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2.05-2.o9 Schiumberger Fluid Analysis of MDT Samples ConocoPhillips Field:West Sak Well:1H North Black Oil Full PVT Study Report Prepared for Michael Werner/Dennis Wegener ConocoPhillips scANNED JUN 2 4 2015, Standard Conditions Used: Pressure: 14.696 psia Temperature:60°F Prepared by: Stefan Smuk Schlumberger WCP Oilphase-DBR 16115 Park Row, Suite 150 Houston,Texas,77084 (281)285-6370 Date: 06/30/2006 Report#200600050 r , Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Table of Contents List of Figures ... 2 List of Tables .... .. 3 EXECUTIVE SUMMARY 4 Objective 4 Introduction 4 Scope of Work 4 Results 4 PVT Study Data Quality Check Summary 6 Sequence of Events 6 Chain of Sample Custody 6 RESULTS AND DISCUSSIONS 7 Fluids Preparation and Analysis 7 Reservoir Fluid Analysis 7 PVT Analysis on Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 D.MD 30 Constant Composition Expansion at Tres 30 Reservoir Oil Viscosity at Tres. 32 Multi-Stage Separation Test 34 PVT Analysis on Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD. 42 Constant Composition Expansion at Tres 42 Reservoir Oil Viscosity 45 Multi-Stage Separation Test 53 Appendix A:Nomenclature and Definitions 56 Appendix B:Molecular Weights and Densities Used 57 Appendix C:EQUIPMENT 58 Fluid Preparation and Validation 58 Fluid Volumetric(PVT/and Viscosity Equipment 58 Appendix D:PROCEDURE 61 Fluids Preparation and.Validation 61 Constant Composition Expansion Procedure 61 Differential Vaporization Procedure 61 Multi-Stage Separation Test 61 Liquid Phase Viscosity and Density Measurements During DV Step 62 Stock-Tank Oil(STO/Viscosity and Density Measurements 62 Asphaltene,Wax and Sulfur Content Measurements 62 SAR(P/A Analysis 62 High-Temperature High Pressure Filtration Test 63 Oilphase-DBR 1 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 List of Figures Figure 1:Stock Tank Oil Chromatogram(Sample 1.09). 13 Figure 2:k-Plot for Equilibrium Check(Sample 1.09) 13 Figure 3:Stock Tank Oil Chromatogram(Sample 1.10). 16 Figure 4:k-Plot for Equilibrium Check(Sample 1.10) 16 Figure 5:Stock Tank Oil.Chromatogram(Sample 1-11) 19 Figure 6:k-Plot for Equilibrium Check(Sample 1.11) 19 Figure 7:Stock Tank Oil Chromatogram(Sample 1.12) 22 Figure 8:k-Plot for Equilibrium Check(Sample 1.12) 22 Figure 9:Stock Tank Oil Chromatogram(Sample 1.13) 25 Figure 10:k-Plot for Equilibrium Check(Sample 1.13) 25 Figure 11:Stock Tank Oil.Chromatogram(Sample 1.15) 28 Figure 12:k-Plot for Equilibrium Check(Sample 115) 28 Figure 13:Constant Composition Expansion.at 79.0°F-Relative Volume(Sample 1.15) 31 Figure 14:Reservoir Fluid Viscosity 79°F (Sample 1.15) 33 Figure 15:k-Plot for Equilibrium Check(Sample 1.09.1.10&1.11) as Figure 16:Constant Composition Expansion at 81.0°F-Relative Volume(Sample 1.09,1.10&1.11) 43 Figure 17:Reservoir Fluid Viscosity at 81°F(Sample 1.09,1-10&1.11) 45 Figure 18:Reservoir Fluid Viscosity at 150°F(Sample 1.09,1.10&1.11) 47 Figure 19:Reservoir Fluid Viscosity at 90°F(Sample 1.09,1.10&1.11) 49 Figure 20:Reservoir Fluid Viscosity at 60°F(Sample 1.09,1.10&1.11) 51 Oilphase-DBR 2 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 List of Tables Table 1:Well and Sample.Identification Table 2:Well Position.Data 8 Table 3:Sampling.and.Transfer.Summary 9 Table 4:Reservoir.Fluid Properties 18 Table 5:Stock-Tank Oil Properties 10 Table 6:C36+Composition.GOR,°API.byZero-Flash.(Sample.1.09) 11 Table 7:Calculated Fluid Properties 12 Table 8:C36+Composition.GDR,°API,by Zero-Flash.(Sample.1..10) 14 Table 9:Calculated Fluid Properties 15 Table 10:C36+Composition,.GOR,°API,.by.Zero-Flash.(Sample.1.1.1I 17 Table 11:Calculated fluid.Properties 18 Table 12:C36+Com position,.GOR,°APL.hy.Zero-Flash.(Sample.1.12) 20 Table 13:Calculated Fluid Properties 21 Table 14:C36+Composition,.GOR,°API,.by.Zero-Flash.(Sample.1.13) 23 Table 15:Calculated Fluid Properties 24 Table 16:C36+Composition,GOR,°API,.hy.Zero-Flash.(Sample.1.15) 26 Table 17:Calculated Fluid Properties 27 Table 18:Summary of Results of Sample.1.15 29 Table 19:Constant Composition Expansion.at79.0°F.(Sample.1.15) 30 Table 20:Reservoir Fluid Viscosity 79°F.(Sample.1.15) 32 Table 21:Multi-Stage Separation.Test Vapor&Liquid Properties..(Sample.1.15) 35 Table 22:Multi-Stage Separator Test Vapor Composition(mol%) 36 Table 23:Multi-Stage Separator Test Residual Liquid Composition(mol%) 37 Table 24:C30+Composition..GOR,°API,.by.Zero,Flash.(Sample.1.09,.1.10&.1.1.1) 38 Table 25:Calculated Fluid Properties 39 Table 26:Summary of Results of Sample 1.09,1.10&1..11 41 Table 27:Constant Composition Expansion.at 81.0°F(Sample.1.09,1.1(1&.1.1.1) 42 Table 28:Reservoir Fluid Viscosity at 81°F(Sample 1.09.1.10&1.11) 44 Table 32:Multi-Stage Separation Test Vapor&Liquid Properties(Sample.1.09,.1.10&.1.11) 53 Table 33:Multi-Stage Separator Test Vapor.Composition(mol%) 54 Table 34:Multi-Stage Separator Test Residual Liquid.Composition(mot%) 55 Oilphase-DBR 3 Job fk 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Installation: - Job it 200600050 EXECUTIVE SUMMARY Objective To evaluate the compositions and phase behavior of bottomhole fluid samples collected during modular formation dynamics testing(MDT). Introduction At the request of ConocoPhillips,Oilphase has conducted a fluid analysis study on bottomhole fluid samples collected during the modular formation dynamics testing(MDT)of Well 1H North drilled in the field West Sak. Scope of Work • Homogenize bottomhole hydrocarbon fluid samples at the reservoir conditions with rocking for five • Conduct preliminary evaluation on bottomhole hydrocarbon samples that include single-stage flash Gas- Oil Ratio(GOR),reservoir fluid composition,stock-tank oil(STO)and monophasic fluid properties. • Select representative samples for PVT studies. Results The following bullets summarize the PVT analysis conducted on the bottomhole hydrocarbon and water samples: • Six bottomhole samples were used for validation purposes.They were homogenized at the reservoir conditions for five days. • The zero flash GOR was determined to be from 185- 245 SCF/STB, and the STO density to be from 0.9302 to 0.9496 g/cc. • Samples 1.09,1.10 and 1.11,D Sand,were settled in a vertical position,and the top portions of the fluid were transferred to a single new cylinder and de-emulsified for a full PVT study. Sample 1.09, 1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD,D Sand FLASHING CUMULATIVE API Gas Relative FVF FVF OPERATION GOR(scf/stb) GRAVITY Density(air=1) at Pres/Tres at Psat/Tres Zero Flash 238 20.62 0.661 1.103 1.105 DL Flash CO Tres - - - - - Separator Test 214 21.26 0.624 1.093 1.095 • Sample 1.15,B Sand,was used for complete PVT analysis,including constant-composition expansion multi-stage separation testing. Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 ft.MD,B Sand FLASHING CUMULATIVE API Gas Relative FVF FVF OPERATION GOR(scf/stb) GRAVITY Density lair=1) at Pres/Tres at Psat/Tres Zero Flash 186 17.54 0.613 1.069 1.070 DL Flash CO Tres - - - - - Separator Test 182 17.62 0.606 1.067 1.068 Oilphase-DBR 4 Job#:200600050 • Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Installation: - Job#: 200600050 Quality Assurance Process Oilphase-DBR Schlumberger is committed to providing unsurpassed services in bottom hole reservoir fluid sampling and fluid property analyses while maintaining high standards of safety and quality. Our objective is to deliver the most accurate and reliable sampling processes and fluid property measurements available in the industry. This objective requires persistent innovation and ongoing development of state-of-the-art technologies and equipment. A rigorous quality assurance program,continuous employee training and enforcement of strict safety standards maintain our compliance with Quality,Health, Safety and Environment(QHSE)requirements. Proactive integration of QHSE objectives and management goals at every level supports the communication and implementation of QHSE policies and standards. Schlumberger requires that qualified engineering technologists perform all laboratory measurements according to specified analytical procedures designed for obtaining accurate and reliable data. Rigorous quality assurance programs and instrument calibration protocols are in place to ensure and maintain the validity of the procedures. Details of these programs are available upon request. The lab-generated data undergoes the following five levels of quality checks to establish the integrity of the reported results. a) Establish quality of measurement during data generation. b) Establish quality of processed data as per checklist during data processing by Data Quality Engineer. c) Data Quality Supervisor confirms the overall quality of the processed data and ensures cross correlative consistency d) The responsible Project Engineer confirms consistency of reported data of Engineering Project Manager review the results/report for overall consistency Hence the completion of each project requires that a qualified and experienced team of engineers perform a variety of independent review of all technical data to confirm the consistency and accuracy of the report as per pre-established Quality checklists designed for each operation and based on the level of complexity.All property measurements and calculation procedures are maintained in company archives for a period of 1 year. This information is available for review by clients upon request. The file and laboratory records information are listed below to provide access reference to all records related to this project.For any questions,please do not hesitate to contact the undersigned Project Engineer. File No.:200600050 Laboratory Records:200600050 Data Quality Data Reporting Suyu Ye Meisong Yan Data Quality Engineer Project Engineer Overall Report Quality Clay Young Clay Young Oilphase-DBR Operation Manager,NGC Oilphase-DBR 5 Job#:200600050 r r Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Sequence of Events 04/03/06 Samples arrived and client informed. 04/18/06 Project work scope discussed. 04/18/06 Work agreement approved. 04/19/06 Prelim PVT tests request for all six samples issued. Chain of Sample Custody The samples collected from the well 1H North were sent to Oilphase-DBR in Houston,Texas.The samples were used to preliminary measurements and subsequent PVT studies. The measurement details are in the following text. Samples remaining after measurements are stored in Oilphase-DBR storage unless otherwise instructed. Oilphase-DBR 6 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job d: 200600050 RESULTS AND DISCUSSIONS fluids Preparation and Analysis Six bottomhole samples collected during the MDT were transferred to Oilphase-DBR.The well and formation data with their respective reservoir conditions for the bottomhole samples are summarized in Table 1.The quality check for the bottomhole samples were conducted and the results are summarized in Table 2.After 5-days of homogenization, sample validation tests were conducted to evaluate the validity of the samples. It was determined that all the samples needed de-emulsification prior to conducting PVT analysis. The reservoir fluid and stock-tank oil properties for all the samples are presented in Tables 4 and 5. Reservoir Fluid Analysis The gas and liquid phases from the single-stage flash were subjected to chromatography and their compositions were determined.These compositions were recombined mathematically according to single-stage flash Gas-Oil Ratio(GOR) to calculate the reservoir fluid composition.The reservoir fluid analysis is summarized in Table 6,8,10,12,14 and 16. The molecular weight of the stock-tank oil(STO)was measured.Other properties such as the plus fraction properties and heat content for the flash gas were calculated from the compositions and are listed in Tables 7,9,11,13,15 and 17. After quiescent restoration in a vertical position,the top portions of samples 1.09,1.10 and 1.11 were transferred into a single cylinder, and underwent de-emulsification. Afterwards the sample was flashed, and GOR, API and compositional data were found to be consistent with the data for original sample.The Base Sediment and Water were also measured for the blended sample,and found to be close to zero. BS&W checks of samples 1.13 and 1.15 showed that both fluids had very little water and sediment content,making them appropriate for PVT testing without further treatment.Sample 1.15 was selected for PVT testing because of its large volume. The scope of PVT testing included constant composition expansion and viscosity experiments at reservoir temperature,and a multistage separation test. The blended sample was also subjected to viscosity measurements at three additional temperatures. Oilphase-DBR 7 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Table 1:Well and Sample Identification Client ConocoPhillips Job# 200600050 Field: Beechy Point Well: 11-1 North Sample ID Chamber# Zone Sampling Date Opening Pres. Reservoir Conditions in the field Pressure Temperature Depth (psia/°F) (psia) (°F) (ft) 1.09 MRSC 182 D Sand 03/09/06 915/26 1,720 81 4068 1.10 SPMC 451 D Sand 03/09/06 6515/49 1,720 81 4068 1.11 SPMC 450 D Sand 03/09/06 6515/49 1,720 81 4068 1.12 SPMC443 DSand 