Commingled Oil Date Collected % *Put River % Ivishak Quality of Solution 15-41B Sept. 27, 2019 65% (± 2.14%) 35% (± 1.56%) Excellent 15-41B Aug. 19, 2019 69% (± 3.00%) 31% (± 2.47%) Very Good (*Results reported in Table 2 are calculated using the preferred Put River end-member oil collected July 22, 2018.) Summary of the Report Structure: Sample descriptions are provided in Table 1. Table 2 tabulates the allocation solution for commingled samples. Table 3 lists the alternate allocation results using the contaminated Put River end member (collected July 24, 2018). Table 4 lists the GC peak ratios for the end member oils used to construct the PCA plot in Figure 1. Table 5 lists the peak height values used for the allocation calculations. One page plots of the Gas Chromatography (GC) traces of the oils can be found in Appendix 1. An expanded view of one chromatogram is provided in Appendix 2 to allow identification of the peaks used in the allocation calculations. Appendix 3 shows the details of the allocation results for the commingled oils. III. BACKGROUND INFORMATION Allocation of Commingled Production Methods for using oil compositional differences to allocate commingled production from a single well are detailed in Kaufman et al., 1987, 1990, and McCaffrey et al., 1996, 2011, and 2012. Similar methods for allocating the contribution of multiple fields to commingled pipeline production streams are discussed by Hwang et al., 1999 and 2000. In brief, production allocation is achieved by identifying chemical differences between "end-member" oils (samples of oil from each of the zones or production streams being commingled). Parameters reflecting these compositional differences are then measured in the end-member oils and in the commingled oil. The data are then used to mathematically BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 4 express the composition of the commingled oil in terms of contributions from the respective end-member oils. Using a simple mixing model, a single geochemical difference between oils from two sands is sufficient to allocate commingled production from those two units (e.g., Kaufman et al, 1990). By using data for several peak ratios, independent solutions to the problem can be derived, allowing the accuracy of the allocation to be assessed. Using a simple mixing model, a single geochemical difference between oils from two sands (i.e., a singe difference in the relative abundance of 1 peak on a GC trace) is sufficient to allow allocation of commingled production from those two units (e.g., Kaufman et al, 1990). By using data for several peak ratios, independent solutions to the problem can be derived, allowing the accuracy of the allocation to be assessed. Using the concentrations (not ratios) of several compounds, the commingled production from several sands (or several fields) can be allocated to the discrete units using a linear algebra approach described in detail by McCaffrey et al., 1996, 2011, and 2012. In brief, it works as follows: Consider the following hypothetical example. The concentrations of four compounds (A, B, C, and D) are measured in oils from four zones that may be contributing to a produced oil. These data can be expressed as a 4 by 4 matrix (Matrix G) where the numbers are compound concentrations. The same four compounds are then measured in a produced oil, and form a 1 by 4 matrix (Matrix D). If the produced oil came only from some combination of production from the four intervals sampled by Matrix G, then the relative contributions from the four intervals to the commingled oil could be readily determined (as Matrix M) since: M = [GTG]-1GTD Equation 1 where GT is the transpose of Matrix G. If the number of rows (compounds) in matrix G is less than the number of columns (contributing oil intervals), then no solution to the problem can be identified. However, the form in which Equation 1 is written does allow the number of compounds to exceed the number of contributing oil intervals (data for the compounds in Table 4 were used to derive the results reported in the present study). In the current study (as well as all other production allocation projects performed by Stratum Reservoir), data were processed using a proprietary geochemical production allocation software package, OilUnmixerTM v. 4.01, developed and owned by OilTracers (now part of Stratum Reservoir). This package is based on a more sophisticated version of Equation 1. The package differs from the hypothetical matrix example described above in that it has a more sophisticated method for (i) dealing with analytical uncertainty, (ii) assessing the validity of end member (zone specific) calibration samples, (iii) looking for contamination in the end members, and (iv) “testing” the validity of the allocation results. The geochemical allocation approach described above is based on the well-established proposition that oils from separate reservoirs tend to differ from one another in composition (e.g., Slentz, 1981; Kaufman et al., 1990; Hwang and Baskin, 1994; Hwang BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 5 et al., 1994). As described in the previous section of this report. When oils from discrete zones are commingled, these chemical differences between the oils can be used to assess the contribution of each zone or each field to the commingled production, as described above. IV. MATERIALS AND METHODS AND DISCUSSION The oils were analyzed by High Resolution Gas Chromatography (GC) at Stratum Reservoir (Houston, TX) using a GC equipped with a 60 m DB-1column; the injector was at 275°C, and the heating program was: 35°C (hold 5 minutes), 3°/min ramp to 320°C (hold for 20 minutes). The carrier gas was helium. Appendix 1 provides 1 page views of the GC traces of all samples analyzed in this study. A twelve-page expanded view of the GC trace of one end member oil is provided in Appendix 2. Peak identification numbers are marked on the 12 expanded views of the GC for that sample. Data for those peaks were processed to calculate peak ratios for the statistical comparison of the oils and to calculate the production allocation splits using a proprietary geochemical production allocation software package (OilUnmixerTM v. 4.01). This package is based on a more sophisticated version of Equation 1. The method used by the OilUnmixerTM v. 4.01 software differs from the hypothetical example described in the previous section in that it has a more sophisticated method for: (i) dealing with analytical uncertainty, (ii) assessing the validity of end member (zone specific) calibration samples, (iii) looking for contamination in the end members, and (iv) “testing” the validity of the allocation results. Figure 1: PCA diagram showing compositional differences among the oils based on Euclidian distance. The shorter the Euclidian distance between any two samples, the more similar they are in composition. BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 6 As an independent check on allocation results and to help identify which of the Put River end member oils should be used for allocation, we performed a multivariate statistical comparison of the GC data for the 5 oils using Principal Component Analysis (PCA). The PCA diagram is shown in Figure 1 and is based on 20 GC peak height ratios in (Table 4). The Principle Component diagram in Figure 1 shows the compositional similarity and dissimilarity among the three “single-zone” end member samples and the two commingled oils. The Principal Components analysis (PCA) transforms a number of possibly correlated variables (a similarity matrix) into a two dimensional plot called principal components based on Euclidian distance. The first principal axis accounts for as much of the variability in the data as possible and the second axis accounts for as much of the remaining variability as possible. In general, the shorter the Euclidian distance between any two samples, the more similar they are in composition. Figure 1 shows the Ivishak end-member plots on the far right of the PCA diagram whereas the two (possible) end-member oils for the Put River Fm. plot on the far left of the diagram. Noteworthy is that the Put River samples and the Ivishak sample are separated by a relatively large Euclidian distance. The two commingled oils from the 15-41B well plot between the end-member oils and plot closer to the Ivishak end-member oil than the Put River end-member oils. This observation is not incongruous with the allocation result we have reported (in Table 2) that the commingled oils are dominantly Put River oil, since the PCA diagram is constructed using compound ratios, not compound concentrations, and therefore, plot location on the PCA diagram cannot be converted directly into allocation percentages (allocation percentages are calculated using the method described elsewhere in this report). The Put River sample collected on July 24, 2018 indicates likely contamination with Ivishak oil since it plots closer to the Ivishak end-member than the Put River sample collected on July 22, 2018. When used as an end-member for allocation, the contaminated Put River sample (collected on July 24, 2018) will cause the allocation result for the for the Put River contribution to the commingled oil to be too high (see Table 3 below). For example, comparison of the allocation results in Table 3 to allocation results in Table 2 show a larger contribution of Put River. Table 3: Allocation results for commingled oils from 15-41B well using the contaminated Put River end-member oil (collected July 24, 2018). Commingled Oil Date Collected % *Put River % Ivishak Quality of Solution 15-41B Sept. 27, 2019 75% (± 2.00%) 25% (± 2.92%) Very Good 15-41B Aug. 19, 2019 80% (± 1.42%) 20% (± 2.08%) Excellent (*Results reported in Table 3 are calculated using the Put River end-member oil collected July 24, 2018.) Because the Put River end-member oil collected on July 24, 2018 is partly contaminated with Ivishak oil (as shown on the PCA diagram in Figure 1) the effect will be to BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 7 erroneously raise the calculated allocation result for the Put River contribution in the allocation result (as shown in Table 3). As an illustration, consider the example shown below in Figure 2. Figure 2: Contamination of the Put River end member with oil from the Ivishak raises the apparent contribution of Put River oil to any commingled oils that are allocated using the contaminated Put River end member. This concept is illustrated by the two diagrams shown above. In the top diagram, both end member oils are pure oil from their respective zones. The commingled oil in that diagram has a composition of exactly half-way between the compositions of the two end members, and is correctly allocated as a 50/50 mix of oil from the Put River and Ivishak. In the bottom diagram, the Put River end member is contaminated with 25% Ivishak oil (so the Put-River end member plots closer to the Ivishak end member). The effect of this contamination on the allocation results is to erroneously increase the calculated Put River contribution to 67%. (Figure 2 is modified from Figure 8 in McCaffrey et al., 2011.) V. REFERENCES Hwang, R. J., Ahmed A. S. and Moldowan J. M. (1994). Oil composition variation and reservoir continuity: Unity Field, Sudan. Organic Geochemistry 21(2), 171-188. Hwang, R. J. and Baskin D. K. (1994). Reservoir connectivity and oil homogeneity in a large- scale reservoir. Middle East Petroleum Geoscience Geo 94 2, 529-541. Hwang, R. J., D. K. Baskin, et al. (1999). Allocation of commingled pipeline oils to field production. Abstracts, 19th Internatisonal Meeting on Organic Geochemistry. Istanbul, Turkey, Tubitak Marmara Research Center Earth Sciences Research Institute. Vol. II: p. 602. Hwang, R. J., D. K. Baskin, and S. C. Teerman, 2000, Allocation of commingled pipeline oils to field production: Org. Geochem., v. 31, p. 1463-1474. Kaufman, R. L., A. S. Ahmed, and W. B. Hempkins, 1987, A new technique for the analysis of commingled oils and its application to production allocation calculations, paper IPA 87-23/21: 16th Annual Indonesian Petro. Assoc., p. 247-268. BP Alaska Allocation Project 19-2531 Stratum Reservoir Page 8 Kaufman, R. L., Ahmed A. S. and Elsinger R. J. (1990). Gas Chromatography as a development and production tool for fingerprinting oils from individual reservoirs: applications in the Gulf of Mexico. In: Proceedings of the 9th Annual Research Conference of the Society of Economic Paleontologists and Mineralogists. (D. Schumaker and B. F. Perkins, Ed.), New Orleans. 263- 282. McCaffrey, M. A., Legarre H. A. and Johnson S. J. (1996). Using biomarkers to improve heavy oil reservoir management: An example from the Cymric field, Kern County, California. American Association of Petroleum Geologists Bulletin 80(6), 904-919. McCaffrey, M. A., D. H. Ohms., M. Werner, C. Stone, D. K. Baskin, and B. A. Patterson (2011) Geochemical allocation of commingled oil production or commingled gas production. Society of Petroleum Engineers Paper Number 144618. p 1-19. McCaffrey, M. A., D. K. Baskin, B. A. Patterson, D. H. Ohms., C. Stone, D. Reisdorf (2012) Oil fingerprinting dramatically reduces production allocation costs. World Oil, March 2012, p 55-59. Slentz, L. W. (1981). Geochemistry of reservoir fluids as unique approach to optimum reservoir management. SPE #9582. Presented at Middle East Oil Technical Conference, Manama, Baharain. Peak1/Peak2 819.0/821.6 829.6/844.4 835.9/847.3 858.2/864.2 865.3/875.0 871.8/884.9 879.6/894.0 911.5/919.2 921.0/922.6 935.3/945.9 15-41B Commingled 8/19/19 0.367 0.624 0.989 0.412 0.559 2.854 0.417 2.955 0.319 0.961 15-41B Commingled 9/27/19 0.289 0.481 0.841 0.501 0.438 2.478 0.352 3.533 0.272 0.762 Put River End Member 7/22/18 0.385 0.695 1.019 0.398 0.618 2.969 0.425 2.854 0.331 0.979 Put River End Member 7/24/18 0.373 0.653 0.986 0.411 0.589 2.884 0.412 2.975 0.314 0.936 Ivishak End Member 11/7/18 0.259 0.457 0.743 0.571 0.388 2.139 0.308 3.921 0.236 0.7 942.2/953.7 961.2/967.2 965.5/977.6 1046.7/1058.8 1510.6/1521.1 1515.0/1525.1 1564.7/1575.1 1739.4/1748.9 1834.1/1829.9 1864.6/1878.7 0.898 2.631 0.552 1.037 0.439 0.245 2.775 1.397 4.059 0.726 0.738 2.292 0.454 1.18 0.477 0.279 3.131 1.317 3.928 0.792 0.906 2.682 0.563 1.035 0.602 0.35 3.763 0.982 2.868 1.003 0.891 2.61 0.54 1.07 0.566 0.322 3.542 1.07 3.125 0.946 0.664 1.986 0.4 1.411 0.483 0.286 3.045 1.315 3.877 0.752 Table 4: Peak height ratios used to construct principal component diagram (Figure 1). Table 5: Peak heights used to allocate the commingled oils. Well Name 15-41B 15-41B 15-41B 15-17 Name of Zone Commingled Commingled Put River Ivishak Collection Date 19-Aug-19 27-Sep-19 22-Jul-18 7-Nov-18 Peak G6191838 G6191837 G6191839 G6191841 821.6 1228.000 1420.000 1733.000 772.000 823.1 2287.000 2160.000 3322.000 1098.000 827.0 15230.000 17457.000 21373.000 9249.000 829.6 6140.000 5748.000 9223.000 2809.000 832.4 10801.000 11981.000 15365.000 6531.000 834.6 1056.000 1172.000 1532.000 632.000 835.9 2879.000 2775.000 4270.000 1392.000 837.7 855.000 895.000 1229.000 487.000 839.0 1094.000 1177.000 1588.000 633.000 840.6 679.000 727.000 992.000 387.000 844.4 9841.000 11948.000 13272.000 6141.000 846.0 2200.000 2398.000 3190.000 1301.000 847.3 2911.000 3298.000 4192.000 1873.000 853.3 22734.000 27417.000 29823.000 15095.000 856.1 4530.000 4640.000 6635.000 2463.000 858.2 1933.000 2409.000 2736.000 1460.000 861.2 926.000 967.000 1351.000 538.000 864.2 4691.000 4809.000 6873.000 2558.000 865.3 6031.000 6111.000 8929.000 3227.000 871.8 7288.000 7603.000 10790.000 4092.000 875.0 10794.000 13955.000 14455.000 8315.000 882.7 4894.000 5775.000 6946.000 3628.000 884.9 2554.000 3068.000 3634.000 1913.000 887.8 548.000 642.000 785.000 397.000 889.4 625.000 734.000 894.000 447.000 908.5 1979.000 2573.000 2824.000 1683.000 911.5 3877.000 4996.000 5428.000 3478.000 913.9 1935.000 2420.000 2731.000 1655.000 916.7 1074.000 1234.000 1545.000 797.000 919.2 1312.000 1414.000 1902.000 887.000 921.0 222.000 240.000 323.000 148.000 922.6 695.000 882.000 977.000 628.000 925.0 6437.000 8126.000 9109.000 5567.000 929.5 2012.000 2479.000 2860.000 1670.000 931.3 931.000 1051.000 1337.000 689.000 935.3 6496.000 7052.000 9418.000 4562.000 938.0 4588.000 6157.000 6435.000 4314.000 940.4 1144.000 1319.000 1632.000 896.000 Table 5: Peak heights used to allocate the commingled oils. 942.2 3359.000 3792.000 4810.000 2523.000 944.1 887.000 1091.000 1251.000 784.000 945.9 6760.000 9254.000 9624.000 6513.000 947.8 2757.000 3805.000 3962.000 2599.000 951.2 2238.000 2916.000 3185.000 2272.000 953.7 3741.000 5140.000 5311.000 3799.000 955.4 1883.000 2242.000 2687.000 1589.000 956.6 1196.000 1432.000 1729.000 1004.000 958.1 732.000 943.000 1039.000 713.000 961.2 1460.000 1682.000 2092.000 1142.000 962.7 6965.000 8751.000 9977.000 6371.000 965.5 5058.000 5880.000 7307.000 4054.000 967.2 555.000 734.000 780.000 575.000 968.8 1435.000 1836.000 2053.000 1399.000 971.8 4225.000 5010.000 6084.000 3572.000 977.6 9162.000 12948.000 12985.000 10124.000 979.7 2089.000 2704.000 2966.000 2088.000 982.2 3119.000 4045.000 4464.000 3095.000 983.7 774.000 984.000 1111.000 751.000 985.7 797.000 1044.000 1134.000 826.000 987.4 724.000 947.000 1038.000 723.000 992.5 1469.000 1951.000 2077.000 1585.000 995.4 1758.000 2375.000 2485.000 1931.000 1006.7 1869.000 2503.000 2644.000 2062.000 1009.7 1102.000 1514.000 1572.000 1254.000 1016.1 915.000 1141.000 1337.000 892.000 1017.4 858.000 1139.000 1219.000 978.000 1019.7 1687.000 2237.000 2422.000 1869.000 1022.3 968.000 1298.000 1394.000 1114.000 1024.6 5652.000 6758.000 8185.000 5179.000 1027.7 3253.000 4482.000 4691.000 3771.000 1029.7 950.000 1180.000 1373.000 937.000 1032.4 2219.000 2974.000 3161.000 2508.000 1033.8 1052.000 1471.000 1515.000 1255.000 1036.4 3564.000 4956.000 5152.000 4186.000 1040.2 3499.000 4684.000 5063.000 3950.000 1043.4 1793.000 2517.000 2587.000 2225.000 1046.7 2224.000 3181.000 3209.000 3116.000 1051.1 2092.000 2974.000 2997.000 2668.000 1053.3 700.000 910.000 1024.000 763.000 1054.8 594.000 788.000 867.000 684.000 1058.8 2144.000 2695.000 3100.000 2208.000 1061.7 3630.000 4838.000 5233.000 4233.000 Table 5: Peak heights used to allocate the commingled oils. 1063.2 1640.000 2330.000 2377.000 2196.000 1065.4 2935.000 3788.000 4314.000 3089.000 1067.3 1422.000 1978.000 2047.000 1909.000 1069.1 1471.000 2114.000 2158.000 2011.000 1071.5 2504.000 3247.000 3674.000 2748.000 1074.7 873.000 1231.000 1264.000 1174.000 1081.5 1232.000 1705.000 1787.000 1570.000 1083.2 1241.000 1693.000 1781.000 1546.000 1087.5 1928.000 2693.000 2808.000 2668.000 1089.6 1394.000 1943.000 2039.000 1833.000 1095.4 748.000 1042.000 1082.000 1011.000 1097.4 408.000 571.000 598.000 539.000 1107.6 717.000 983.000 1052.000 952.000 1109.7 621.000 851.000 900.000 829.000 1114.4 714.000 985.000 1057.000 939.000 1116.3 517.000 710.000 761.000 683.000 1119.9 2452.000 3380.000 3568.000 3666.000 1121.9 931.000 1317.000 1361.000 1327.000 1125.1 710.000 974.000 1059.000 922.000 1129.1 2213.000 2978.000 3242.000 2938.000 1131.1 2590.000 3631.000 3825.000 3699.000 1134.6 1549.000 2170.000 2269.000 2466.000 1135.7 1450.000 1996.000 2128.000 1974.000 1142.1 969.000 1364.000 1436.000 1418.000 1146.3 928.000 1289.000 1353.000 1360.000 1151.9 1440.000 2004.000 2121.000 2212.000 1156.6 3330.000 4469.000 4565.000 4809.000 1159.1 740.000 1048.000 1089.000 1146.000 1160.8 1838.000 2528.000 2715.000 2457.000 1165.1 2886.000 3988.000 4345.000 3846.000 1171.4 2244.000 3087.000 3309.000 3171.000 1175.5 892.000 1226.000 1302.000 1449.000 1178.8 968.000 1336.000 1423.000 1527.000 1182.3 893.000 1222.000 1307.000 1433.000 1183.9 1041.000 1444.000 1540.000 1618.000 1185.3 771.000 1069.000 1145.000 1170.000 1188.5 1009.000 1415.000 1496.000 1492.000 1192.2 564.000 778.000 826.000 907.000 1194.0 852.000 1168.000 1258.000 1388.000 1209.9 527.000 725.000 783.000 840.000 1212.4 540.000 755.000 820.000 850.000 1216.0 4039.000 5558.000 6000.000 5818.000 1222.0 1399.000 1915.000 2099.000 2306.000 Table 5: Peak heights used to allocate the commingled oils. 1227.9 430.000 583.000 630.000 730.000 1230.4 715.000 960.000 1060.000 1157.000 1235.7 1463.000 2001.000 2163.000 2393.000 1239.2 898.000 1231.000 1358.000 1489.000 1244.6 865.000 1131.000 1195.000 1408.000 1251.3 530.000 704.000 779.000 889.000 1253.8 900.000 1238.000 1339.000 1385.000 1255.8 1313.000 1781.000 1959.000 2089.000 1260.4 1372.000 1884.000 2062.000 2165.000 1265.0 1756.000 2375.000 2652.000 2768.000 1268.6 4392.000 5442.000 5408.000 6447.000 1271.4 1474.000 2009.000 2240.000 2357.000 1273.6 333.000 423.000 465.000 555.000 1276.0 3245.000 4511.000 5020.000 5114.000 1279.7 798.000 1075.000 1186.000 1357.000 1283.3 3457.000 4260.000 4167.000 5223.000 1287.7 978.000 1278.000 1448.000 1670.000 1292.7 548.000 711.000 795.000 909.000 1297.1 572.000 736.000 804.000 937.000 1306.6 437.000 558.000 611.000 716.000 1311.8 598.000 775.000 836.000 956.000 1313.7 415.000 562.000 628.000 694.000 1319.9 1216.000 1623.000 1841.000 2015.000 1326.3 437.000 560.000 614.000 717.000 1329.2 131.000 160.000 181.000 205.000 1340.0 1158.000 1450.000 1607.000 1855.000 1342.8 670.000 863.000 976.000 1102.000 1349.7 705.000 838.000 803.000 1024.000 1352.1 929.000 1213.000 1367.000 1540.000 1354.9 798.000 1038.000 1194.000 1340.000 1359.8 1176.000 1502.000 1776.000 1981.000 1364.9 1791.000 2302.000 2640.000 2999.000 1371.5 1153.000 1442.000 1715.000 1916.000 1379.4 3946.000 5065.000 5678.000 6493.000 1383.7 526.000 639.000 672.000 793.000 1387.6 269.000 332.000 385.000 433.000 1390.3 714.000 879.000 999.000 1136.000 1393.2 2281.000 2592.000 2465.000 3240.000 1396.2 2224.000 2567.000 2481.000 3204.000 1405.9 828.000 1050.000 1191.000 1368.000 1423.0 414.000 504.000 552.000 650.000 1426.3 637.000 733.000 685.000 911.000 1431.4 285.000 332.000 347.000 424.000 Table 5: Peak heights used to allocate the commingled oils. 1434.8 374.000 460.000 505.000 588.000 1440.3 230.000 277.000 310.000 357.000 1442.3 125.000 156.000 187.000 200.000 1444.5 842.000 1019.000 1093.000 1275.000 1446.1 700.000 848.000 924.000 1063.000 1451.2 668.000 810.000 896.000 1038.000 1454.2 509.000 632.000 724.000 812.000 1456.1 664.000 748.000 713.000 936.000 1459.4 947.000 1146.000 1275.000 1468.000 1465.2 3523.000 4357.000 5049.000 5594.000 1471.5 872.000 1060.000 1211.000 1366.000 1476.4 249.000 287.000 312.000 369.000 1479.9 815.000 899.000 869.000 1148.000 1483.5 560.000 679.000 751.000 860.000 1486.8 196.000 231.000 251.000 285.000 1488.8 240.000 273.000 264.000 339.000 1495.1 743.000 809.000 800.000 1038.000 1506.0 1111.000 1201.000 1128.000 1527.000 1510.6 357.000 419.000 468.000 540.000 1515.0 148.000 181.000 201.000 234.000 1518.3 205.000 233.000 234.000 296.000 1521.1 814.000 879.000 778.000 1119.000 1525.1 603.000 648.000 575.000 818.000 1530.2 206.000 246.000 264.000 310.000 