03/09/06 6515/51 1,720 81 4068 1.13 SPMC 441 B Sand 03/09/06 6315/53 1,707 79 4154 1.15 SPMC 444 B Sand 03/09/06 6515/51 1,707 79 4154 1.09,1.10&1.11 - D Sand - - 1,735 81 4068 Table 2:Well Position Data Well Name Strat Name Latitude Longitude X Loc Y Loc 1H-NORTH SURFACE 70.394828853 -149.559222785 1694586.97 5994052.42 1H-NORTH WEST SAK D 70.396903765 -149.555190463 1695077.43 5994814.88 1H-NORTH WEST SAK B 70.396963574 -149.555067093 1695091.76 5994836.51 Oilphase-DBR 8 Job#:200600050 • , Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Table 3:Sampling and Transfer Summary Opening Transfer Closing Opening Transferred Sample ID Chamber# conditions Cylinder conditions conditions Water Content Sample in the field ID in the field in the Lab Volume (psia/°F) (psia/°F) (psia/°F) (wt%) (cc) 1.09 MASC 182 915/26 CSB 7720-0A 815/65 1015/75 2.3 600 1.10 SPMC 451 6515/49 SSB 18532-0A 6015/65 6265/75 1.7 245 1.11 SPMC 450 6515/49 SSB 18537-0A 6015/65 6265/75 1.3 240 1.12 SPMC 443 6515/51 SSB 18540-0A 6015/65 6515/75 2.6 245 1.13 SPMC 441 6315/53 SSB 18538-0A 6015/65 7265/75 0.7 220 1.15 SPMC 444 6515/51 SSB 18535-0A 6015/65 6765/75 0.4 245 1.09,1.10 841.11 - - CSB 7356-MA - - Nil 600 Oilphase-DBR 9 Job t 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Table 4:Reservoir Fluid Properties Zero Flash Saturation Molar Mass of Monophasic Sample ID Cylinder# Depth GOR* Bo** Pressure monophasic fluid***OBM at Tres fluid contamination (ft) (scf/stb) (psia) %(w/w) 1.09 CSB 7720-QA 4,068 232 205.6 - 1.10 SSB 18532-0A 4,068 245 195.8 - 1.11 SSB 18537-0A 4,068 242 195.0 - 1.12 SSB 18540-0A 4,068 239 197.4 - 1.13 SSB 18538-0A 4,154 185 244.2 - 1.15 SSB 18535-0A 4,154 186 242.9 - 1.09,1.10&1.11 CSB 7356-MA 4,068 238 1.105 1544 194.7 - *Flashed gas volume(scf)per barrel of stock tank liquid C 60°F **Volume of live oil at it's bubble point pressure per flashed stock tank liquid volume CO 60°F ***Calculated from oil-based mud contamination in STO Table 5:Stock-Tank Oil Properties STO Properties Sample ID Cylinder# Depth Molar Mass Density API* OBM Contamination (ft) (g/cc) %(w/w) 1.09 CSB 7720-QA 4,068 315.8 0.9329 20.2 - 1.10 SSB 18532-0A 4,068 301.3 0.9309 20.5 - 1.11 SSB 18537-0A 4,068 296.6 0.9314 20.4 - 1.12 SSB 18540-QA 4,068 301.3 0.9315 20.4 - 1.13 SSB 18538-0A 4,154 365.0 0.9496 17.5 - 1.15 SSB 18535-0A 4,154 363.1 0.9494 17.5 - 1.09,1.10&1.11 CSB 7356-MA 4,068 293.6 0.9302 20.6 - "API=141.5/Density-131.5. Oilphase-DBR 10 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 6:C36+Composition,GOR,°API,by Zero-Flash(Sample 1.09) Sample 1.09;Cylinder CSB 7720-QA;Depth 4068 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT% MOLE% WT% MOLE% WT% MOLE% Carbon Dioxide 44.01 0.23 0.10 0.00 0.00 0.01 0.04 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.130 Nitrogen 28.01 1.93 1.33 0.00 0.00 0.07 0.49 Methane 16.04 76.06 91.00 0.00 0.00 2.64 33.80 Ethane 30.07 2.20 1.41 0.00 0.00 0.08 0.52 Propane 44.10 4.32 1.88 0.00 0.03 0.15 0.72 I-Butane 58.12 2.79 0.92 0.02 0.09 0.11 0.40 N-Butane 58.12 4.20 1.39 0.04 0.22 0.18 0.65 I-Pentane 72.15 2.90 0.77 0.12 0.53 0.22 0.62 N-Pentane 72.15 1.40 0.37 0.08 0.33 0.12 0.35 C6 84.00 1.72 0.39 0.43 1.60 0.47 1.15 M-C-Pentane 84.16 0.27 0.06 0.14 0.53 0.14 0.35 Benzene 78.11 0.04 0.01 0.03 0.11 0.03 0.07 Cyclohexane 84.16 0.27 0.06 0.19 0.73 0.20 0.48 C7 96.00 0.68 0.14 0.75 2.45 0.74 1.59 M-C-Hexane 98.19 0.24 0.05 0.35 1.11 0.34 0.72 Toluene 92.14 0.07 0.02 0.20 0.68 0.20 0.44 C8 107.00 0.37 0.07 1.27 3.74 1.24 2.38 E-Benzene 106.17 0.01 0.00 0.18 0.55 0.18 0.35 M/P-Xylene 106.17 0.02 0.00 0.40 1.18 0.38 0.74 O-Xylene 106.17 0.01 0.00 0.14 0.42 0.14 0.26 C9 121.00 0.17 0.03 1.38 3.60 1.34 2.27 010 134.00 0.06 0.01 2.28 5.38 2.20 3.38 C11 147.00 0.02 0.00 2.17 4.66 2.09 2.93 C12 161.00 0.00 0.00 2.49 4.88 2.40 3.07 C13 175.00 0.00 0.00 2.71 4.89 2.61 3.07 C14 190.00 0.00 0.00 2.78 4.61 2.68 2.90 C15 206.00 0.00 0.00 2.89 4.43 2.79 2.78 C16 222.00 2.72 3.86 2.62 2.43 C17 237.00 2.69 3.59 2.60 2.26 C18 251.00 2.29 2.88 2.21 1.81 C19 263.00 2.45 2.94 2.36 1.85 C20 275.00 2.42 2.78 2.34 1.75 C21 291.00 2.08 2.26 2.01 1.42 C22 300.00 1.98 2.08 1.91 1.31 C23 312.00 1.90 1.92 1.83 1.21 C24 324.00 1.77 1.72 1.70 1.08 C25 337.00 1.69 1.58 1.63 0.99 C26 349.00 1.66 1.50 1.60 0.94 C27 _ 360.00 1.61 1.41 1.55 0.89 C28 372.00 1.67 1.42 1.61 0.89 C29 382.00 1.75 1.44 1.69 0.91 C30 394.00 1.41 1.13 1.36 0.71 C31 404.00 1.13 0.88 1.09 0.56 032 415.00 1.21 0.92 1.17 0.58 C33 426.00 0.88 0.65 0.85 0.41 C34 437.00 1.04 0.75 1.00 0.47 C35 445.00 0.96 0.68 0.93 0.43 C36+ 819.70 43.70 16.84 42.18 10.58 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.19 315.83 205.64 MOLE RATIO 0.3715 0.6285 Oilphase-DBR 11 Job#:200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Table 7:Calculated Fluid Properties Sample 1.09;Cylinder CSB 7720-QA;Depth 4068 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole C7+ 2.23 0.44 99.32 97.20 95.95 61.26 C12+ 0.00 0.00 89.85 72.06 86.73 45.29 C20+ - 68.84 39.97 66.45 25.12 C30+ - - 50.32 21.86 48.58 13.74 C36+ - - 43.70 16.84 42.18 10.58 Molar Mass C7+ 96.86 322.71 322.11 C12+ 161.00 393.79 393.79 C20+ - 543.90 543.90 C30+ - _ 727.25 727.25 C36+ 819.70 819.70 Density C7+ - 0.9358 - C12+ - 0.9565 0.9565 C20+ - 1.0006 1.0006 C30+ 1.0516 1.0516 C36+ 1.0755 1.0755 Fluid at 60°F 0.9329 Gas Gravity(Air=11 0.663 Dry Gross Heat Content(BTU/scf) 1,156 Wet Gross Heat Content IBTU/scf) 1,136 ORM Contamination Level(wt%) - STO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 315.83 315.83 819.70 Density(g/cm3) 0.9329 - 1.0755 Single Stage Flash Data Original STO De-Contaminated GOR Iscf/stb) 232 - STO Density(g/cm3) 0.9329 - STO API Gravity 20.2 - OBM Density Ig/cm31©60°F - Oilphase-DBR 12 Job#:200600050 • Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Figure 1:Stock Tank Oil Chromatogram(Sample 1.09) Sample 1.09;Cylinder CSB 7720-0A;Depth 4068 ft.MD FID I A,(F'QtDATAl005000501C`r7720 0) Nom. 200600050 CONOCOPHILLIPS 1.09 CSB 7720-QA 700 D/F CYLINDER • 500- 500 400- 300- 00- 300- m 315 N to o mm r TO.) c 100' 7c'' u o A 0 7- N m a N '- ^ °'N NNNNNN�1 L. ccccrz • c� ♦• c G c U C C c c c c c c c c C C c C c c C` 0 5 10 15 20 25 30 35 miq Figure 2:k-Plot for Equilibrium Check(Sample 1.09) Sample 1.09;Cylinder CSB 7720-QA;Depth 4068 ft.MD 4 3 •C3 2 ,t4C4 Y 1 •ifCS rn •C6 D •C7 •C8 1 - — •C9 •C10 -2 -4 -3 -2 -1 0 1 2 3 F Oilphase-DBR 13 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 8:C36+Composition,GOR,°API,by Zero-Flash(Sample 1.10) Sample 1.10;Cylinder SSB 18532-QA;Depth 4068 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT% MOLE% WT% MOLE% WT% MOLE% Carbon Dioxide 44.01 0.23 0.10 0.00 0.00 0.01 0.04 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.23 0.16 0.00 0.00 0.01 0.06 Methane 16.04 77.86 92.28 0.00 0.00 2.82 34.47 Ethane 30.07 2.20 1.39 0.00 0.00 0.08 0.52 Propane 44.10 4.26 1.84 0.00 0.01 0.16 0.69 I-Butane 58.12 2.74 0.90 0.01 0.06 0.11 0.37 N-Butane 58.12 4.17 1.36 0.03 0.15 0.18 0.60 I-Pentane 72.15 2.92 0.77 0.11 0.46 0.21 0.58 N-Pentane 72.15 1.38 0.36 0.07 0.28 0.11 0.31 C6 84.00 1.75 0.40 0.44 1.58 0.49 1.14 M-C-Pentane 84.16 0.27 0.06 0.15 0.55 0.16 0.37 Benzene 78.11 0.04 0.01 0.03 0.12 0.03 0.08 Cyclohexane 84.16 0.28 0.06 0.21 0.75 0.21 0.49 C7 96.00 0.69 0.14 0.84 2.64 0.83 1.70 M-C-Hexane 98.19 0.24 0.05 0.37 1.12 0.36 0.72 Toluene 92.14 0.08 0.02 0.21 0.68 0.20 0.43 C8 107.00 0.36 0.06 1.44 4.06 1.40 2.57 E-Benzene 106.17 0.01 0.00 0.20 0.58 0.20 0.36 M/P-Xylene 106.17 0.02 0.00 0.43 1.23 0.42 0.77 O-Xylene 106.17 0.05 0.01 0.15 0.44 0.15 0.28 C9 121.00 0.13 0.02 1.58 3.94 1.53 2.47 C10 134.00 0.07 0.01 2.58 5.81 2.49 3.64 C11 147.00 0.02 0.00 2.46 5.05 2.38 3.17 C12 161.00 0.01 0.00 2.81 5.25 2.70 3.29 C13 175.00 0.00 0.00 3.03 5.22 2.92 3.27 C14 190.00 0.00 0.00 3.08 4.88 2.96 3.06 C15 206.00 0.00 0.00 3.16 4.62 3.05 2.90 C16 222.00 3.07 4.16 2.96 2.61 C17 237.00 2.59 3.30 2.50 2.07 C18 251.00 2.65 3.18 2.55 1.99 C19 263.00 2.64 3.03 2.55 1.90 C20 275.00 2.63 2.88 2.53 1.80 C21 291.00 2.39 2.47 2.30 1.55 C22 300.00 1.95 1.96 1.88 1.23 C23 312.00 2.10 2.03 2.02 1.27 C24 324.00 1.70 1.58 1.64 0.99 C25 337.00 1.66 1.49 1.60 0.93 C26 349.00 1.47 1.27 1.42 0.80 C27 360.00 1.64 1.38 1.58 0.86 C28 372.00 1.38 1.12 1.33 0.70 C29 _ 382.00 1.45 1.14 1.40 0.72 C30 394.00 1.07 0.82 1.03 0.51 C31 404.00 1.01 0.75 0.97 0.47 C32 415.00 1.11 0.80 1.07 0.50 C33 426.00 0.87 0.62 0.84 0.39 C34 437.00 1.03 0.71 0.99 0.45 C35 445.00 0.93 0.63 0.89 0.39 C36+ 816.64 41.25 15.22 39.75 9.53 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.02 301.28 195.84 MOLE RATIO 0.3735 0.6265 Oilphase-DBR 14 Job#:200600050 • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 9:Calculated Fluid Properties Sample 1.10;Cylinder SSB 18532-QA;Depth 4068 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole% C7+ 2.27 0.45 99.34 97.46 95.82 61.23 C12+ 0.01 0.00 88.67 70.50 85.45 44.17 C20+ - - 65.64 36.86 63.26 23.09 C30+ - - 47.27 19.55 45.55 12.25 • C36+ - - 41.25 15.22 39.75 9.53 Molar Mass C7+ 96.74 307.08 306.51 C12+ 162.18 378.92 378.92 C20+ - _ 536.50 536.50 C30+ _ 728.48 728.48 C36+ - 816.64 816.64 Density C7+ - 0.9336 - C12+ - 0.9570 0.9570 C20+ - 1.0085 1.0085 C30+ 1.0674 1.0674 C36+ 1.0934 1.0934 Fluid at 60°F 0.9309 Gas Gravity(Air=1) I 0.657 Dry Gross Heat Content(BTU/scf) 1,166 Wet Gross Heat Content(BTU/scf) 1,146 OBM Contamination Level(wt%) - .STO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 301.28 301.28 816.64 Density(g/cm3) 0.9309 - 1.0934 Single Stage Flash Data Original STO De-Contaminated GOR(scf/stb) 245 - STO Density(g/cm3) 0.9309 - STO API Gravity 20.5 - OBM Density(g/cm3)©60°F - Oilphase-DBR 15 Job 6:200600050 • Client: ConocoPhilhps Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 3:Stock Tank Oil Chromatogram(Sample 1.10) Sample 1.10,Cylinder SSB 18532-GA;Depth 4068 ft.MD IID1 A a:\PDATMSEP261[Y111532R D) 355 155 250 160 100 d') UU bb � v Y � 212 X ry m b m m m ry nry itQ }Pi Q'i�mm mmm f 8 U U p 1 c c c c c `'= V V V UV 52 `a)ccc 1 ( I 1 ► �� l �� �I ,' �' �r r�4>a.aniti1rlllmul 1111fiIIlilifIi!11��I1 N � . I�;:_TT LEE- 0 4.0 5 10 15 20 25 00 Figure 4:k-Plot for Equilibrium Check(Sample 1.10) Sample 1.10;Cylinder SSB 18532-QA;Depth 4068 ft.MD 4 •C3 3 •nt4C4 2 Y •ItC§S 'e1 1 3 •C6 o .C7 •C8 -1 'CO •C10 -2 -4 -3 -2 -1 0 1 2 3 F Oilphase-DBR 16 Job Ik 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 10:C36+Composition,GOR,°API,by Zero-Flash(Sample 1.11) Sample 1.11;Cylinder SSB 18537-QA;Depth 4068 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/molel WT% MOLE% WT% MOLE% WT% MOLE% Carbon Dioxide 44.01 0.26 0.12 0.00 0.00 0.01 0.04 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.19 0.13 0.00 0.00 0.01 0.05 Methane 16.04 76.28 91.64 0.00 0.00 2.76 33.59 Ethane 30.07 2.32 1.49 0.00 0.00 0.08 0.55 Propane 44.10 4.60 2.01 0.03 0.17 0.19 0.85 I-Butane 58.12 2.98 0.99 0.05 0.23 0.15 0.51 N-Butane 58.12 4.46 1.48 0.11 0.55 0.27 0.89 I-Pentane 72.15 3.11 0.83 0.21 0.85 0.31 0.84 N-Pentane 72.15 1.48 0.40 0.14 0.57 0.19 0.50 C6 84.00 1.86 0.43 0.55 1.96 0.60 1.40 M-C-Pentane 84.16 0.29 0.07 0.17 0.59 0.17 0.40 Benzene 78.11 0.05 0.01 0.04 0.14 0.04 0.09 Cyclohexane 84.16 0.30 0.07 0.23 0.81 0.23 0.54 C7 96.00 0.75 0.15 0.78 2.40 0.78 1.57 M-C-Hexane 98.19 0.26 0.05 0.42 1.28 0.42 0.83 Toluene 92.14 0.08 0.02 0.25 0.82 0.25 0.52 C8 107.00 0.39 0.07 1.42 3.94 1.38 2.52 E-Benzene 106.17 0.02 0.00 0.12 0.34 0.12 0.22 M/P-Xylene 106.17 0.03 0.01 0.35 0.97 0.34 0.62 0-Xylene 106.17 0.01 0.00 0.18 0.49 0.17 0.31 C9 121.00 0.21 0.03 1.66 4.06 1.60 2.58 C10 134.00 0.06 0.01 2.54 5.61 2.45 3.56 C11 147.00 0.00 0.00 2.45 4.94 2.36 3.13 C12 161.00 0.00 0.00 2.75 5.08 2.66 3.22 C13 175.00 0.00 0.00 2.83 4.79 2.72 3.03 C14 190.00 0.00 0.00 3.03 4.73 2.92 2.99 C15 206.00 0.00 0.00 3.23 4.65 3.11 2.94 C16 222.00 2.86 3.82 2.75 2.42 C17 237.00 2.63 3.29 2.54 2.09 C18 251.00 2.57 3.03 2.47 1.92 C19 263.00 2.59 2.92 2.49 1.85 C20 275.00 2.35 2.54 2.27 1.61 C21 291.00 2.22 2.26 2.14 1.43 C22 300.00 2.12 2.09 2.04 1.33 C23 312.00 1.97 1.87 1.90 1.19 C24 324.00 1.86 1.70 1.79 1.08 C25 337.00 1.72 1.51 1.66 0.96 C26 349.00 1.61 1.37 1.55 0.87 C27 360.00 1.59 1.31 1.53 0.83 C28 372.00 1.57 1.25 1.52 0.79 C29 382.00 1.55 1.21 1.50 0.76 C30 394.00 1.50 1.13 1.44 0.71 C31 404.00 1.28 0.94 1.23 0.60 C32 415.00 1.22 0.88 1.18 0.55 C33 426.00 0.98 0.68 0.94 0.43 C34 437.00 0.95 0.65 0.92 0.41 C35 445.00 0.85 0.57 0.82 0.36 C36+ 800.00 40.50 15.02 39.03 9.51 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.27 296.63 194.96 MOLE RATIO 0.3666 0.6334 Oilphase-DBR 17 Job#:200600050 i 1 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 11:Calculated Fluid Properties Sample 1.11;Cylinder SSB 18537-QA;Depth 4068 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole% C7+ 2 44 0.49 98.92 95.67 95.43 _ 60.78 C12+ 0.00 0.00 88.33 69.28 85.13 43.88 C20+ - - 65.85 36.98 63.46 23.42 C30+ - - 47.29 19.86 45.57 12.58 C36+ - 40.50 15.02 39.03 9.51 Molar Mass C7+ 96.66 306.71 306.10 C12+ 166.68 378.19 378.19 C20+ - _ 528.23 528.23 C30+ - _ 706.38 _ 706.38 C36+ - 800 00 800.00 Density C7+ - 0.9362 C12+ - 0.9600 0.9600 C20+ - 1.0114 1.0114 C30+ 1.0722 1.0722 C36+ 1.1036 1.1036 Fluid at 60°F 0 9314 Gas Gravity(Air=1) 0.666 Dry Gross Heat Content IBTU/scfl 1,180 _ Wet Gross Heat Content IBTU/scf) 1,159 OBM Contamination Level(wt%/a) - STO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 296.63 296.63 800.00 Density(g/cm3) 0.9314 - 1.1036 Single Stage Flash Data Original STO De-Contaminated GOR Iscf/stb) 242 - STO Density(g/cm3) 0.9314 - STO API Gravity 20.4 - OBM Density(g/cm3)0360°F - Oilphase-DBR 18 Job#:200600050 Client: ConocoPhilhps Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 5:Stock Tank Oil Chromatogram(Sample 1.11) Sample 1.11;Cylinder SSB 18537-DA;Depth 4068 ft.MD , Nor- JOB 200600050 CONOCO PHILLIPS 1.11 SSB 18537-QA RF FLASH CYLINDER 250- 200- 150- 0 m U m 100- ukf U° T^ W () 66 cu C lC t 3 a'm v I , o ' U In m r.m m o�Ninv(nml. 50- h F CO 'X N (n C UNNNNNNNy"�� • ., 'iU ' U o° 0 U ° U U= C UUUUUUW Iyyrr)� C C C C U I C C C CC1CCCpCC CC CCS �,�- ,...,,,1,1. ;i4a,i1YrlllV i Nil�11H ii lilt 11 MIA 11111------- 0 1 ��� --- 0 5 10 15 20 25 30 35 mit Figure 6:k-Plot for Equilibrium Check(Sample 1.11) Sample 1.11;Cylinder SSB 18537-QA;Depth 4068 ft.MD 2.5- •C3 2 •iC4 1.5- •n •iC1 - 5 S. 0.5 •C6 3 0- •C7 0.5- •-CO 1 - •-C9 - — -1.5 •C10 -4 -3 -2 -1 0 1 2 3 F Oilphase-DBR 19 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 12:C36+Composition,GOR,°API,by Zero-Flash(Sample 1.12) Sample 1.12;Cylinder SSB 18540-QA;Depth 4068 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT% MOLE% WT% MOLE% WT% MOLE Carbon Dioxide 44.01 0.29 0.12 0.00 0.00 0.01 0.05 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.26 0.18 0.00 0.00 0.01 0.07 Methane 16.04 78.13 92.33 0.00 0.00 2.76 33.98 Ethane 30.07 2.21 1.39 0.00 0.00 0.08 0.51 Propane 44.10 4.28 1.84 0.03 0.17 0.18 0.79 I-Butane 58.12 2.740.89 0.05 0.24 0.14 0.48 N-Butane 58.12 4.10 1.34 0.11 0.57 0.25 0.85 I-Pentane 72.15 2.85 0.75 0.21 0.88 0.30 0.83 N-Pentane 72.15 1.36 0.36 0.14 0.58 0.18 0.50 C6 84.00 1.67 0.38 0.56 2.02 0.60 1.41 M-C-Pentane 84.16 0.26 0.06 0.17 0.60 0.17 0.40 Benzene 78.11 0.04 0.01 0.04 0.14 0.04 0.09 Cyclohexane 84.16 0.26 0.06 0.23 0.83 0.23 0.55 C7 96.00 0.65 0.13 0.78 2.44 0.77 1.59 M-C-Hexane 98.19 0.22 0.04 0.42 1.29 0.41 0.83 Toluene 92.14 0.07 0.01 0.26 0.85 0.25 0.54 C8 107.00 0.33 0.06 1.40 3.94 1.36 2.51 E-Benzene 106.17 0.01 0.00 0.12 0.34 0.12 0.21 M/P-Xylene 106.17 0.02 0.00 0.34 0.96 0.33 0.61 O-Xylene 106.17 0.01 0.00 0.17 0.49 0.17 0.31 C9 121.00 0.16 0.02 1.60 3.99 1.55 2.53 C10 134.00 0.05 0.01 2.42 5.45 2.34 3.45 C11 147.00 0.02 0.00 2.32 4.76 2.24 3.01 C12 161.00 0.00 0.00 2.62 4.91 2.53 3.10 C13 175.00 0.00 0.00 2.90 5.00 2.80 3.16 C14 190.00 0.00 0.00 3.04 4.83 2.94 3.05 C15 206.00 0.00 0.00 2.84 4.16 2.74 2.63 C16 222.00 2.80 3.79 2.70 2.40 C17 237.00 2.68 3.41 2.59 2.16 C18 251.00 2.59 3.10 2.49 1.96 C19 263.00 2.35 2.69 2.27 1.70 C20 275.00 2.30 2.52 2.21 1.59 C21 291.00 2.21 2.29 2.13 1.45 C22 300.00 2.13 2.14 2.06 1.35 C23 312.00 1.84 1.77 1.77 1.12 C24 324.00 1.74 1.62 1.68 1.02 C25 337.00 1.70 1.52 1.64 0.96 C26 349.00 1.58 1.36 1.52 0.86 C27 360.00 1.54 1.29 1.49 0.82 C28 372.00 1.54 1.25 1.49 0.79 C29 382.00 1.53 1.21 1.47 0.76 C30 394.00 1.43 1.09 1.38 0.69 C31 404.00 1.23 0.92 1.18 0.58 C32 415.00 1.16 0.84 1.12 0.53 C33 426.00 1.12 0.79 1.08 0.50 C34 437.00 0.96 0.66 0.93 0.42 C35 445.00 0.90 0.61 0.87 0.39 C36+ 805.00 41.91 15.68 40.43 9.91 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 18.96 301.28 197.39 MOLE RATIO 0.3680 0.6320 Oilphase-DBR 20 Job it 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 13:Calculated Fluid Properties Sample 1.12;Cylinder SSB 18540-QA;Depth 4068 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole To C7+ 2.10 0.41 98.91 95.53 95.48 60.53 C12+ 0.00 0.00 88.63 69.45 85.50 43.89 C20+ - - 66.80 37.56 64.44 23.74 C30+ - - 48.70 20.60 _ 46.98 13.02 C36+ - - 41.91 15.68 40.43 9.91 Molar Mass C7+ 96.45 311.91 311.38 C12+ 167.15 384.50 384.50 C20+ - 535.92 535.92 C30+ - 712.41 712.41 C36+ - 805.00 805.00 Density C7+ - 0.9364 - C12+ - 0.9594 0.9594 C20+ - 1.0083 1.0083 C30+ 1.0641 1.0641 C36+ 1.0925 1.0925 Fluid at 60°F 0.9315 Gas Gravity(Air=1) I 0.655 Dry Gross Heat Content(BTU/scf) 1,162 Wet Gross Heat Content(BTU/scf) 1,142 OBM Contamination Level(wt%) - STO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 301.28 301.28 805.00 Density(g/cm3) 0.9315 - 1.0925 Single Stage Flash Data Original STO De-Contaminated GOR(scf/stb) 239 - STO Density(g/cm3) 0.9315 - STO API Gravity 20.4 - OBM Density(g/cm3)©60°F - Oilphase-DBR 21 Job#:200600050 Client ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Figure 7:Stock Tank Oil Chromatogram(Sample 1.12) Sample 1.12;Cylinder SSB 18540-0A;Depth 4068 ft.MD FIN A,(F l2 DAT.Ak1050005)1CY18540.D1 Nom,. JOB 200600050 CONOCO PHILIPS " 1.12 SSB 18540-OA - RF FLASH CYLINDER 253 200- 150- , CO m U m 100- 90 o u w.-•oo T c c e m • � � c �0 (D n m.-0,-N(na no3NoS1D 50- N. m QX N (h U UNNNNNNN � '1 U 0 Nom o 0 0 0 0 CU UUUU .0"( C C 0 0 O = C C c CCCCCCCCCCCCCCC 11, .. I.,,..,„,,. .,,ii,.. __...l: INIIi III II L II! _' r— o 5 10 15 20 25 30 35 mir Figure 8:k-Plot for Equilibrium Check(Sample 1.12) Sample 1.12;Cylinder SSB 18540-QA;Depth 4068 ft.MD 2.5 •C3 2 . •iC4 1.5 . •nCa 1 •n• C5 Y 0.5 •Co Tti 3 0 - •C7 -0.5 •C8 -1 •C9 -1.5 •C10 -4 -3 -2 -1 0 1 2 3 F Oilphase-DBR 22 Job N:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 14:C36+Composition,GOR,°API,by Zero-Flash(Sample 1.13) Sample 1.13;Cylinder SSB 18538-QA;Depth 4154 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT% MOLE% WT% MOLE% WT% MOLE% Carbon Dioxide 44.01 0.26 0.11 0.00 0.00 0.01 0.04 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen _ 28.01 0.09 0.06 0.00 0.00 0.00 0.02 Methane 16.04 84.64 94.28 0.00 0.00 2.15 32.80 Ethane 30.07 2.80 1.66 0.00 0.00 0.07 0.58 Propane 44.10 4.33 1.75 0.03 0.24 0.14 0.77 I-Butane 58.12 1.97 0.60 0.03 0.19 0.08 0.33 N-Butane _ 58.12 2.52 0.77 0.06 0.37 0.12 0.51 I-Pentane 72.15 1.33 0.33 0.08 0.42 0.12 0.39 N-Pentane _ 72.15 0.55 0.14 0.05 0.23 0.06 0.20 C6 84.00 0.65 0.14 0.20 0.87 0.21 0.62 M-C-Pentane 84.16 0.09 0.02 0.05 0.21 0.05 0.14 Benzene 78.11 0.04 0.01 0.03 0.14 0.03 0.10 Cyclohexane 84.16 0.08 0.02 0.06 0.26 0.06 0.18 C7 96.00 0.25 0.05 0.26 0.98 0.26 0.65 M-C-Hexane 98.19 0.06 0.01 0.08 0.32 0.08 0.21 Toluene 92.14 0.04 0.01 0.14 0.55 0.14 0.36 C8 _ 107.00 0.14 0.02 0.43 1.47 0.42 0.97 E-Benzene 106.17 0.01 0.00 0.05 0.17 0.05 0.11 M/P-Xylene 106.17 0.01 0.00 0.10 0.35 0.10 0.23 O-Xylene 106.17 0.00 0.00 0.06 0.21 0.06 0.14 C9 - 121.00 0.07 0.01 0.56 1.69 0.55 1.11 C10 134.00 0.04 0.00 0.98 2.67 0.96 1.75 C11 147.00 0.02 0.00 1.26 3.13 1.23 2.04 C12 161.00 0.01 0.00 1.76 3.99 1.72 2.60 C13 175.00 0.00 0.00 2.17 4.52 2.11 2.95 C14 _ 190.00 0.00 0.00 2.48 4.76 2.41 3.10 C15 206.00 0.00 0.00 2.72 4.81 2.65 3.14 C16 222.00 2.82 4.64 2.75 3.03 C17 237.00 2.97 4.57 2.89 2.98 C18 251.00 2.88 4.18 2.80 2.73 C19 263.00 2.85 3.96 2.78 2.58 C20 275.00 2.74 3.64 2.67 2.37 C21 291.00 2.66 3.33 2.59 2.17 C22 300.00 2.62 3.19 2.56 2.08 C23 312.00 2.29 2.68 2.23 1.75 C24 324.00 2.16 2.43 2.10 1.58 C25 337.00 2.15 2.32 2.09 1.52 C26 349.00 2.00 2.09 1.95 1.36 C27 360.00 1.97 1.99 1.92 1.30 C28 372.00 1.95 1.92 1.90 1.25 C29 382.00 1.91 1.83 1.86 1.19 C30 394.00 1.78 1.65 1.73 1.07 C31 404.00 1.58 1.42 1.54 0.93 C32 415.00 1.44 1.27 1.40 0.83 C33 426.00 1.39 1.19 1.36 0.78 C34 437.00 1.32 1.10 1.28 0.72 C35 445.00 1.21 1.00 1.18 0.65 C36+ 935.00 43.69 17.05 42.57 11.12 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 17.87 364.97 244.22 MOLE RATIO 0.3479 0.6521 Oilphase-DBR 23 Job#:200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Table 15:Calculated Fluid Properties Sample 1.13;Cylinder SSB 18538-QA;Depth 4154 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole% C7+ 0.86 0.16 99.55 97.68 97.04 63.75 C12+ 0.01 0.00 95.49 85.53 93.06 55.78 C20+ 74.85 74.85 50.10 72.94 32.67 C30+ 52.40 24.68 51.07 16.09 C36+ - - 43.69 17.05 42.57 11.12 Molar Mass C7+ 98.25 _ 371.97 371.74 C12+ 161.00 407.45 407.45 C20+ - 545.25 545.25 C30+ - _ 775.00 _ 775.00 _ C36+ - 935.00 935.00 Density C7+ - 0.9519 - C12+ - 0.9609 0.9609 C20+ - 1.0010 1.0010 C30+ 1.0612 1.0612 C36+ 1.0955 1.0955 Fluid at 60°F 0.9496 Gas Gravity(Air=11 0.617 Dry Gross Heat Content IBTU/scf) 1,106 _ Wet Gross Heat Content(BTU/scf) 1,087 OBM Contamination Level(wt°7o) - STO Basis • Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 364.97 364.97 935.00 Density(g/cm3) 0.9496 - 1.096 Single Stage Flash Data Original STO De-Contaminated GOR(scf/stbl 185 - STO Density Ig/cm3) 0 9496 - STO API Gravity 17.5 - OBM Density(g/cm3)©60°F - i Oilphase-DBR 24 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 9:Stock Tank Oil Chromatogram(Sample 1.13) Sample 1.13;Cylinder SSB 18538-QA;Depth 4154 ft.MD FID1 A,(F 121DAT.A1008000501CY18538 D} Norm. 0 0 JOB 200600050 CONOCO PHILLIPS 1.13 SSB 18538-QA 250- RF FLASH CYLINDER 200' 150 100- m Q me uN U m ®m D o m C h Q O,Nlnautm �N3111 50 6-6 m 2 m a in I9 N N NNNNN a 1 • t`0 W ��XQ D 7 U U j c C c c«�c�cccccC 1 • ei C CT0C U C C'I .y 11 17 Ilul,4t 0 5 10 15 20 25 30 35 mir Figure 10:k-Plot for Equilibrium Check(Sample 1.13) Sample 1.13;Cylinder SSB 18538-QA;Depth 4154 ft.MD 2.5 - -- 2 •C3 •iC4 1.5rr •,.C4 1 • •nC5"'- 6 0.5 •C6 0 •1,/ -0.5 •Cd -1 •C9 -1.5 -4 -3 -2 -1 0 1 2 3 F Oilphase-DBR 25 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 16:C36+Composition,GOR,°API,by Zero-Flash(Sample 1.15) Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT% MOLE% WT% MOLE% WT% MOLE% Carbon Dioxide 44.01 0.26 0.10 0.00 0.00 0.01 0.04 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.30 0.19 0.00 0.00 0.01 0.07 Methane 16.04 85.31 94.47 0.00 0.00 2.17 32.89 Ethane 30.07 2.77 1.64 0.00 0.00 0.07 0.57 Propane 44.10 4.09 1.65 0.03 0.22 0.13 0.71 I-Butane 58.12 1.78 0.55 0.03 0.19 0.07 0.31 N-Butane 58.12 2.28 0.70 0.06 0.36 0.11 0.48 I-Pentane 72.15 1.20 0.30 0.08 0.41 0.11 0.37 N-Pentane 72.15 0.51 0.13 0.05 0.23 0.06 0.19 C6 84.00 0.63 0.13 0.18 0.77 0.19 0.55 M-C-Pentane 84.16 0.09 0.02 0.05 0.21 0.05 0.14 Benzene 78.11 0.04 0.01 0.03 0.14 0.03 0.10 Cyclohexane 84.16 0.08 0.02 0.06 0.26 0.06 0.18 C7 96.00 0.25 0.05 0.27 1.01 0.27 0.67 M-C-Hexane 98.19 0.06 0.01 0.08 0.31 0.08 0.21 Toluene 92.14 0.05 0.01 0.14 0.54 0.14 0.36 C8 107.00 0.14 0.02 0.43 1.48 0.43 0.97 E-Benzene 106.17 0.01 0.00 0.05 0.17 0.05 0.11 M/P-Xylene 106.17 0.01 0.00 0.10 0.34 0.10 0.23 O-Xylene 106.17 0.01 0.00 0.06 0.21 0.06 0.14 C9 121.00 0.08 0.01 0.56 1.68 0.55 1.10 C10 134.00 0.04 0.00 0.99 2.68 0.97 1.75 C11 147.00 0.02 0.00 1.27 3.15 1.24 2.05 C12 161.00 0.00 0.00 1.79 4.03 1.74 2.63 C13 175.00 0.00 0.00 2.05 4.24 1.99 2.77 C14 190.00 0.00 0.00 2.66 5.09 2.60 3.32 C15 206.00 0.00 0.00 2.76 4.87 2.69 3.17 C16 222.00 2.86 4.68 2.79 3.05 C17 237.00 2.91 4.46 2.84 2.91 C18 251.00 2.95 4.27 2.87 2.78 C19 263.00 3.02 4.17 2.94 2.72 C20 275.00 2.79 3.69 2.72 2.40 C21 291.00 2.64 3.30 2.58 2.15 C22 300.00 2.55 3.09 2.49 2.01 C23 312.00 2.39 2.78 2.33 1.82 C24 324.00 2.30 2.58 2.24 1.68 C25 337.00 2.16 2.33 2.11 1.52 C26 349.00 2.03 2.11 1.98 1.38 C27 360.00 1.95 1.96 1.90 1.28 C28 372.00 1.93 1.89 1.88 1.23 C29 382.00 1.90 1.81 1.86 1.18 C30 394.00 1.85 1.70 1.80 1.11 C31 404.00 1.59 1.43 1.55 0.93 C32 415.00 1.46 1.28 1.43 0.83 C33 426.00 1.38 1.17 1.34 0.76 C34 437.00 1.16 0.96 1.13 0.63 C35 445.00 1.14 0.93 1.11 0.61 C36+ 933.00 43.26 16.83 42.16 10.97 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 17.77 363.07 242.87 MOLE RATIO 0.3481 0.6519 Oilphase-DBR 26 Job it 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 17:Calculated Fluid Properties Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole% C7+ 0.87 0.16 99.58 97.83 97.07 63.83 C12+ 0.00 0.00 95.48 85.64 93.05 55.83 C20+ - - 74.49 49.85 72.59 32.50 C30+ - - 51.83 24.31 50.51 15.85 C36+ - - 43.26 16.83 42.16 10.97 Molar Mass C7+ 97.92 369.58 369.34 C12+ 162.56 404.78 404.78 C20+ - 542.55 542.55 C30+ - 774.15 774.15 C36+ - 933.00 933.00 Density C7+ - 0.9515 - C12+ _ - 0.9606 0.9606 C20+ _ - 1.0015 1.0015 C30+ _ 1.0633 1.0633 C36+ 1.0981 1.0981 Fluid at 60°F 0.9494 Gas Gravity(Air=1) I 0.613 Dry Gross Heat Content(BTU/sof) 1,099 Wet Gross Heat Content IBTU/scf) 1,080 OBM Contamination Level(wt%) - STO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 363.07 363.07 933.00 Density(g/cm3) 0.9494 1.098 Single Stage Flash Data Original STO De-Contaminated GOR Iscf/stb) 186 - STO Density(g/cm3) 0.9494 _ - STO API Gravity 17.5 - OBM Density(g/cm3)©60°F - Oilphase-DBR 27 Job#:200600050 • Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 11:Stock Tank Oil Chromatogram(Sample 1.15) Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD HD^a :r+210ATM00600rJ: 1D°3' Nom. JOB 200600050 CONOCO PHILLIPS 700- 1.15 SSB 18538-QA RF FLASH CYLINDER 800 500 400- 300- 200 111jlp U oDo c 100- o „Q.' i mcT U U N a to W«O�0 FINmNNpriVVI 1D—riN(rl+NlrmIl ' m,rNTom 5 U U 0000U00000LWWLUX)k' ;to c2 C O C C C CC C cc : : • C C c C C C CCC CC CCCC 0 5 10 15 20 25 30 35 mir Figure 12:k-Plot for Equilibrium Check(Sample 1.15) Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD 2.5 2 •11 •iC4 1.5 •nC4 1 •g5 3 0.5 •C6 0 •0/ -0.5 •C8 -1 •C9 -1.5 -4 -3 -2 -1 0 2 3 F Oilphase-DBR 28 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 18:Summary of Results of Sample 1.15 Sample 1.15;Cylinder SSB 18535-QA; Depth 4154 ft.MD Reservoir Conditions: Pressure 1707 psia Temperature: 79 °F Summary of Fluid Properties: OBM Contamination - Wt%STO Basis OBM Contamination - Wt%RF Basis Bubble Point Pressure At Tres 1,440 psia At 130°F psia At 100°F psia Gas-Oil Ratio Single-stage Flash: 186 scf/stb Total Differential Liberation: - scf/stb Total Separator Flash: 182 scf/stb Properties at 60°F STO°API Gas Gravity(Average) Single-stage STO: 17.54 0.613 Differential Liberation STO: - - Separator STO: 17.62 0.606 Properties at Reservoir Conditions Viscosity: 107.08 cP Compressibillity(Co): 4.7 10 s/psi Density 0.9115 g/cc Properties at Saturation Conditions Viscosity: 102.16 cP Compressibillity(Co(. 