1533.0 126.000 150.000 161.000 187.000 1535.9 418.000 463.000 445.000 578.000 1538.6 813.000 867.000 790.000 1089.000 1543.3 298.000 334.000 323.000 421.000 1549.2 1312.000 1504.000 1515.000 1915.000 1553.6 650.000 735.000 744.000 927.000 1559.4 1017.000 1158.000 1174.000 1451.000 1564.7 1035.000 1215.000 1268.000 1495.000 1568.9 648.000 738.000 772.000 924.000 1571.8 1006.000 1125.000 1114.000 1431.000 1575.1 373.000 388.000 337.000 491.000 1580.6 262.000 280.000 249.000 358.000 1584.6 132.000 138.000 122.000 178.000 1590.7 440.000 470.000 400.000 586.000 1595.1 594.000 663.000 648.000 834.000 1609.3 419.000 464.000 454.000 583.000 1612.8 281.000 301.000 281.000 377.000 1617.2 285.000 300.000 269.000 374.000 1638.3 235.000 247.000 235.000 314.000 Table 5: Peak heights used to allocate the commingled oils. 1647.0 663.000 714.000 685.000 911.000 1652.9 2613.000 2916.000 2981.000 3636.000 1659.2 569.000 637.000 622.000 800.000 1661.9 455.000 478.000 418.000 600.000 1672.0 1066.000 1128.000 1028.000 1423.000 1690.8 336.000 352.000 306.000 438.000 1710.3 3244.000 3572.000 3659.000 4555.000 1730.5 155.000 158.000 142.000 199.000 1739.4 623.000 619.000 442.000 789.000 1744.9 380.000 402.000 377.000 513.000 1748.9 446.000 470.000 450.000 600.000 1753.0 358.000 384.000 342.000 476.000 1756.4 702.000 741.000 680.000 931.000 1764.7 701.000 753.000 676.000 942.000 1768.6 225.000 233.000 193.000 280.000 1772.1 387.000 414.000 380.000 524.000 1790.4 235.000 230.000 173.000 298.000 1794.6 280.000 270.000 206.000 335.000 1814.2 2219.000 2304.000 2110.000 2914.000 1824.6 187.000 182.000 137.000 226.000 1829.9 85.000 83.000 76.000 106.000 1834.1 345.000 326.000 218.000 411.000 1839.4 229.000 227.000 193.000 287.000 1852.7 251.000 246.000 216.000 311.000 1856.3 378.000 364.000 260.000 466.000 1861.1 659.000 633.000 473.000 821.000 1864.6 377.000 384.000 333.000 473.000 1872.5 399.000 410.000 340.000 505.000 1878.7 519.000 485.000 332.000 629.000 1883.6 453.000 428.000 294.000 553.000 1888.4 112.000 113.000 93.000 139.000 1907.0 244.000 228.000 173.000 293.000 1917.3 322.000 309.000 234.000 390.000 1921.9 127.000 120.000 93.000 156.000 1927.9 70.000 67.000 46.000 85.000 1932.6 187.000 174.000 123.000 223.000 1942.5 297.000 290.000 230.000 359.000 1948.3 184.000 174.000 138.000 216.000 1952.3 132.000 125.000 100.000 155.000 1961.8 327.000 314.000 220.000 393.000 1964.7 530.000 520.000 398.000 645.000 1972.7 334.000 320.000 241.000 403.000 1977.7 212.000 190.000 130.000 244.000 Table 5: Peak heights used to allocate the commingled oils. 1987.9 210.000 203.000 166.000 251.000 1995.3 520.000 474.000 296.000 602.000 15 Appendix 1 This appendix provides a one-page chromatogram of each whole oil sample analyzed as part of this report. Each of these pages shows the distribution and amount of hydrocarbon compounds between the regions of about n-C4 to n-C41 (although the paraffins are only numbered through ~n-C40). A detailed view of the individual peaks can be readily seen on the 12 page expanded view of one of the GC traces in Appendix 2. Sample GC File Client Id Site Name Sample Id Collection Date Remarks Notes Commingled Put River/Ivishak G6191837.D 00600397-001 15-41B BP077133 Friday, September 27, 2019 10:52:00 AM TEST SEPERATOR Sample GC File Client Id Site Name Sample Id Collection Date Remarks Notes Put River End Member G6191839.D 10004086-002 15-41B BP072879 Sunday, July 22, 2018 9:26:00 AM TEST UNIT #6 Sample GC File Client Id Site Name Sample Id Collection Date Remarks Notes Put River End Member G6191840.D 10004086-003 15-41B BP072880 Tuesday, July 24, 2018 1:26:00 PM TEST UNIT #6 Sample GC File Client Id Site Name Sample Id Collection Date Remarks Notes Ivishak End Member G6191841.D 10004092-001 15-17 BP073589 Wednesday, November 07, 2018 1:27:00 PM T/S, S/R, PRUDOE BAY UNIT Appendix 2 This appendix provides a 8-page expanded view of the n-C8 to n-C14 region of the Gas Chromatogram of ONE of the samples analyzed. This 8 page expanded view is provided so that the GC peaks used in this study can be readily identified. Each of these 8 pages shows the distribution of compounds between two paraffins (e.g., the first page shows the C8-C9 portion of the chromatogram, the second page shows the C9-C10 portion of the chromatogram, etc.). The peaks in Table 3 through 6 are marked on the expanded view of this sample. These peaks cannot be readily seen on the one-page GC traces in Appendix 1 because the chromatograms in Appendix 1 are too compressed. Appendix 3 For each allocation result presented in Table 1, we have included in Appendix 3 a table and two figures corresponding to that allocation result. The table and two figures provide the details on the uncertainty (i.e., “goodness of fit”) associated with the allocation result for that sample. NEITHER FIGURE has anything to do with HOW the allocation solution was derived; rather, these figures simply represent a way to visualize the solution and visually assess its goodness of fit. The table lists the commingled sample ID, names of the commingled zones, the names of the end member samples used in the allocation, the number of peaks used and rejected by the OilUnmixer software, and the wt.% contribution of each end member calculated by the software. In addition, the % Error at various confidence levels for each contributing horizon is also calculated. The smaller the % Error, the better the better the DEGREE of FIT of the data. The first figure for each sample is a “star diagram”. Each axis on the diagram shows the ratio of two GC peaks. The black star shows the composition of the commingled oil, and the red star shows the composition of a “theoretical” oil corresponding to the allocation solution yielded by the OilUnmixer software. If the allocation solution were perfect, then the red and black stars would overlay one another perfectly. The second figure shows GC peak HEIGHTS (not ratios) in the commingled oil, the end member oils and a “theoretical” oil corresponding to the allocation solution yielded by the OilUnmixer software. If the allocation solution were perfect, then the traces for the commingled and theoretical oil would overlay one another perfectly. The trace labeled as “scaled” corresponds to the commingled oil corrected for calculated differences in injection volume. Summary of Allocation Results Commingled Well:15-41B Date of Collection of Commingled Oil:9/27/2019 Commingled Oil GC File:G6191837 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:254 Number Of GC Peaks Rejected:1 GC Peaks Rejected:829.6 Allowed Impact of Each Peak on Solution:1.00 % Number Of End Members:2 Names Of End Members:15-41B Put River G6191839 7-22-2018 15-17 Ivishak G6191841 11-7-2018 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.6220 64.82% 2.14% 2.74% 3.26% 3.87% 4.29% %Ivishak 0.3375 35.18% 3.36% 4.31% 5.13% 6.09% 6.75% Totals 0.9595 100.00% 0 0.5 1 1.5 2 2.5 3 3.5 4 Pk 821.6/823.1Pk 834.6/835.9Pk 840.6/844.4Pk 853.3/856.1Pk 864.2/865.3Pk 882.7/884.9Pk 908.5/911.5 Pk 919.2/921.0 Pk 929.5/931.3 Pk 940.4/942.2 Pk 947.8/951.2 Pk 956.6/958.1 Pk 965.5/967.2 Pk 977.6/979.7 Pk 985.7/987.4 Pk 1006.7/1009.7 Pk 1019.7/1022.3 Pk 1029.7/1032.4 Pk 1040.2/1043.4 Pk 1053.3/1054.8 Pk 1063.2/1065.4 Pk 1071.5/1074.7 Pk 1087.5/1089.6 Pk 1107.6/1109.7 Pk 1119.9/1121.9 Pk 1131.1/1134.6Pk 1146.3/1151.9Pk 1160.8/1165.1Pk 1178.8/1182.3Pk 1188.5/1192.2Pk 1212.4/1216.0Pk 1230.4/1235.7Pk 1251.3/1253.8Pk 1265.0/1268.6Pk 1276.0/1279.7Pk 1292.7/1297.1Pk 1313.7/1319.9Pk 1340.0/1342.8Pk 1354.9/1359.8 Pk 1379.4/1383.7 Pk 1393.2/1396.2 Pk 1426.3/1431.4 Pk 1442.3/1444.5 Pk 1454.2/1456.1 Pk 1471.5/1476.4 Pk 1486.8/1488.8 Pk 1510.6/1515.0 Pk 1525.1/1530.2 Pk 1538.6/1543.3 Pk 1559.4/1564.7 Pk 1575.1/1580.6 Pk 1595.1/1609.3 Pk 1638.3/1647.0 Pk 1661.9/1672.0 Pk 1730.5/1739.4 Pk 1753.0/1756.4 Pk 1772.1/1790.4 Pk 1824.6/1829.9Pk 1852.7/1856.3Pk 1872.5/1878.7Pk 1907.0/1917.3Pk 1932.6/1942.5Pk 1961.8/1964.7Pk 1987.9/1995.3 15-41B 9-27-2019 G6191837 15-41B Put River 15-17 Ivishak 15-41B 9-27-2019 G6191837 Artificial 64:35 0 5000 10000 15000 20000 25000 30000 35000 821.6846.0882.7922.6947.8968.81006.71033.81063.21095.41131.11171.41212.41255.81292.71349.71393.21446.11486.81533.01575.11652.91753.01834.11907.01972.715-41B 9-27-2019 G6191837 15-41B Put River 7-22-2018 G6191839 15-17 Ivishak 11-7-2018 G6191841 Commingled Scaled 102.41% Artificial 64:35 Summary of Allocation Results Commingled Well:15-41B Date of Collection of Commingled Oil:8/19/2019 Commingled Oil GC File:G6191838 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:255 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.00 % Number Of End Members:2 Names Of End Members:15-41B Put River G6191839 7-22-2018 15-17 Ivishak G6191841 11-7-2018 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.5523 69.03% 1.56% 2.00% 2.38% 2.82% 3.13% %Ivishak 0.2479 30.97% 2.47% 3.17% 3.77% 4.48% 4.96% Totals 0.8002 100.00% 0 0.5 1 1.5 2 2.5 3 3.5 4 Pk 821.6/823.1Pk 832.4/834.6Pk 839.0/840.6Pk 847.3/853.3Pk 861.2/864.2Pk 875.0/882.7Pk 889.4/908.5Pk 916.7/919.2 Pk 925.0/929.5 Pk 938.0/940.4 Pk 945.9/947.8 Pk 955.4/956.6 Pk 962.7/965.5 Pk 971.8/977.6 Pk 983.7/985.7 Pk 995.4/1006.7 Pk 1017.4/1019.7 Pk 1027.7/1029.7 Pk 1036.4/1040.2 Pk 1051.1/1053.3 Pk 1061.7/1063.2 Pk 1069.1/1071.5 Pk 1083.2/1087.5 Pk 1097.4/1107.6 Pk 1116.3/1119.9 Pk 1129.1/1131.1Pk 1142.1/1146.3Pk 1159.1/1160.8Pk 1175.5/1178.8Pk 1185.3/1188.5Pk 1209.9/1212.4Pk 1227.9/1230.4Pk 1244.6/1251.3Pk 1260.4/1265.0Pk 1273.6/1276.0Pk 1287.7/1292.7Pk 1311.8/1313.7Pk 1329.2/1340.0Pk 1352.1/1354.9Pk 1371.5/1379.4 Pk 1390.3/1393.2 Pk 1423.0/1426.3 Pk 1440.3/1442.3 Pk 1451.2/1454.2 Pk 1465.2/1471.5 Pk 1483.5/1486.8 Pk 1506.0/1510.6 Pk 1521.1/1525.1 Pk 1535.9/1538.6 Pk 1553.6/1559.4 Pk 1571.8/1575.1 Pk 1590.7/1595.1 Pk 1617.2/1638.3 Pk 1659.2/1661.9 Pk 1710.3/1730.5 Pk 1748.9/1753.0 Pk 1768.6/1772.1 Pk 1814.2/1824.6Pk 1839.4/1852.7Pk 1864.6/1872.5Pk 1888.4/1907.0Pk 1927.9/1932.6Pk 1952.3/1961.8Pk 1977.7/1987.9 15-41B 8-19-2019 G6191838 15-41B Put River 15-17 Ivishak 15-41B 8-19-2019 G6191838 Artificial 69:30 Geochemical Allocation of Four Oils from the 15-41B Well with Identification of New End-Member Oils for the Ivishak and Put River Formations, North Slope, Alaska Stratum Reservoir Project No. BH-102366 (OilTracers Report No. 20-2575) By Matthew M. Laughland, Ph.D. Prepared for BP Alaska February 2020 CONFIDENTIAL Stratum Reservoir 3141 Hood St., Suite 103 Dallas, TX 75219 Telephone: 214-732-7174 www.stratumreservoir.com email: matt.laughland@stratumreservoir.com BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 1 Table of Contents I. Introduction................................................................................................... 2 II. Conclusions................................................................................................... 3 Summary of the Report Structure……………….………………… 3 III. Background Information...................................................................……. 4 Allocation of Commingled Production ….........................................4 IV. Materials and Methods................................................................................. 5 V. References.................................................................................................... 8 VI. Tables............................................................................................................ 9 VII. Appendices…………………………………………………………………. 14 BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 2 I. INTRODUCTION Four samples of commingled oil that were collected from the same well 15-41B, but on different dates (August 19, 2019, September 27, 2019, October 14, 2019, and December 17, 2018), were submitted for quantitative geochemical allocation (see Table 1). The samples of produced (commingled) oil are believed to have contributions of oil from two different zones or “end-member” oils, the Put River Formation and Ivishak Formation. The main objective of this study is to determine the percent contributions of Put River and Ivishak oil in the commingled samples. Samples of oil that could serve as end-member oils for the Ivishak and Put River Formations also were analyzed (Table 1). For the Put River Fm., this includes the oil that was used as an end-member in the December 2019 study (Report 19-2531), as wells two samples of Put River oil that were archived at Stratum Reservoir. For the Ivishak Fm., this includes the oil that was used as an end-member in the December 2019 study (Report 19-2531), as well as a recently collected sample (December 30, 2019) that was provided to Stratum Reservoir. Table 1: Samples used in this study for oil allocation. Sample ID Client ID GC ID Well Name Sample Type Collection Date Purpose for Analysis BP077133 00600397-001 C G9200134.D 15-41B Commingled Put River/Ivishak 9/27/2019 Commingled oil unmixed previously in December 2019 Study (Report 19-2531) BP077149 00600397-003 C G9200135.D 15-41B Commingled Put River/Ivishak 8/19/2019 Commingled oil unmixed previously in December 2019 Study (Report 19-2531) BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample BP078607 10004455-001 C G9200137.D 15-41 Commingled Put River/Ivishak 12/17/2019 New December Sample BP072879 10004086-002 C G9200138.D 15-41B Put River (end member)7/22/2018 Put River End-Member Identified in December 2019 Study (Report 19-2531) BP072878 10004086-001 C G9200139.D 15-41B Put River 7/20/2018 Archived oil analyzed to compare to Put River end member BP072879 BP072881 10004086-004 C G9200140.D 15-41B Put River 7/25/2018 Archived oil analyzed to compare to Put River end member BP072879 BP073589 10004092-001 C G9200141.D 15-17 Ivishak (end member) 11/7/2018 Ivishak end-member used in December 2019 Study (Report 19-2531) BP078606 10003569-002 C G9200142.D 15-45B Ivishak 12/30/2019 New sample. May be possible Ivishak end-member; compare to BP073589 BP077133 00600397-001 C G9200143.D 15-41B Commingled Put River/Ivishak (dup)9/27/2019 Duplicate to assess analytical uncertainty The objectives of this study are to: (1) Determine which of the Put River and Ivishak oil samples are the more reliable end-member oils for allocation. (2) Determine the percent contribution of oil from the Put River Fm. and the Ivishak Fm. in the four commingled samples using the preferred end- member oils identified for each formation. BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 3 II. CONCLUSIONS 1.) Multi-variate statistical analysis indicates that the archived sample of Put River oil (BP072878) is the better end-member among the Put River samples analyzed in this study. This sample was used for unmixing the four commingled oils in this study. 2.) Multi-variate statistical analysis indicates that the recently collected sample of Ivishak oil (BP078606) is the better end-member among the Ivishak samples analyzed in this study. This sample was used for unmixing commingled oils in this study. 3.) Allocation results for the four commingled oils are presented in Table 2 and show differences in the contributions of Ivishak and Put River oils to the commingled oils. 4.) Allocation results achieve of Quality of Solution of “Very Good” to “Excellent”. (Note: OilUnmixer™ calculates the uncertainty in solution at the 80% confidence level as follows: Excellent <2.5%; Very Good 2.5-3.99%; Good 4-5.99%; Fair 6-6.99%; Poor 7-7.99%; No Solution >8%) Table 2: Allocation results for commingled oils from 15-41B well. (*Results reported in Table 2 are calculated using Put River end-member oil BP072878 and Ivishak end-member oil BP078606. A duplicate (dup.) analysis of commingled oil BP077133 was performed to assess analytical uncertainty.) Summary of the Report Structure: Sample descriptions are provided in Table 1. Table 2 tabulates the allocation solution for commingled samples. Table 3 lists the alternate allocation results using the contaminated Put River end member (collected July 24, 2018). Table 4 lists the GC peak ratios for the end member oils used to construct the PCA plot in Figure 1. Table 5 lists the peak height values used for the allocation calculations. One-page plots of the Gas Chromatography (GC) traces of the oils can be found in Appendix 1. An expanded view of one chromatogram is provided in Appendix 2 to allow identification of the peaks used in the allocation calculations. Appendix 3 shows the details of the allocation results for the commingled oils. Commingled Oil Date Collected %Put River %Ivishak Quality of Solution BP077149 8/19/2019 57.0% (±0.84%) 49.0% (±1.44%) Excellent BP077133 9/27/2019 49.3% (±1.81%) 50.7% (±3.11%) Very Good BP077133 (dup.) 9/27/2019 49.6% (±1.85%) 50.4% (±3.19%) Very Good BP078153 10/14/2019 72.1% (±1.72%) 27.6% (±2.96%) Very Good BP078607 12/17/2019 51.0% (±0.57%) 49.0% (±0.99%) Excellent BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 4 III. BACKGROUND INFORMATION Allocation of Commingled Production Methods for using oil compositional differences to allocate commingled production from a single well are detailed in Kaufman et al., 1987, 1990, and McCaffrey et al., 1996, 2011, and 2012. Similar methods for allocating the contribution of multiple fields to commingled pipeline production streams are discussed by Hwang et al., 1999 and 2000. In brief, production allocation is achieved by identifying chemical differences between "end-member" oils (samples of oil from each of the zones or production streams being commingled). Parameters reflecting these compositional differences are then measured in the end-member oils and in the commingled oil. The data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils. Using a simple mixing model, a single geochemical difference between oils from two sands is sufficient to allocate commingled production from those two units (e.g., Kaufman et al, 1990). By using data for several peak ratios, independent solutions to the problem can be derived, allowing the accuracy of the allocation to be assessed. Using a simple mixing model, a single geochemical difference between oils from two sands (i.e., a singe difference in the relative abundance of 1 peak on a GC trace) is sufficient to allow allocation of commingled production from those two units (e.g., Kaufman et al, 1990). By using data for several peak ratios, independent solutions to the problem can be derived, allowing the accuracy of the allocation to be assessed. Using the concentrations (not ratios) of several compounds, the commingled production from several sands (or several fields) can be allocated to the discrete units using a linear algebra approach described in detail by McCaffrey et al., 1996, 2011, and 2012. In brief, it works as follows: Consider the following hypothetical example. The concentrations of four compounds (A, B, C, and D) are measured in oils from four zones that may be contributing to a produced oil. These data can be expressed as a 4 by 4 matrix (Matrix G) where the numbers are compound concentrations. The same four compounds are then measured in a produced oil, and form a 1 by 4 matrix (Matrix D). If the produced oil came only from some combination of production from the four intervals sampled by Matrix G, then the relative contributions from the four intervals to the commingled oil could be readily determined (as Matrix M) since: M = [GTG]-1GTD Equation 1 where GT is the transpose of Matrix G. If the number of rows (compounds) in matrix G is less than the number of columns (contributing oil intervals), then no solution to the problem can be identified. However, the form in which Equation 1 is written does allow the number of compounds to exceed the number of contributing oil intervals (data for the compounds in Table 4 were used to derive the results reported in the present study). BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 5 In the current study (as well as all other production allocation projects performed by Stratum Reservoir), data were processed using a proprietary geochemical production allocation software package, OilUnmixerTM v. 4.01, developed and owned by OilTracers (now part of Stratum Reservoir). This package is based on a more sophisticated version of Equation 1. The package differs from the hypothetical matrix example described above in that it has a more sophisticated method for (i) dealing with analytical uncertainty, (ii) assessing the validity of end member (zone specific) calibration samples, (iii) looking for contamination in the end members, and (iv) “testing” the validity of the allocation results. The geochemical allocation approach described above is based on the well-established proposition that oils from separate reservoirs tend to differ from one another in composition (e.g., Slentz, 1981; Kaufman et al., 1990; Hwang and Baskin, 1994; Hwang et al., 1994). As described in the previous section of this report. When oils from discrete zones are commingled, these chemical differences between the oils can be used to assess the contribution of each zone or each field to the commingled production, as described above. IV. MATERIALS AND METHODS AND DISCUSSION The oils were analyzed by High Resolution Gas Chromatography (GC) at Stratum Reservoir (Houston, TX) using a GC equipped with a 60 m DB-1column; the injector was at 275°C, and the heating program was: 35°C (hold 5 minutes), 3°/min ramp to 320°C (hold for 20 minutes). The carrier gas was helium. Appendix 1 provides one-page views of the GC traces of all samples analyzed in this study. A twelve-page expanded view of the GC trace of the oils is provided in Appendix 2. Peak identification numbers are marked on the 12 expanded views of the GC for that sample. Data for those peaks were processed to calculate peak ratios for the statistical comparison of the oils and to calculate the production allocation splits using a proprietary geochemical production allocation software package (OilUnmixerTM v. 4.01). This package is based on a more sophisticated version of Equation 1. The method used by the OilUnmixerTM v. 4.01 software differs from the hypothetical example described in the previous section in that it has a more sophisticated method for: (i) dealing with analytical uncertainty, (ii) assessing the validity of end member (zone specific) calibration samples, (iii) looking for contamination in the end members, and (iv) “testing” the validity of the allocation results. BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 6 Figure 1: PCA diagram showing compositional differences among the oils in this study based on Euclidian distance. The shorter the Euclidian distance between any two samples, the more similar they are in composition. End-member oils identified in this study are highlighted with red box. Commingled oils show percent contributions of end-member oils based on unmixing results (see Appendix 3). As an independent check on allocation results and to help identify which of the Put River and Ivishak oils should be used as end member