4.7 10.6/psi Density: 0.9104 g/cc Formation Volume Factor @Pres&Tres @Psat&Tres Single-stage Flash: 1.069 1.070 Total Differential Liberation: - - Total Separator Flash: 1.067 1.068 Note:Standard conditions are 14.696 psia and 60°F Oilphase-DBR 29 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger PVT Analysis on Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD Constant Composition Expansion at Tres The CCE study was initiated by charging a sub-sample of live reservoir fluid into the PVT cell at a reservoir temperature of 79.0°F and at a pressure of 10,015 psia.Sequential pressure decrease in steps and the corresponding volume changes are presented in Table 19.The pressure-volume(P-V)plots of the CCE data are presented in Figure 13.The intersection of the single-phase and two-phase lines in the P-V plot and the visual observation was used to define the bubblepoint. For the subject fluid, the bubblepoint was determined to be 1,440 psia at the reservoir temperature of 79.0°F.Also,calculated relative volume and oil compressibility is presented in Table 19.As seen in the table,the compressibility of this oil is 4.7 x 10e-6 1/psia at the saturation pressure. Table 19:Constant Composition Expansion at 79.0°F(Sample 1.15) Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 ft.MD Pressure Relative Vol °/0 Liquid %Liquid Liquid Density Y Function Compressibility (psia) (Vr=VNsat) (VlNsat) (VlNtotal) (g/cm3) (10-6/psia) 1 10015 0.9660 96.6 100.0 0.9425 3.4 2 9015 0.9693 96.9 100.0 0.9392 3.5 3 7015 0.9765 97.6 100.0 0.9323 3.8 4 5015 0.9843 98.4 100.0 0.9249 4.1 5 4015 0.9884 98.8 100.0 0.9210 4.3 6 3015 0.9928 99.3 100.0 0.9170 4.5 7 2015 0.9973 99.7 100.0 0.9129 4.6 Pi 1707 0.9987 99.9 100.0 0.9115 4.7 9 1670 0.9989 99.9 100.0 0.9114 4.7 Pb 1440 1.0000 100.0 100.0 0.9104 4.7 11 1207 1.0242 99.3 96.9 8.0 12 1098 1.0398 99.0 95.2 7.8 13 943 1.0696 98.7 92.2 7.6 14 842 1.0960 98.5 89.9 7.4 15 650 1.1702 98.2 83.9 7.1 16 479 1.2891 98.0 76.0 6.9 17 268 1.6681 97.8 58.6 6.5 18 169 2.1750 97.7 44.9 6.4 Oilphase-DBR 30 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 13:Constant Composition Expansion at 79.0°F-Relative Volume(Sample 1.15) Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 ft.MD 2.4 2.2 2.0 1.8 d Cei O E 1.6 = 0 m ec C m 1.4 . • 1.2 • • • 1.0 •• • —•—• • 0 0 0 0.8 0 2000 4000 6000 8000 10000 Pressure(psial Oilphase-DBR 31 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 79°F.These values as a function of selected pressure steps are summarized in Table 20.The liquid phase viscosity values are graphically presented in Figure 14. As seen in the figures and as expected,the viscosity values decrease with decreasing pressure up to the bubblepoint and increase with further reduction in pressure below the bubblepoint. The resported reservoir-fluid viscosities at reservoir temperature are considered to be high relative to associated 1 H- North data,however,the results were confirmed through duplicate testing. Table 20:Reservoir Fluid Viscosity 79°F(Sample 1.15) Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD Pressure Viscosity @ Tres (psis) (cP) 1 10060 459.9 2 9047 383.5 3 8034 318.2 4 7055 264.6 5 6022 211.4 6 4995 177.4 7 4013 148.6 8 3010 126.8 9 2015 108.9 Pi 1707 102.0 Pb 1440 97.8 12 1274 122.7 13 1166 135.2 14 1077 153.2 STO 15 524.0 Oilphase-DBR 32 Job 4:200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Figure 14:Reservoir Fluid Viscosity 79°F (Sample 1.15) Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD 600 - • 500 ' 400 • • 7, 300 O • • 200 • • • •• • 100 •• • 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 Pressure(psis) Oilphase-DBR 33 Job#-200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Multi-Stage Separation Test Multi-stage separation test results are presented in Tables 21 -23.The fluid properties(i.e., GOR,density and oil formation volume factor)are presented in Table 21.Multi-stage separation test conditions are: STAGE 1 105 psia 125°F STAGE 2 75 psia 185°F STAGE STO 14.696 psia 60°F As seen in Table 21,the GOR value obtained from the multi-stage separation test is 182 SCF/STB and the formation volume factor is 1.068.The compositional analyses of separator gas and tank gas are summarized in Table 22 and the composition of tank liquid is tabulated in Table 23. The total dry gross heat content of the separation gases is calculated to be 1,088 BTU/scf whereas the total wet gross heat content is calculated to be 1,069 BTU/scf. With reference to the assumption made in"The Properties of Petroleum Fluids"(McCain,1990),the assumption made in generating reservoir fluid properties from a PVT study is that at pressures below the bubblepoint,the process in the reservoir can be mimicked by differential vaporization,while the process in the wellbore is simulated by the separator test.Hence,fluid properties at pressures below saturation pressure can be calculated by combining the data from the differential vaporization and a separator test. Oilphase-DBR 34 Job#:200600050 Client: ConocoPhiHips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 21:Multi-Stage Separation Test Vapor&Liquid Properties (Sample 1.15) Sample 1.15;Cylinder SSB 18535-QA;Depth 4154 ft.MD PROPERTY STAGE Pb STAGE 1 STAGE2 STAGE STO Pressure(psia) 1440 105 75 14.696 Temperature(°F) 79 125 185 60 Liq.Den(g/cm3) 0.9103 0.9294 0.9180 0.9384 Vap.Gravity' 0.604 0.668 0.641 Vap.M„„ 17.48 19.33 18.58 Vap Heat Val° 1083 1180 1143 GOR` 170 4 8 GORd 167 3 8 Sep.FVF` 1.068 1.022 1.034 1.011 a)Calculated,at 60°F(air=1) b)Calculated,Dry basis BTU/scf c)scf gas/bbl of oil at STD conditions d)scf gas/bbl of oil at separator conditions e)fluid volume at sep conditions/fluid volume at STD conditions Residual oil density at standard conditions 0.9489 g/cc Sep gas gravity(average) Sg=ERjSgj/ER 0.606 Where: R:GOR(scf gas/bbl of oil at STD conditions), j:separator stages Sep gas gross heating value(a L°=ER1*Lc1/ER1 10 BTU/scf(dry basis) Where: A.GOR(scf gas/bbl of oil at STD conditions), j:separator stages SEPARATION TEST SUMMARY 'Total Separation Test GOR 182 Separation Test STO Gravity 17.62 bSeparation Test FVF 1.068 a)scf gas/bbl of condensate at STD conditions b)Fluid volume at Psat&Tres/Fluid volume at STD Oilphase-DBR 35 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger • Table 22:Multi-Stage Separator Test Vapor Composition(mol%) Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 ft.MD Component MW Mole% (g/mol) STAGE 1 STAGE 2 STAGE STO Carbon Dioxide 44.01 0.10 0.28 0.16 Hydrogen Sulfide 34.08 0.00 0.00 0.00 Nitrogen 28.01 0.21 0.09 0.03 Methane 16.04 95.29 89.95 90.97 Ethane 30.07 1.46 2.57 3.38 Propane 44.10 1.36 3.00 3.06 I-Butane 58.12 0.42 1.12 0.80 N-Butane 58.12 0.52 1.54 0.89 I-Pentane 72.15 0.21 0.57 0.32 N-Pentane 72.15 0.20 0.53 0.12 C6 84.00 0.08 0.22 0.11 M-C-Pentane 84.16 0.02 0.03 0.02 Benzene 78.11 0.00 0.00 0.01 Cyclohexane 84.16 0.02 0.02 0.02 C7 96.00 0.08 0.05 0.03 M-C-Hexane 98.19 0.01 0.01 0.01 Toluene 92.14 0.02 0.02 0.01 C8 107.00 0.01 0.00 0.02 E-Benzene 106.17 0.00 0.00 0.00 M/P-Xylene 106.17 0.00 0.00 0.00 0-Xylene 106.17 0.00 0.00 0.00 C9 121.00 0.00 0.00 0.01 C10 134.00 0.00 0.00 0.00 C11 147.00 0.00 0.00 0.00 C12 161.00 0.00 0.02 0.00 C13 175.00 0.00 0.00 0.00 C14 190.00 0.00 0.00 0.00 C15 206.00 0.00 0.00 0.00 C16 222.00 0.00 0.00 0.00 C17 237.00 0.00 0.00 0.00 C18 251.00 0.00 0.00 0.00 C19 263.00 0.00 0.00 0.00 C20 275.00 0.00 0.00 0.00 C21 291.00 0.00 0.00 0.00 C22 300.00 0.00 0.00 0.00 C23 312.00 0.00 0.00 0.00 C24 324.00 0.00 0.00 0.00 C25 337.00 0.00 0.00 0.00 C26 349.00 0.00 0.00 0.00 C27 360.00 0.00 0.00 0.00 C28 372.00 0.00 0.00 0.00 C29 382.00 0.00 0.00 0.00 C30+ 774.15 0.00 0.00 0.00 Total 100.00 100.00 100.00 MW 17.48 19.33 18.58 Relative Density(air=1) 0.603 0.667 0.641 Dry Gross Heat Content(BTU/scf) 1083 1180 1143 Oilphase-DBR 36 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 23:Multi-Stage Separator Test Residual Liquid Composition(mol%) Sample 1.15;Cylinder SSB 18535-0A;Depth 4154 ft.MD COMPONENT MW Residual Liquid (g/mol) (mol%) Carbon Dioxide 44.01 0.00 Hydrogen Sulfide 34.08 0.00 Nitrogen 28.01 0.00 Methane 16.04 0.00 Ethane 30.07 0.00 Propane 44.10 0.47 I-Butane 58.12 0.35 N-Butane 58.12 0.64 I-Pentane 72.15 0.61 N-Pentane 72.15 0.30 C6 84.00 1.07 M-C-Pentane 84.16 0.25 Benzene 78.11 0.17 Cyclohexane 84.16 0.31 C7 96.00 1.05 M-C-Hexane 98.19 0.37 Toluene 92.14 0.64 C8 107.00 1.59 E-Benzene 106.17 0.19 M/P-Xylene 106.17 0.38 0-Xylene 106.17 0.22 C9 121.00 1.69 C10 134.00 2.46 C11 147.00 2.86 C12 161.00 3.62 C13 175.00 4.06 C14 190.00 4.45 C15 206.00 5.01 C16 222.00 4.48 C17 237.00 4.21 C18 251.00 4.18 C19 263.00 4.04 C20 275.00 3.57 C21 291.00 3.32 C22 300.00 3.15 C23 312.00 3.22 C24 324.00 2.38 C25 337.00 2.42 C26 349.00 1.55 C27 360.00 2.26 C28 372.00 2.36 C29 382.00 1.65 C30+ 762.34 24.48 Total 100.00 MW 359.79 Oilphase-DBR 37 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 24:C30+Composition,GOR,°API,by Zero-Flash(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) _ WT% MOLE% WT% MOLE% WT% MOLE To Carbon Dioxide 44.01 0.21 0.09 0.00 0.00 0.01 0.03 Hydrogen Sulfide 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 _ 0.27 0.19 0.00 0.00 0.01 0.07 Methane 16.04 77.01 91.91 0.00 0.00 2.73 33.14 Ethane 30.07 2.25 1.43 0.00 0.00 0.08 0.52 Propane 44.10 _ 4.50 1.96 0.03 0.21 0.19 0.84 I-Butane 58.12 2.94 0.97 0.05 0.25 0.15 0.51 N-Butane 58.12 4.35 1.43 0.13 0.65 0.28 0.93 I-Pentane 72.15 2.99 0.79 0.23 0.94 0.33 0.89 N-Pentane 72.15 1.39 0.37 0.16 0.66 0.21 0.55 C6 84.00 1.73 0.39 0.71 2.49 0.75 1.73 M-C-Pentane 84.16 0.27 0.06 0.17 0.61 0.18 0.41 Benzene 78.11 0.04 0.01 0.05 0.18 0.05 0.12 Cyclohexane 84.16 0.27 0.06 0.27 0.93 0.27 0.61 C7 96.00 0.69 0.14 1.11 3.39 1.09 2.22 M-C-Hexane 98.19 0.24 0.05 0.42 1.26 0.42 0.83 Toluene 92.14 0.11 0.02 0.29 0.92 0.28 0.60 C8 107.00 0.36 0.06 1.63 4.47 1.58 2.88 E-Benzene 106.17 0.01 0.00 0.12 0.34 0.12 0.22 M/P-Xylene 106.17 0.03 0.01 0.34 0.94 0.33 0.61 O-Xylene 106.17 0.01 0.00 0.19 0.54 0.19 0.34 C9 121.00 0.20 0.03 1.86 4.51 1.80 2.89 C10 134.00 0.09 0.01 2.88 6.32 2.78 4.04 C11 147.00 0.03 0.00 2.53 5.06 2.44 3.24 C12 161.00 0.00 0.00 2.92 5.32 2.82 3.41 C13 175.00 0.00 0.00 3.16 5.31 3.05 3.39 C14 190.00 0.00 0.00 3.24 5.01 3.13 3.20 C15 206.00 0.00 0.00 3.14 4.47 3.02 2.86 C16 222.00 2.75 3.64 2.65 2.33 C17 237.00 2.61 3.23 2.51 2.07 C18 251.00 2.25 2.64 2.17 1.69 C19 263.00 _ 2.27 2.53 2.18 1.62 C20 275.00 2.05 2.19 1.98 1.40 C21 291.00 1.83 1.84 1.76 1.18 C22 300.00 1.70 1.67 1.64 1.07 C23 312.00 1.44 1.36 1.39 0.87 C24 324.00 1.37 1.24 1.32 0.79 C25 337.00 1.28 1.12 1.24 0.72 C26 349.00 1.18 0.99 1.13 0.63 C27 360.00 1.10 0.90 1.06 0.58 C28 372.00 1.11 0.87 1.07 0.56 C29 382.00 1.10 0.84 1.06 0.54 C30 394.00 1.04 0.78 1.00 0.50 C31 404.00 0.84 0.61 0.81 0.39 C32 415.00 0.75 0.53 0.72 0.34 C33 426.00 0.71 0.49 0.68 0.31 C34 437.00 0.56 0.37 0.54 0.24 C35 445.00 0.58 0.38 0.56 0.24 C36+ 791.00 45.85 17.02 44.23 10.88 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.15 293.62 194.67 MOLE RATIO 0.3605 0.6395 Oilphase-DBR 38 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 25:Calculated Fluid Properties Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+Composition Mass% Mole% Mass% Mole% Mass% Mole% C7+ 2.36 0.46 98.69 94.81 95.27 60.79 C12+ 0.00 0.00 86.82 65.35 83.74 41.79 C20+ - - 64.48 33.20 62.19 21.23 C30+ - - - 50.32 _ 20.18 48.54 12.90 C36+ - - 45.85 17.02 44.23 10.88 Molar Mass C7+ 97.34 305.64 305.07 C12+ 165.63 390.09 390.09 C20+ - 570.25 570.25 C30+ - 732.27 _ 732.27 _ I C36+ - 791.00 791.00 Density C7+ - 0.9360 - _ C12+ - 0.9637 0.9637 C20+ - 1.0185 1.0185 C30+ 1.0645 1.0645 C36+ 1.0815 1.0815 Fluid at 60°F 0.9302 Gas Gravity(Air=1) 0.661 Dry Gross Heat Content(BTU/scf) 1,173 Wet Gross Heat Content(BTU/scf) 1,153 OBM Contamination Level(wt%) - STO Basis Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C30+Properties MW 293.62 293.62 791.00 Density(g/cm3) 0.9302 - 1.081 Single Stage Flash Data Original STO De-Contaminated GOR(scf/stb) 238 - STO Density(g/cm3) 0.9302 _ - STO API Gravity 20.6 - OBM Density(g/cm3)©60°F Oilphase-DBR 39 Job#:200600050 r r Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 15:k-Plot for Equilibrium Check(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD 2.5 2 •C3 •iC4 1.5 •FICA 1 •nl•15 S. 0.5 •C6 of 3 0 •c/ -0.5 •CO -1 - •C9 -1.5 • •C10 -2 -4 -3 -2 -1 0 1 2 3 F Oilphase-DBR 40 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 26:Summary of Results of Sample 1.09,1.10&1.11 Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Reservoir Conditions: Pressure: 1735 psia Temperature: 81 °F Summary of Fluid Properties: Bubble Point Pressure At Tres 1,544 psia Gas-Oil Ratio Single-stage Flash: 238 scf/stb Total Differential Liberation: scf/stb Total Separator Flash: 214 scf/stb Properties at 60°F STO°API Gas Gravity(Average) Single-stage STO: 20.62 0.661 Differential Liberation STO: Separator STO: 21.26 0.624 Properties at Reservoir Conditions Viscosity: 20.1 cP Compressibillity(Co): 9.4 10-6/psi Density: • 0.8741 g/cc Properties at Saturation Conditions Viscosity: 19.9 cP Compressibillity(Co): 9.6 10-6/psi Density: 0.8725 g/cc Formation Volume Factor @Pres&Tres @Psat&Tres Single-stage Flash: 1.103 1.105 Total Differential Liberation: Total Separator Flash: 1.093 1.095 Note:Standard conditions are 14.696 psia and 60°F Oilphase-DBR 41 Job 4:200600050 Client: ConocoPhillips Field: West Sak Well: tH North Sand: B&D Schlumberger PVT Analysis on Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Constant Composition Expansion at Tres The CCE study was initiated by charging a sub-sample of live reservoir fluid into the PVT cell at a reservoir temperature of 81.0°F and at a pressure of 10,015 psia.Sequential pressure decrease in steps and the corresponding volume changes are presented in Table 27.The pressure-volume (P-V)plots of the CCE data are presented in Figure 16.The intersection of the single-phase and two-phase lines in the P-V plot and the visual observation was used to define the bubblepoint. For the subject fluid, the bubblepoint was determined to be 1,544 psia at the reservoir temperature of 81.0°F.Also, calculated relative volume and oil compressibility is presented in Table 27.As seen in the table,the compressibility of this oil is 9.6 x 10e-6 1/psia at the saturation pressure. Table 27:Constant Composition Expansion at 81.0°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Pressure Relative Vol %Liquid %Liquid Liquid Density Y Function Compressibility (psia) (Vr=VNsat) (VlNsat) (VI/Vtotal) (g/cm3) (10-6/psia) 1 10015 0.9526 0.9159 3.0 2 9015 0.9557 0.9129 3.5 3 8016 0.9593 0.9095 4.0 4 7016 0.9634 0.9056 4.6 5 6014 0.9682 0.9012 5.3 6 5014 0.9737 0.8961 6.0 7 4015 0.9800 0.8903 6.9 8 3015 0.9872 0.8838 7.9 9 2015 0.9956 0.8763 9.0 10 1816 0.9974 0.8747 9.3 Pi 1735 0.9982 0.8741 9.4 Pb 1544 1.0000 100.0 100.0 0.8725 9.6 13 1495 1.0067 99.9 99.2 4.9 14 1390 1.0234 99.6 97.4 4.7 15 1241 1.0549 99.3 94.1 4.5 16 1090 1.0969 99.1 90.3 4.3 17 977 1.1412 98.8 86.6 4.1 18 834 1.2191 98.6 80.9 3.9 19 713 1.3105 98.3 75.0 3.8 20 569 1.4796 98.1 66.3 3.6 21 439 1.7295 98.0 56.6 3.5 22 327 2.1039 97.8 46.5 3.4 Note on compressibility data:the reported compressibilities are considered to be significantly high for the temperature and fluid typology in question. The CCE at reservoir temperature was repeated using extended stabilisation times,and the results of the duplicate test were closely similar to the original data,as reported. We conclude that the resolution of volumetric data,for very heavy oils,in the current configuration of the visual PVT cell is insufficient to permit more accurate delineation of compressibilities. Thus,the reported Br data should be considered as approximate and likely overestimated. Oilphase-DBR 42 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 16:Constant Composition Expansion at 81.0°F-Relative Volume(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD 2.2 0 2.0 1.8 O 1.6 a E • 0 > 1.4 W ec • 1.2 • • • • • 1.0 b•u• • • • 0.8 . 0 2000 4000 6000 8000 10000 12000 Pressure(psia) Oilphase-DBR 43 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Reservoir Oil Viscosity The liquid phase viscosity was measured at the reservoir temperature of 81°F,as well as at 150°F, 90°F and 60°F. These values as a function of selected pressure steps are summarized in Table 28.The liquid phase viscosity values are graphically presented in Figure 17. As seen in the figures and as expected, the viscosity values decrease with decreasing pressure up to the bubblepoint and increase with further reduction in pressure below the bubblepoint. Table 28:Reservoir Fluid Viscosity at 81°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Pressure Viscosity @ Tres (psia► (cP) 1 10045 63.5 2 9002 55.9 3 7995 46.9 4 6990 42.1 5 6002 36.1 6 5004 31.0 7 4019 27.4 8 3167 24.2 9 2453 22.3 10 1926 21.1 Pi 1735 20.1 Pb 1544 19.9 13 1353 21.9 14 1264 22.5 15 1124 24.1 16 1014 25.8 17 919 27.7 18 841 28.9 19 719 30.8 20 556 37.6 STO 15 125.5 Oilphase-DBR 44 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 17:Reservoir Fluid Viscosity at 81°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD 140 120 100 80 H a - O V VJ • 60 • _ • • 40 • • • • •� • •• • 20 %• • 0 2000 4000 6000 8000 10000 12000 Pressure(psis) Oilphase-DBR 45 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 29:Reservoir Fluid Viscosity at 150°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Pressure Viscosity @ Tres (psia) (cP) 1 10066 13.37 2 9016 11.86 3 8001 10.61 4 7000 9.51 5 6006 8.48 6 5014 7.58 7 4025 6.81 8 3500 6.44 9 3184 6.21 10 2994 6.10 11 2745 5.92 12 2497 5.76 13 2243 5.59 14 2010 5.44 15 1901 5.38 16 1708 5.27 17 1499 5.39 18 1382 5.39 19 1215 5.80 20 1085 6.19 21 920 6.96 22 750 7.84 23 490 11.97 24 287 16.15 STO 15 22.50 Oilphase-DBR 46 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 18:Reservoir Fluid Viscosity at 150°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD 25 • 20 • 15 • • • • 10 • • • • • • • •• •••�••�••• • 5 0 2000 4000 6000 8000 10000 12000 Pressure(psia) Oilphase-DBR 47 Job 4:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 30:Reservoir Fluid Viscosity at 90°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Pressure Viscosity @ Tres (psia) (cP) 1 10081 48.74 2 9044 42.18 3 8040 37.20 4 7052 33.72 5 6040 29.39 6 4992 26.10 7 4030 23.50 8 3494 20.80 9 3231 20.28 10 3041 19.78 11 2549 18.41 12 2279 17.92 13 1834 16.87 14 1592 16.17 15 1516 16.05 16 1437 16.14 17 1388 16.80 18 1269 17.86 19 1039 19.72 20 959 20.32 21 842 21.64 22 670 23.19 23 500 24.81 24 287 32.55 STO 14.696 93.13 Oilphase-DBR 48 Job 4:200600050 • Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 19:Reservoir Fluid Viscosity at 90°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD 100 80 60 F. . • 40 • .• • • • •• • 20 ••i • •• •• • • 0 2000 4000 6000 8000 10000 12000 Pressurelpsia) Oilphase-DBR 49 Job 4:200600050 • Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 31:Reservoir Fluid Viscosity at 60°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Pressure Viscosity @ Tres (psia) (cP) 1 9999 104.56 2 9087 84.35 3 7999 69.17 4 7006 60.04 5 6004 50.60 6 5011 44.11 7 3987 38.15 8 3535 35.77 9 3244 34.24 10 3000 33.22 11 2752 32.19 12 2502 31.18 13 2255 30.16 14 2001 29.09 15 1750 28.24 16 1506 27.40 17 1337 29.44 18 1259 30.90 19 1183 33.88 20 1078 35.91 21 997 38.15 22 920 39.51 23 767 58.51 STO 15 236.14 Oilphase-DBR 50 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Figure 20:Reservoir Fluid Viscosity at 60°F(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD 260 - 240 • 220 i 200 180 160 ii `—' 140 O 120 7 100 • 80 • • 60 • • • 40 • • 20 0 2000 4000 6000 8000 10000 12000 Pressure(psia) Oilphase-DBR 51 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Multi-Stage Separation Test Multi-stage separation test results are presented in Tables 32-34. The fluid properties (i.e., GOR, density and oil formation volume factor)are presented in Table 32.Multi-stage separation test conditions are: STAGE 1 105 psia 125°F STAGE 2 75 psia 185°F STAGE STO 14.696 psia 60°F As seen in Table 32,the GOR value obtained from the multi-stage separation test is 214 SCF/STB and the formation volume factor is 1.095.The compositional analyses of separator gas and tank gas are summarized in Table 33 and the composition of tank liquid is tabulated in Table 34. The total dry gross heat content of the separation gases is calculated to be 1,116 BTU/scf whereas the total wet gross heat content is calculated to be 1,096 BTU/scf. With reference to the assumption made in"The Properties of Petroleum Fluids"(McCain, 1990),the assumption made in generating reservoir fluid properties from a PVT study is that at pressures below the bubblepoint,the process in the reservoir can be mimicked by differential vaporization,while the process in the wellbore is simulated by the separator test.Hence,fluid properties at pressures below saturation pressure can be calculated by combining the data from the differential vaporization and a separator test. Oilphase-DBR 52 Job#:200600050 r T Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 32:Multi-Stage Separation Test Vapor&Liquid Properties(Sample 1.09,1.10&1.11) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD PROPERTY STAGE Pb STAGE 1 STAGE 2 STAGE STO Pressure(psia) 1544 105 75 14.696 Temperature(°F) 81 125 185 60 Liq.Den(g/cm3) 0.8725 0.9043 0.8843 0.9262 Vap.Gravity° 0.619 0.727 0.717 Vap.M,,,, 17.92 21.06 20.75 Vap Heat Val.b 1107 1277 1259 GOR` 203 6 5 GOR° 198 6 5 Sep.FVF° 1.095 1.026 1.048 1.000 a)Calculated,at 60°F(air=1) b)Calculated,Dry basis BTU/scf c)scf gas/bbl of oil at STD conditions d)scf gas/bbl of oil at separator conditions e)fluid volume at sep conditions/fluid volume at STD conditions Residual oil density at standard conditions 0.9263 g/cc Sep gas gravity(average) Sa=ERjSgj/ERj 0.624 Where: R:GOR(scf gas/bbl of oil at STD conditions), j:separator stages Sep gas gross heating value(alLc=ERN/ER1 1116 BTU/scf(dry basis) Where: R:GOR(scf gas/bbl of oil at STD conditions), j:separator stages SEPARATION TEST SUMMARY 'Total Separation Test GOR 214 Separation Test STO Gravity 21.26 bSeparation Test FVF 1.095 a)scf gas/bbl of condensate at STD conditions b)Fluid volume at Psat&Tres/Fluid volume at STD Oilphase-DBR 53 Job#:200600050 A Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 33:Multi-Stage Separator Test Vapor Composition(mol%) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD Component MW Mole% (g/mol) STAGE 1 STAGE 2 STAGE STO Carbon Dioxide 44.01 0.09 0.12 0.15 Hydrogen Sulfide 34.08 0.00 0.00 0.00 Nitrogen 28.01 0.21 0.09 0.04 Methane 16.04 94.56 86.65 88.17 Ethane 30.07 1.27 2.34 1.88 Propane 44.10 1.55 3.94 3.70 I-Butane 58.12 0.56 1.62 1.59 N-Butane 58.12 0.74 2.21 2.21 I-Pentane 72.15 0.34 1.07 0.86 N-Pentane 72.15 0.19 0.59 0.42 C6 84.00 0.23 0.77 0.23 M-C-Pentane 84.16 0.03 0.09 0.01 Benzene 78.11 0.01 0.01 0.00 Cyclohexane 84.16 0.03 0.07 0.01 C7 96.00 0.11 0.29 0.00 M-C-Hexane 98.19 0.03 0.05 0.00 Toluene 92.14 0.01 0.02 0.12 C8 107.00 0.04 0.04 0.00 E-Benzene 106.17 0.00 0.00 0.05 M/P-Xylene 106.17 0.00 0.01 0.02 0-Xylene 106.17 0.00 0.00 0.01 C9 121.00 0.01 0.01 0.00 C10 134.00 0.00 0.01 0.05 C11 147.00 0.00 0.00 0.26 C12 161.00 0.00 0.00 0.21 C13 175.00 0.00 0.00 0.00 C14 190.00 0.00 0.00 0.00 C15 206.00 0.00 0.00 0.00 C16 222.00 0.00 0.00 0.00 C17 237.00 0.00 0.00 0.00 C18 251.00 0.00 0.00 0.00 C19 263.00 0.00 0.00 0.00 C20 275.00 0.00 0.00 0.00 C21 291.00 0.00 0.00 0.00 C22 300.00 0.00 0.00 0.00 C23 312.00 0.00 0.00 0.00 C24 324.00 0.00 0.00 0.00 C25 337.00 0.00 0.00 0.00 C26 349.00 0.00 0.00 0.00 C27 360.00 0.00 0.00 0.00 C28 372.00 0.00 0.00 0.00 C29 382.00 0.00 0.00 0.00 C30 394.00 0.00 0.00 0.00 C31 404.00 0.00 0.00 0.00 C32 415.00 0.00 0.00 0.00 C33 426.00 0.00 0.00 0.00 C34 437.00 0.00 0.00 0.00 C35 445.00 0.00 0.00 0.00 C36+ 790.00 0.00 0.00 0.00 Total 100.00 100.00 100.00 MW 17.92 21.06 20.75 Relative Density lair=1) 0.619 0.727 0.716 Dry Gross Heat Content(BTU/scf) 1107 1277 1259 Oilphase-DBR 54 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Table 34:Multi-Stage Separator Test Residual Liquid Composition(mol%) Sample 1.09,1.10&1.11;Cylinder CSB 7356-MA;Depth 4068 ft.MD COMPONENT MW Residual Liquid (g/mol) (mol%) Carbon Dioxide 44.01 0.00 Hydrogen Sulfide 34.08 0.00 Nitrogen 28.01 0.00 Methane 16.04 0.00 Ethane 30.07 0.00 Propane 44.10 0.53 I-Butane 58.12 0.49 N-Butane 58.12 0.99 I-Pentane 72.15 1.18 N-Pentane 72.15 0.78 C6 84.00 2.15 M-C-Pentane 84.16 0.61 Benzene 78.11 0.15 Cyclohexane 84.16 0.91 C7 96.00 2.71 M-C-Hexane 98.19 1.28 Toluene 92.14 0.90 C8 107.00 4.38 E-Benzene 106.17 0.34 M/P-Xylene 106.17 0.91 0-Xylene 106.17 0.48 C9 121.00 4.75 C10 134.00 5.62 C11 147.00 4.80 C12 161.00 4.83 C13 175.00 4.67 C14 190.00 4.98 C15 206.00 4.10 C16 222.00 3.75 C17 237.00 3.34 C18 251.00 3.06 C19 263.00 2.88 C20 275.00 2.35 C21 291.00 2.24 C22 300.00 2.23 C23 312.00 1.78 C24 324.00 1.49 C25 337.00 1.50 C26 349.00 1.58 C27 360.00 1.23 C28 372.00 1.18 C29 382.00 1.19 C30 394.00 0.95 C31 404.00 0.84 C32 415.00 0.84 C33 426.00 0.53 C34 437.00 0.60 C35 445.00 0.26 C36+ 790.00 13.64 Total 100.00 MW 281.02 Oilphase-DBR 55 Job#:200600050 w Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Appendix A:Nomenclature and Definitions API Gravity American Petroleum Institute gravity Bg Gas formation volume factor Bo Oil formation volume factor CCE Constant composition Expansion DV Differential Vaporization GLR Gas Liquid Ratio GOR Gas Oil Ratio LO Live Oil n Number of moles OBM Oil Based Mud P Absolute pressure Pb Bubble point pressure PV Pressure-Volume Method Pi Initial Reservoir Pressure R Universal gas constant Rs Solution gas oil ratio T Temperature V Volume Vr Relative volume STL Stock Tank Liquid STO Stock Tank Oil %,w/w Weight Percent Z Gas deviation factor Dry Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as liquid.Wet Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction of water saturated gas at a standard