oils for allocation, we performed a multivariate statistical comparison of the GC data for the 9 oils (plus one duplicate analysis to assess analytical uncertainty) using Principal Component Analysis (PCA). The PCA diagram is shown in Figure 1 and is based on 21 GC peak height ratios in (Table 4). The Principle Component diagram in Figure 1 shows the compositional similarity and dissimilarity among the five possible “single-zone” end member samples (i.e., Put River and Ivishak) and the four commingled oils. The Principal Components analysis (PCA) transforms a number of possibly correlated variables (a similarity matrix) into a two- dimensional plot called principal components based on Euclidian distance. The first principal axis accounts for as much of the variability in the data as possible and the second axis accounts for as much of the remaining variability as possible. In general, the shorter the Euclidian distance between any two samples, the more similar they are in composition. Figure 1 shows that the Ivishak oil, BP078606, plots on the far left of the PCA diagram and accordingly was selected as the end-member among the two oils for the Ivishak Formation. In contrast, two Put River oils plot on the far right of the PCA diagram and one Put River oil plots on the left-hand side of the PCA diagram with the Ivishak oils. Accordingly, Put River oil BP072878 was selected as the end-member oil. Each of these end-member oils are separated by a larger Euclidian distance on the PCA plot than the BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 7 two oils (BP073589 and BP072879) that were used as end-members in the December 2020 study (OilTracers Report 19-2531). The four commingled oils (plus one duplicate of oil BP077133) from the 15-41B well plot between the end-member oils. Unmixing results (Table 2 and Appendix 3) are shown on the PCA diagram for each of the commingled oils. These results are slightly different when compared to allocation results (Table 3) reported for two of the oils, BP077133 and BP077149, as reported in the December 2019 study (Report 19-2531). This difference in unmixing result can be attributed to the selection of the two new end-member oils identified in this study. (See annotations on Figure 1 for Ivishak oil BP-073589 and Put River oil BP-072879 that were used as end-member oils in the December 2019 study, Report 19-2531). The other two commingled oils analyzed in this study, BP078153 and BP078607, were collected recently on 10/14/19 and 12/17/19, respectively, and have not been previously unmixed. Table 3: Allocation Results for Commingled Oils as Reported in Report 19-2531 (*Results reported in Table 3 were calculated using Put River oil BP-072879 and Ivishak oil BP-073589 as end-member oils as reported in the December 2019 study, Report 19-2431.) Commingled Oil Date Collected % *Put River % Ivishak Quality of Solution BP-077133 Sept. 27, 2019 65% (± 2.14%) 35% (± 1.56%) Excellent BP-077149 Aug. 19, 2019 69% (± 3.00%) 31% (± 2.47%) Very Good BP Alaska Allocation Project 20-2575 Stratum Reservoir Page 8 V. REFERENCES Hwang, R. J., Ahmed A. S. and Moldowan J. M. (1994). Oil composition variation and reservoir continuity: Unity Field, Sudan. Organic Geochemistry 21(2), 171-188. Hwang, R. J. and Baskin D. K. (1994). Reservoir connectivity and oil homogeneity in a large- scale reservoir. Middle East Petroleum Geoscience Geo 94 2, 529-541. Hwang, R. J., D. K. Baskin, et al. (1999). Allocation of commingled pipeline oils to field production. Abstracts, 19th Internatisonal Meeting on Organic Geochemistry. Istanbul, Turkey, Tubitak Marmara Research Center Earth Sciences Research Institute. Vol. II: p. 602. Hwang, R. J., D. K. Baskin, and S. C. Teerman, 2000, Allocation of commingled pipeline oils to field production: Org. Geochem., v. 31, p. 1463-1474. Kaufman, R. L., A. S. Ahmed, and W. B. Hempkins, 1987, A new technique for the analysis of commingled oils and its application to production allocation calculations, paper IPA 87-23/21: 16th Annual Indonesian Petro. Assoc., p. 247-268. Kaufman, R. L., Ahmed A. S. and Elsinger R. J. (1990). Gas Chromatography as a development and production tool for fingerprinting oils from individual reservoirs: applications in the Gulf of Mexico. In: Proceedings of the 9th Annual Research Conference of the Society of Economic Paleontologists and Mineralogists. (D. Schumaker and B. F. Perkins, Ed.), New Orleans. 263- 282. McCaffrey, M. A., Legarre H. A. and Johnson S. J. (1996). Using biomarkers to improve heavy oil reservoir management: An example from the Cymric field, Kern County, California. American Association of Petroleum Geologists Bulletin 80(6), 904-919. McCaffrey, M. A., D. H. Ohms., M. Werner, C. Stone, D. K. Baskin, and B. A. Patterson (2011) Geochemical allocation of commingled oil production or commingled gas production. Society of Petroleum Engineers Paper Number 144618. p 1-19. McCaffrey, M. A., D. K. Baskin, B. A. Patterson, D. H. Ohms., C. Stone, D. Reisdorf (2012) Oil fingerprinting dramatically reduces production allocation costs. World Oil, March 2012, p 55-59. Slentz, L. W. (1981). Geochemistry of reservoir fluids as unique approach to optimum reservoir management. SPE #9582. Presented at Middle East Oil Technical Conference, Manama, Baharain. 9 Table 4: Peak height ratios used to construct principal component diagram (Figure 1). Table 4 (cont’d): Sample ID (Collection Date) - Description 865.3/875.3 1275.9/1284.0 835.9/844.7 965.5/977.8 1128.8/1139.4 942.3/953.9 1157.1/1160.8 827.2/829.7 911.7/919.2 1740.9/1748.9 BP078153 (10/14/19) - Commingled 0.559 1.317 0.301 0.523 2.721 0.826 1.764 2.552 3.288 1.12 BP077133 (9/27/19) - Commingled 0.443 1.054 0.232 0.447 2.41 0.714 2.038 3.042 3.689 1.486 BP077149 (8/19/19) - Commingled 0.561 0.9 0.293 0.551 2.438 0.868 2.054 2.45 3.063 1.576 BP078607 (12/17/19) - Commingled 0.516 0.975 0.271 0.49 2.362 0.779 2.063 2.663 3.369 1.34 BP072879 (7/22/18) - Put River 0.617 1.177 0.317 0.557 2.545 0.873 1.939 2.314 2.981 1.083 BP072878 (7/20/18) - Put River 0.643 1.267 0.326 0.595 2.82 0.924 1.806 2.295 2.853 1.069 BP072881 (7/25/18) - Put River 0.381 0.849 0.209 0.377 1.754 0.614 2.61 3.238 4.041 1.434 BP073589 (11/7/18) - Ivishak 0.39 0.958 0.229 0.394 1.925 0.637 2.257 3.27 4.194 1.443 BP078606 (12/30/19) - Ivishak 0.373 0.742 0.203 0.376 1.726 0.608 2.719 3.35 4.164 1.476 BP077133 (9/27/19) - Commingled (dup.)0.444 1.051 0.232 0.445 2.389 0.713 2.067 3.034 3.669 1.436 1063.4/1065.4 1872.6/1880.3 1024.5/1036.6 1165.1/1175.8 948.0/961.1 1569.0/1576.0 1379.5/1393.9 1069.3/1071.4 1371.5/1381.6 1245.1/1253.7 1483.3/1485.2 0.551 1.036 1.682 3.437 2.009 2.07 2.278 0.569 1.346 0.893 1.268 0.604 0.833 1.518 3.151 2.346 1.704 1.892 0.619 1.114 0.983 1.082 0.539 0.793 1.743 3.157 1.94 1.568 1.695 0.563 1.009 1.021 0.965 0.591 0.874 1.59 3.113 2.149 1.802 1.849 0.612 1.081 1.012 1.092 0.535 1.051 1.773 3.24 1.941 2.116 2.233 0.564 1.305 0.957 1.301 0.494 1.121 1.886 3.463 1.896 2.209 2.254 0.529 1.334 0.901 1.321 0.733 0.826 1.306 2.49 2.544 1.778 1.893 0.733 1.126 1.165 1.118 0.695 0.821 1.362 2.613 2.374 1.712 1.909 0.691 1.195 1.071 1.096 0.704 0.82 1.313 2.474 2.613 1.697 1.666 0.711 1.005 1.237 1.04 0.602 0.845 1.515 3.153 2.329 1.752 1.879 0.628 1.108 0.981 1.071 Table 5: Peak heights used to allocate the commingled oils. 10 GC G9200136 G9200134 G9200135 G9200137 G9200143 Collection Date 10/14/2019 9/27/2019 8/19/2019 12/17/2019 9/27/2019 Sample ID BP078153 BP077133 BP077149 BP078607 BP077133 (Dup.) 823.1 2839.000 1972.000 2038.000 2146.000 1994.000 827.2 19525.000 15795.000 13463.000 15403.000 16016.000 829.7 7650.000 5192.000 5494.000 5785.000 5278.000 832.6 14289.000 10958.000 9781.000 11000.000 11136.000 835.9 3603.000 2500.000 2565.000 2741.000 2545.000 844.7 11963.000 10764.000 8749.000 10104.000 10973.000 846.1 2880.000 2192.000 1981.000 2230.000 2215.000 847.5 3773.000 2936.000 2552.000 2903.000 2988.000 853.5 27193.000 25266.000 20201.000 23458.000 25624.000 856.2 5786.000 4229.000 4036.000 4432.000 4281.000 864.2 5947.000 4367.000 4215.000 4597.000 4414.000 865.3 7623.000 5541.000 5364.000 5883.000 5663.000 871.8 9397.000 6969.000 6591.000 7244.000 7046.000 875.3 13626.000 12503.000 9553.000 11392.000 12759.000 882.9 6519.000 5244.000 4289.000 5093.000 5292.000 885.1 3512.000 2847.000 2325.000 2743.000 2898.000 908.7 2668.000 2298.000 1750.000 2158.000 2344.000 914.1 2599.000 2147.000 1670.000 2007.000 2172.000 925.2 8614.000 7208.000 5638.000 6804.000 7310.000 929.6 2711.000 2278.000 1779.000 2134.000 2298.000 935.3 8426.000 6292.000 5715.000 6422.000 6447.000 938.3 6255.000 5617.000 4071.000 5137.000 5673.000 942.3 4403.000 3367.000 2914.000 3345.000 3412.000 946.1 9120.000 8286.000 5858.000 7488.000 8364.000 948.0 3787.000 3454.000 2437.000 3127.000 3512.000 951.5 3196.000 2650.000 1993.000 2469.000 2692.000 953.9 5333.000 4718.000 3357.000 4296.000 4787.000 955.4 2266.000 1810.000 1480.000 1749.000 1832.000 961.1 1885.000 1472.000 1256.000 1455.000 1508.000 962.8 10523.000 8825.000 6876.000 8361.000 8957.000 965.5 6681.000 5248.000 4415.000 5184.000 5304.000 969.0 1806.000 1517.000 1134.000 1399.000 1530.000 971.8 5343.000 4259.000 3511.000 4140.000 4338.000 977.8 12784.000 11750.000 8018.000 10582.000 11930.000 979.9 2882.000 2421.000 1828.000 2262.000 2453.000 982.4 4347.000 3613.000 2723.000 3364.000 3662.000 992.7 2034.000 1737.000 1244.000 1597.000 1749.000 995.6 2474.000 2132.000 1521.000 1965.000 2162.000 1006.9 2599.000 2234.000 1592.000 2047.000 2262.000 Table 5: Peak heights used to allocate the commingled oils. 11 1009.9 1577.000 1384.000 971.000 1276.000 1411.000 1019.9 2355.000 1972.000 1440.000 1845.000 2007.000 1024.5 7944.000 6294.000 5089.000 6116.000 6413.000 1027.9 4741.000 4072.000 2875.000 3737.000 4119.000 1032.5 3245.000 2772.000 1999.000 2568.000 2794.000 1036.6 4722.000 4145.000 2920.000 3846.000 4233.000 1040.2 4953.000 4173.000 3049.000 3923.000 4240.000 1043.6 2615.000 2285.000 1584.000 2100.000 2297.000 1047.1 3280.000 2901.000 1981.000 2667.000 2951.000 1051.3 2948.000 2597.000 1790.000 2405.000 2634.000 1058.7 2982.000 2404.000 1837.000 2292.000 2441.000 1061.7 5277.000 4446.000 3251.000 4210.000 4530.000 1065.4 4188.000 3453.000 2611.000 3243.000 3483.000 1067.5 2017.000 1769.000 1229.000 1656.000 1793.000 1069.3 2123.000 1915.000 1285.000 1774.000 1944.000 1071.4 3733.000 3096.000 2283.000 2899.000 3097.000 1074.9 1323.000 1138.000 790.000 1060.000 1164.000 1081.6 1780.000 1526.000 1069.000 1412.000 1526.000 1083.3 1827.000 1550.000 1089.000 1433.000 1555.000 1087.6 2485.000 2147.000 1487.000 2018.000 2196.000 1089.7 2059.000 1762.000 1227.000 1648.000 1782.000 1125.1 1115.000 925.000 657.000 879.000 935.000 1128.8 3058.000 2555.000 1843.000 2416.000 2587.000 1131.3 3799.000 3292.000 2271.000 3095.000 3330.000 1138.0 1736.000 1543.000 1060.000 1443.000 1562.000 1152.2 1981.000 1789.000 1234.000 1681.000 1796.000 1157.1 4775.000 4604.000 3293.000 4414.000 4676.000 1160.8 2707.000 2259.000 1603.000 2140.000 2262.000 1165.1 4262.000 3513.000 2497.000 3337.000 3563.000 1171.4 3499.000 3039.000 2146.000 2901.000 3066.000 1179.1 1281.000 1140.000 817.000 1102.000 1165.000 1184.0 1522.000 1338.000 927.000 1274.000 1343.000 1188.6 1436.000 1234.000 864.000 1172.000 1242.000 1194.3 1141.000 1001.000 714.000 987.000 1034.000 1212.5 838.000 720.000 501.000 691.000 722.000 1215.9 5937.000 4846.000 3491.000 4725.000 4999.000 1222.2 1935.000 1733.000 1226.000 1669.000 1762.000 1235.8 2157.000 1862.000 1342.000 1807.000 1883.000 1239.3 1430.000 1272.000 905.000 1234.000 1273.000 1245.1 1322.000 1258.000 940.000 1253.000 1269.000 1253.7 1480.000 1280.000 921.000 1238.000 1293.000 1255.7 1704.000 1480.000 1043.000 1433.000 1486.000 1260.3 1908.000 1649.000 1171.000 1594.000 1655.000 Table 5: Peak heights used to allocate the commingled oils. 12 1264.9 2807.000 2393.000 1689.000 2286.000 2409.000 1269.1 4800.000 5100.000 3983.000 5170.000 5180.000 1271.3 2162.000 1886.000 1325.000 1796.000 1876.000 1275.9 4889.000 4093.000 2841.000 3916.000 4155.000 1279.9 1183.000 1057.000 772.000 1049.000 1059.000 1284.0 3711.000 3884.000 3156.000 4017.000 3954.000 1287.7 1364.000 1180.000 862.000 1185.000 1212.000 1319.8 1744.000 1511.000 1099.000 1490.000 1522.000 1340.2 1526.000 1421.000 1069.000 1414.000 1426.000 1342.9 922.000 842.000 643.000 850.000 847.000 1352.1 1318.000 1187.000 894.000 1196.000 1202.000 1354.8 1246.000 1110.000 845.000 1110.000 1133.000 1359.7 1622.000 1408.000 1064.000 1437.000 1447.000 1364.9 2337.000 2033.000 1539.000 2058.000 2037.000 1371.5 1557.000 1403.000 1064.000 1409.000 1413.000 1379.5 5398.000 4878.000 3716.000 4901.000 4896.000 1381.6 1157.000 1259.000 1054.000 1303.000 1275.000 1390.5 845.000 799.000 626.000 826.000 801.000 1393.9 2370.000 2578.000 2192.000 2651.000 2606.000 1397.0 2128.000 2288.000 1956.000 2370.000 2360.000 1405.8 1057.000 935.000 732.000 972.000 956.000 1427.2 720.000 756.000 658.000 794.000 781.000 1444.9 978.000 934.000 757.000 981.000 945.000 1451.3 729.000 680.000 543.000 702.000 679.000 1456.8 703.000 756.000 639.000 764.000 755.000 1459.5 1419.000 1346.000 1099.000 1413.000 1366.000 1465.2 4586.000 4192.000 3282.000 4312.000 4205.000 1471.5 1202.000 1126.000 904.000 1171.000 1140.000 1480.6 795.000 862.000 758.000 898.000 874.000 1506.9 960.000 1088.000 984.000 1104.000 1111.000 1510.6 475.000 470.000 393.000 486.000 475.000 1522.1 718.000 844.000 753.000 847.000 843.000 1526.1 586.000 680.000 607.000 677.000 681.000 1539.5 643.000 753.000 677.000 757.000 759.000 1549.6 1339.000 1363.000 1151.000 1415.000 1371.000 1553.8 661.000 684.000 598.000 714.000 692.000 1559.1 999.000 1007.000 848.000 1054.000 1011.000 1564.7 1107.000 1053.000 892.000 1136.000 1068.000 1569.0 617.000 598.000 497.000 638.000 601.000 1571.9 847.000 877.000 759.000 930.000 875.000 1595.6 522.000 550.000 485.000 573.000 556.000 1647.0 483.000 515.000 446.000 533.000 518.000 1653.1 2500.000 2565.000 2222.000 2746.000 2611.000 Table 5: Peak heights used to allocate the commingled oils. 13 1659.3 534.000 567.000 479.000 593.000 567.000 1664.7 814.000 880.000 770.000 916.000 876.000 1672.3 668.000 738.000 670.000 777.000 769.000 1710.4 3208.000 3291.000 2958.000 3539.000 3371.000 1740.9 411.000 596.000 580.000 572.000 599.000 1748.9 367.000 401.000 368.000 427.000 417.000 1756.2 555.000 642.000 592.000 658.000 646.000 1764.7 528.000 611.000 566.000 624.000 615.000 1814.0 1687.000 1894.000 1720.000 1928.000 1867.000 1859.1 420.000 543.000 527.000 535.000 536.000 1862.0 363.000 511.000 522.000 496.000 520.000 1872.6 286.000 355.000 352.000 354.000 361.000 1880.3 276.000 426.000 444.000 405.000 427.000 1885.2 236.000 366.000 378.000 346.000 363.000 1942.8 210.000 272.000 276.000 270.000 280.000 1948.0 129.000 164.000 172.000 167.000 170.000 1952.5 127.000 169.000 176.000 164.000 172.000 1965.0 308.000 414.000 424.000 405.000 413.000 1972.8 212.000 286.000 300.000 280.000 295.000 1979.4 139.000 203.000 217.000 194.000 205.000 15 Appendix 1 This appendix provides a one-page chromatogram of each whole oil sample analyzed as part of this report. Each of these pages shows the distribution and amount of hydrocarbon compounds between the regions of about n-C4 to n-C41 (although the paraffins are only numbered through ~n-C40). A detailed view of the individual peaks can be readily seen on the 12 page expanded view of one of the GC traces in Appendix 2. Sample ID Client ID GC ID Well Name Sample Type Collection Date Purpose for Analysis BP077133 00600397-001 C G9200134.D 15-41B Commingled Put River/Ivishak 9/27/2019 Commingled oil unmixed previously in December 2019 Study (Report 19-2531) Sample ID Client ID GC ID Well Name Sample Type Collection Date Purpose for Analysis BP077149 00600397-003 C G9200135.D 15-41B Commingled Put River/Ivishak 8/19/2019 Commingled oil unmixed previously in December 2019 Study (Report 19-2531) Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Sample Id Client Id G02E Site Name Collection Date Comments BP078607 10004455-001 C G9200137.D 15-41 Commingled Put River/Ivishak 12/17/2019 New December Sample Sample ID Client ID GC ID Well Name Sample Type Collection Date Purpose for Analysis BP072879 10004086-002 C G9200138.D 15-41B Put River (end member)7/22/2018 Put River End-Member Identified in December 2019 Study (Report 19-2531) Sample Id Client Id G02E Site Name Collection Date Comments BP072878 10004086-001 C G9200139.D 15-41B Put River 7/20/2018 Archived oil analyzed to compare to Put River end member BP072879 Sample Id Client Id G02E Site Name Collection Date Comments BP072881 10004086-004 C G9200140.D 15-41B Put River 7/25/2018 Archived oil analyzed to compare to Put River end member BP072879 Sample ID Client ID GC ID Well Name Sample Type Collection Date Purpose for Analysis BP073589 10004092-001 C G9200141.D 15-17 Ivishak (end member) 11/7/2018 Ivishak end-member used in December 2019 Study (Report 19-2531) Sample Id Client Id G02E Site Name Collection Date Comments BP078606 10003569-002 C G9200142.D 15-45B Ivishak 12/30/2019 12/30/2019 New sample. May be possible Ivishak end-member; compare to BP073589 Sample Id Client Id G02E Site Name Collection Date Comments BP077133 00600397-001 C G9200143.D 15-41B Commingled Put River/Ivishak (dup)9/27/2019 6/27/19 Duplicate to assess analytical uncertainty Appendix 2 This appendix provides a 8-page expanded view of the n-C8 to n-C14 region of the Gas Chromatogram of ONE of the samples analyzed. This 8 page expanded view is provided so that the GC peaks used in this study can be readily identified. Each of these 8 pages shows the distribution of compounds between two paraffins (e.g., the first page shows the C8-C9 portion of the chromatogram, the second page shows the C9-C10 portion of the chromatogram, etc.). The peaks in Table 3 through 6 are marked on the expanded view of this sample. These peaks cannot be readily seen on the one-page GC traces in Appendix 1 because the chromatograms in Appendix 1 are too compressed. Annotated GC from n-C8 to n-C9 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C8 n-C9 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C9 to n-C10 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C9 n-C10 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C10 to n-C11 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C10 n-C11 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C11 to n-C12 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C11 n-C12 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C12 to n-C13 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C12 n-C13 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C13 to n-C14 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C13 n-C14 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C14 to n-C15 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C14 n-C15 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C15 to n-C15 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C15 n-C16 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C16 to n-C17 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C16 n-C17 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C17 to n-C18 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C17 n-C18 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C18 to n-C19 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C18 n-C19 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Annotated GC from n-C19 to n-C20 for oil collected October 14, 2019 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C19 n-C20 Sample Id Client Id G02E Site Name Collection Date Comments BP078153 10004086-006 C G9200136.D 15-41B Commingled Put River/Ivishak 10/14/2019 New October Sample Appendix 3 For each allocation result presented in Table 1, we have included in Appendix 3 a table and two figures corresponding to that allocation result. The table and two figures provide the details on the uncertainty (i.e., “goodness of fit”) associated with the allocation result for that sample. NEITHER FIGURE has anything to do with HOW the allocation solution was derived; rather, these figures simply represent a way to visualize the solution and visually assess its goodness of fit. The table lists the commingled sample ID, names of the commingled zones, the names of the end member samples used in the allocation, the number of peaks used and rejected by the OilUnmixer software, and the wt.% contribution of each end member calculated by the software. In addition, the % Error at various confidence levels for each contributing horizon is also calculated. The smaller the % Error, the better the better the DEGREE of FIT of the data. The first figure for each sample is a “star diagram”. Each axis on the diagram shows the ratio of two GC peaks. The black star shows the composition of the commingled oil, and the red star shows the composition of a “theoretical” oil corresponding to the allocation solution yielded by the OilUnmixer software. If the allocation solution were perfect, then the red and black stars would overlay one another perfectly. The second figure shows GC peak HEIGHTS (not ratios) in the commingled oil, the end member oils and a “theoretical” oil corresponding to the allocation solution yielded by the OilUnmixer software. If the allocation solution were perfect, then the traces for the commingled and theoretical oil would overlay one another perfectly. The trace labeled as “scaled” corresponds to the commingled oil corrected for calculated differences in injection volume. Summary of Allocation Results Commingled Well:10004086-006 Date of Collection of Commingled Oil:10/14/19 Commingled Commingled Oil GC File:(BP078153) G9200136 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:145 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:10004086-001 Put River (BP072878) G9200139 7-20-2018 10003569-002 Ivishak BP (078606) G9200142 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.8299 72.09% 1.72% 2.20% 2.63% 3.12% 3.45% %Ivishak 0.3213 27.91% 2.96% 3.79% 4.52% 5.36% 5.94% Totals 1.1513 100.00% Summary of Allocation Results Commingled Well:00600397-001 Date of Collection of Commingled Oil:9/27/19 Commingled Commingled Oil GC File:(BP077133) G9200134 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:145 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:10004086-001 Put River (BP072878) G9200139 7-20-2018 10003569-002 Ivishak BP (078606) G9200142 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.5205 49.27% 1.81% 2.32% 2.77% 3.28% 3.63% %Ivishak 0.5358 50.73% 3.11% 4.00% 4.76% 5.65% 6.26% Totals 1.0563 100.00% Summary of Allocation Results Commingled Well:00600397-003 Date of Collection of Commingled Oil:8/19/19 Commingled Commingled Oil GC File:(BP077149) G9200135 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:145 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:10004086-001 Put River (BP072878) G9200139 7-20-2018 10003569-002 Ivishak BP (078606) G9200142 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.4771 56.98% 0.84% 1.08% 1.28% 1.52% 1.69% %Ivishak 0.3602 43.02% 1.44% 1.85% 2.21% 2.62% 2.90% Totals 0.8373 100.00% Summary of Allocation Results Commingled Well:10004455-001 Date of Collection of Commingled Oil:12/17/19 Commingled Commingled Oil GC File:(BP078607) G9200137 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:145 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:10004086-001 Put River (BP072878) G9200139 7-20-2018 10003569-002 Ivishak BP (078606) G9200142 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.5256 51.02% 0.57% 0.74% 0.88% 1.04% 1.15% %Ivishak 0.5045 48.98% 0.99% 1.27% 1.51% 1.79% 1.99% Totals 1.0301 100.00% Summary of Allocation Results Commingled Well:00600397-001 Date of Collection of Commingled Oil:9/27/19 Commingled (Dup) Commingled Oil GC File:(BP077133) G9200143 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:145 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:10004086-001 Put River (BP072878) G9200139 7-20-2018 10003569-002 Ivishak BP (078606) G9200142 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.5299 49.56% 1.85% 2.38% 2.83% 3.36% 3.72% %Ivishak 0.5394 50.44% 3.19% 4.09% 4.88% 5.79% 6.41% Totals 1.0692 100.00% Geochemical Allocation of Two Oils from the 15-41 Well, North Slope, Alaska Stratum Reservoir Project No. HH-106423 (OilTracers Report No. 20-2605) By Matthew M. Laughland, Ph.D. Prepared for BP Alaska April 2020 CONFIDENTIAL Stratum Reservoir 3141 Hood St., Suite 103 Dallas, TX 75219 Telephone: 214-732-7174 www.stratumreservoir.com email: matt.laughland@stratumreservoir.com BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 1 Table of Contents I. Introduction................................................................................................... 