temperature and pressure in which all water formed appears as liquid. Molar masses,densities and critical values of pure components are from CRC handbook of Chemistry and Physics and those of pseudo components are from Katz data. Gas viscosity is calculated from the correlation of Carr, Kobayshi and Burrows as given in the "Phase Behavior of Oilfield Hydrocarbon Systems"by M.B.Standing Compressibility in constant mass study is obtained from mathematical derivation of relative volume. Gas gravity is calculated from composition using the perfect gas equation(Gas deviation factor,Z=1) The Stiff and Davis Stability Index is an extension of the Langlier Index and is used as an indicator of the calcium carbonate scaling tendencies of oil field brine. • A positive index indicates scaling tendencies. • A negative index indicates corrosive tendencies. An index of zero indicates the water is in chemical equilibrium and will neither deposit nor dissolve calcium carbonates. Oilphase-DBR 56 Job#:200600050 a r Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Appendix B:Molecular Weights and Densities Used Components MW Density (g/cc) CO2 44.01 0.827 H2S 34.08 0.993 N2 28.013 0.808 Cl 16.043 0.300 C2 30.07 0.356 C3 44.097 0.508 I-C4 58.124 0.567 N-C4 58.124 0.586 I-05 72.151 0.625 N-05 72.151 0.631 C6 84 0.660 MCYC-05 84.16 0.753 BENZENE 78.11 0.884 CYCL-C6 84.16 0.781 C7 96 0.688 MCYCL-C6 98.19 0.773 TOLUENE 92.14 0.871 C8 107 0.749 C2-BENZEN 106.17 0.870 M&P-XYLEN 106.17 0.866 0-XYLENE 106.17 0.884 C9 121 0.768 C10 134 0.782 C11 147 0.793 C12 161 0.804 C13 175 0.815 C14 190 0.826 C15 206 0.836 C16 222 0.843 C17 237 0.851 C18 251 0.856 C19 263 0.861 C20 275 0.866 C21 291 0.871 C22 300 0.876 C23 312 0.881 C24 324 0.885 C25 337 0.888 C26 349 0.892 C27 360 0.896 C28 372 0.899 C29 382 0.902 Oilphase-DBR 57 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job IS: 200600050 Appendix C:EQUIPMENT Fluid Preparation and Validation The opening pressure of the cylinder is measured using a Heise pressure gauge soon after the sample arrives in the laboratory.Subsequently,the sample bottle is pressurized to the reservoir pressure using water-glycol mixture at the bottomside of the piston cylinder. Custom made heating jacket is wrapped around the cylinder to heat the sample bottle to the reservoir temperature.The sample bottle is then placed into a rocking stand and rocked for 5 days to homogenize the reservoir fluid. Live reservoir fluid analysis is necessary in the sample validation process as well as during the completion of various fluid studies.A description of the experimental equipment used for these analysis follows. All live fluid analyses are completed with a JEFRI Gasometer.This unit in conjunction with GC analysis(see below) provides the full fluid compositional analysis, GOR, density at sampling P&T corrected to standard conditions.The JEFRI gasometer consists of a motor-driven piston in a stationary cylinder.The piston displacement is monitored to determine the swept volume of the cylinder.The cylinder pressure is automatically held at ambient pressure.Piston motion is tracked by a linear encoder,which is subsequently,converted to measure the gas volume in the cylinder. The total Gasometer volume is 10 L.The evolved gas can be re-circulated through the system to facilitate equilibrium at a maximum flow rate of 40 L/hr.The operating pressure of the Gasometer is ambient pressure(up to a maximum of 40 psia)and the operating temperature ranging from room temperature to 40°C. Following the flash of the live fluid sample to ambient conditions in the gasometer,compositional analysis of residual hydrocarbon liquid and evolved gas phase is conducted using gas chromatography(GC). Analysis of hydrocarbon liquids is conducted using an HP6890 liquid injection gas chromatograph equipped with flame ionization detector(FID). In this system, separation of individual components is carried out in a 30m long, 530mm diameter "Megabore" capillary column made of fused silica with 2.6-micrometer thick methyl silicone as the stationary phase. The operating temperature range of the stationary phase is 60 to 400°C. Over this temperature range,the components eluted are from C1 to C36 along with naphthenes and aromatics components. Based on the physical properties,these components are retarded in a segregated fashion by the stationary phase during the flow of carrier gas(helium)through the column.With prior knowledge of the amount of "retention"for known compounds contained in calibration standards, the same compounds can be identified in the unknown hydrocarbon sample by matching"retention"times.The relative concentration of each component is determined by the concentration of ions hitting the FID upon the elution of each component. The analysis of hydrocarbon gases is carried out using an HP6890 gas injection GC equipped with two separation columns.The first column is a combination of a 100 mesh packed column and 100 mesh molecular sieve using high purity helium as a carrier gas.The molecular sieve is used to achieve separation of the light gaseous components (nitrogen,oxygen,and methane)while the packed column serves to separate ethane,propane,butanes,pentanes,and hexanes along with carbon dioxide and hydrogen sulfides. The second column is a packed column as described previously in liquid analysis.This column is capable of achieving separation of components up to Cep+,along with the associated naphthenes and aromatics that are lumped into the Cs,fraction during analysis and reporting.Components up to C4 are analyzed using a thermal conductivity detector(TCD)while the Cs,components are analyzed for using a FID detector. The instrument has programmable air actuated multiport valves that allow the flow of the sample mixture to be varied between the two columns,and hence,allowing for the correct separation and analysis of the injected gas. Fluid Volumetric(PVT)and Viscosity Equipment Oilphase-DBR 58 Job#:200600050 Client ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 The preliminary saturation pressure,constant composition expansion(CCE),differential vaporization(DV),multi-stage separation tests (MSST) are measured using a pressure-volume-temperature(PVT) apparatus. The PVT apparatus consists of a variable volume,visual JEFRI PVT cell.The main component of the cell consists of a Pyrex glass cylinder 15.2-cm long with an internal diameter of 3.2 cm.An especially designed floating piston and a magnetically coupled impeller mixer are mounted inside the Pyrex cylinder to allow for mercury-free operation.The bottom section of the piston is furnished with o-rings to isolate the hydraulic fluid from the cell content. The piston allows liquid level measurements as small as 0.005 cc.The magnetically coupled impeller mixer,mounted on the bottom end cap of the PVT cell,allow quick equilibration of the hydrocarbon fluid.The effective volume of the cell is approximately 120 cc. The Pyrex cylinder is housed inside a steel shell with vertical tempered glass plates to allow visual observation of the internal tube contents. A variable volume JEFRI displacement pump controls the volume, and hence, the pressure of the fluids under investigation by means of injection or withdrawal of transparent hydraulic fluid connected to the floating piston from the top of the JEFRI PVT cell. The same hydraulic fluid is also connected to the outer steel shell to maintain a balanced differential pressure on the Pyrex cylinder.The PVT cell is mounted on a special bracket,which can be rotated 360°.The bracket along with the PVT cell is housed inside a temperature controlled,forced air circulation oven.The cell temperature is measured with a platinum resistance thermal detector(RTD)and displayed on a digital indicator with an accuracy of 0.2°F. The cell pressure is monitored with a calibrated digital Heise pressure gauge precise to±0.1%of full scale.The temperature and pressure ratings of this PVT system are 15,000 psi(103 MPa)and 360°F 1182°CI. The fluid volume in the PVT cell is determined using a cathetometer readable to the nearest 0.01 mm. The cathetometer is equipped with a high-resolution video camera that minimizes parallax in readings and uses a high- resolution encoder producing both linear and volumetric readings.The height measurements by the cathetometer have been precisely calibrated with the total cell volume prior to the start of the test.The floating piston is designed in the shape of a truncated cone with gradually tapered sides,which allows measurement of extremely small volumes of liquid(0.005 cc)corresponding to roughly 0.01%of the cell volume. The viscosity of the live reservoir fluid is measured at the reservoir temperature and pressure conditions using Cambridge SPL440 electromagnetic viscometer,which consists of one cylindrical cell containing the fluid sample and a piston located inside the cylinder. The piston is moved back and forth through the fluid by imparting an electromagnetic force on the piston.Viscosity is measured by the motion of the piston,which is impeded by viscous flow around the annulus between the piston and the sample cylinder wall. Various sizes of pistons are used to measure the viscosity of various fluids having different levels of viscosity. The temperature is maintained at the experimental condition using a re-circulating fluid heating system. The internal temperature is monitored using an internal temperature probe.The temperature rating of the viscometer is 190°C and pressure rating is 15,000 psig.The accuracy is±1.5%of full scale for each individual piston range.The total volume of fluid sample required for viscosity measurement is 5 cc. A cylindrical piston cell(carrier chamber)with a maximum internal volume of 25 ml is attached at the top of the viscometer.The purpose of this cell is to allow the operator to conduct the differential vaporization pressure steps within the viscometer.The back and forth motion of the piston within a narrow clearance provides sufficient agitation to achieve phase equilibration and allow gases to escape and accumulate at the top of the carrier chamber. The heating jacket is wrapped around the viscometer and the carrier chamber and maintains experimental temperature uniformly throughout the system. Oilphase-DBR 59 Job#:200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job N: 200600050 The JEFRI PVT cell is also equipped with fiber optic light transmittance probes to measure the onsets of hydrocarbon solids nucleation(OHSP)due to changes in the temperature, pressure and/or composition.These fiber optic probes are mounted across the windows of the visual cell. The principle behind the measurement is based on the transmittance of a laser light in the near infra red(NIR)wavelength through the test fluid undergoing temperature, pressure or the fluid composition changes.In this system,a computerized pump is controlled to maintain the system pressure during isobaric temperature sweeps for wax nucleation,isothermal pressure drop and/or isobaric injections of precipitating solvents for asphaltene nucleation studies.The process variables(i.e.,temperature,pressure,solvent volume,time and transmitted light power level)are recorded and displayed from the detector.The fiber optic light transmittance system referred to here that detects the conditions of OHSP is termed as the light scattering system (LSS). High pressure filters are also used during the asphaltene nucleation study to quantify the amount of asphaltene in the fluid at the specified conditions.The filter manifold used is rated for 10,000 psia.The filter assembly consists of two plates screwed together with the hydrophobic filter sandwiched between them. Oilphase-DBR 60 Job*200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job#: 200600050 Appendix D:PROCEDURE Fluids Preparation and Validation After homogenizing, a small portion of the single-phase reservoir fluid is first subjected to a single stage flash experiment to determine flash Gas-Oil-ratio (GOR). The flashing is conducted from some pressure above the bubblepoint pressure at reservoir temperature into an atmospheric Gasometer and measuring the corresponding volumes of gas and liquid.The atmospheric flash also provides parameters such as GOR and stock tank oil density. The flashed fluids(gas and liquid)are then subjected to compositional analysis using gas chromatographic technique. Subsequently,live oil composition is calculated based on the measured gas and liquid compositions and GOR values. In addition, a sub-sample taken from each cylinder is isobarically transferred into the PVT cell at the reservoir temperature.Subsequently,a quick P-V relationship is established to determine the saturation pressure. Constant Composition Expansion Procedure A sub-sample of the test fluid is initially charged to the PVT apparatus and the system temperature stabilized at the reservoir temperature. The CCE experiment is then conducted by incrementally reducing the pressure from some pressure above the bubblepoint pressure to a pressure well below the bubblepoint pressure in a number of discrete steps.At each pressure step,the magnetic stirrer is used to make sure that the subject fluid achieved equilibrium. Total fluid volume(with visual observation