2 II. Conclusions................................................................................................... 3 Summary of the Report Structure……………….………………… 3 III. Background Information...................................................................……….3 Allocation of Commingled Production ….........................................3 IV. Materials and Methods................................................................................. 5 V. Discussion…………….................................................................................. 5 VI. References.................................................................................................... 9 VII. Tables............................................................................................................ 10 VIII. Appendices…………………………………………………………………. 16 BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 2 I. INTRODUCTION Two samples of commingled oil that were collected from the same well (15-41) on different dates (February 6, 2020 and February 11, 2020) were submitted for quantitative geochemical allocation (see Table 1). The samples of produced (commingled) oil are believed to have contributions of oil from two different zones or “end-member” oils, the Put River Formation and Ivishak Formation. The main objective of this study is to determine the percent contributions of Put River and Ivishak oil in the commingled samples. Samples of oil that serve as end-member oils for the Ivishak and Put River Formations also were analyzed (Table 1). In addition to the samples listed in Table 1, a single oil sample (not listed in Table 1) collected from the western lobe of the Put River Fm. in 2005 was analyzed as a possible end-member oil (BP009340; originally analyzed in OilTracers Report 05-312). As reviewed in the Discussion section (Section V), the GC trace for this sample shows extreme evaporative loss. Accordingly, results for this sample are considered unreliable and are not utilized in this study owing to concerns for data fidelity. Table 1: Samples used in this study for oil allocation. Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078606 15-45B 12/30/2019 10003569-002 G6200605 Ivishak End Member End member used in Feb. 2020 study; OT 20-2575 BP078606 (duplicate)15-45B 12/30/2019 10003569-002 G6200604 Ivishak End Member Duplicate analysis to assess analytical uncertainty BP072878 15-41B 7/20/2018 10004086-001 G6200606 Put River End Member End member used in Feb. 2020 study; OT 20-2575 BP078666 15-41 2/6/2020 10004455-005 G6200608 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River The objective of this study is to: (1) Determine the percent contribution of oil from the Put River Fm. and the Ivishak Fm. in the two commingled samples using the end-member oils identified for each formation. BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 3 II. CONCLUSIONS 1.) Allocation results for the two commingled oils are presented in Table 2 and show differences in the contributions of Ivishak and Put River oils to the commingled oils. 2.) Allocation results achieve of Quality of Solution of “Excellent”. (Note: OilUnmixer™ calculates the uncertainty in solution at the 80% confidence level as follows: Excellent <2.5%; Very Good 2.5-3.99%; Good 4-5.99%; Fair 6-6.99%; Poor 7-7.99%; No Solution >8%) Table 2: Allocation results for commingled oils from 15-41B well. Sample Date %Put River %Ivishak Quality of Solution BP078666 2/6/2020 74.7% (±0.78%)25.3% (±1.27%)Excellent BP078667 2/11/2020 67.5% (±1.04%)32.5% (±1.70%)Excellent (Results reported in Table 2 are calculated using Put River end-member oil BP072878 and Ivishak end-member oil BP078606.) Summary of the Report Structure: Sample descriptions are provided in Table 1. Table 2 tabulates the allocation solution for commingled samples. Table 3 lists allocation results through time based on previous analyses of commingled oils from the 15-41 well (Figure 3). Table 4 lists the GC peak ratios for the end member oils used to construct the PCA plot in Figure 2. Table 5 lists the peak height values used for the allocation calculations. One-page plots of the Gas Chromatography (GC) traces of the oils can be found in Appendix 1. An expanded view of one chromatogram is provided in Appendix 2 to allow identification of the peaks used in the allocation calculations. Appendix 3 shows the details of the allocation results for the commingled oils. III. BACKGROUND INFORMATION Allocation of Commingled Production Methods for using oil compositional differences to allocate commingled production from a single well are detailed in Kaufman et al., 1987, 1990, and McCaffrey et al., 1996, 2011, and 2012. Similar methods for allocating the contribution of multiple fields to commingled pipeline production streams are discussed by Hwang et al., 1999 and 2000. In brief, production allocation is achieved by identifying chemical differences between "end-member" oils (samples of oil from each of the zones or production streams being commingled). Parameters reflecting these compositional differences are then measured in the end-member oils and in the commingled oil. The data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils. BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 4 Using a simple mixing model, a single geochemical difference between oils from two sands is sufficient to allocate commingled production from those two units (e.g., Kaufman et al, 1990). By using data for several peak ratios, independent solutions to the problem can be derived, allowing the accuracy of the allocation to be assessed. Using a simple mixing model, a single geochemical difference between oils from two sands (i.e., a single difference in the relative abundance of 1 peak on a GC trace) is sufficient to allow allocation of commingled production from those two units (e.g., Kaufman et al, 1990). By using data for several peak ratios, independent solutions to the problem can be derived, allowing the accuracy of the allocation to be assessed. Using the concentrations (not ratios) of several compounds, the commingled production from several sands (or several fields) can be allocated to the discrete units using a linear algebra approach described in detail by McCaffrey et al., 1996, 2011, and 2012. In brief, it works as follows: Consider the following hypothetical example. The concentrations of four compounds (A, B, C, and D) are measured in oils from four zones that may be contributing to a produced oil. These data can be expressed as a 4 by 4 matrix (Matrix G) where the numbers are compound concentrations. The same four compounds are then measured in a produced oil, and form a 1 by 4 matrix (Matrix D). If the produced oil came only from some combination of production from the four intervals sampled by Matrix G, then the relative contributions from the four intervals to the commingled oil could be readily determined (as Matrix M) since: M = [GTG]-1GTD Equation 1 where GT is the transpose of Matrix G. If the number of rows (compounds) in matrix G is less than the number of columns (contributing oil intervals), then no solution to the problem can be identified. However, the form in which Equation 1 is written does allow the number of compounds to exceed the number of contributing oil intervals (data for the compounds in Table 4 were used to derive the results reported in the present study). In the current study (as well as all other production allocation projects performed by Stratum Reservoir), data were processed using a proprietary geochemical production allocation software package, OilUnmixerTM v. 4.01, developed and owned by OilTracers (now part of Stratum Reservoir). This package is based on a more sophisticated version of Equation 1. The package differs from the hypothetical matrix example described above in that it has a more sophisticated method for (i) dealing with analytical uncertainty, (ii) assessing the validity of end member (zone specific) calibration samples, (iii) looking for contamination in the end members, and (iv) “testing” the validity of the allocation results. The geochemical allocation approach described above is based on the well-established proposition that oils from separate reservoirs tend to differ from one another in composition (e.g., Slentz, 1981; Kaufman et al., 1990; Hwang and Baskin, 1994; Hwang et al., 1994). As described in the previous section of this report. When oils from discrete zones are commingled, these chemical differences between the oils can be used to assess BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 5 the contribution of each zone or each field to the commingled production, as described above. IV. MATERIALS AND METHODS The oils were analyzed by High Resolution Gas Chromatography (GC) at Stratum Reservoir (Houston, TX) using a GC equipped with a 60 m DB-1column; the injector was at 275°C, and the heating program was: 35°C (hold 5 minutes), 3°/min ramp to 320°C (hold for 20 minutes). The carrier gas was helium. Appendix 1 provides one-page views of the GC traces of all samples analyzed in this study. A twelve-page expanded view of the GC trace of the oils is provided in Appendix 2. Peak identification numbers are marked on the 12 expanded views of the GC for that sample. Data for those peaks were processed to calculate peak ratios for the statistical comparison of the oils and to calculate the production allocation splits using a proprietary geochemical production allocation software package (OilUnmixerTM v. 4.01). This package is based on a more sophisticated version of Equation 1. The method used by the OilUnmixerTM v. 4.01 software differs from the hypothetical example described in the previous section in that it has a more sophisticated method for: (i) dealing with analytical uncertainty, (ii) assessing the validity of end member (zone specific) calibration samples, (iii) looking for contamination in the end members, and (iv) “testing” the validity of the allocation results. V. DISCUSSION In addition to the samples listed in Table 1, a single oil sample (not listed in Table 1) collected from the western lobe of the Put River Fm. in 2005 was analyzed as a possible end-member oil (BP009340; originally analyzed in OilTracers Report 05-312). Very little oil was in the archived sample bottle (see Photo 1), and a comparison of the current GC analysis to previous analyses of the same oil (2005 and 2010) is shown in Figure 1. The top GC trace is the 2010 analysis which is nearly identical to the original analysis in 2005 (middle GC trace). The GC trace from 2005 and 2010 show a normal paraffin envelope. The last GC trace (bottom) is the analysis completed for this study (2020) and shows strong evaporative loss of the oil. Accordingly, results for this sample are considered unreliable and are not utilized in this study owing to concerns for data fidelity. Notwithstanding, there is insufficient sample remaining in the bottle to use for future studies even if the GC data were of good quality. BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 6 Photo 1: Sample of Put River oil collected in 2005 (BP009340). Figure 1: Comparison of GC traces of Put River oil sample (BP009340). Evaporative loss is evident in 2020 analysis (c.). BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 7 Figure 2: PCA diagram showing compositional differences among the oils in this study based on Euclidian distance. The shorter the Euclidian distance between any two samples, the more similar they are in composition. End-member oils identified in this study are indicated in light blue (Ivishak) and green (Put River) symbols and text. Commingled oils (navy blue) show percent contributions of end-member oils based on unmixing results (see Table 2 and Appendix 3). As an independent check on allocation results, we performed a multivariate statistical comparison of the GC data for the 2 oils (plus one duplicate analysis to assess analytical uncertainty) using Principal Component Analysis (PCA). Analytical uncertainty is less than 1% based on duplicate analyses of the Ivishak oil (BP078606). The PCA diagram is shown in Figure 1 and is based on 20 GC peak height ratios in (Table 4). The PCA diagram (Figure 1) shows the compositional similarity and dissimilarity among the “single-zone” end member samples (i.e., Put River and Ivishak) and the two commingled oils. The Principal Components analysis (PCA) transforms a number of possibly correlated variables (a similarity matrix) into a two-dimensional plot called principal components based on Euclidian distance. The first principal axis accounts for as much of the variability in the data as possible and the second axis accounts for as much of the remaining variability as possible. In general, the shorter the Euclidian distance between any two samples, the more similar they are in composition. Figure 1 shows that the Ivishak oil, BP078606, plots on the far right of the PCA diagram and accordingly is used as the end-member oil for the Ivishak Formation. In contrast, the Put River oil, BP072878, plots on the far left-hand of the PCA diagram and is used as the end-member oil for the Put River Fm. Each of these end-member oils are separated by a relatively large Euclidian distance on the PCA plot. BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 8 The two commingled oils from the 15-4 well plot between the end-member oils. Unmixing results (Table 2 and Appendix 3) are shown on the PCA diagram for each of the commingled oils. Unmixing results for the two commingled oil samples in this study are presented in Table 3 along with unmixing results from a previous study of commingled oils from the 15-41 well. Unmixing results (Table 3) are plotted with respect to collection date in Figure 3 to show how oil(s) from the Put River and Ivishak Fms. contribute production over time. Table 3: Allocation Results for Commingled Oils Collected from the 15-41 Well. Sample Date %Put River %Ivishak Quality of Solution OilTracers Report No. BP077149 8/19/2019 57.0 43.0 Excellent 20-2575 BP077133 9/27/2019 49.3 50.7 Very Good 20-2575 BP078153 10/14/2019 72.1 27.6 Very Good 20-2575 BP078607 12/17/2019 51.0 49.0 Excellent 20-2575 BP078666 2/6/2020 74.7 25.3 Excellent 20-2605 BP078667 2/11/2020 67.5 32.5 Excellent 20-2605 Figure 3: Plot of allocation results for commingled oil samples collected on different dates from the 15-41 well show differing contributions of Put River and Ivishak oils through time. BP Alaska Allocation Project 20-2605 Stratum Reservoir Page 9 VI. REFERENCES Hwang, R. J., Ahmed A. S. and Moldowan J. M. (1994). Oil composition variation and reservoir continuity: Unity Field, Sudan. Organic Geochemistry 21(2), 171-188. Hwang, R. J. and Baskin D. K. (1994). Reservoir connectivity and oil homogeneity in a large- scale reservoir. Middle East Petroleum Geoscience Geo 94 2, 529-541. Hwang, R. J., D. K. Baskin, et al. (1999). Allocation of commingled pipeline oils to field production. Abstracts, 19th Internatisonal Meeting on Organic Geochemistry. Istanbul, Turkey, Tubitak Marmara Research Center Earth Sciences Research Institute. Vol. II: p. 602. Hwang, R. J., D. K. Baskin, and S. C. Teerman, 2000, Allocation of commingled pipeline oils to field production: Org. Geochem., v. 31, p. 1463-1474. Kaufman, R. L., A. S. Ahmed, and W. B. Hempkins, 1987, A new technique for the analysis of commingled oils and its application to production allocation calculations, paper IPA 87-23/21: 16th Annual Indonesian Petro. Assoc., p. 247-268. Kaufman, R. L., Ahmed A. S. and Elsinger R. J. (1990). Gas Chromatography as a development and production tool for fingerprinting oils from individual reservoirs: applications in the Gulf of Mexico. In: Proceedings of the 9th Annual Research Conference of the Society of Economic Paleontologists and Mineralogists. (D. Schumaker and B. F. Perkins, Ed.), New Orleans. 263- 282. McCaffrey, M. A., Legarre H. A. and Johnson S. J. (1996). Using biomarkers to improve heavy oil reservoir management: An example from the Cymric field, Kern County, California. American Association of Petroleum Geologists Bulletin 80(6), 904-919. McCaffrey, M. A., D. H. Ohms., M. Werner, C. Stone, D. K. Baskin, and B. A. Patterson (2011) Geochemical allocation of commingled oil production or commingled gas production. Society of Petroleum Engineers Paper Number 144618. p 1-19. McCaffrey, M. A., D. K. Baskin, B. A. Patterson, D. H. Ohms., C. Stone, D. Reisdorf (2012) Oil fingerprinting dramatically reduces production allocation costs. World Oil, March 2012, p 55-59. Slentz, L. W. (1981). Geochemistry of reservoir fluids as unique approach to optimum reservoir management. SPE #9582. Presented at Middle East Oil Technical Conference, Manama, Baharain. Sample GC Datafile 1268.9/1275.9 865.3/875.1 829.6/844.5 935.3/946.0 965.5/977.7 1156.9/1160.8 942.2/953.8 1271.3/1283.6 1046.9/1058.7 BP078667 G6200609 1.186 0.52 0.574 0.871 0.499 1.928 0.806 0.498 1.146 BP078666 G6200608 1.239 0.561 0.608 0.92 0.528 1.903 0.85 0.47 1.073 BP072878 G6200606 1.033 0.642 0.7 1.045 0.59 1.745 0.956 0.546 0.973 BP078606 G6200605 1.775 0.372 0.413 0.655 0.373 2.644 0.622 0.365 1.437 BP078606 (dup.)G6200604 1.732 0.372 0.415 0.658 0.374 2.665 0.624 0.359 1.436 1065.4/1069.2 1244.9/1253.7 1024.6/1036.4 1872.5/1879.6 1165.1/1175.7 1120.3/1125.1 871.8/885.0 1740.2/1744.9 1371.5/1381.3 1379.5/1393.6 1319.8/1321.9 1.882 0.939 1.522 0.917 3.162 2.885 2.679 1.531 1.187 2.145 2.07 2.007 0.954 1.608 0.906 3.211 2.795 2.798 1.53 1.133 2.04 2.04 2.219 0.876 1.757 1.127 3.426 2.664 3.028 1.218 1.344 2.374 2.197 1.513 1.245 1.231 0.785 2.462 3.64 2.236 1.679 0.986 1.77 1.721 1.52 1.229 1.235 0.776 2.468 3.635 2.234 1.744 1.002 1.784 1.7 Table 4: Peak height ratios used to construct principal component diagram (Figure 2). 