of a single or two phase condition in the cell)is measured at each pressure stage,and subsequently,a pressure-volume(P-V)plot is created identifying the phase state at each P-V condition.The intersection of the two lines plotted using the pressure and volume data above and slightly below the observed phase change corresponded to the measured saturation pressure of the fluid. In this manner,the P-V plot confirms the saturation pressure observed visually in the PVT cell. The measured pressure and volume data are then used to compute live oil compressibility above the bubblepoint pressure and relative oil volumes over the entire pressure rang( Differential Vaporization Procedure Subsequent to the completion of the CCE experiment, another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A differential vaporization (DV) experiment is then conducted by incrementally reducing the pressure in the PVT cell in discrete steps.In these steps,the pressure is reduced below the saturation pressure,and hence,allowing the gas phase to evolve.A typical pressure stage in a DV test is described below: • The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the DV test. • The pressure of the fluid is then reduced to the first pressure stage(below the bubblepoint pressure)of the DV test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. • The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure(see Fluid Analysis Equipment Section) • The previous two steps are repeated until either an atmospheric pressure or a predetermined abandonment pressure is reached. Mu/ti=Stage Separation Test Oilphase-DBR 61 Job#.200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B&D Schlumberger Installation: - Job It 200600050 Subsequent to the completion of the DV experiment, another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A multi-stage separation experiment is then conducted by incrementally reducing the pressure and temperature conditions in the PVT cell in discrete steps. In these steps,the pressure is reduced below the saturation pressure,and hence,allowing the gas phase to evolve.A typical pressure stage in a separation test is described below: • The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the separation test. • The temperature of the PVT cell are then reduced to the first-stage separation test temperature and allowed the cell content to equilibrate.The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the separation test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. • The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure(see Fluid Analysis Equipment Section) The previous two steps are repeated in five stages to stock tank conditions. Liquid Phase Viscosity and Density Measurements During DV Step Prior to measuring the viscosity, a suitable size piston is selected with the proper viscosity range and the electromagnetic viscometer is calibrated using a fluid with known viscosity. A portion of the live reservoir fluid used in the DV test is then transferred into a high-pressure high-temperature electromagnetic viscometer.The viscometer is initially evacuated and kept at the same temperature as that of the PVT cell.During the transfer of approximately 15 cc of live hydrocarbon liquid to the evacuated viscometer,flashing of oil takes place,and hence,the viscometer system is flushed with live oil twice to make sure a representative live oil sample is taken. Subsequent to transfer of live reservoir fluid into the viscometer, the fluid system is allowed to achieve thermal and pressure equilibration. Then, the viscosity reading is taken. Following the viscosity reading, incremental pressure reduction steps are repeated as those used in DV steps.At each pressure point,the piston was allowed to run back and forth for sufficient time to achieve pressure equilibration and allow the liberated gas to migrate vertically upwards and accumulate at the top of the carrier chamber. Experiments are also conducted independently using a PVT cell for phase equilibration.The viscosity measurements done on liquid sample transferred from the PVT cell after equilibration compares very well with the measurements done on liquid sample subjected to pressure steps within the viscometer. Stock-Tank Oil(STD)Viscosity and Density Measurements A sample of STO is taken in a known capillary tube to measure the STO viscosity at a preset temperature. The temperature bath is maintained at the preset temperature. A small sample of the liquid is also transferred into the Anton Paar DMA45 densitometer to measure the density of the liquid phase.The viscosity and density measurements are repeated for data consistency check. Asphaltene, Wax and Sulfur Content Measurements Asphaltene content of stock-tank oil samples is conducted using the IP-143(French Institute of Petroleum)procedure. In this procedure,the asphaltenes are characterized as the n-heptane insoluble fractions of the crude oil.Wax content of the STO is measured using UOP(Universal Oil Product)46-64 procedure.The sulfur content of the STO is measured using ASTM D 2494 procedure..All other STO analysis were measured according to industrial standards. SAR(P)A Analysis Oilphase-DBR 62 Job#:200600050 Ai • a Client ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B&D Installation: - Job IF 200600050 A spinning band distillation was carried out on the original sample to establish two fractions.The initial boiling point to 300°C fraction was then analysed using a supercritical fluid chromatographic(ASTM 5186-91)method to determine the saturates and aromatics content. The greater than 300°C fraction first subjected to a gravimetric analysis to determine the pentane insoluble content(asphaltenes).This method dissolves the fraction in an equal weight of toluene,then 40 volumes of pentane were added to precipitate the insoluble portion of the sample.The precipitate was filtered,dried and weighed.The solvent was removed from the soluble portion of the sample,which was referred to as the maltenes. The maltenes were then redissolved in pentane and were chromatographically separated into saturates,aromatics and resins(polars)fraction by elution from a column filled with activated alumina,using various solvents and solvent mixtures. The solvents were then removed from each fraction and the amount of material The data from the three methods were combined to determine the amount of each component type in the original sample.Mass balances were calculated throughout the procedure to assure accurate data. High-Temperature High Pressure Filtration Test During the filtration process,it is important that the monophasic fluid remains monophasic as it passes through the filter manifold. Hence, high pressure nitrogen is used on the back side of the filter so that the equal pressure is maintained on both sides of the filter. This procedure prevents any flashing of the fluid in the filter manifold and assures filtration of a representative fluid. Oilphase-DBR 63 Job#:200600050 ~ i ~,~~( DATA SUBMITTAL COMPLIANCE REPORT 5/20/2008 Permit to Drill 2052090 Well Name/No. KUPARUK RIV UNIT 1H-NORTH Operator CONOCOPHILLIPS ALASKA INC API No. 50-029-23294-00-00 MD 4630 TVD 4459 Completion Date 3/11/2006 REQUIRED INFORMATION Mud Log Yes DATA INFORMATION Types Electric or Other Logs Run: GR/Res/Dens/Neutron, Dipole Sonic Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name Log Log Run Interval OH / Scale Media No Start Stop CH Received Comments ;fig i// ~l-09 ~o " pt Wrd ~~, ED C Wrd Il~ ",,E,,~CD C Pdf ~V9 ED C Pdf t~9 i ED C Pdf (~og ED C Pdf I ~ ogg Induction/Resistivity 5 Col Neutron 5 Col Neutron 2 Col Induction/Resistivity 2 Col 13946 Report: Final Well R 13946 Report: Final Well R ~ A~ C9 ~tk~~ ~~~ 13946 Mud Log +1~~.~o....v.aw~, ,~1. IP1~too$ Col 13946 Mud Log "'"~" Col 13946 Mud Log Col 13946 Mud Log Col 13946 Mud Log Col 13946 Mud Log Col 13946 Mud Log Col 13946 Mud Log Col 13946 Mud log Col 1-2 rn A 220 4630 Open 6/8!2006 DGR CTN ALD 28-Feb- 2006 1-2 M ~ 220 4630 Open 6/8/2006 ROP, DGR, EWR 28-Feb- 2006 1-2 TV/) 220 4458 Open 6/8/2006 ROP, DGR, EWR 28-Feb- 2006 1-2 )`~D 220 4458 Open 6/8/2006 DGR EWR 28-Feb-2006 0 0 Open 6/9!2006 Final Report 06-Mar-2006 0 0 Open 6/9/2006 Final Report 06-Mar-2006 110 4630 Open 6/9/2006 Formation Log, MD 28-Feb- 2006 110 4630 Open 6/9/2006 Formation Log, MD 28-Feb- 2006 110 4459 Open 6/9/2006 Formation Log, TVD 28- Feb-2006 110 4459 Open 6/9/2006 Formation Log, TVD 28- Feb-2006 110 4630 Open 6/9/2006 Drilling Dynamics, MD 28- Feb-2006 110 4630 Open 6/9/2006 Drilling Dynamics, MD 28- Feb-2006 110 4459 Open 6/9/2006 Drilling Dynamics, TVD 28- Feb-2006 110 4459 Open 6/9/2006 Drilling Dynamics, TVD 28- Feb-2006 110 4630 Open 6/9/2006 Combo Log, MD 28-Feb- 2006 DATA SUBMITTAL COMPLIANCE REPORT si2oizoos Permit to Drilt 2052090 Well Name/No. KUPARUK RIV UNIT 1H-NORTH Operator CONOCOPHILLIPS ALASKA INC API No. 50-029-23294-00-00 MD 4630 TVD 4459 Completion Date 3/11/2006 Completion Status P&A Current Status P&A UIC N ED C Pdf 13946 Mud Log Col 110 4630 Open 6/9/2006 Combo Log, MD 28-Feb- 2006 13946 Mud Log Col 110 4459 Open 6/9/2006 Combo Logs, TVD 28-Feb- 2006 ', ED C Pdf 13946 Mud Log Col 110 4459 Open 6/9/2006 Combo Logs, TVD 28-Feb- 2006 ', Lo 13946 Mud Log Col 110 4630 Open 6!9/2006 Gas Ratio, MD 28-Feb- 2006 ED C Pdf 13946 Mud Log Col 110 4630 Open 6/9/2006 Gas Ratio, MD 28-Feb- 2006 t1.6g 13946 Mud Log Col 110 4459 Open 6/9/2006 Gas Ratio, TVD 28-Feb- 2006 ED C Pdf 13946 Mud Log Col 110 4459 Open 6/9/2006 Gas Ratio, TVD 28-Feb- 2006 i ~g C Pds 13949 ration Micro Ima 5 Blu 1 2767 4630 Open 6/14/2006 FMI-DSI-GR 6-Mar-2006 C Pds 13950 Formation Micro Ima 2 Blu 1 2767 4630 Open 6/14/2006 P&S and Dipoles 6-Mar- (/ 2006 1.~9 C Pdf 13950 Sonic Col 0 0 Open 6/14/2006 Best DT* Final Result Dipole Sonic Processing 6- Mar-2006 C Pdf 13950 Sample 5 Blu 3 3450 4352 Open 6/14/2006 CST-U, CST-V, GR 6-Mar- t.L6g C Pdf 13950 Formation AAis- eime~ ~cy~'c f Coi 2 3502 4322 Open 6/14/2006 2006 MDT-GR 6-Mar-2006 ~~ C Pdf 13950 / See Notes/ 0 0 Case 6/14/2006 Field MDT DLIS/PDS, j Field CST PDS, Final LDWG Tif and PDS Files 6• Mar-2006 C Pds 13949 VSee Notes 0 0 Case 6/14/2006 Processed DSI DLIS, LAS ', and PDS Files 3-Mar-2006 LED C Lis 14116 ~~ `~~'~~° J., ~ ~~! +~.~. ~ 115 4630 Open 8/30/2006 Lis Veri (Sent back) w/Graphics t,.ED C Pdf /14116 Induction/Resistivity 220 4630 Open 8/30/2006 MD-ROP, DGR, EWR phase 4 6-Mar-2006 ~D C Pdf -14116 Induction/Resistivity 220 4630 Open 8/30/2006 TVD-ROP, DGR, EWR phase 4 6-Mar-2006 QED C Pdf ~ 14116 Neutron 220 4630 Open 8/30/2006 MD-DGR, CTN, ALD 6-Mar 2006 L:i ED C Pdf 14116 ~d'eutron 220 4630 Open 8/30/2006 TVD-DGR, CTN, ALD 6- Mar-2006 s DATA SUBMITTAL COMPLIANCE REPORT 5/2012008 Permit to Drill 2052090 Well Name/No. KUPARUK RIV UNIT 1H-NORTH Operator CONOCOPHILLIPS ALASKA INC API No. 50-029-23294-00-00 MD 4630 TVD 4459 Completion Date 3/11/2006 Completion Status P&A Current Status P&A UIC N pt 14345 See Notes 0 0 Case 1/22/2007 Fiuid Anal of MDT Sample, Black Oil Full PVT Study Report ~ 'kD C Pdf 345 See Notes 0 0 Case 1/22/2007 Fluid Anal of MDT Sample, Black Oil Full PVT Study Report Well Cores/Samples Information: Name Interval Start Stop ADDITIONAL INFORMATION Well Cored? Y /~ Chips Received? Yy-ht- Analysis JL1-Pt Received? Comments: Compliance Reviewed By: Sample Set Sent Received Number Comments - -- - -- - _ --_ --- --- -- --- __.. _--- __--- - _ _ --- --- - _----- -- I Cores and/or Samples are required to be submitted. This record automatically created from Permit to Drill Module on: 1/3/2006. i Daily History Received? ~ N Formation Tops ~ N Date: d~ 01 /11 /08 >I?~r~~~~Ll~s~~~~' NO. 4547 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503-2838 Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay, Milne Pt. Woll _Inh it 1 nn rlascrintinn rata RI Cnlnr Cr) Z-06 11594523 STATIC TEMP LOG ~ - 09/09/07 1 14-18B 11975743 SBHP SURVEY - 12108107 1 14-02C 11767144 SBHP LOG - 11/02/07 1 H-24A 11963073 MEM CBL -~ 11/30/07 1 C-35A 11624351 CEMENT BOND & GRAVEL PACK ^a 11/03107 1 MPH-19 11982423 USIT - (p ~ 12/10/07 1 1 E-03A 11628773 MEM PROD PROFILE -- 05/09/07 1 E-116 11434760 OH LDWG EDIT (DSI) - L to 10/29/06 1 1 G-06A 11209587 MCNL - ~~ L' 02125/06 1 1 D-07B 11162822 MCNL - f ~ 12/04/05 1 1 G-10C 11209607 MCNL Q(p- a 06115/06 1 1 G-09B 11649989 MCNL ~ ~- ~ j j b'~~ 09/11/07 1 1 K-086 11745243 MCNL q '~) ~ 11/06/07 1 1 V-07 11978425 COMPOSITE CBL 12106107 1 V-07 11978425 USIT 12/06107 1 L2-33 11970801 RST j ' V ~ 07107/07 1 1 03-14A 40013340 OH MWD/LWD EDIT ~ ( 04123/06 2 1 ~~ PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE DOPY EAGtt TO: BP Exploration (Alaska) Inc. _, ,,, Petrotechnical Data Center LR2-1 i 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: - `= `~ '_ - Alaska Data & Consulting Services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth j Received by: ~`~-''" ,°,. '~t~N'1O~iCJ~~ 1 ~ ~ 1 TRANSMITTAL CONFIDENTIAL DATA FROM: Sandra D. Lemke, AT01486 TO: Christine Mahnken ConocoPhillips Alaska, Inc. AOGCC P.O. fox 100360 333 W. 7`h avenue, Suite 100 Anchorage AK 99510-0360 Anchorage, Alaska 99501 RE: North East West Sak (NEWS) wells -PVT and API gravity oil analysis summaries DATE: 1 /17/2007 Hand del West Sak 3J-101 LO/NS 084-130 CD &Hardcopy report ,02 b S ~ (~ 5 ~ ~ /mil 3 ~/3 ySchlumberger-Analysis of MDT Fluid Samples -Black Oil PVT Study Report; report 200500215; 8/25/2006; Disk(contains all 5 wells) and &Hardcopy report V Kuparuk Labs Report of Analysis; DS 3J-1011 Produced oil ;report and spreadsheet West Sak 1Q-101 LO/NS 083-135 CD &Hardcopy report ~o~ - (~ /Schlumberger-Analysis of MDT Fluid Samples -Black Oil PVT Study Report; report 200500199; 3/29/2006; ~tsk(contains all 5 wells) and &Hardcopy report ~! Kuparuk Labs Report of Analysis; DS 1 Q-101 Produced oil ;report and spreadsheet West Sak 1 R-East LO/NS 05-026 CD &Hardcopy report 2 b ~ _ 00 / ~ ~- / L~ 3 c~~ / Schlumberger-Analysis of MDT Fluid Samples -Black Oil PVT Study Report; report 200600071; 5/23/2006; ~ Disk(contains all 5 wells) and &Hardcopy report Kuparuk Labs Report of Analysis; DS 1 R-East Produced oil ;report and spreadsheet West Sak 1 H-South LO/NS 05-026 CD &Hardcopy report .a p5-_ a f a ~ /'~3~b Schlumberger-Analysis of MDT Fluid Samples -Black Oil PVT Study Report; report 200600089 6/30/2006; Disk(contains all 5 wells) and &Hardcopy report ~uparuk Labs Report of Analysis; DS 1 H-South Produced oil ;report and spreadsheet West Sak 1 H-North LO/NS 05-026 r ,BCD &Hardcopy report ~ b S _ ~c~ ~ jC.