10 Table 5: Peak Heights used to allocate commingled oils. 11 GC G6200609 G6200608 G6200606 G6200605 Collection Date 2/11/2020 2/6/2020 12/30/2019 12/30/2019 Zone Commingled Commingled Put River Ivishak Sample ID BP078667 BP078666 BP072878 BP078606 821.7 1443.000 1478.000 1646.000 687.000 823.1 2466.000 2603.000 3180.000 965.000 827.1 17463.000 17881.000 19954.000 8339.000 829.6 6573.000 6982.000 8656.000 2473.000 832.5 12315.000 12651.000 14332.000 5657.000 835.9 3107.000 3303.000 4014.000 1222.000 844.5 11446.000 11480.000 12360.000 5988.000 847.4 3318.000 3424.000 3812.000 1589.000 853.4 26064.000 26113.000 27440.000 14573.000 856.2 4968.000 5256.000 6157.000 2144.000 858.3 2322.000 2357.000 2505.000 1251.000 865.3 6585.000 7066.000 8201.000 2813.000 871.8 8051.000 8551.000 9874.000 3557.000 875.1 12654.000 12602.000 12769.000 7568.000 882.8 5643.000 5761.000 6197.000 2980.000 885.0 3005.000 3056.000 3261.000 1591.000 908.5 2369.000 2382.000 2428.000 1409.000 911.6 4645.000 4655.000 4727.000 2805.000 913.9 2260.000 2282.000 2343.000 1309.000 916.7 1242.000 1287.000 1384.000 659.000 919.2 1407.000 1481.000 1643.000 680.000 925.1 7567.000 7633.000 7852.000 4450.000 929.6 2370.000 2406.000 2492.000 1371.000 935.3 7131.000 7490.000 8330.000 3572.000 938.1 5595.000 5561.000 5534.000 3624.000 942.2 3743.000 3904.000 4223.000 1946.000 946.0 8188.000 8141.000 7974.000 5452.000 947.8 3412.000 3379.000 3337.000 2228.000 951.4 2693.000 2697.000 2689.000 1740.000 953.8 4644.000 4593.000 4416.000 3127.000 955.4 2057.000 2112.000 2234.000 1176.000 961.1 1633.000 1683.000 1805.000 879.000 962.7 8655.000 8771.000 8975.000 5369.000 965.5 5699.000 5937.000 6297.000 3129.000 968.9 1617.000 1613.000 1626.000 1032.000 971.8 4659.000 4843.000 5105.000 2656.000 Table 5: Peak Heights used to allocate commingled oils. 12 977.7 11432.000 11237.000 10666.000 8383.000 979.8 2469.000 2477.000 2510.000 1591.000 982.3 3656.000 3696.000 3734.000 2352.000 992.6 1789.000 1756.000 1733.000 1219.000 995.5 2104.000 2077.000 2016.000 1467.000 1006.7 2186.000 2162.000 2108.000 1533.000 1009.8 1335.000 1325.000 1259.000 973.000 1019.8 2008.000 2000.000 1959.000 1400.000 1024.6 6537.000 6679.000 7031.000 3917.000 1027.8 3971.000 3942.000 3809.000 2907.000 1032.4 2700.000 2680.000 2620.000 1943.000 1033.9 1315.000 1277.000 1212.000 988.000 1036.4 4295.000 4154.000 4002.000 3183.000 1040.2 4283.000 4205.000 4123.000 3004.000 1043.5 2256.000 2153.000 2070.000 1693.000 1046.9 2825.000 2705.000 2487.000 2359.000 1051.1 2588.000 2485.000 2330.000 2035.000 1058.7 2465.000 2521.000 2556.000 1642.000 1061.7 4457.000 4396.000 4340.000 3213.000 1063.3 2030.000 1970.000 1793.000 1669.000 1065.4 3479.000 3539.000 3597.000 2304.000 1067.4 1761.000 1704.000 1602.000 1464.000 1069.2 1849.000 1763.000 1621.000 1523.000 1071.4 2993.000 2987.000 3007.000 2068.000 1074.8 1091.000 1061.000 988.000 890.000 1081.5 1503.000 1465.000 1394.000 1153.000 1083.3 1536.000 1486.000 1432.000 1170.000 1087.5 2324.000 2222.000 2066.000 1900.000 1089.6 1722.000 1679.000 1596.000 1353.000 1114.4 856.000 831.000 799.000 666.000 1120.3 2617.000 2490.000 2283.000 2541.000 1125.1 907.000 891.000 857.000 698.000 1129.0 2531.000 2423.000 2385.000 1954.000 1131.2 3235.000 3070.000 2893.000 2752.000 1137.9 1522.000 1434.000 1347.000 1339.000 1152.0 1739.000 1645.000 1509.000 1620.000 1156.9 4283.000 4130.000 3644.000 4672.000 1160.8 2221.000 2170.000 2088.000 1767.000 1165.1 3497.000 3397.000 3316.000 2824.000 1171.3 2928.000 2778.000 2662.000 2514.000 Table 5: Peak Heights used to allocate commingled oils. 13 1178.9 1169.000 1117.000 1025.000 1160.000 1182.5 1036.000 979.000 888.000 1039.000 1183.9 1297.000 1227.000 1156.000 1214.000 1185.3 956.000 896.000 856.000 842.000 1188.6 1232.000 1163.000 1104.000 1089.000 1194.2 1033.000 983.000 881.000 1034.000 1216.0 4909.000 4613.000 4505.000 4003.000 1222.1 1677.000 1600.000 1468.000 1721.000 1235.7 1782.000 1684.000 1591.000 1769.000 1239.2 1164.000 1076.000 1012.000 1176.000 1244.9 1087.000 1042.000 915.000 1312.000 1253.7 1157.000 1092.000 1044.000 1054.000 1255.8 1497.000 1423.000 1327.000 1442.000 1260.3 1622.000 1517.000 1460.000 1530.000 1264.9 2239.000 2084.000 2005.000 2065.000 1268.9 4689.000 4652.000 3796.000 6201.000 1271.3 1803.000 1694.000 1599.000 1733.000 1275.9 3953.000 3755.000 3674.000 3494.000 1279.8 980.000 923.000 861.000 1079.000 1283.6 3617.000 3603.000 2931.000 4748.000 1287.6 1163.000 1102.000 1026.000 1267.000 1292.9 653.000 611.000 576.000 750.000 1297.3 683.000 631.000 580.000 795.000 1319.8 1472.000 1383.000 1329.000 1528.000 1340.1 1341.000 1267.000 1176.000 1636.000 1342.8 809.000 751.000 699.000 967.000 1352.0 1141.000 1069.000 1010.000 1304.000 1354.8 1020.000 958.000 917.000 1164.000 1359.8 1368.000 1264.000 1223.000 1547.000 1364.9 2041.000 1916.000 1833.000 2338.000 1371.5 1366.000 1281.000 1219.000 1581.000 1379.5 4913.000 4543.000 4221.000 5608.000 1390.4 773.000 742.000 672.000 972.000 1393.6 2290.000 2227.000 1778.000 3168.000 1396.6 2113.000 2108.000 1691.000 2925.000 1405.9 925.000 872.000 830.000 1125.000 1426.8 673.000 649.000 531.000 922.000 1444.7 888.000 867.000 763.000 1183.000 1451.3 694.000 669.000 603.000 896.000 1454.2 578.000 547.000 512.000 721.000 Table 5: Peak Heights used to allocate commingled oils. 14 1456.5 641.000 627.000 506.000 892.000 1459.4 1195.000 1127.000 1015.000 1530.000 1465.2 4070.000 3772.000 3625.000 4936.000 1471.5 1024.000 980.000 894.000 1301.000 1480.3 780.000 766.000 617.000 1091.000 1506.5 993.000 947.000 746.000 1375.000 1521.7 703.000 696.000 540.000 1013.000 1525.7 563.000 554.000 429.000 799.000 1536.4 392.000 376.000 306.000 543.000 1539.0 682.000 669.000 510.000 983.000 1549.5 1255.000 1205.000 1027.000 1707.000 1553.7 639.000 612.000 519.000 860.000 1559.1 890.000 866.000 761.000 1214.000 1564.7 1016.000 958.000 854.000 1368.000 1569.0 599.000 575.000 517.000 811.000 1571.9 898.000 855.000 735.000 1208.000 1595.3 537.000 515.000 425.000 752.000 1609.5 376.000 364.000 303.000 521.000 1647.2 525.000 500.000 416.000 727.000 1653.0 2433.000 2350.000 2035.000 3289.000 1659.3 524.000 507.000 433.000 734.000 1664.7 808.000 786.000 649.000 1131.000 1672.3 832.000 814.000 627.000 1206.000 1710.2 3071.000 2893.000 2498.000 4205.000 1740.2 487.000 459.000 302.000 752.000 1756.3 581.000 554.000 446.000 814.000 1764.7 567.000 532.000 433.000 802.000 1772.2 334.000 319.000 264.000 481.000 1813.7 1660.000 1565.000 1322.000 2372.000 1835.0 232.000 217.000 132.000 358.000 1861.6 482.000 455.000 304.000 753.000 1864.6 289.000 275.000 222.000 430.000 1872.5 311.000 298.000 222.000 457.000 1879.6 339.000 329.000 197.000 582.000 1884.4 312.000 295.000 183.000 495.000 1907.8 164.000 158.000 107.000 266.000 1918.1 208.000 196.000 127.000 319.000 1933.6 119.000 112.000 68.000 194.000 1942.7 231.000 219.000 159.000 356.000 1952.4 123.000 120.000 82.000 197.000 Table 5: Peak Heights used to allocate commingled oils. 15 1962.1 236.000 222.000 149.000 373.000 1965.0 386.000 355.000 248.000 579.000 1972.8 231.000 213.000 152.000 363.000 1978.9 154.000 143.000 92.000 251.000 1987.9 145.000 146.000 105.000 229.000 1996.1 336.000 314.000 189.000 570.000 15 Appendix 1 This appendix provides a one-page chromatogram of each whole oil sample analyzed as part of this report. Each of these pages shows the distribution and amount of hydrocarbon compounds between the regions of about n-C4 to n-C41 (although the paraffins are only numbered through ~n-C40). A detailed view of the individual peaks can be readily seen on the 12 page expanded view of one of the GC traces in Appendix 2. Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078606 15-45B 12/30/2019 10003569-002 G6200605 Ivishak End Member End member used in Feb. 2020 study; OT 20-2575 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078606 (duplicate)15-45B 12/30/2019 10003569-002 G6200604 Ivishak End Member Duplicate analysis to assess analytical uncertainty Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP072878 15-41B 7/20/2018 10004086-001 G6200606 Put River End Member End member used in Feb. 2020 study; OT 20-2575 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078666 15-41 2/6/2020 10004455-005 G6200608 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Appendix 2 This appendix provides a 8-page expanded view of the n-C8 to n-C14 region of the Gas Chromatogram of ONE of the samples analyzed. This 8 page expanded view is provided so that the GC peaks used in this study can be readily identified. Each of these 8 pages shows the distribution of compounds between two paraffins (e.g., the first page shows the C8-C9 portion of the chromatogram, the second page shows the C9-C10 portion of the chromatogram, etc.). The peaks in Table 3 through 6 are marked on the expanded view of this sample. These peaks cannot be readily seen on the one-page GC traces in Appendix 1 because the chromatograms in Appendix 1 are too compressed. Annotated GC from n-C8 to n-C9 for oil collected February 11, 2020 from the 15-41 well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C8 n-C9 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C9 to n-C10 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C9 n-C10 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C10 to n-C11 for oil collected February 11, 2020 from the 15 -41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C10 n-C11 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C11 to n-C12 for oil collected February 11, 2020 from the 15 -41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C11 n-C12 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C12 to n-C13 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C12 n-C13 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C13 to n-C14 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C13 n-C14 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C14 to n-C15 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C14 n-C15 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C15 to n-C15 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C15 n-C16 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C16 to n-C17 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C16 n-C17 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C17 to n-C18 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C17 n-C18 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C18 to n-C19 for oil collected February 11, 2020 from the 15-41B well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C18 n-C19 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Annotated GC from n-C19 to n-C20 for oil collected February 11, 2020 from the 15-41 well. This GC trace is provided as an example of the inter-paraffin peaks used to calculate peak heights and ratios for unmixing these oils. n-C19 n-C20 Sample ID Well Collection Date Lab ID GC Sample Type Purpose for Analysis BP078667 15-41 2/11/2020 10004455-006 G6200609 Commingled sample New sample not previously analyzed. Unmix using end- member oils for Ivishak and Put River Appendix 3 For each allocation result presented in Table 1, we have included in Appendix 3 a table and two figures corresponding to that allocation result. The table and two figures provide the details on the uncertainty (i.e., “goodness of fit”) associated with the allocation result for that sample. NEITHER FIGURE has anything to do with HOW the allocation solution was derived; rather, these figures simply represent a way to visualize the solution and visually assess its goodness of fit. The table lists the commingled sample ID, names of the commingled zones, the names of the end member samples used in the allocation, the number of peaks used and rejected by the OilUnmixer software, and the wt.% contribution of each end member calculated by the software. In addition, the % Error at various confidence levels for each contributing horizon is also calculated. The smaller the % Error, the better the better the DEGREE of FIT of the data. The first figure for each sample is a “star diagram”. Each axis on the diagram shows the ratio of two GC peaks. The black star shows the composition of the commingled oil, and the red star shows the composition of a “theoretical” oil corresponding to the allocation solution yielded by the OilUnmixer software. If the allocation solution were perfect, then the red and black stars would overlay one another perfectly. The second figure shows GC peak HEIGHTS (not ratios) in the commingled oil, the end member oils and a “theoretical” oil corresponding to the allocation solution yielded by the OilUnmixer software. If the allocation solution were perfect, then the traces for the commingled and theoretical oil would overlay one another perfectly. The trace labeled as “scaled” corresponds to the commingled oil corrected for calculated differences in injection volume. Summary of Allocation Results Commingled Well:15-41 Date of Collection of Commingled Oil:2/6/2020 Commingled Oil GC File:G6200608 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:162 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:15-45B Put River G6200606 7-20-2018 15-41B Ivishak G6200605 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.7896 74.73% 0.78% 1.00% 1.19% 1.41% 1.56% %Ivishak 0.2671 25.27% 1.27% 1.63% 1.95% 2.31% 2.56% Totals 1.0567 100.00% Summary of Allocation Results Commingled Well:15-41 Date of Collection of Commingled Oil:2/11/2020 Commingled Oil GC File:G6200609 Number Of Commingled Zones:2 Names Of Commingled Zones:Put River Ivishak Number Of GC Peaks Used For Result:162 Number Of GC Peaks Rejected:0 Allowed Impact of Each Peak on Solution:1.50 % Number Of End Members:2 Names Of End Members:15-45B Put River G6200606 7-20-2018 15-41B Ivishak G6200605 12-30-2019 ALLOCATION RESULT: Values in Weight (wt.%)Confidence Level: (Error +/-) Raw Result Normalized 80%90%95%97.5%99% %Put River 0.7287 67.45% 1.04% 1.33% 1.58% 1.88% 2.08% %Ivishak 0.3516 32.55% 1.70% 2.18% 2.59% 3.08% 3.41% Totals 1.0803 100.00% Permit to Drill 2001800 MD 11818 ,"' 'I-VD DATA SUBMITTAL COMPLIANCE REPORT 10/312003 Well Name/No. PRUDHOE BAY UNIT 15-41A Operator BP EXPLORATION (ALASKA) INC 8798 _ Completion Date 9/17/2001 ~-~ Completion Status OPSHD Current Status P&A -! APl No. 50-029-22492-01-00 UIC N .... REQUIRED INFORMATION Mud Log No Samples N_.go Directional Survey N._9o DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Electr Data Digital Dataset ~TMed/Frmt Numbe~ Name Rpt Rpt ~K~29 ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: Directional Survey :::::::::::::::::::::::::::::::::::::::::::::::::::..'_L'::: :.'. ' Directional Survey C ~J~54 (data taken from Logs Portion of Master Well Data Maint) Log Log Run Interval OH / Scale Media No Start Stop CH Received Comments 5 BM I 8750 9463 Case 1/3/2001 8750-9463 10810 11818 ~'"' 6~20~2002 FINAL Open 7/6/2001 MWD Survey, Digital Data 1 10810 11818 Case 6/20/2002 1 10810 11818 Case 6/20/2002 FINAL 4/5/2001 FINAL Open 7/6/2001 5 BM FINAL 4/5/2001 I 10810 11818 ~ 6/20/2002 FINAL 8750 9463 Case 1/3/2001 8750-9463 Digital Data Directional Survey Paper Copy Directional Survey,Paper Copy Directional Survey Digital Data Well Cores/Samples Information: Name Start Interval Stop Sent Sample Set Received Number Comments DATA SUBMITTAL COMPLIANCE REPORT 101312003 Permit to Drill 2001800 Well Name/No. PRUDHOE BAY UNIT 15-41A Operator BP EXPLORATION (ALASKA) INC MD 11818 TVD 8798 ADDITIONAL INFORMATION Well Cored? Y ~ Chips Received? ~ Analysis ~ Received? Completion Date 9/17/2001 Completion Status OPSHD Daily History Received? Formation Tops Current Status P&A -/'-.~ / N APl No. 50-029-22492-01-00 UIC N Comments: Compliance Reviewed By: Date: STATE OF ALASKA ( ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Plugged Back for Sidetrack 1. Status of Well Classification of Service Well [] Oil [] Gas [] Suspended [] Abandoned [] Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 200-180 301-052 & 301-202 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-22492-01 4. Location of well at surface ~?.:,..~,~,~,,:.,.~.~;_ 9. Unit or Lease Name · ' ~c.,~-~, ' · 1476' SNL, 710' EWL, SEC.22, T11N, R14E, UM ~ ~.~ ~,: Prudhoe Bay Unit At top of productive interval ~;~ r~?. ~_--~ ~~ ~:~'t,_ ~,.. N/A ]",'"'~~i 10. Well Number 15-41A 4487' USE, 395' EWL, SEC. 15, T11N, R14E, UM 11. Field and Pool 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Prudhoe Bay Field / Prudhoe Bay Pool KBE = 66.25' ADL 028306 12. Date Spudded2/21/2001 113' Date I'D' Reached 114' Date C°mp" Susp" °r Aband'2/25/2001 9/17/2001 115' water depth' if °ffshoreN/A MSL 116' NO' °f Completi°nsZero 17. Total Depth (MD+TVD) 118. Plug BaCk Depth (MD+TVD) 119. Directional Survey 1 20. Depth where SSSV set121. Thickness of Permafrost 11818 8798 FTI 10750 8583 FTI [] Yes [] NoI , U/A MDI 1900' (Approx.) 22. Type Electric or Other Logs Run MWD, GR 23. CASING~ LINER AND CE, MENTING RECORD ,, CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE TOP BOTTOM S~ZE 'CEMENTING RECORD AMOUNT PULLED 20" 91.5# H-40 Surface 110' 30" _~60 sx Arctic Set (Approx.) 9-5/8" 47# L-80 Surface 3964' 12-'i/4'")44 sx PF 'E', 375 sx PF 'C' , ,, 7" 26# L-80 Surface 10438' 8-1/2" 307 sx Class 'G' 5" 15# 13Cr80 10270' 10810' 6" 112 sx Class 'G' , 24. Perforations open to Production (MD+TVD of Top and 25. TUBING RECORD Bottom and interval, size and number) S~ZE DEPTH SET (MD) PACKER SET (MD) None 3-1/2", 9.2#, 13Cr80 10156' 10102' MD TVD MD TVD 3-1/2", 9.2#, L-80 10281' 10210' 26.. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 10738' Set Cement Retainer 10706' P&A with 10 BBIs Class 'G' 10706' 2nd P&A w/7 Bbls 'G', Sqzd to 1450 psi 10706' 3rd P&A w/6 Bbls Class 'G' . 27. PRODUCTION TEST . . Date First Production Method of Operation (Flowing, gas lift, etc.) Not on Production N/A Date of Test Hours Tested PRODUCTION FOR OIL-'BBL GAs-MCF WATER-B'BL CHOKE SIZE I GAS-OIL RATIO TEST PERIOD I Flow Tubing Casing Pressure CALCULATED OIL-DEL GAS-MCF WATER-BBL OIL GRAVITY-APl (CORR) Press. 24-Hour RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. RECEIVED NOV 1 9 ZOO1 Form 10-407 Rev. 07-01-80 Submit In Duplicate 29. Geologic Markers Marker Name Sag River Shublik Sadlerochit Measured Depth 10381' 10425' 10491' True Vertical Depth 8220' 8264' 832g' 31. List of Attachments: Summary of Daily Drilling Reports 30. Formation Tests Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. RECEIVED NOV 1 9 2001 Alaska 011 & G~ Cons. C.,aalaisa~ Anchorage ,hereby certify that the fore, going is true and correct to the best of my knowledge Signed Terrie Hubble ,~,~~~~ Title Technical Assistant Date 15-41A 200-180 301-052 & Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Permit No. / Approval No. INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1; Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 A,O 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the' details of any multiple stage cementing and the location of the cementing tool. ITEM 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 STATE OF ALASKA . ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: [] Abandon [] Alter Casing [] Change Approved Program 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 Location of well at surface 1474' SNL, 4566' FEL, SEC.22, T11 N, R14E, UM At top of productive interval N/A At effective depth N/A At total depth 792' SNL, 4883' FEL, SEC. 15, T11 N, R14E, UM [] Suspend [] Repair Well [] Operation Shutdown [] Plugging [] Time Extension [] Pull Tubing [] Variance [] Re-Enter Suspended Well [] Stimulate [] Perforate [] Other Plug Back for Sidetrack 5. Type of well: [] Development [] Exploratory [] Stratigraphic [] Service 6. Datum Elevation (DF or KB) KBE = 66.25' 7. Unit or Property Name Prudhoe Bay Unit 8. Well Number 15-41A 9. Permit Number 200-180 / 301-052 10. APl Number 50- 029-22492-01 11. Field and Pool Prudhoe Bay Field / Prudhoe Bay Pool 12. Present well condition summary Total depth: measured 11818 feet true vertical 8798 feet Effective depth: measured 10750 feet true vertical 8583 feet Casing Length Size Structural Conductor 110' 20" Surface 3925' 9-5/8" Intermediate 10372' 7" Production Liner 880' 5" Plugs (measured) Junk (measured) Top of 2" CT (filled w/cement) at 10750' (03/01) Top of mill/motor BHA at 11605'; 2" CT f/10750' to 11380' w/cement; Cement f/11500' - 11380' Cemented MD TVD 260 sx Arcticset (Approx.) 944 sx PF 'E', 375 sx PF 'C' 307 sx Class 'G' 112 sx Class 'G' Perforation depth: measured Open Hole w/Fish: 10814' - 11818' true vertical Open Hole w/Fish: 8646' - 8798' Tubing (size, grade, and measured depth) 110' 110' 3964' 3558' 10438' 8276' 10270' - 10810' 8111' - 8642" RECEIVED JUL 1 7 2001 Alaska 0il & Gas Cons. Commission Anchorage 3-1/2", 9.2#, 13Cr80 to 10156'; 3-1/2", 9.2//, L-80 10156'- 10281' Packers and SSSV (type and measured depth) 7"x 3-1/2" Baker 'S-3' packer at 10102'; 7"x 4-1/2" Baker 'SABL-3' packer at 10210' 13. Attachments [] Description Summary of Proposal [] Detailed Operations Program [] BOP Sketch 4. Estimated date for commencing operation 115. Status of well classifications as: August 15, 2001 I [] Oil [] Gas [] Suspended 16. If proposal was verbally approved Service Name of approver Date Approved Contact Engineer Name/Number: John Cub, b_,bony~-4158 o~. ~f~-~.."~o~n~o~, ~c{-5 {,,~,~, Prepared By Name/Number: Terrie Hubble, 564-4628 17.1 hereby certify that the/~/,~3~g ~,~j~yand correct to the best of my knowledge / ! Signed John Cubbon /,//~. ~ Title CT Drilling Engineer Date ~//~/~,90/ f/, ' ' Commission,Use Only,' //' , Conditions ofAp~)roval: N(~ffy d;ommissio'n so representative may. witness 'z~..~ ~, ~.~Q:)~D,~.~.¥ I Approva~ No ..~/q! Plug integrity BOP Test ~ Location clearance I ' UI,' , AII Mechanical Integrity Test Subseauent fo[m required 10- I.~,O ~'~ Approved by order of the Commission J. ~. ~"~l~lr~ rTM ~ ~ ! /[ ! Commissioner Date Form 10-403 Rev. 06/15/88 I~/ j\ J U I J~ J~L Submit'l{~ Trip~i}~"~t~ bp July 18, 2001 To: Attention: Subject: Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Tom Maunder Petroleum Engineer Well 15-41B CTD Sidetrack Prep BP Exploration Alaska Inc. Drilling & Wells Coiled Tubing Drilling Team Well 15-41A is scheduled for a through tubing sidetrack to be drilled with coiled tubing. The following summarizes the procedure required to prep 15-41A for drilling and is submitted as an attachment to Form 10-403. A schematic diagram of this proposed completion is attached. 1. Tree wing & master valves will be tested. 2. Using slickline, the tubing will be drifted and the gas lift mandrels will be dummied off. 3. Inner Annulus will be liquid packed and pressure tested. 4. Service coil will spot a kickoff plug with 17 ppg cement. The cement plug will extend approximately 100 feet above the proposed KOP, which will be at approximately 10,710'md (8,478' TVDss). 5. Service coil may then mill a window out of the 5" liner. Slickline, wireline & service coil prep work is expected to commence August 15, 2001. Coil tubing drilling operations, as detailed below will commence September 1,2001. 1. A 3" sidetrack, -2070' long will be drilled out of the 5" liner into the Zone 1 reservoir. 2. The sidetrack will be completed with a 2-3/8", solid, cemented & perforated liner. John Cubbon CT Drilling Engineer Tel' 564-4158 Fax: 564-5510 Cell: 240-8040 cubbonjr@bp.com Well File Petrotechnical Data Center Terrie Hubble TREE = 4-1/1 ~' ClW 5K VVELLHE~D= FMC ACTUATOR=- BAKER C KB. ELL:V= 66' BF. ELEV: ? KOP = 1450' Max Angle = 53 (~ 7281' Datum IVD = Datum 'IV D= 8800' SS I 10'3/4" CSG' 45'5#' L'80' ID: 9'953" H 39' I9-5/8" CSG, 47#, L-80, ID: 8.681" H 3964' 3-1/2"TBG, 9.2#, FOX 13CR80, ID :2.992" H 10148' JMinimum ID = 2.750"@ 10267' 3-1/2" PARKER SWN NIPPLE 15-41A ISAFETY NOTES: COILEDTBG FISH IN WELL (SIDETRACK SECTION). 3.5" UI',IQUE CA/ERSHOT WAS SPACED OUT TO SWALLOWTBG STUB @10,170'. DEPTH DISCREPANCY DUE TO DIFFERENC~ BETWEEN E-LINE & RIG MEASUREMI~ITS. GAS LFT MANDRELS TYPE MAN CA-FIVHO CA-FlVl-IO 10080' 10102' 10127' 10170' 10156' 10207' 10210' 3 -1/2" IllS X NP, ID = 2.813" } H 7" X 4-1/2" BAKER S'3 I=KR' ID = 3'875" I I I 3'1/2" I-ES X NIP' ID = 2'813" 1 HCI-EMCALLY CUT TBG-12/23/00 [~3-1/2" UNQUE OVERSHOT, ID: 3.625" 10214' J----j 4-1/2"X3-1/Z'XO J 10245' [---'J 3-1/2" OTIS X NIP, ID = 2.813"I I 7" X 5" TIW LNPJI-IqGPJPKR H 3-1/Z' TBG, 9.2#, L-80, .0087 bpf, ID= 2.99Z' H 7" CSG, 26#, L-80, ID = 6.276" H 10270' 10281' 10438' PERFORATION SUrvtVIARY REF LOG: SWS GPJCCL 11-1%94 ANGLEATTOP PERF'. Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE NO PERFS 5"LNR, 15#, 13CR-80, .0196 bpf, D =4.408" H 11150' 10267' 3-1/2" PARKER SWN NIP, ID= 2.75" 10281' ~ 3-1/2" TUBINGTAIL WI_EG I ELM'Ir DATE NOTAVAILABLE I 10750' CTM ]----] 2" COILTBG, TOPOFFISH, ' I 3RD CillM CUT (SUCCESSFUL) I M ILLED WINDOW IN 5" LNRI TOP @ 10,810' BTM @ 10,814' 10925' ]--'"'1 DEPTH OF 2ND Gl-EM CUT (DID NOT FREE PPE) 11150' DEFq'H OF 1ST CillM CUT J I (DD NOT FREE PIPE) 11380' ~ END OF FISH- BHA .111687' ]----.-] TOP OF FISH- BI-IA / (51' LONG) BTM OF FISH .. (BHA #1) DATE REV BY COMIVENTS DATE REV BY COMIVENTS 11/12/94 ORIGINAL COMFL EtlON 03/05/01 ABORTED SIDErRACK 08/09/94 WORKOVER 05124101 cFrrP OORRECTIONS 12/04/00 SlS-lsl CONVERTED TO CANVAS 01/1 3/01 LAST WORKOVER 01/1 9/01 SIS-MD FNAL PRUDHOE BAY UNIT WELL: 15-41A PERMIT No: 94-094 APl No: 50-029-22492-00 Sec. 16T11N R14E299.39 FEL 1205.99 FN_ BP Exploration (Alaska) 'I'RI~= 4-1/16'CNV5K 15-41B SAFETY NOTES: COILEDTBG FISHINWELL (S[3ETRACK : WELL~D= FMC SECTION). 3.5" UNIQUE OVERSHOT WAS SPAC::~D OUT TO ~,c~Yc~-~ ....... 8;~'K~C PROPOSED CTD SIDETRACK SWALLOWTBGSTUI3 @10,170'. DEFrrHDISCREPA~ ~ KB~ I=j ~V '= ......... 6(~' TO DI:FEt:~ BETWEEN ~L~ & ~ ~S~. i~'i=~ ~E~'= ........................... ............. ? '~ ~ ~ --' J C.,AS LFT MANDRELS Max'~n~e = ........../ STA , MD TVD DEV TYPE MAN LATCH ~:~t~m-1~3-~- ................. 1 3577, CA-FlVlHO RK J~-~-r~':i;~'i~. __~_~:~;-§'~ ~ 2 6746, CA-FIVlI-E) RK L I 10-3/4' CSG, 45.5,9, L-80, D = 9.953' m . ~ 3 9125' C~-~ RK ; 4 10008' CA-~ RK 19'5/8"CSG, 47#,L-80,Io=8-681" ~ 3964' ~ , I I 13'l/2'~G'9'2#'F°x13c~°'~=2'992'i-I ?. t : I I ~t ~0~7' t----I 3'1~2'~s'~"~=2'813"1 --~1 10156' I~-I 3-1/2" UNIQUE OVERSHOT, IO=3.625"I '"Mini.rnumlD = 2.750"@ 10267' ~ 10207' ~ 3-1/2- x 4- ~ /2" xoI 3-1/2 PARKER SWN NIPPLE 1 '~~~~ 10210' ~----J ~--17"x4'a/2"BAKERSABL-aPACKERI i-- ~ '10240' HTop of Proposed 2-3/8" Liner I I' 'TOPOF 5"LNR I~ ~ I;--~ 3'1/2" PARKER SWN NIPPLE, ID=2.75"I 3-1/2"'mG, 9.2#.L-80,.0087bp',lO=2.992"l~ ]---'-~l~l ,--~ ~-~,~'~,~*^,_W~ I I ," csG. 2~. L-80. ~= 6.2~- I~ ~ / · . ~ __ ~ ~,.:-- ~ 10550 ~ Cement ~op I ANGLEATTOP Pl3~: 17 @ 10957 Note: Refer to Production DB for historical perf data / s~,~ s.= .rERv^L ,~./Sqz ~ 5-,u~ lS~, 13m-80,.o19~p~,~--4.408. I--! ~-~ ]____a~ DATE REV BY COMMENTS DATE REV BY COMlV~ PRUOHOEBA¥ UNIT 11112/94 ORIGI~IAL COMPLETION 03/05/01 ABORTED SIDETRACK WELL: 15-41B Proposed ST 08/09/94 WORKOVER 04118/01 CHrrP CORRECTIONS PERMIT No: 94-094 12/04100 SIS-Isl CONVERTED TO CANVAS 04/24/01 pcr Proposed ST 15-41B APl NO: 50-029-22492-00 01113101 : LAST WORKOVE~ Sec. 16 T11N R14E 299.39 FEI. 1205.99 FNL 01119/01 SIS-MD FINAL BP Exploration (Alaska) .., SIZE SPF INT13~AL OpnlSqz DATE DATE REV BY COMNENTS DATE REV BY COMlVENTS 11112/94 ORIGI~IA L COMPLETION 03/05/01 ABORTED SIDETRACK 08/09/94 WORKOVER 04118/01 CHrrP CORRECTIONS 12/04100 SlS-Isl CONVERTED TO CANVAS 04/24/01 pcr Proposed ST 15-41B 01113101 LAST WORKOVER 01/19/01 SIS-MD FINAL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_X Stimulate_ Plugging _ Perforate _ Pull tubing _ Alter casing _ Repair well _ Other _ 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchorage, AK 99519-6612 5. Type of Well: Development __X Exploratory__ Stratigraphic_ Service__ 4. Location of well at surface 1474' FNL, 4566' FEL, Sec. 22, T11N, R14E, UM At top of productive interval At effective depth At total depth 792' FNL, 4883' FEL, Sec. 15, T11N, R14E, UM (asp's 676649, 5960022) (asp's 676183, 5965976) 6. Datum elevation (DF or KB feet) RKB 66.25 feet 7. Unit or Property name Prudhoe Bay Unit 8. Well number 15-41A 9. Permit number / approval number 200-180 / 301-052 signed 3/21/2001 lO. APl number 50-029-22492-01 11. Field / Pool Prudhoe Bay Oil Pool 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Conductor 110' Surface 3925' Intermediate 10372' Liner 880' 11818 feet Plugs (measured) 8798 feet 10750 feet Junk (measured) 8583 feet Size Cemented 20" 260 SX AS 9-5/8" 944 Sx PFE & 375 Sx PFC 7" 307 Sx Class G 5" 112 Sx Class G Top of 2" CT(filled w/cement) @ 10750' MD 3/4/01. Top of mill/motor BHA @ 11605' MD. 2" CT f/10750' to 11380' MD w/cement. Cement fl 11500' - 11380' MD Measured Depth True Vertical Depth 110' 110' 3964' 3558' 10438, 8276' 10810' 8642' Perforation depth: measured Uncased Open Hole w/fish fl 10814' - 11818'. true vertical Uncased Open Hole w/fish f/8646'- 8798'. Tubing (size, grade, and measured depth) Packers & SSSV (type & measured depth) RECEIVED 30 2001 Alaska Oil & Gas Cons. Commission 3-1/2", 9.2#, 130R-80 Tbg @ 10156' MD; 3-1/2", 9.3#, L-80 Tubing @ 10281' MD. Anchorage 7" x 3-1/2" Baker S-3 Packer @ 10102' MD; 7" X 4-1/2" BAKER SABL-3 PACKER @ 10210' MD; 13. Stimulation or cement squeeze summary Intervals treated (measured) (see attached) Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation OiI-Bbl Shut in Shut in Representative Daily Avera.qe Production or Injection Data Gas-Md Water-Bbl . Casing Pressure Tubing Pressure 15. Attachments Copies of Logs and Surveys run ._X (End of Well Survey) Daily Report of Well Operations __X 16. Status of well classification as: Oil __X Gas m Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed~~-'-'/ /'~f"'¢'~'~ "~/~¢/ Title: CTDEngineer Lamar Gantt Date March 29, 2001 Prepared by Paul Rauf 564~5799 Form 10-404 Rev 06/15/88 · SUBMIT IN DUPLICATE 15-41A DESCRIPTION OF WORK COMPLETED MILLED WINDOW / OPERATIONS SHUTDOWN FOR CTD SIDETRACK Date Event Summary 2/10/2001' 2/11/2001: 2/1 2/2001' 2/13/2001' 3/05/2001' 3/08/2001: 3/21/2001: MIRU CTE Unit. Tested BOPE. Injectivity check - zero. PT'd cement plug to 1600 psi - held solid. RIH w/BHA. Tagged TOC @ 10759' MD. POOH. RIH & milled pilot hole to 10804'. Pumped Biozan Sweep. Milled ramp to 10810' & POOH. RIH & milled window f/10810' to 10814' MD. Drilled FM to 10820' & POOH. RIH w/Crayola Mill & conditioned window interval. Reamed window interval. Pumped Biozan Sweep. POOH w/BHA. RD CT Eline Unit. See Final Well~ Event Summary Sheet & Operations Summary Report (attachted)for continuation of this report. Notified AOGCC concerning operations shutdown of operations. Verbal received. Submitted 10-403 for Operations Shutdown to AOGCC. Received 10-403 back from AOGCC w/approval number 301-052. Subsequent 10-404 required. Evaluating options concerning this well. Well is currently shut in. Page 1 BP EXPLORATION Page 1 of 1 Final Well i Event Summary Legal Well Name: 15-41 Common Well Name: 15-41A Event Name: REENTER+COMPLETE Start Date: 2/18/2001 End Date: 3/5/2001 DATE TMD 24 HOUR SUMMARY 2/19/2001 10,820.0 (ft) Moved Rig from C-05A to 15-41A. Rigging-up CTD equipment. 2/20/2001 10,820.0 (ft) R/U rig. N/U BOPE & spot tanks, hardline. Test BOPE. Weld on connect 2/21/2001 10,915.0 (ft) Pull BPV, RIH BHA #1, drill to 10,915', POOH f/orienter, RIH. 2/22/2001 11,220.0 (ft) OOH, Safety Stand Down, RIH drill to 11,222', POOH f/motor. 2/23/2001 11,487.0 (ft) OOH, washed bleed sub. CIO BHA, RIH, drill to 11,487', STUCK. 2/24/2001 11,667.0 (ft) Drill to 11,667' & experience total losses. Mix/Pump Form A Set pill. 2/25/2001 11,817.0 (ft) POOH, p/u Weatherford orienter, RIH & drill to 11,817'. No returns. 2/26/2001 11,818.0 (ft) Stuck @ 11,734'. Work to 11,714'. Pump to open cir¢ sub, disconnected. 2/27/2001 11,818.0 (ft) Continued fishing operations w/o success. 2/28/2001 11,818.0 (ft) Attempt down jarring - no success. Jar w/"hiptripper" & moved fish. 3/1/2001 11,818.0 (ft) Heal losses. Weekly BOP test. 3/2/2001 11,818.0 (ft) Stuck CT during cement plug. Work pipe - no success. 31312001 11,818.0 (ft) Cont waiting while organising equp't/personnel & plan. Cut CT at surf. 3/4/2001 11,818.0 (ft) Cut CT and recover from 10750'. 3/5/2001 11,818.0 (ft) Recover CT. Freeze protect well & secure same. Release rig. Printed: 3/29/2001 1:21:59 PM BP EXPLORATION Page I of 7 Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL ~Rig Name: CDR-1 Rig Number: 1 Sub Date From-To Hours Task Code Phase Description of Operations 2/19/2001 00:00 - 07:00 7.00 MOB PRE Continue to move pieces from C-05A to 15-41A. Main sub & pits moved @ 07:00 Hrs. 07:00 - 18:00 11.00 RIGU PRE Rig up. Spot Sub, coil trailer, & various rig components. Complete some modifications regarding ODS floor winch & fairleads going to same. 18:00 - 00:00 6.00 RIGU PRE Build & trim berms around all complexes. M/U mud, choke, orienter & steam lines. Change out faulty valves in Pump #2 & cetrifugal pump rooms. 2/20/2001 00:00 - 05:00 5.00 RIGU PRE Continue to rig up, clean & secure area around C-05a including tiger tank & open top area. Hardline & tiger tank/open top hook up along with uprights & fluids delayed due to incident on drill site 7. 05:00 - 15:00 10.00 BOPSUF DECOMP N/U BOPE & help spot & berm tanks & rig up hardline to outside tanks. Rig accepted @ 0500 hrs 2-20-2002. 15:00 - 22:30 7.50 BOPSUF DECOMP Commence testing BOPE. AOGCC rep Chuck Scheve waived witnessing of test. Complete test of all BOP components. Function test gas alarms, drawdown test on accumulator & test overflow alarm in cuttings box, all OK. 22:30 - 23:00 0.50 BOPSUF DECOMP Cut 22' off of coil. 23:00 - 23:30 0.50 BOPSUF DECOMP Weld on coil connector. 23:30 - 00:00 0.50 BOPSUF DECOMP Pull test/pressure test coil connector, OK. 2/21/2001 00:00 - 00:30 0.50 BOPSUF DECOMP Finish pull testing coil connector, OK. 00:30 - 03:15 2.75 BOPSUF DECOMP Pick up lubricator & attempt to pull BPV, no good. M/U nozzle & wash top of BPV. R/U lubricator & pull BPV. Well stable. 03:15 - 03:30 0.25 DRILL PROD1 Pre job safety meeting on BHA make up w/emphasis on piPe wrench safety. 03:30 - 05:00 1.50 DRILL PROD1 M/U BHA #1. Surface test Sperry orienter, OK. 05:00 - 07:30 2.50 DRILL PROD1 M/U to coil & RIH. Shallow hole test, OK. Continue in. 07:30 - 08:15 0.75 DRILL PROD1 Pre Spud Meeting. Well bore IDs, lost circulation & projected fault depths. Window/ramp depths & tie in depths & procedures regarding same. Spill prevention & spotting trucks in close quarters. Flagging pipe on every trip. Chrome tubing..watch f/wear spots on coil. Awareness & communication. Housekeeping. 08:15 - 09:30 1.25 DRILL PROD1 Continue in hole, correct @ EOP flag, add 16'. 09:30 - 10:15 0.75 DRILL PROD1 Tie in w/gamma, add 42' correction. 10:15 - 10:25 0.17 DRILL PROD1 RIH, dry tag @ 10,824'. 10:25 - 10:30 0.08 DRILL PROD1 P/U & get toolface, 20R. 10:30 - 11:15 0.75 DRILL PROD1 RBIH, & tag @ 10,820', drill to 10,846' @ HS-20R TF. ROP 20-30 fph. 11:15 - 12:00 0.75 DRILL PROD1 Pull into liner & dispalce coil to FIo Pro. 12:00 - 15:00 3.00 DRILL PROD1 Drill ahead to 10,915', ratty drilling, TF 45R. Freespin @ 1.6 bpm 3600 psi, 200-300 dp on motor, 2K WOB. 15:00 - 16:15 1.25 DRILL ORNT PROD1 Attempt to orient in open hole, no good. Pull into liner & attempt to get clicks, NG. 16:15 - 18:45 2.50 DRILL ORNT PROD1 POOH f/orienter, flag pipe @ 10,400' EOP. 18:45 - 19:45 1.00 DRILL ORNT PROD1 L/D orienter, equalizer sub was plugged w/wood...? Flushed same, c/o orienter, motor & MHA. 1.75 deg motor. 19:45 - 21:30 1.75 DRILL ORNT PROD1 RIH, shallow hole test, OK. 21:30 - 22:00 0.50 DRILL ORNT PROD1 Pre Spud w/night crew. 22:00 - 23:30 1.50 DRILL ORNT PROD1 Tie into EOP flag, add 47' correction. 23:30 - 00:00 0.50 DRILL ORNT PROD1 Tie in w/gamma. 2/22/2001 00:00 - 00:30 0.50 DRILL PROD1 Finish tie in w/gamma, subtract 6' correction. 00:30 - 01:00 0.50 DRILL PROD1 Continue in hole, tag bottom @ 10,911'. 01:00 - 02:30 1.50 DRILL PROD1 Drill ahead f/10,911' to 10,972'. TF 60L, ROP 25-35 fph. 23K up wt, 34K dn. Getting 27deg/100'. Printed: 3/29/2001 1:22:18 PM BP EXPLORATION Page 2 of 7 Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL Rig Name: CDR-1 Rig Number: 1 Sub Date From-To Hours Task Code Phase Description of Operations 2/22/2001 02:30 - 03:00 0.50 DRILL ;PROD1 Orient to 80R. 03:00 - 04:15 1.25 DRILL I PROD1 Drill ahead @ 70-80R. ROP 25 fph w/2-3K WOB. 04:15 - 07:15 3.00 DRILL PROD1 POOH f/.8 deg motor to land build & continue drilling. 07:15 - 07:45 0.50 DRILL PROD1 ~ L/D BHA #2 & circulate coil to pits. 07:45 - 09:45 2.00 DRILL PROD1 :Safety Stand Down 09:45 - 10:45 1.00 DRILL PROD1 M/U BHA #3 10:45 - 13:00 2.25 DRILL PROD1 RIH, shallow hole test, OK. EOP flag tie in, add 25'. 13:00 - 13:20 0.33 DRILL PROD1 Tie in w/gamma, subtract 5'. ~ 13:20 - 13:45 0.42 DRILL PROD1 Continue in hole, window smooth, tag @ 11,002'. 13:45 - 14:15 0.50 DRILL PROD1 Orient TF to 70R. 14:15 - 17:45 3.50 DRILL PROD1 Drill ahead, TF 50R & gradually clicking around to 160R as .8 deg motor building @ 18/100. Drill to 11,186' into shale. 17:45 - 18:10 0.42 DRILL PROD1 Wiper trip to window. 18:10 - 18:30 0.33 DRILL PROD1 Orientto 70-80R 18:30 - 21:00 2.50 DRILL PROD1 Drill ahead to 11,220', shale, weak stalls, 300-400 psi. Call for a tight motor. 21:00 - 00:00 3.00 DRILL OCOL PROD1 POOH due to weak motor. Monitor well & paint EOP flag @ 10,200. Monitor well @ 500', well stable. 2/23/2001 00:00 - 01:00 1.00 DRILL OCOL PROD1 M/U BHA #4. Motor appeared loose & cio same, no other apparent problems w/BHA. 01:00 - 03:30 2.50 DRILL OCOL PROD1 RIH, shallow hole test, OK. 03:30 - 04:30 1.00 DRILL OCOL PROD1 Tie in w/gamma, subtract 14' correction. 04:30 - 05:00 0.50 DRILL OCOL PROD1 Continue in hole, tag @ 11,222'. 05:00 - 05:15 0.25 DRILL OCOL PROD1 Orient TF to 80-90R. 05:15 - 06:15 1.00 DRILL OCOL PROD1 Attempt to drill ahead, same results as last run, freespin @ 3400 @ 1.6 bpm, set down & stall, (weak), w/300-400 psi dp on motor. Unable to drill. 06:15 - 09:30 3.25 DRILL OCOL PROD1 POOH, flag EOP @ 10,400, monitor well @ 500', stable. 09:30 - 11:00 1.50 DRILL OCOL PROD1 LID bit, MHA & swivel, discover bleed sub washed out, cio same. P/U DPI bicenter. 11:00 - 13:15 2.25 DRILL OCOL PROD1 RIH, shallow hole test, OK. Tie in @ EOP flag, add 8' correction. 13:15 - 14:15 1.00 DRILL PROD1 Tie in w/gamma, add 1' correction. 14:15 - 14:45 0.50 DRILL PROD1 Continue in hole, tag @ 11,222'. 14:45 - 15:40 0.92 DRILL PROD1 Drill ahead to 11,260'. TF 130R, freespin @ 1.6 bpm, 3400 psi, 100-200 dp on motor, 34K up wt, 23K dn. ROP 80 fph. 15:40 - 16:10 0.50 DRILL PROD1 Orient to 80-90R. 16:10 - 17:00 0.83 DRILL PROD1 Drill ahead @ 50-70R. 2K WOB, 200-300 dp on motor. Drilling becoming ratty ..... fault..? Drill to 11,311' ROP 60 fph. 17:00 - 17:30 0.50 DRILL PROD1 Orient TF to 30R. 17:30 - 19:30 2.00 DRILL PROD1 Drill ahead to 11,431'. Experience near total losses @ 11,418'. 19:30 - 19:45 0.25 DRILL DS PROD1 Stuck @ 11,431', relax pipe w/pumps off 15 mini pull free. 19:45 - 21:15 1.50 DRILL PROD1 Drill w/losses, pump 5 bbl LCM pill & drill to 11,487'. gettting returns back up to 80%. Stuck again. 21:15 - 00:00 2.75 DRILL DS PROD1 Work pipe a few times after relaxing w/pumps off, unable to pull free, pulling 20K over up wt. Take on 300 bbls new mud, and crude on the way. Circulate @ minimum rate & W/O crude. 2/24/2001 00:00 - 01:45 1.75 DRILL DS PROD1 PJSM on pumping crude, pump 7 bbls & chase w/mud. Pull free w/6 bbls crude out. Recieved 300 bbls new FIo Pro. 01:45 - 02:05 0.33 DRILL PROD1 Wiper trip to window, hole smooth. 02:05 - 02:35 0.50 DRILL PROD1 Orient TF to 80-90R...14 clicks. 02:35 - 04:00 1.42 DRILL PROD1 Drill ahead f/11,487'-11,547'. TF 75R, 3K WOB, ROP 40 fph. 3700 freespin @ 1.5 bpm, 300 dp on motor. Inclination dropping @ 75R. Return rate 70-80%. Adding OM Seal/Liquid Casing as we drill. Printed: 3/29/2001 1:22:18 PM BP EXPLORATION Page 3 of 7 Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL Rig Name: CDR-1 Rig Number: 1 Sub Phase Description of Operations Date From-To Hours Task Code 2/24/2001 04:00 - 04:20 0.33 DRILL PROD1 Orient to 20-30R, MWD quit pulsing. 04:20 - 04:45 0.42 DRILL PROD1 Wait for MWD to clean up, getting good pulses. 04:45 - 05:30 0.75 DRILL PROD1 Continue orienting, orienter not getting 1:1. 05:30 - 06:15 0.75 DRILL PROD1 Drill ahead to 11,576'. Return rate 70-80%. Losing 20 bbls/hr. 06:15 - 07:15 1.00 DRILL PROD1 Orient TF to 80R. 07:15 - 08:00 0.75 DRILL PROD1 Drill to 11,598'. TF rolled to 40R...ratty drilling. 08:00 - 08:30 0.50 DRILL PROD1 P/U above fault to orient. Orient to 90R. 08:30 - 11:30 3.00 DRILL PROD1 Drill ahead to 11,667'. TF 30-70R. ROP 60 fph, Abrupt loss of all returns @ 11,667'. .11:30 - 16:00 4.50 DRILL ClRC PROD1 Stop pumping mud, 240 bbls FIo Pro on surface, go to KCL. Lead KCL w/20 bbl LCM pill, see returns pick up to 40-50% f/3-5 minutes when LCM out bit, then back to no returns. Orienter not responding, MWD not getting a good signal. Opt to pumping FORM A SET. Circulate KCL w/ prepping for pill. Losing all returns. 16:00 - 16:15 0.25 DRILL CIRC PROD1 Pre job on mixing Form a Set pill. Proper PPE...full face mask for mixing accellerator. 16:15 - 22:30 6.25 DRILL ClRC PROD1 Take on fresh water & heat to 90-95 degrees. Mix pill. Take on 300 bbls KCL. Continue circulating @ 1 bpm/1800 psi w/mixing pill, no returns. 22:30 - 22:45 0.25 DRILL ClRC PROD1 Add accellerator to Form a Set pill. 22:45 - 00:00 1.25 DRILL ClRC PROD1 'Pump 36 bbls Form a Set followed by 18 bbls 15#/bbl OM Seal/Liquid : casing pill & 25 bbls FIo Pro. POOH f/11,600' @ 45 fph after allowing 2 bbls of pill out, pumping @ .75 bpm. Continue out pumping !approximately 25-30% faster than pulling pipe. 2/25/2001 00:00 - 01:00 1.00 DRILL ClRC PROD1 ;Shut down pump w/last of LCM out the bit. Pull up to 6500' & bring on !pump to fill hole. Getting partial returns after pumping 8 bbls, shut down i& monitor. After 15 minutes pump to fill hole, 2 bbls to get partial returns. 01:00 - 02:30 1.50 DRILL ClRC PROD1 POOH, monitor well @ 500', 2 bbls to fill hole. 02:30 - 03:45 1.25 DRILL CIRC PROD1 CIO MWD & surface test & M/U new orienter, OK. 03:45 - 06:30 2.75 DRILL ClRC PROD1 RIH, shallow hole test, OK. Continue in to tie in point. 06:30 - 07:20 0.83 DRILL PROD1 Tie in w/gamma, add 9' correction. 07:20 - 08:00 0.67 DRILL PROD1 Continue in hole, wash/ream Form a Set, no real resistance. Tag @ :11,673', 30% returns. Orient to 90R. 08:00 - 10:35 2.58 DRILL PROD1 !Drill ahead to 11,683' w/KCL/water & experience total losses. TF 90R, !36K up wt, 24K dn, 2400 psi freespin @ 1.6 bpm. 1-2K WOB, ROP 85 fph. Drill ahead to 11,755' w/no returns. 10:35 - 11:30 0.92 DRILL ClRC PROD1 :Attempt to orient, not getting clicks. Not enough back pressure as well , is drinking. Try by closing reel valve when down on pump, NG. 11:30 - 16:00 4.50 DRILL ClRC PROD1 :POOH f/ Weatherford non locking orienter. Stop & monitor well, taking 'fluid, no returns. Paint EOP flag @ 10,400'. Monitor well at surface. ;Continue filling down annulus. 16:00 - 16:15 0.25 DRILL PROD1 ;Pre job on BHA. 16:15 - 17:45 1.50 DRILL PROD1 L/D orienter surface test Weatherford orienter. Continue filling backside w/doing BHA. Shut down & observe well mid way. Pump entire tubing volume down well @ 2-3 bpm, no returns. Finish BHA w/pumping down annulus @ .7 bpm. Stab on well. 17:45 - 20:00 2.25 DRILL PROD1 RIH, shallow hole test, OK. Continue in to tie in point. 20:00 - 22:00 2.00 DRILL PROD1 Some trouble w/MWD, will not go to gravity TF. Tie in w/gamma, add 3' correction. 22:00 - 22:55 0.92 DRILL PROD1 Continue in hole, work w/MWD, get gravity TF & tag @ 11,760'. Hole smooth, no bobbles. 22:55 - 00:00 1.08 DRILL PROD1 Drill ahead to 11,817'. TF 110-140R, WOB 1-2K, ROP 80-90 fph. 39K up wt, 26K dn. 2550 psi freespin @ 1.6 bpm, 100-200 dp on motor. Printed: 3/29/2001 1:22:18 PM BP EXPLORATION Page 4 of 7 Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL Rig Name: CDR-1 Rig Number: 1 Sub Date From-To Hours Task Code Phase Description of Operations 2/26/2001 00:00 - 00:15 0.25, DRILL PROD1 Drill ahead to 11,818', note weight starting to stack, pick up & become stuck @ 11,734' 00:15 - 01:30 1.25 DRILL FORM PROD1 Attempt to pull free using the relaxation technique, NG. Call f/crude. 01:30 - 01:45 0.25 DRILL FORM PROD1 Pre job on pumping dead crude. Focus on going slow, securing all connections & monitoring lines. Communication. 01:45 - 02:45 1.00 DRILL FORM PROD1 Pump 9 bbls crude & chase w/KCL/water. With 6 bbls out, pull 20 K over up wt, nothing, slack off, unable to go down, bring pump up to 1.6 bpm & pull, gain 12' & stuck...dragging. No returns. 02:45 - 04:15 1.50 DRILL FORM PROD1 Pump 20 bbls crude, w/7 out, pick up pump rate to ensure crude getting up around BHA, work pipe up & down no movement. Slow pump down to minimum rate, work pipe, no good. Circulate to clear wellbore of crude, no returns. 04:15 - 05:45 1.50 DRILL FORM PROD1 Pump 20 bbls crude, w/6bbls out bring pump rate up & pull 60K, make 8-10', dragging & stuck. Try to go down, no good. Unable to free. Circulate..no returns. 05:45 - 06:15 0.50 DRILL FORM PROD1 Crew change, pre tour safety meeting. Try to orient (5) clicks, not seeing TF change indicating BHA stuck. '06:15 - 09:00 2.75 DRILL FORM PROD1 Prepare 20#/bbl OM Seal/Liquid Casing pill, (5 bbls). Consult town .... discuss options. Work pipe after relaxing, no good. Continue to circulate w/waiting on orders. 09:00 - 10:00 1.00 DRILL FORM =ROD1 Pump 1 last crude pill, (20 bbls). Unable to free pipe, got a small amount of returns. Pump (1) annular volume @ 1.5 bpm, 250 psi, pressure down to 50 psi after 10 bbls away. 10:00 - 11:30 1.50 DRILL FORM PROD1 Drop 5/8" ball to open circ sub & chase w/25 bbls FIo Pro. Ball on seat & shear @ 3100 psi, pump 1.9 bpm @ 1900 psi, Pick up & free w/49K up wt. Pull thru window & circulate. 11:30- 13:00 1.50 DRILL ClRC PROD1 POOH. 13:00 - 14:00 1.00 DRILL CIRC :)ROD1 Pump # 2 down w/leaking swab, pump #1 down, engine failure, (bad oil cooler). Repair #2 pump w/pumping down coil w/charge pump @ .3 bpm. HCR shut in w/working on pump. 14:00 - 16:00 2.00 DRILL ClRC F~ROD1 POOH pumping @ 2 bpm. OOH, check well f/pressure, 100-150 psi on well. 16:00 - 19:15 3.25 DRILL CIRC PROD1 RBIH, pumping down 3 1/2" tbg. Take returns thru choke to tiger tank. Pumping 1.8 bpm @ 10,400', getting 1.1 bpm clean KCL returns w/150 psi back pressure .... ? Pump hole volume & shut down 10 minutes, pump 9 bbls to fill well. Pump 1.8 bpm, getting 1 bpm returns. 19:15 - 23:30 4.25 DRILL CIRC PROD1 POOH. Monitor well @ 5000' & 500'. 23:30 - 00:00 0.50 DRILL ClRC PROD1 OOH, disconnected. Retrieve 5~8" ball. Call f/fishing tools. Keep hole full. 2/27/2001 00:00 - 01:30 1.50 FISH GEOM PROD1 Wait on tools. Displace coil to methanol w/waiting. Fill hole w/charge pump. 01:30 - 02:30 1.00 FISH GEOM PROD1 M/U BHA & hang off tugger. 02:30 - 04:30 2.00 FISH ClRC PROD1 Replace swabs & liners in #2 mud pump. Filling hole w/charge pump. 04:30 - 05:00 0.50 FISH FORM PROD1 M/U fishing tools. 05:00 - 08:15 3.25 FISH FORM PROD1 RIH w/fishing BHA. Getting 50-60% returns. Tie in @ EOP flag, ;subtract 26' correction. 08:15 - 10:30 2.25 FISH FORM PROD1 :24K dn wt, 4K up. Tag top of fish @ 11,605', should be approximately 11,663'. Wash down to & successfully latch up. Attempt to down jar, up jar w/no indication of any movement. 24 down jars, 20 up. Max up pull..70K. 10:30 - 17:00 6.50 FISH FORM PROD1 POOH, town consulting on next step. Monitor well @ 10,000'. Continue OOH. Monitor well at 500' & POH to BHA. 17:00 - 18:00 1.00 FISH FORM PROD1 Rack back injector. LD fishing BHA. Printed: 3/29/2001 1:22:18 PM BP EXPLORATION Page 5 of 7 Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL Rig Name: CDR-1 Rig Number: 1 Sub Date From-To Hours Task Code Phase Description of Operations 2/27/2001 18:00 - 22:30 4.50 FISH FORM PROD1 Displace coil to MeOH & cut 200' for fatigue management. Weld on new connector. PT 20klbs/2500 psi. Displace coil to KCl. Circ across top of hole - losing approx 50 bph to formation. 22:30 - 23:30 1.00 FISH FORM PROD1 MU new fishing BHA with 20 additional feet of weight bar. MU coil connector. 23:30 - 00:00 0.50 FISH FORM PROD1 RIH with fishing BHA. 2/28/2001 00:00 - 03:15 3.25 FISH FORM PROD1 RIH with fishing assembly. Correct depth at flag (+94'). Cont RIH and tag TOF at 11587' corrected depth. Engage fish with GS spear on 3rd attempt. 03:15 - 06:00 2.75 FISH FORM PROD1 Jar down on fish total of 35 times slacking off to 8500 lbs to trip jars. Attempt circulation down coil but no returns - can't tell if circ thru fish or at GS spear. Attempt to slack off to zero wt after jars hit but no movement. Jars quit hitting down on last 2 cycles. 06:00 - 07:00 1.00 FISH PROD1 Crew change and pre-tour safety meeting while discuss forward plan with Anch office. 07:00 - 08:00 1.00 FISH FORM PROD1 ~Pull #1 mud pump skid out of pump house to send to Deadhorse to i change out diesel engine. 08:00 - 11:00 3.00 FISH FORM PROD1 POH. 11:00 - 11:30 0.50 FISH FORM PROD1 Rack back injector. LD fishing tools. 11:30 - 12:00 0.50 FISH FORM PROD1 I MU "HipTripper" hydraulic impact tool to attempt to vibrate fish free. MU injector. 12:00 - 14:45 2.75 FISH FORM PROD1 RIH with BHA #10. Correct depth at EOP flag (-104'). Cont RIH and tag ~up on TOF at 11582'. 14:45 - 15:30 0.75 FISH FORM PROD1 ~Start impacting TOF and progress down to 11593'. PU and fill hole. Go back down and progress down to 11620'. PU clean to 11550'. 15:30 - 16:00 0.50 FISH FORM PROD1 !Continue progressing with hiptripper tool pushing fish down to 11687' i then started stacking wt. Losses started increasing during this period as ~if something has been exposed below fish. Getting zero returns at 1.5 !bpm in. 16:00 - 17:00 1.00 FISH FORM PROD1 :POH to 11589' and go down to 11603'. Stacked wt and briefly stuck. . POH to 11500' and fill hole (12 bbl). Make multiple attempts to get past 11605' w/o success. PU clean each time but losses are now at 50 bbl per 30 min. 17:00 - 21:00 4.00 FISH FORM PROD1 POH. Monitor well at 500' - losses have increased to 180 bph. 21:00 - 22:00 1.00 FISH CIRC PROD1 Chg BHA to nozzle + MHA to go in and heal losses. 22:00 - 00:00 2.00 FISH ClRC PROD1 RIH. 3/1/2001 00:00 - 03:00 3.00 FISH CIRC PROD1 RIH with nozzle and correct at flag (-103'). RIH to window & pump 37 bbl LCM pill 15 ppb MI Seal Med, 10 ppb OM Seal, 10 ppb Liquid Casing. Displace from nozzle until started getting returns and then POH laying in remainder at 1:1. POH to 9200'. 03:00 - 04:30 1.50 FISH ClRC PROD1 Circ above LCM pill and use ECD to squeeze away approx 20 bbls to formation. Losses at zero when circ at 1.9 bpm after squeezing LCM away. 04:30 - 06:00 1.50 FISH ClRC PROD1 Wash back down from 9200' to 11557' with full returns. Got stuck at 11557' for approx 15 rain but worked free. No further attempt to go below 11557'. 06:00 - 06:30 0.50 FISH PROD1 POH to window. Crew change & PTSM while cir¢ at safety to get excess LCM out of hole and vac waste fluids. 06:30 - 08:15 1.75 FISH ClRC PROD1 Cont clean out surface tankage while POH. SD at 6500' on orders from Anch to discuss forward plan with Asset. 08:15 - 10:00 1.75 FISH ClRC PROD1 Circ and monitor well while agreeing forward plan. Clean suction and discharge mud pump screens. 10:00 - 11:30 1.50 FISH ClRC PROD1 Cont POH. Observe well at 500'. Printed: 3/29/2001 1:22:18 PM BP EXPLORATION Page 6 of Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL ,Rig Name: CDR-1 Rig Number: 1 Sub Date From-To Hours Task Code Phase Description of Operations 3/1/2001 11:30- 12:00 0.50 FISH ClRC PROD1 Rack back injector. LD nozzle. 12:00 - 13:30 1.50 FISH ClRC PROD1 Monitor wll for losses prior to weekly BOP test. Initially some air/gas breakout but settled down. Standing full after filling with 2,5 bbl. 13:30 - 14:30 1.00 BOPSUR PROD1 Stab on well and displace coil and BOP to MeOH. 14:30 - 14:45 0.25 BOPSUR PROD1 PJSM for BOP test. 14:45 - 00:00 9.25 BOPSUR PROD1 Test BOPE 300/3500 psi. Had to call grease crew to grease master valve - OK. Witness of test waived by AOGCC Rep. 3/2/2001 00:00 - 01:00 1.00 BOPSUR PROD1 Complete weekly BOP test. No failures. 01:00 - 02:00 1.00 STKOH ClRC PROD1 MU cmt nozzle + stinger + MHA. RIH to 2500'. 02:00 - 02:30 0.50 STKOH ClRC PROD1 Circ out MeOH freeze protect from coil. 02:30 - 05:45 3.25 STKOH ClRC PROD1 RIH with nozzle and circ down to 11500'. 05:45 - 06:30 0.75 STKOH PROD1 Circ at 1.5 bpm while slowly moving CT. 36K up 22K dn. Crew change. Hold PTSM for new crew and PJSM with Nabors, Dowell, Peak, BPX for cement plug. 06:30 - 07:00 0.50 STKOH ClRC PROD1 Air up and mix 9 bbl Class G + 8% gel slurry at 13.5 ppg. Pump 5 bbl' water to CT and PT lines to 2000 psi. Pump cement slurry to CT. 07:00 - 07:30 0.50 STKOH ClRC PROD1 Displace cement with 5 bbl water and switch to rig pump. Displace cement to put lead of slurry 1/2 bbl outside nozzle. 07:30 - 08:00 0.50 STKOH ClRC PROD1 Start POH from 11500' with nozzle at 50 fpm pumping 0.5 bpm laying in at 1:1. Approx 2 bbl out at 11380' started pulling heavy. Pull up to max (70K). Slack off and try to work pipe free - no success. Have full circulation with only slight losses (0.1-0.2 bpm). Continue to circ cement out of hole. CT is stuck. 08:00 - 11:30 3.50 STKOH FORM PROD1 Pump 50 bbl Biozan sweep around to help hole cleaning. Follow with 100 bbl FIo Pro and circ to surface- no sucess. CT remains stuck. 11:30 ~ 13:00 1.50 STKOH FORM PROD1 Pump & spot 10 bbl crude in OH annulus. Let soak 20 min and pull up to 70 klbs. No success. 13:00 - 15:00 2.00 STKOH FORM PROD1 Discuss forward plan with Anch office. Drop 3/4" ball and pump on seat to disconnect. Pressure up to 4000 psi and activate disconnect - OK. Work pipe up to 70 klbs & down to zero. No success. 15:00 - 16:00 1.00 STKOH FORM PROD1 Spot additional 10 bbl crude in OH annulus and freeze protect coil with MeOH. 16:00 - 00:00 8.00 STKOH FORM PROD1 Soak stuck CT with crude working pipe every 2 hours. Wait on tools and personnel from Schlumberger CT to assist/advise in operations to cut CT at surface. 3/3/2001 00:00 - 12:00 12.00 STKOH FORM PROD1 Cont circ across top of hole while waiting on assistance and equipment for coil cutting and recovery operations. Discuss procedure with Schlum CT personnel and prepare written plan. 12:00 - 14:00 2.00 STKOH FORM PROD1 Circ out freeze protect and circ well to KCI. 14:00 - 20:00 6.00 STKOH FORM PROD1 Circ well & observe 1-2 bbl/hr loss. Service companies organising tools and machining parts for coil cutting and recovery ops. 20:00 - 20:30 0.50 STKOH FORM PROD1 Circ MeOH into CT on reel to freeze protect same. 20:30 - 21:00 0.50 STKOH PROD1 Safety meeting with crew. Non routine operation. Review written plan and HazlD. Fall protection, pinch points, stored CT energy, well control. 21:00 - 23:00 2.00 STKOH FORM PROD1 Close slip rams to hold CT. RU hot tap equp't and drill into CT wall below injector to verify no pressure in CT. Drain off liquid. 23:00 - 23:30 0.50 STKOH FORM PROD1 RU hydraulic tubing cutter below injector head and cut CT - OK. 23:30 ~ 00:00 0.50 STKOH FORM PROD1 Dress stub with hand cutter and install Baker slip type CT connector. 3/4/2001 00:00 - 02:00 2.00 STKOH FORM PROD1 Install Baker coil connector on CT stub and pull test same. Re-set connector - OK. MU TIW valve, pump in sub, wireline packoff. 02:00 - 04:30 2.50 STKOH FORM PROD1 Circ MeOH out of hole. 04:30 - 05:00 0.50 STKOH PROD1 PJSM for running chemical cutter. 05:00 - 07:45 2.75 STKOH FORM PROD1 RU SWS. RIH ith chemical cutter. Pump down to space out and fire at Printed: 312912001 1:22:18PM BP EXPLORATION Page 7 of 7 Operations Summary Report Legal Well Name: 15-41 Common Well Name: 15-.41A Spud Date: 7/22/1994 Event Name: REENTER+COMPLETE Start: 2/18/2001 End: 3/5/2001 Contractor Name: NABORS TRANSOCEAN Rig Release: 3/5/2001 Group: COIL Rig Name: CDR-1 Rig Number: 1 Sub Date From-To Hours Task Code Phase Description of Operations 3/4/2001 05:00 - 07:45 2.75 STKOH FORM PROD1 11150'. (Window at 10810-10814'). Pull 50 klbs on CT. 07:45 - 09:00 1.25 STKOH FORM PROD1 Cut pipe - good indiation cutter fired but no loss of string wt. POH with chemical cutter and work CT. Pipe is still stuck. 09:00 - 13:00 4.00 STKOH FORM PROD1 Repeat with chemical cutter #2 at 10925'- 110' below window. Again, good indication cutter fired but pipe is still stuck. 13:00 - 15:00 2.00 STKOH FORM PROD1 Wait on another chemical cutter. Work stuck CT - no success. 15:00 - 18:00 3.00 STKOH FORM PROD1 Run chemical cutter #3 and cut pipe at 10750' - 60' above window. Cut was successful and pipe is free. 18:00 - 19:30 1.50 STKOH FORM PROD1 RD SWS and clear floor. 19:30 - 20:00 0.50 STKOH PROD1 PJSM for dressing CT stub and attaching spoolable connector. 20:00 - 22:30 2.50 STKOH FORM PROD1 Dress off ends of CT in hole and on reel and couple together with spoolable connector. Pull test connector. 22:30 - 00:00 1.50 STKOH FORM PROD1 Jack connector up into injector chains with snubbing table. POH with CT spooling onto reel. 3/5/2001 00:00 - 00:30 0.50 .STKOH FORM PROD1 POH with coiled tubing to 2000'. 00:30 - 03:30 3.00 STKOH PROD1 Line up on MeOH and freeze protect tubing from 2000' to surface while finish POH. 03:30 - 04:00 0.50 WHSUR PROD1 Fill hole. DSM set BPV in tubing hanger. Close master valve. 04:00 - 08:00 4.00 WHSUR PROD1 Run CT into BOP stack. RU Schlumberger N2 truck & blow down coil with N2. 08:00 - 16:00 8.00 WHSUR PROD1 Clean pits & prep for reel swap to 2 3/8" CT. Release rig at 16:00 hrs on 3/5/2001. Printed: 3/29/2001 1:22:18 PM BP Exploration (Alaska), Inc. Baker Hu hes INTEQ Survey Report INYF. Q Company: BP Amoco Field: Prudhoe Bay Site: PB DS 15 Well: 15-41 Wellpnt#: 15-41APB1 Date: 3113/2001 Time: 15:40:47 Page: I Co=ordinate(NE) Reference: Well: 15-41, True North Vert~al (TVD) Reference: 58: 41 7/22/1994 00:00 66.2 Section (VS) Reference: Well (0.00E,0.00N,61.00Azi) Survey Calculation Method: Minimum Curvature Db: Oracle Field: Prudhoe Bay North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Coordinate System: Geomagnetic Model: Site: PB DS 15 TR-11-14 UNITED STATES: North Slope Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 ft Ground Level: 0.00 ft 5958837.36 ft Latitude: 70 676296.98 ff Longitude: 148 34 21.213 W North Reference: True Grid Convergence: 1.34 deg Well: 15-41 Slot Name: 41 15-41 Well Position: +N/-S 1176.23 ft Northing: 5960022.10 ff Latitude: 70 17 46.805 N +E/-W 379.93 ff Easting: 676649.20 ff Longitude: 148 34 10.139W Position Uncertainty: 0.00 ft Wellpath: 15-41APB1 Drilled From: 15-41 500292249270 Tie-on Depth: 10810.00 ft Current Datum: 58: 41 7/22/1994 00:00 Height 66.25 ft Above System Datum: Mean Sea Level Magnetic Data: 3/13/2001 Declination: 26.79 dug Field Strength: 57484 nT Mag Dip Angle: 80.79 dug Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ff ff ff deg 0.00 0.00 0.00 61.00 Survey: MWD Start Date: 3/1/2001 Company: Baker Hughes INTEQ Engineer: Tool: MWD,MWD - Standard Tied-to: From: Definitive Path Annotation MD TVD ff 10810.00 8641.67 Kick-off Point 11818.00 8798.01 Projected to TD Survey MD lncl Azlm TVD SSTVD N/S E/W MapN MapE DLS VS ff deg deg ff ff ff ft ff ff deg/100ft ft 10810.00 13.27 358.76 8641.67 8575.42 5456.68 -1018.31 5965452.99 675502.99 0.00 10869.00 39,50 15.30 8694.12 8627.87 5482.02 -1013.41 5965478,44 675507.29 45.77 10899.00 49.00 24.10 8715.61 8649,36 5501.62 -1006.25 5965498.20 675513.99 37.65 10935.00 56,60 18.80 8737.37 8671.12 5528.30 -995.84 5965525.11 675523.77 24.14 10976.00 67.60 15.30 8756.53 8690.28 5562,89 -985.29 5965559.94 675533.51 27.86 11002.00 72.80 20.60 8765.34 8699.09 5586.14 -977.74 5965583.36 675540.51 27.70 11040.00 79.50 24.10 8774.43 8708.18 5620.23 -963.70 5965617.77 675553.74 19.77 11081.00 85.70 28.70 8779.71 8713.46 5656.62 -945.63 5965654.57 675570.95 18.77 11118.00 87.90 33,30 8781.78 8715.53 5688.27 -926.61 5965686.66 675589.22 13.76 11154.00 86.80 35.70 8783.44 8717.19 5717.91 -906.24 5965716.76 675608.88 7.33 11183.00 64.60 38,90 8785.62 8719.37 5740.91 -888.72 5965740.17 675625.86 13.36 11224.00 83,70 43.90 8789.80 8723.55 5771.49 -861.76 5965771.38 675652.09 12.33 11287.00 81.10 48.00 8798.13 8731.88 5814.90 -816.89 5965815.83 675695.92 7.66 11343.00 85.10 51.10 8804.86 8738.61 5850.96 -774.60 5965852.86 675737.35 9,01 11372.00 88.50 54.00 8806.48 8740.23 5868.56 -751.61 5965870.99 675759.91 15.40 11410.00 90.60 59.60 8806.78 8740.53 5889.35 -719.83 5965892.53 675791.20 15.74 11451.00 91.00 63.80 8806.21 8739.96 5908.79 -683.75 5965912.80 675826.82 10.29 11496.00 90.70 70.20 8805.54 8739.29 5926.36 -642.35 5965931.34 675867.78 14.24 1754.82 1771.39 1787.15 1809.19 1835.19 1853.07 1881.87 1915.32 1947.30 1979.48 2005.96 2044.37 2104.65 2159.12 2187.76 2225.64 2266.62 2311.34 BP Exploration (Alaska), Inc. Baker Hughes INTEQ Survey Report ~i'[~:~ Compaay: BP Amoco Date: 3113/2001 Time: 15:40:47 Page: 2 Field: Prudhoe Bay Coordinate(NE) Reference: Well: 15-41, Tree North Site: PB DS 15 Vertical (TVD) Refereaee: 58: 41 7/22/1994 00:00 66.2 Well: 15-41 Sectioa (VS) Refereaee: Well (0.00E,0.00N,61.00Azi) Wellpath: 15-41APB1 Sarvey Calcalatlea Method: Minimum Curvature Db: Oracle Survey MD l~cl Azim TVD SSTVD NIS E/W MapN MapE DLS VS ff deg deg ff ff ff ff ff ff deg/100ff 11529.00 88.90 70.50 8805.65 8739.40 5937.45 -611.27 5965943.17 675898.59 5.53 2343.90 11563.00 90.10 74.00 8805.95 8739.70 5947.82 -578.90 5965954.29 675930.71 10.88 2377.24 11594.00 90.50 76.80 8805.79 8739.54 5955.63 -548.90 5965962.80 675960.51 9.12 2407.27 11643.00 92.20 81.80 8804.63 8738.38 5964.72 -500.78 5965973.02 676008.40 10.77 2453.76 11710.00 92.40 88.79 8801.94 8735.69 5970.21 -434.11 5965980.08 676074.93 10.43 2514.74 11749.00 92.80 93.40 8800.17 8733.92 5969.47 -395.16 5965980.25 676113.87 11.85 2548.44 11788.00 91.40 95.80 8798.74 8732.49 5966.34 -356.32 5965978.04 676152.78 7.12 2580.90 11818.00 91.40 95.80 8798.01 8731.76 5963.31 -326.48 5965975.71 676182.68 0.00 2605.52 Amoco WELLPATH DETAILS Rig: CDR 1 REFERENCE INFORMATION Coordinate {N/E) Re~erence We~Ce~tre: 15-41 T~e Nodh Vertical (TVD) Re[erence: System Mea~ Sea Leve~ Sectior~ (VS) Reference: Slot - 41 (0 00,0 00) Measured Depth Reference 58 41 7/22~994 0000 662 Ca~iation Me[hod Minimum Cu~ature -1~20 1020-1000 950 9O0 ~520 400 -750 -700 650 600 -550 -500 420 -400 -350 300 250 200 -150 -100 -50 0 50 100 150 200 West(-)/East(+) [5Oft/in] 1400 1450 1500 1550 1600 1650 1720 1750 1800 1820 1900 1950 2000 2050 2100 2150 2200 2250 23OO 2350 24O0 2450 2500 2550 2600 2650 2700 2750 2800 2850 290O 295O 3OO0 3O50 3100 3150 3220 3250 3300 3350 3/13/2001 3:52 PM 15-41A operational shutdown Subject: 15-41A operational shutdown Date: Tue, 13 Mar 2001 00:36:12 -0000 From: "McCarty, Thomas M" <McCartTM@BP.com> To: "Tom Maunder (E-mail)" <Tom_maunder@admin.state.ak.us> Tom: We are currently putting together a revised technical package for the subject sidetrack. The revision will likely consist of a different geological target out of the existing liner thus having to plug and abandon the existing open hole section and kick out of the liner above the current window. Timing for this operation is within the next six months, dependent upon 2" coil availability and the flexibility of the existing CTD rig schedule. Thank You Thomas McCarty Coil Tubing Drilling Engineer Alaska Drilling & Wells Office: 907-564-5697 Cell: 907-240-8065 1 of I 3/12/01 4:23 PM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 10-403 RECEIVED MAR 0 9 2001 Alaska Oil & Gas Cons. Commission Anchorage 1. Type of request: Abandon_ Suspend_ Operational shutdown _X Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Variance _ Perforate _ Other_ 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchorage, AK 99519-6612 4. Location of well at surface 1474' FNL, 4566' FEL, Sec. 22, T11N, R14E, UM At top of productive interval At effective depth 1312' FNL, 297' FEL, Sec. 16, T11N, R14E, UM At total depth 786' FNL, 4907' FEL, Sec. 15, T11N, R14E, UM 5. Type of Well: Development _X Exploratory _ Stratigraphic _ Service__ (asp's 676649, 5960022) (asp'$ 675503, 5965440) (asp's 676159, 5965981) 6. Datum elevation (DF or KB feet) RKB 66.25 feet 7. Unit or Property name Prudhoe Bay Unit 8. Well number 15-41A 9. Permit number / approval number 200-180 10. APl number 50-029-22492-01 11. Field / Pool Prudhoe Bay Oil Pool 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Size Conductor 110' 20" Surface 3925' 9-5/8" Intermediate 10372' 7" Liner 880' 5" 11817 8736 10750 8583 feet Plugs (measured) feet feet Junk (measured) feet Cemented 260 sx AS 944 Sx PFE & 375 Sx PFC 307 Sx Class G 112 Sx Class G Top of 2" CT @ 10750' MD 3/4/01. Top of mill~motor BHA @ 11605' MD. 2" CT f/10750' to 11380' MD. Measured Depth True vertical Depth 110' 110' 3964' 3558' 10438' 8276' 10810' 8642' Perforation depth: measured Uncased OH f/10810' - 11817'. true vertical OH f/8642' - 8736'. Tubing (size, grade, and measured depth 3~1/2", 9.2#, 13CR80 Tbg @ 10156' MD; 3-1/2", 9.3#, L-80 Tbg @ 10281' MD. Packers & SSSV (type & measured depth) 7"x 3-1/2" Baker S-3 Packer @ 10102' MD; 7" X 4-1/2" BAKER SABL-3 PACKER @ 10210' MD; 13. Attachments Description summary of proposal __X Detailed operations program __ BOP sketch __.X 15. Status of well classification as: 14. Estimated date for commencing operation March 5, 2001 16. If proposal was verbally approved . ~ ~._¢ / Name of approver ~""~,~ /'~/'/~,""Date approved Oil __X Gas __ Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~ , Title: Coil Tubing Drilling Engineer Tom McCa~ FOR COMMISSION USE ONLY Questions? Call Tom McCarty @ 564-5697. Date Ra~fuf ~6~4.~/9~ / Prepared by Paul Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test _ Location clearance _ Mechanical Integrity Test__ Subsequent form required lo- ORIGINAL ,~'~ ...... D Tailor Approved by order of the Commission Commissioner . %.,/ [ , : [ Appr°val n°~,~)l _ 0,_~.~ bp BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 March 8, 2001 Tom Maunder Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 Fax 276-7542 Dear Tom: Re: 15-41A Operations Shutdown (Permit # 200-180): During the sidetrack drilling phase, loss of drilling fluid to mapped faults could not be controlled. As a result the drilling BHA became stuck and was subsequently left in hole. At this point the plan was to cement back to a point were we had 100% returns, and sidetrack below the abandoned wellpath to TD. However the cementing operation did not go to plan, resulting in the 2" coil being cut 60' above the window. At this time the coil sticking mechanism, 110' below the window is not fully understood. It was most likely a combination of factors; cuttings, hole stability, fluid dynamics associated with pumping cement in open hole. Operational data and personnel are currently being consulted with a view to identifying the sticking mechanism. The well is currently sitting with the master valve closed and a BPV in the tubing awaiting the forward plan. If you have any questions concerning this revision, please don't hesitate to call me at 440-8301 or E-mail me at SherwooA@bp.com. Sincerely, . / ?'L/, ./. / kuistair Sherwood CTD Engineer Alaska Drilling & Wells RECEIVED MAR 0 9 2001 Alaska Oil & Gas Cons. Commission Anchorage bp February 28,2001 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Julie Heusser, Dan Seamount, & Cammy Oechsli Taylor Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, AK 99501 Fax 276-7542 Dear Commissioners: , . . .. Re: Prudhoe-EOA, Pt. Mac, & Lisbume Well Work This listing is provided as required under the terms of Conservation Order No. 34 lC (Rule 14) & Order No. 342. This is a list of well work tentatively scheduled for Februm3~ 26 - March 4, 2001: Well 03-28 02-34A "~,~,~' t~ :._' ..... 16-05Ai 13-27A 11-32 15-35 16-21 Work Planned REPERFORATION CT SET C]BP FOR GSO CTD SIDETRACK (NABORS CDR1) CTD SIDETRACK (NABORS 3S) CT ADD PERFORATION W/WORK PLATFORM ADD PERFORATION ADD PERFORATION REPERFORATION S-101 ADD PERFORATION If additional data or scheduling information is needed, please call me at 564-5799 or E-mail me at raufpc @bp.com. ;i:ulerCilYl uf~ ~~ Technical Assistant, BPXA Alaska Drilling & Wells ALASKA OIL AND GAS CONSERVATION COH~MISSION TONY KNOWLES, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 Thomas McCarty CT Drilling Engineer BP Exploration (Alaska) Inc. P O box 196612 Anchorage, AK 99519-6612 Re~ Prudhoe Bay Unit 15-41A BP Exploration (Alaska) Inc. Permit No: 200-180 Sur Loc: 1476'SNL, 710'EWL, Sec. 22, T1 IN, R14E, UM Btmhole Loc. 4494'NSL, 813'EWL, Sec. 15, T11N, R14E, UM Dear Mr. McCarty: Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Daniel T. Seamount, Jr. Commissioner BY ORDER OF THE COMMISSION DATED this / ,~ 7~ day of November, 2000 dlffEnclosures CC~ Department of Fish & Game, Habitat Section w/o encl. Department of Enviromnental Conservation w/o encl. STATE OF ALASKA , ALASK,~' IL AND GAS CONSERVATION COM~{ ,SION PERMIT TO DRILL 20 AAC 25.005 I [] Exploratory [] Stratigraphic Test [] Development Oil a. Type of work [] Drill [] Redrill lb. Type of well [] Service [] Development Gas [] Single Zone [] Re-Entry [] Deepen [] Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. KBE = 66.25' Prudhoe Bay Field / Prudhoe 3. Address 6. Property Designation Bay Pool P.O. Box 196612, Anchorage, Alaska 99519-6612 ADL 028306 4. Location of well at surface ~,' ~ ./- 7. Unit or Property Name 11. Type Bond (See 2O AAC 25.025) 1476' SNL, 710' EWL, SEC.22, T11N, R14E, UM Prudhoe Bay Unit At top of productive interval 8. Well Number 3921' NSL, 297' WEL, SEC. 16, T11N, R14E, UM 15-41A Number 2S100302630-277 At total depth 9. Approximate spud date 4494' NSL, 813' EWL, SEC. 15, T11N, R14E, UM 11/17/00 Amount $200,000.00 12. Distance to nearest property line 113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL 028303, 784' MDI No Close Approach 2560 12288' MD/8870' TVDss 16. To be completed for deviated wells 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Kick Off Depth 10810' MD Maximum Hole Angle 90 ° Maximum.surface 2482 Psig, At total depth (TVD) 8800'/3362 psig 18. Casing Program Specifications Setting .Depth Size Top BOttOm quantity of Cement Hole Casinq Weiqht Grade Couplinq Lenqth MD TVD MD' ' TVD (include stare data) 3" 2-3/8" 4.6# L-80 FL4S 2048' 10240' 8015' 12288' 8870' 73 cu ft Class 'G' 19. To be completed for Redrill,Re-entry, and Deepen Operations. Present well condition summary Total depth: measured 11150 feet '/ Plugs (measured) true vertical 8969 feet ~ Effective depth: measured 11063 feet Junk (measured) A~a$~a 0il & Gas Co~s. Commissior~, true vertical 8886 feet Casing Length Size Cemented MD TVD Structural Conductor 80' 20" 260 sx Arcticset (Approx.) 110' 110' Surface 3929' 9-5/8" 944 sx PF 'E', 375 sx PF 'C' 3964' 3558' Intermediate 10406' 7" 307 sx Class 'G' 10438' 8276' Production Liner 880' 5" 112 sx Class 'G' 10270'- 11150' 8111'-8969' Perforation depth: measured 10957'- 10984', 11001'- 11011' true vertical 8784' - 8810', 8826' - 8836' 20. Attachments [] Filing Fee [] Property Plat [] BOP Sketch [] Diverter Sketch [] Drilling Program [] Drilling Fluid Program [] Time vs Depth Plot [] Refraction Analysis [] Seabed Report [] 20 AAC 25.050 Requirements Contact Engineer Name/Number: Thomas McCarty, 564-5697 Prepared By Name/Number: Terrie Hubble, 564-4628 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed Thomas McCarty f .~ ~,~ .,.~'"...~,"~ Title CT Drilling Engineer Date .: :, ..' ..:.....! ',,. i,i::.': .::..".....'..: ::. :..'.':..:.': :......',."'.i.'~,:: !.'.i: i:;...::..'.. :..,::~:'. '..;:.: :.:,;~:.::':: ;:..,..,...:: i.;:..::.:com~i~Si:on:;,~.u:~e,.:.O~ly:.,..:::: .,..:~,...,:,.; :.~.:,:;:!,:,,:,: ::.~;..!,:.:i.~:.:: ~ ~'/~.~ 50- 029-22492-01 /,/~/.Z/¢-.-~),¢ for other requirements Conditions of Approval: Samples Required [] Yes ~ No Mud Log Required [] Yes [] No Hydrogen Sulfide Measures ~] Yes [] No Directional Survey Required J[~ Yes [] No Required Working Pressure for BOPE [] 2K [] 3K [] 4K [] 5K [] 10K [] 15K 1~3.5K psi for CTU Other: ORIGINAL SIGNED BY Approved By D Taylor Seamount by order of // ~ I-~ I ~, ~,C¢)~miissi°ner the commission Date ~' (~) .. Form 10-401 Rev. 12-01-85 ORIGi 'L Submit In Triplicate BPX 15-41A Sidetrack Summary of Operations: 15-41 is being sidetracked to target lower Zone 1 reserves. This sidetrack will be conducted in two phases. Phase 1: P&A existing perforations, mill window off cement plug: Planned for Nov. 11-15, 2000. · The well recently passed a TIT. · A Mechanical Integrity Test will be performed. · A whipstock drift and tubing caliper has been run. · Service coil will be used to cement the existing perforations and pressure test. · Service coil will be used to mill the window. Phase 2: Drill and Complete sidetrack: Planned for Nov 17, 2000. Drilling coil will be used to drill and complete the directional hole as per attached plan. Mud Program' · Phase 1&2: Seawater · Phase 3: FIo-Pro (8.5- 8.7 ppg) RECEIVED Disposal: · No annular injection on this well. · All drilling and completion fluids and all other Class II wastes will go to Grind & I~"g~a0jj &GasCons. Commission · All Class I wastes will go to Pad 3 for disposal. .A~chor~e Casing Program: · 2 3/8", 4.6#, L-80, FL4S liner will be run from TD to approx. 10,240' MD (TOL) and cemented with approx. 13 bbls. To bring the top of cement to approx. 10,510'md (TOC). The liner will be pressure tested to 2200 psi and perforated with coiled tubing conveyed guns. Well Control: · BOP diagram is attached. · Pipe rams, blind rams and the CT pack off will be pressure tested to 400 psi and to 3500 psi. · The annular preventer will be tested to 400 psi and 2000 psi. Directional · See attached directional plan · Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Logging · A Gamma Ray log will be run over all of the open hole section. · A Memory CNL will be run in cased hole. Hazards No faults or lost circulation are expected. Res. pressure is normal. DS 15 is not an H2S Pad - last test 1/12/96 at 7ppm. Reservoir Pressure Res. pressure is approx. 3362psi @ 8800ss based on a SBHP (11/10/99). Max. surface pressure with gas (0.1 psi/ft) to surface is 2482 psi. 15-41A Potential Drilling Hazards Post on Rig I · Please perform pre-job Hazard ID and Safety meetings prior to every change in work scope during the operation. Also, if things don't feel right shut-down the operation and discuss the situation before making the next operational move. SAFETY FIRST. 2. H2S is not expected on this well. DS 15 is not an H2S Pad -last test 1/12/96 at 7ppm. 3. BHP is expected to be 3362psi (7.34ppg) @ 8800ss based on a on a SBHP (11/lO/99), 4. Maximum anticipated well head pressure w/full column of gas 2482psi. 5. Lost circulation risk is Iow with no anticipated faults in polygon. 6. The well is planned not to penetrate the Kavik, but there is a chance of accidentally penetrating the Kavik due to regional depth uncertainty. The Kavik could cause some drilling difficulties (sticky shale). RECEIVED ~ ~,'",,,,; ~ .Ar~c~or~e DS 15-41a - OPOSED CT HORIZONTALt"',.,iDETRACK 9 5/8" @ 3964' 3-1/2" SSSV Nipple @ 2243' GLM's @ 3579', 6725', 9095' & 10,119' 3-1/2", 9.3#, L-80 Production Tubing to 10281' 3-1/2 x 4- 1/2" Crossover @ 10,207'-- 7" x 5" Packer @ 10259' 7"@ 10438' Estimated TOC @ 10,510'md 3-1/2" Otis XN Nipple @ 10155' 3-1/2 x 4- 1/2" Crossover @ 10,207' 7"x 4-1/2" Baker SABL-3 Packer @ 10,210' 3-1/2" Otis X Nipple @ 10245' 3-1/2" Parker SWN NipPle @ 10267' Desired Top of 2-3/8" Liner @ - 10,240', inside 3 1/2" TT Mill Window through 5" Liner @ 10,810' off of cement ramp 5", 15#, 13CR Liner to 11,150' Perforations P&A'd by Cement 2-3/8" 4.6# FL4S Liner Cemented & Perforated T 3" Open Hole TD @ -12288' 5" 15# 13CR Liner @ 11,150' Proposal Calculations BAKER HUGHES Coordinates provided in: TRUE and GRID relative to Wellhead INTEQ and ALASKA STATE PLANE Company: BP Exploration Alaska, Inc. Vertical Sect. Plane: 61.000 TRUE Job No: Field: Prudhoe Bay Unit Mag. Declination: 26.920 AFE No: Well: 15-41A Plan #3 Grid Correction: 1.340 APl No: 50-029-22492-01 Rig: Total Correction: 25.580 Coordinate System: TRUE Surface Location Dip: 80.790 Drilled from: 15-41 ×: 676649.2 RKB Height: 66.250 Y: 5960022.1 Meas. Incl. TRUE Subsea Coords. - True Coords. - ASP Dogleg Vertical Tool Face Build Turn Depth Angle Azi. TVD N(+)/S(-) E(+)/W(-) N(+)/S(-) E(+)/W(-) Severity Section Comments (ft) (deg) (deg) (ft) (£t) (£t) Lat. (Y) Dep. (X) (°/100ft) (tt) (do9) (°/100£t) (°/100£t) 10712.60 11.69 0.33 8480.32 5435.65 -1018.14 5965431.97 675503.65 1.28 1744.77 i.70 1.28 0.19 Tie-in Point from 15-41 10805.51 13.18 358.92i 8571.05 5455.65 -1018.29 5965451.97 675503.04 1.64 1754.34 -12.21 1.60 -! .52 10810.00 13.27 358.76i 8575.42 5456.68 -1018.31 5965452.99 675502.99 2.16 1754.82 -22.21 2.00 -3.56 Kick-off Point 10820.00 15.83 3.43 8585.10 5459.19 -1018.25 5965455.50 675502.99 28.18 1756.09 26.86 25.64 46.69 10840.00 21.15 9.37 8604.06 5465.48 -1017.50 5965461.81 675503.59 28.18 1759.79 22.34 26.59 29.69 10860.00 26.60 12.98 8622.35 5473.41 -1015.91 5965469.77 675505.00 28.18 1765.03 16.70 27.23 15.07 10880.00 32.11 15.43 8639.77 5482.90 -1013.48 5965479.32 675507.20 28.18 1771.75 13.39 27.54 12.27 10900.00 37.65 17.231 8656.17 5493.87 -1010.26 5965490.36 675510.17 28.18 1779.89 11.25 27.71 8.99 10920.00 43.21 18.63 8671.39 5506.20 -I006.26 5965502.78 675513.87 28.18 1789.37 9.78 27.82 6.98 10940.00 48.79 19.76 8685.28 5519.78 -1001.52 5965516.46 675518.29 28.18 1800.09 8.71 27.88 5.67 10960.00 54.37i 20.71 8697.70 5534.48 -996.10 5965531.28 675523.36 28.18 1811.96 7.92 27.93 4.77 · . 10980.00 59.97 21.54 8708.54 5550.14 -990.04 5965547.09 675529.05 28.18 1824.85 7.33 27.96 4.15 :~ .~ ...... · 11000.00 65.561 22.28 8717.69 5566.63 -983.40 5965563.73 675535.30 28.18 1838.65 6.88 27.99 3.70 11020.00 71.17 22.96 8725.06 5583.79 -976.25 5965581.04 675542.04 28.18 1853.22 6.54 28.00 3.39 11040.00 76.771 23.60 8730.58 5601.44 -968.66 5965598.86 675549.22 28.18 1868.42 6.29 28.02 3.17 11060.00 82.37' 24.20 8734.20 5619.41 -960.69 5965617.02 675556.76 28.18 1884.10 6.12 28.02 3.02 11080.00 87.98 24.79 8735.88 5637.54 -952.43 5965635.34 675564.59 28.18 1900.! 2 6.01 28.03 2.95 11087.19 90.00 25.00 8736.01 5644.06 -949.41 5965641.93 675567.46 28.27 1905.92 5.96 28.12 2.93 .~,- 1 11100.00 90.00 26.28 8736.01 5655.61 -943.86 5965653.60 675572.73 10.00 1916.37 90.00 0.00 10.00 11150.00 90.00 31.28 8736.01 5699.42 -919.80 5965697.96 675595.76 10.00 1958.66 90.00 0.00 10.00 11200.00 90.00 36.28 8736.01 5740.96 -892.01 5965740.15 675622.57 l 0.00 2003. l I 90.00 0.00 10.00 11250.00 90.00 41.28 8736.01 5779.93 -860.70 5965779.83 675652.95 10.00 2049.38 90.00 0.00 10.00 11300.00 90.00 46.28 8736.01 5816.02 -826.12 5965816.72 675686.67 10.00 2097.12 90.00 0.00 10.00 11350.00 90.00 51.28 8736.01 5848.95 -788.52 5965850.53 675723.48 10.00 2145.98 90.00 0.00 10.00 11400.00 90.00 56.28 8736.01 5878.49 -748.19 5965881.00 675763.10 10.00 2195.56 90.00 0.00 I0.00 11450.00 90.00 61.28 8736.01 5904.40 -705.45 5965907.91 675805.22 10.00 2245.51 90.00 0.00 10.00 11500.00 90.00' 66.28 8736.01 5926.48 -660.60 5965931.04 675849.53 10.00 2295.44 90.00 0.00 10.00 11550.00 90.00 71.28 8736.01 5944.57 -614.01 5965950.22 675895.69 10.00 2344.96 90.00 0.00 10.00 11600.00 90.00 76.28 8736.01 5958.53 -566.01 5965965.30 675943.34 10.00 2393.71 90.00 0.00 10.00 11650.00 90.00 81.28 8736.01 5968.26 -516.99 5965976.17 675992.12 10.00 2441.30 90.00 0.00 10.00 Meas. Incl. TRUE Subsea Coords. - True Coords. - ASP Dogleg Vertical Tool Face Build Turn Depth Angle Azi. TVD N(+)/S(-) E(+)/W(-) N(+)/S(-) E(+)/W(-) Severity Section Comments (t~) (de~) (dc~) (~) (~) (ft) Lat. (Y) Dep. (X) (°/100ft) (~) (deg) (°/100fi) (°/100k) 11700.00 90.00 86.28 8736.01 5973.67 -467.30 5965982.75 676041.67 10.00 2487.39 90.00 0.00 10.00 11750.00 90.00 91.28 8736.01 5974.73 -417.32 5965984.99 676091.60 10.00 2531.61 90.00 0.00~ 10.00 11800.00 90.00 96.28 8736.01 5971.44 -367.45 5965982.87 676141.53 10.00 2573.63 90.00 0.00 I0.00 11817.19 90.00~ 98.00 8736.01 5969.30 -350.39 5965981.13 676158.63 10.00 2587.51 90.00 0.00 10.00 2 11850.00 86.72 98.00 8736.95 5964.74 -317.92 5965977.33 676191.20 10.00 2613.70 180.00 -I0.00 0.00 11900.00 81.72 98.00 8741.99 5957.82 -268.67 5965971.57 676240.59 10.00 2653.42 180.00 -10.00 0.00 11950.00 76.72 98.00 8751.33 5950.98 -220.05 5965965.88 676289.36 10.00 2692.63 180.00 -10.00 0.00 12000.00 71.72 98.00 8764.93 5944.29 -172.42 5965960.31 676337.14 10.00 2731.05 180.00 -10.00 0.00 12015.57 70.16 98.00 8770.01 5942.24 -157.84 5965958.61 676351.75 10.01 2742.80 -180.00 -10.01 0.00 3 12050.00 69.56 94.35 8781.87 5938.76 -125.71 5965955.89 676383.95 10.11 2769.22 -100.58 -1.75 -10.61 12100.00 68.82 89.00 8799.65 5937.39 -79.02 5965955.61 676430.66 10.11 2809.39 -99.32 -1.47 -10.70 12150.00 68.26 83.60 8817.95 5940.39 -32.60 5965959.70 676476.99 10.11 2851.44 -97.42! -1.13 -10.80 12200.00 67.86 78.17 8836.65 5947.73 13.17 5965968.12 676522.58 10.11 2895.04 -95.44: -0.78 -10.87 12250.00 67.65 72.71 8855.58 5959.36 57.94 5965980.80 676567.06 10.11 2939.83 -93.41 -0.42 -10.91 12287.92 67.62 68.56 8870.02 5970.99 91.02 5965993.19 676599.85 10.12 2974.40 -91.30 -0.09 -10.94 TD Proposal Page 2 of 2 (15-41A Plan #3) 11/6/2000 10:21 AM CDR1 Drilling Wellhead I~,,'*ail 15-41a Rig Floor ~ CT Injector Head Otis Q.C. thread half Traveling plate 20.63' 3,8~ .1; 59' 7 /16 ~Shaffer Dual L Hyd-~ill '~,, ~0~0 lei W' R_a__~ Type Dual Gate BOPE 1.95' 7.35' 7" lubricator Traveling Plate 7" O.D. Jacking Frame .~.~Top Stationary Plate Annular BOP (Hydril),7-1/16" ID Annular BOP (Hydril),7-1/16" ID Top blind shea~ Bottom 2" pipes Kill Line __~ Top 2" slips I ~ Bottom 2 3/8" pipes I Manual Master Valve -- Tubing Hanger 9-5/8" Annulus 0.66' Rig Matt Ground Level 13-3/8" Annulus STATE OF ALASKA ALASKf' ")IL AND GAS CONSERVATION COl~: 'SSION ~-,,-PLICATION FOR SUNDRY APPROVe,- 1. Type of Request: I~! Abandon [] Alter Casing [] Change Approved Program 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P.O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1476' SNL, 710' EWL, SEC.22, T11N, R14E, UM At top of productive interval 3921' NSL, 297' WEL, SEC. 16, T11N, R14E, UM At effective depth 4048' NSL, 301' WEL, SEC. 16, T11N, R14E, UM At total depth 4071' NSL, 302' WEL, SEC. 16, T11N, R14E, UM [] Suspend [] Repair Well [] Operation Shutdown [] Plugging [] Time Extension [] Pull Tubing [] Variance [] Re-Enter Suspended Well [] Stimulate 5. Type of well: [] Development [] Exploratory [] Stratigraphic [] Service [] Pedorate [] Other Plug Back for Sidetrack 6. Datum Elevation (DF or KB) KBE = 66.25' 7. Unit or Property Name Prudhoe Bay Unit 8. Well Number 15-41 9. Permit Number 194-094 10. APl Number 50-029-22492-00 11. Field and Pool Prudhoe Bay Field / Prudhoe Bay Pool 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing 11150 feet 8969 feet 11063 feet 8886 feet Length Size Structural Conductor 80' 20" Surface 3929' 9-5/8" Intermediate 10406' 7" Production Liner 880' 5" Plugs (measured) Junk (measured) Cemented 260 sx Arcticset (Approx.) 944 sx PF 'E', 375 sx PF 'C' 307 sx Class 'G' 112 sx Class 'G' DUPLICATE MD TVD 110' 110' 3964' 3558' 10438' 8276' 10270'-11150' 8111'-8969' Perforation depth:measured 10957'- 10984', 11001'- 11011' true vertical 8784'-8810', 8826'-8836' Tubing(size, grade, and measured depth) 3-1/2",9.3#,L-80to 10281' RECEIVED ~aska 0il & Gas Co~s. Oo~tmissio~ ~chorage Packers and SSSV (type and measured depth) Baker 'SABL-3' packer at 10210'; Camco 'TRDP-4A' SSSV Nipple at 2243' 13. Attachments [] Description Summary of Proposal [] Detailed Operations Program [] BOP Sketch 14. Estimated date for commencing operation November 11, 2000 16. If proposal was verbally approved 15. Status of well classifications as: [] Oil [] Gas [] Suspended Service Name of approver Date Approved Contact Engineer Name/Number: Thomas McCar~y, 564-5697 Prepared By Name/Number: Terrie Hubble, 564-4628 17. I hereby certify that the foregoing is true and correct to the best of my knowledge ~ ~..~ ,.~ Date Signed Thomas acCarty ,..-~ ./ Title CT Drilling Engineeii!.' ·... ...... :..........%:c;~m.~¢~p,:u~.~,,y.:-?: ;.:,?' ~.ii,..~... ..".:...'..,~...,;...,.?.' ...~:. ..... ::...:. ., :.~ .. i '1 · . . ' .d. ' ' . "P · ~-_,onditions of Approval: NotifYPlugCOmmissiOnintegrity ~s° representatiVeBoP Testmay~witness Location clearance ~ I ^..rove, Mechanical Integrity Test Subsequent form required 10- Approved by order of the Commiss..!on Form 10-403 Rev. 06/15/88 Commissioner Date Submit In Triplicate bp November 6, 2000 To: Attention: Subject: Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Tom Maunder Petroleum Engineer 15-41 CTD Sidetrack Prep BP Exploration Alaska Inc. Drilling & Wells Coiled Tubing Drilling Team Well 15-41 is scheduled for a through tubing sidetrack to be drilled with coiled tubing. The following summarizes the procedure required to prep 15-41 for drilling and is submitted as an attachment to Form 10-403. A schematic diagram of this proposed completion is attached. ]. The well passed a TIT on 9/22/00. 2.. The well was drifted with a dummy whipstock and a Kinley caliper ran on the tubing. 3. The gas lift mandrels have been dummied off and a Mechanical Integrity Test is planned. 4. Service coil will pump approx. 10bbls of cement to P&A the existing perforations. 5. The window will be milled off of a cement ramp with service coil. The KOP will be at approximately 10,810'md. 6. A sidetrack of approx. 1480 ft into lower Zone I will be drilled with CT. 7. The sidetrack will be completed with a cemented 2 3/8" liner that will 'overlap the existing 3 ~" tubing to -10,207'md (TOL). The estimated Top of cement is planned for 300' above the window to approx. 10,510'md The coil tubing operations are expected to commence November 11. Drilling coil is expected to begin the sidetrack drilling on November 16, 2000. Thomas M. McCarty CT Drilling Engineer Tel: 564-5697 Fax: 564-5510 Cell: 240-8065 mccarttm@bp.com RECEIVED .,; ~', 0il & Gas Cons. Commission ^r~cl~0ra~e Well File Petrotechnical Data Center Terrie Hubble ' DS 15-41a {, ~OPOSED CT HORIZONTAIJ IDETRACK 9 5/8" @ 3964' 3-1/2" SSSV Nipple @ 2243' GLM's @ 3579', 6725', 9095' & 10,119' 3-1/2", 9.3#, L-80 Production Tubing to 10281' RECEIVED .. ~.bv..) 3-1/2" Otis XN Nipple @ 10155' AJaska Oil & Gas Cons. Commission 3-1/2 x 4- 1/2" Crossover @ 10,207' ,Anchorage 3-1/2 x 4- 1/2" Crossover @ 10,2£ 7"x 5" Packer @ 10259' 7" @ 10438' Estimated TOC @ 10,510'md 7" x 4-1/2" Baker SABL-3 Packer @ 10,210' 3-1/2" Otis X Nipple @ 10245' 3-1/2" Parker SWN Nipple @ 10267' Desired Top of 2-3/8" Liner @ ~ 10,240', inside 3 1/2" TT Mill Window through 5" Liner @ 10,810' off of cement ramp 5", 15#, 13CR Liner to 11,150' 2-3/8" 4.6# FL4S Liner Cemented & Perforatec Perforations P&A'd by Cement .T 3" Open Hole TD @ ~12288' 5" 15# 13CR Liner @ 11,1 50' / DATE / CHECK NO. H 1 751 45 V*-NUV~ ~Lf ,~:~1%~ I ~ ! II U DATE INVOICE ! CREDIT MEMO DESCRIPTION GROSS DISCOUNT NET )92&00 ?.½09P&O0! 100. O0 !00. O0 PYMT CDMMENTS: PERMIT TEl DRILL FEE HANDLING INST: S/H TERRIE HUBBLE X4628 ~E ^W^CHEO CHECK ~S ~N PAYUEm FO. ~aS .ESC.m'~ ^SOVE. ~ 1OO- OD 1OO. OD FiI~ST NATIONAL.BANK';bF ASI+II~AND ',".>:! , ":, ]'i: .:Afi]~F.'.FiL;IATE;.O.'~ ::::ii!!': ." '::'" :i:,i:::i ::',':::' NX'~iON,~i/':OITYBAhK .... 'i :: 'v ~[~VELX~O, OHio " .: ' .... ,':.::?756-389 ] ...... ]" .':"" 412 ':,::: :::::: ::?' ':::':,':'.:'.. "i. ::::::::::::::::::::::::: ::,:.:.:: "' ':':':::::,?' .... DATE DAYS . ,.,' ....... :" ;: : ...... NQl?;:.VA. LID AFTER120 ';!; ;',,':':'::" ,.:::::..:,'::.:,,.: :::::'"'"':"::i:i Fo .:.i.![.'Th.e.:'.:i;~. STATE.. OF ALAS:~;:....,......: ...... :.::: :. ~.::~::~.::. .::: :::':;::.: .... ~:.~ .... ~::..:. .... - .'... ...... ::;'b:~ ?.::::?;: .;:".;:: ~OO:Z,::~:'O.cuPZN~['.:::~:~:f::V~:~::'.' ':"::'::,:~.:;': ::: .... :~?: '? :,: ..~::::..: ......., ..::..;.:::: ........ :; ......... : .... ::: ..::.:.~. ~:.:;':;'.:[?..:: .::. ..:.... ............ ANCHORAGE AK 9950 ~ WELL PERMIT CHECKLIST COMPANY FIELD & POOL ~ 4/'O/_,~-'~ INIT CLASS ADMINISTRATION II APPR DATE I E--'~-"~-NEE~ WELL NAME/5'-'~///c~ PROGRAM: exp__ dev ~' redrll ~ '~:~--~' L,,/ ~?'(_.),/d_.- GEOL AREA ~~) 1. Permit fee attached ....................... 2. Lease number appropriate ................... 3. Unique well name and number .................. 4. Well located in a defined pool .................. 5. Well located proper distance from drilling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in drilling unit ............ 8. If deviated, is wellbore plat included ............... 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit can be issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... Conductor string provided ................... 14. 15. Surface casing protects all known USDWs ........... 16. CMT vol adequate to circulate on conductor & surf csg ..... 17. CMT vol adequate to tie-in long string to surf csg ........ 18. CMT will cover all known productive horizons .......... 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. 21. If a re-drill, has a 10-403 for abandonment been approved... 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling fluid program schematic & equiP list adequate ..... '/ serv ~ wellbore seg __ UNIT# (__.2//~, .~-'~(,,.~ ann. disposal para req ~ ON/OFF SHORE Y DATE 25. BOPEs, do they meet regulation ................ 26. BOPE press rating appropriate; test to ~'~3~ psig. 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Work will occur without operation shutdown ........... 29. Is presence of H2S gas probable ................. GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures ..... Y ~ ~ 31. Data presented on potential overpressure zones ....... /,, ~ 32. Seismic analysis of shallow gas zones; ............ ~/'/-~'"Y N II AP,PR DATE ' 33. Seabed condition survey (if off-shore) .......... ._.~-7' Y" ' "N II ,,,~) ~//" ~.OO 34. Contact name/phone for weekly progress reports [explOratory only] Y N "11 s A LT5. II (A) will contain waste in a suitable receiving zonei ....... Y N II ~,PPR DATE (B) will not contaminate freshwater; or cause drilling waste... Y N to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N GEOLOGY: ENGINEERING: U IC:,/,Annular "%. n COMMISSION: JMH ~_~.AH'~' Comments/Instructions: O Z c:\msoffice\wordian\diana\checklist (rev. 11/01//00) Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information· of this nature is accumulated at the end of the file under APPENDIXi .. No special'effort has been made to chronologically organize this categorY of information. **** REEL HEADER **** MWD 02/06/13 BHI 01 LIS Customer Format Tape **** TAPE HEADER **** MWD 02/05/30 110267 01 1.75" NaviGamma - Gamma Ray *** LIS COMMENT RECORD *** Remark File Version 1.000 Extract File: ldwg.las -Version Information VERS. 1.20: WRAP. NO: -Well Information Block #MNEM.UNIT Data Type STRT.FT 10810.0000: STOP.FT 11818.0000: STEP.FT 0.5000: NULL. -999.2500: COMP. COMPANY: WELL. WELL: FLD . FIELD: LOC . LOCATION: CNTY. COUNTY: STAT. STATE: SRVC. SERVICE COMPANY: TOOL. TOOL NAME & TYPE: DATE. LOG DATE: API . API NYUMBER: -Parameter Information Block #MNEM.UNIT Value SECT. 15 : TOWN.N lin : RANG. 14E : PDAT. MSL : EPD .F 0 : LMF . RKB : FAPD.F 66.25 : DMF . KB : EKB .F 66.25 : EDF .F N/A : EGL .F N/A : CASE.F N/A : OS1 . DIRECTIONAL : -Remarks CWLS log ASCII Standard -VERSION 1.20 One line per frame Information ............................... Starting Depth Ending Depth Level Spacing Absent Value BP Exploration Inc. 15-41A Prudhoe Bay Unit 1476' SNL, 710' EWL North Slope Alaska Baker Hughes INTEQ 1.75" NaviGamma - Gamma Ray 21-Mar-01 500292249201 Description ......... Section Township Range Permanent Datum Elevation Of Perm. Datum Log Measured from Feet Above Perm. Datum Drilling Measured From Elevation of Kelly Bushing Elevation of Derrick Floor Elevation of Ground Level Casing Depth Other Services Line 1 (1) Ail depths are Measured Depths (MD) unless otherwise noted. (2) All depths are Bit Depths unless otherwise noted. (3) All Gamma Ray data (GRAX) presented is realtime data. (4) Baker Hughes INTEQ runs 1-7 utilized directional and Gamma Ray services from 10810' to 11818' MD (8575' to 8732' SSTVD). (5) Well 15-41A was drilled to TD @ 11818' MD (8732' SSTVD) on Run 7. (6) The interval from 11800' MD (8732' SSTVD) to 11818' MD (8732' SSTVD) was not logged due to sensor to bit offset. (7) The data presented here is final and has not been shifted to a PDC (Primary Depth Control). There is no overlapping interval to (8) perform correlation with PDC supplied by BP Exploration (SWS 8-Oct-01). A Magnetic Declination correction of 26.79 degrees has been applied to the Directional Surveys. MNEMONICS: GRAX ROPS TVD -> Gamma Ray MWD-API [MWD] (MWD-API units) -> Rate of Penetration, feet/hour -> Subsea True Vertical Depth, feet SENSOR OFFSETS: RUN GAMFiA DIRECTIONAL 18 05 ft 17 94 ft 18 07 ft 18 14 ft 18 14 ft 17 89 ft 17 89 ft 23.03 ft 22.92 ft 23.05 ft 23.12 ft 23.12 ft 22.88 ft 22.88 ft Tape Subfile: 1 72 records... Minimum record length: Maximum record length: 8 bytes 132 bytes **** FILE HEADER **** MWD .001 1024 *** INFORMATION TABLE: CONS MNEM VALU WDFN mwd.xtf LCC 150 CN BP Exploration Inc. WN 15-41A FN Prudhoe Bay Unit COUN North Slope STAT Alaska *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! Remark File Version 1.000 1. The data presented is the field raw data. 2. There was no overlapping data set with PDC supplied by BP Exploration 3. The PDC used is a Schlumberger Gamma Ray dated 10/08/01. *** INFORMATION TABLE: CIFO PINEM CHAN DIMT CNAM ODEP .................... GRAX GRAX GRAX 0.0 ROPS ROPS ROPS 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 12 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.500000 Frame spacing units: IF ] Number of frames per record is: 84 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 2 Curves: Name Tool Code Samples Units Size 1 GRAX MWD 68 1 API 4 2 ROPS MWD 68 1 F/HR 4 Total Data Records: 25 Tape File Start Depth = 10810.000000 Tape File End Depth = 11818.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet **** FILE TRAILER **** Tape Subfile: 2 34 records... Minimum record length: Maximum record length: 18 bytes 4124 bytes **** TAPE TRAILER **** MWD 02/05/30 110267 01 Length 4 4 8 **** REEL TRAILER **** MWD 02/06/13 BHI 01 Tape Subfite: 3 Minimu/n record length: Maximum record length: 2 records... 132 bytes 132 bytes Tape Subfile 2 is type: LIS DEPTH GR3~X 10810.0000 13 10810.5000 13 10900.0000 24 11000.0000 29 11100.0000 24 11200.0000 91 11300.0000 19 11400.0000 23 11500.0000 57 11600.0000 42 11700.0000 63 11800.0000 23 11818.0000 -999 ROPS 1430 -999 8260 -999 2380 62 1220 61 6760 100 4210 34 4850 94 2610 68. 5000 54. 4610 62. 4110 131. 8450 124. 0000 17. 0000 0000 8900 9050 5700 7210 0920 0340 5460 3160 1860 4040 0810 Tape File Start Depth = 10810.000000 Tape File End Depth = 11818.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = feet