(3(~5 I/ Schlumberger-Analysis of MDT Fluid Samples -Black Oil PVT Study Report; report 200600050; 6/20/12006; T ~,Uisk(conta/ns all 5 wells) and &Hardcopy report _ Kuparuk Labs Report of Analysis; DS 1Q-101 Produced oil ;report and spreadsheet Please check off each item as received, promptly sign and return the transmittal to address below. To all o'ata recipients: All data is confidential ~~ntil .~~1~-ate release o'ate CC: Andy /~ndr~u, PAI Geologist 4)~~ ~ ~ 7~1n.~ Receipt: (/~. o Date: die T- GIS-Technical Data Management I ConocoPhillips ~ Anchorage, Alaska I Ph: 907.Z65.b947 Sandra. D. LemkeCa~Conocophillips. com ,~ C I~uparuk Laboratory Report of Analysis Report Date: 3/12/06 ~~C~,v L.~~ To: M. Werner ~AN 2 ~ Z~~ ~ pil & Gas Cons• GOmmission AtIG Lab ID AB09665 AB09666 Sam le Descri tion E loration Sam les E loration Sam les WellNum 0 0 Date 03/09/06 03/09/06 Time 07:30 08:43 LocDescri for 1H-North/4068' MD 1H-North/4154' MD Anal sis Unit Result Result API at 60 degrees F DRY Degrees API 20.4 17.2 If there are any questions regarding this data, please call KLS at 659-7214. Completed By: TJV Reviewed By: MTG ~s aoq ~ ~<<3~rs' .~ • 1 H-North • Sample_ID We11 Sand Depth Type API GCMS-Global Curv GC-Global Cruve Comment US137495 1H-NORTH UgnuC 3452.8 SWC 8.6 11.5 US137493 1H-NORTH UgnuC 3466 SWC 7.5 8.7 US137492 1H-NORTH UgnuC 3502.9 SWC 11.3 9.9 US137491 1H-NORTH UgnuC 3505.9 SWC 8.1 10.0 US137490 1H-NORTH UgnuC 3507.9 SWC 9.2 10.9 US137488 iH-NORTH UgnuC 3551.4 SWC 9.2 7.4 US137487 1H-NORTH UgnuC 3554.8 SWC 9.0 8.8 Average IH NORTH UgnuC SWC n.a. 9.0 n.a. 9.6 n.a. US137485 1H-NORTH UgnuB 3676.9 SWC 11.4 9.0 US137484 1H-NORTH UgnuB 3681.7 SWC 10.4 8.8 US137483 1H-NORTH UgnuB 3686.9 SWC 11.0 9.6 US137481 1H-NORTH UgnuB 3709.8 SWC 11.2 10.1 US137479 1H-NORTH UgnuB 3719.9 SWC 10.9 9.3 US137477 1H-NORTH UgnuB 3734.8 SWC 10.9 8.7 Average 1H-NORTE IignuB SWC n.a. 10.7 n.a. 9.3 n.a. US137476 1H-North N 3903.4 SWC 14.3 14.1 US137475 1H-North N 3910.5 SWC 13.9 13.9 US137474 iH-North N 3914.9 SWC 13.9 13.9 US137473 1H-North N 3917.9 SWC 13.2 13.8 US137472 1H-North N 3923 SWC 13.3 13.5 US137471 1H-North N 3954.8 SWC 14.1 12.2 Average 1H-North. N SWC x.a. 13.8 x.a. 13.6. x.a. US137470 1H-North D 4053.9 SWC 20.9 19.1 US137469 1H-North D 4056.1 SWC 20.8 18.9 USi37468 1H-North D 4058 SWC 21 18.9 U5137467 iH-North D 4064.9 SWC 21.1 19.0 US137466 1H-North D 4066.6 SWC 21.9 19.0 US137465 1H-North D 4069 SWC 21.8 19.2 US137464 1H-North D 4093.7 SWC 21.5 18.8 Average IH-North D 5WC 20.4 21.3 0.9 19.D 1.4 US137463 1H-North B 4132.8 SWC 17.7 15.8 US137462 iH-North B 4140.9 SWC 18.2 15.7 US137461 1H-North B 4144.9 SWC 17.8 15.8 US137460 1H-North B 4146.8 SWC 17.8 15.9 US137459 1H-North B 4150.9 SWC 20.8 15.8 US137457 iH-North B 4152.1 SWC 16.6 15.8 Average 1H-North B SWC 17.2 18.2. 1.0 25.8 1.4 US137456 1H-North A3 4248.1 SWC 18.4 16.7 Average IIi-North A3 SWC x.a. 18.4 x.a. ISJ x.a. US137455 1H-North A2 4316.1 SWC 15.6 16.0 US137454 iH-North A2 4318.1 SWC 14.6 16.1 US137453 1H-North A2 4322 SWC 14.4 16.0 Average IH-North A2 SWC x.a. 14.9 x.a. 16.0 a.a. • WELL LOG TRANSMITTAL • To: State of Alaska August 29, 2006 Alaska Oil and Gas Conservation Comm. Attn: Christine Mahnken 333 West 7th Avenue, Suite 100. Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs 1H-North, AK-MW-4229289 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rob Kalish, Sperry Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 1H-North: LIS Data & Digital Log Images 50-029-23294-00 Note: New CD rom of LIS and Log data as per your request. 1 CD Rom ~~~ -~~i ~ 1 Ll l Flo WELL LOG TRANSMITTAL • To: State of Alaska June 22, 2006 Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7~' Avenue, Suite 100 Anchorage, Alaska RE: MWD Formation Evaluation Logs 1H-North, AK-MW-4229280 1 LDWG formatted Disc with verification listing. API#: 50-029-23294-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry Drilling Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 Date: Signed: Note: This data replaces any previous data for well 1H-North. 09 ~ ~~3~tis~~ cos -a TO Beth @ Schlumberger We also receive these Well Logs and no transmittal to accompany them API 50-029-23294-00 Kuparuk/West Sak Permit # 205-209 MDT-GR FMI-DSI-GR P&S and Dipole CST-U, CST-V, GR Best DT, Final Result and 2 CD's to accompany them with the logs on them Date 6-Mar-2006 API 50-029-22183-01 Point Mclntrye P2-57A Permit # 204-214 RST Sigma, PBMS-A, RST-C Date 29-Apr-2004 REC~~v~O • ~ ~~ ~& pr- y~ ConoCO~'h~rllipS TRANSMITTAL CONF/DENT/AL DATA FROM: Sandra D. Lemke, AT01486 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: 1 H-NORTH DATE: 6/05/2006 ~VC~ JLI~ 0 `~ 2006 TO: Librarian pil ~ Corrs. Commission AOGCC 333 W. 7`h Ave., Suite 100 Anchorage, Alaska 99501 na a West Sak 1 H-North 501032329400 Report and CDROM Epoch- Final Well Report Mudlogging Data; Brian O'Fallon 3/06/2006; includes color prints of Formation log 110- MD &TVD 2"=100'; Drilling Dynamics MD &TVD; Combo Log MD &TVD; Gas Ration log MD &TVD; CDROM ns DML Database, final well reports, morning reports, LAS files, LOG PDF image and lithology remarks files. (Please check off each item as received, promptly sign and return the transmittal to address below. To all data recipients.' All data is confidential until State of Alaska desi Hated AOGCC release date CC: Andy Andreo CAI Geologist /v Receipt: Dater °~~~ x~-~~~~ GIS-Technical Data Management ~ ConocoPhillips ~ Anchorage, Alaska (Ph: 907.265.6997 Sandra. D. L emke~Conocophillips. com ao5 _~a~ ~ r3'~~~ • • WELL LOG TRANSMITTAL To: State of Alaska May 30, 2006 Alaska Oil and Gas Conservation Comm. Attn.: Ceresa Tolley 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs 1 H-North, AK-MW-4229289 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rob Kalish, Spent' Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 1 H-North: Digital Log Images 50-029-23294-00 ~~~ J~.lN U ~ 1006 X011 ~~~G°"s'C'`Nncri-s51~'Ct Pane e E~-_ 1 CD Rom X05 -~C7~ • ConocoPhillips May 5, 2006 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 • Randy Thomas Kuparuk Drilling Team Leader Drilling & Wells P. O. Box 100360 o,~~e~,,AK 99510-0360 Subject: Well Completion Report for 1 H-North (APD 205-209 / 306-079) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Well Completion Report for the recent drilling operations of the Kuparuk well 1 H-North. If you have any questions regarding this matter, please contact me at 265-6830 or Tom Brassfield at 265-6237. Sincerely, l ~~-~~°- --~ R. Thomas Kuparuk Drilling Team Leader CPAI Drilling RT/skad • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT . . . _ ,;~8~91 AND LOG 1a. Well Status: Oil ^ Gas Plugged Abandoned ~ Suspended WAG ^ 20AAC 25.105 20AAC 25.110 GINJ ^ WINJ ^ WDSPL ^ No. ofCompletions_ Other_ 1b. Well Class: Development ^ Exploratory Service ^ StratigraphicTest^ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Date Comp., Susp., i orAband.: March 11, 2006 12. Permit to Drill Number: 205-209 / 306-079 3. Address: P. O. Box 100360, Anchorage, AK 99510-0360 6. Date Spudded: February 28, 2006 ~ 13. API Number: 50-029-23294-00 ' 4a. Location of Well (Governmental Section): Surface: 2276' FNL, 946' FEL, Sec. 15, T12N, R10E, UM 7. Date TD Reached: March 6, 2006 ~ 14. Well Name and Number: 1 H North At Top Productive Horizon: 1517' FNL, 449' FEL, Sec. 15, T12N, R10E, UM 8. KB Elevation (tt): 30' RKB 15. Field/Pool(s): Kuparuk River Field Total Depth: 1362' FNL, 348' FEL, Sec. 15, T12N, R10E, UM 9. Plug Back Depth (MD + TVD): surface West Sak Oil Pool -Exploratory - 4b. Location of Well (State Base Plane Coordinates): Surface: x- 554555 - y- 5994301 Zone- 4 10. Total Depth (MD + TVD): 4630' MD / 4459' TVD ~ 16. Property Designation: ADL 25636 TPI: x- 555046 y- 5995063 Zone- 4 Total Depth: x- 555145 - - 5995219 ~ Zone- 4 11. Depth where SSSV set: none 17. Land Use Permit: LE931811 18. Directional Survey: Yes Q No ^ 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: 1822' MD 21. Logs Run: GR/Res/Dens/Neutron, Dipole Sonic 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE CEMENTING RECORD PULLED 16" 63# B 30' 110' 30' 110' 24" 176 sx AS1 9.625" 40# L-80 30' 2767' 30' 2699' 12.25" 457 sx ASLite, 172 sx DeepCRETE cement plug #1 from 3925'-4630' cement plug #2 from 3115'-3925' cement retainer @ 2711' 23. Pertorations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET none none none 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 3925'-4630' 61 bbls Class G 3115'-3925' 61 bbls Class G surface to 300' 36 bbls AS Ito surface 2661'-2881' cement retainer 18 bbls Class G 26. PRODUCTION TEST Date First Production not applicable Method of Operation (Flowing, gas lift, etc.) P&A'd Date of Test Hours Tested Production for Test Period --> OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO Flow Tubing press. Casing Pressure Calculated 24-Hour Rate -> OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY -API (Corr) 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". .- -- - --~ ' ', ?~d e ' ~r~~~a S~IIS SF~, MAY ~ 5 2006 no rock description available for the side wall core because it is ~ ~ being preserved as oil geochemistry samples. i ~ Form 10-407 Revised 12/2003 ORIGINAL CONTINUED ON REVERSE S•~2•oG ors/~~ t/rood ~ 2s. 2s. GEOLOGIC MARKERS FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". 1H-North Top West Sak Sand 4054' 3913' Base West Sak Sand 4501' 4336' N/A 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, P&A Summary, P&A photos 31. I hereby certiry that the foregoing is true and correct to the best of my knowledge. Contact: Tom Brassfield @ 265-6237 Printed Na~~, ~ R. Thomas Title: GKA Drillino Team Leader ( ~ / ~ 6 5 Signature \ '~-`~'-~ Phone Date ~ ` .i 6 xf 5 c7 Z.CG INSTRUCTIONS Prepared by Sharon Allsup-Drake 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 1a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, salt water disposal, water supply for injection, observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 ConocoPhillips Alaska Page 1 of 5 Operations Summary Report Legal Well Name: 1 H-North Common Well Name: 1 H-North Spud Date: 2/28/2006 Event Name: ROT -DRILLING Start: 2/26/2006 End: 3/11/2006 Contractor Name: n1433@conocophillips.com Rig Release: 3/11/2006 Group: Rig Name: Nordic 3 Rig Number: 3 Date From - To Hours ', Code ;Code Lase ' Description of Operations 2/25/2006 12:00 - 14:30 14:30 - 15:00 15:00 - 16:30 16:30 - 00:00 2/26/2006 00:00 - 07:00 ' 07:00 - 08:00 08:00 - 09:00 09:00 - 15:00 15:00 - 19:00 19:00 - 00:00 2/27/2006 00:00 - 03:00 03:00 - 07:00 07:00 - 08:00 ~ 08:00 - 09:00 09:00 - 10:45 10:45 - 11:15 1,11:15 - 13:00 13:00 - 13:45 1,13:45 - 22:00 22:00 - 00:00 2/28/2006 100:00 - 03:00 2.50 !MOVE DMOB 0.50' MOVE MOVE 1.50! MOVE DMOB 7.50': MOVE MOVE 7.00; MOVE (MOVE 1.00'; MOVE OTHR 1.00; MOVE POSN 6.00', MOVE RURD 4.00; WELCTL NUND 5.00 ~ DRILL OTHR 3.00; DRILL OTHR 4.00'; DRILL PULD 1.00', WELCTL OTHR 1.00'j DRILL PULD 1.75; DRILL OTHR 0.501 WELCT BOPE 1.75 0.75 8.25 2.00 '~, MOVE !Prepared rig for Move MOVE ',Moved rig off 2T-203 ~', MOVE 'Secured diverter and BOP stack in the cellar and finished prep for move MOVE ~ Began moving rig 20.7 miles from 2T-203 to 1 H-North location, have moved approx. 10 miles at 2400 hrs. MOVE 'Fin moving rig from 2T pad to Location, moved rig final 10.7 of the total 20.7 miles !, MOVE 'Preparing to spot rig over well, cleaned off matting boards, prepared to move rig camp from 2T MOVE ';Moved rig over well and leveled same, began moving rig camp from 2T 'pad ', MOVE ' Bermed around rig and insulated cellar, rigged up and camp arrived 'I ',location at 14:00 hrs and set up same. String out & secure Geronimo ' 'line. Put away tools & equipment from rig move. ', RIGUP ;Accept Rig @ 1500 hrs. NU 21 1/4" 2M Diverter, 16" diverter line, '~I ',flowline and bell nipple, spotted service company shacks and hooked ', up same, bermed around camp and cuttings box's for centrifuge and ~I Ishakertank. Install 5-1/2" liners in mud pumps. RIGUP ~ Loaded pipe shed with 5" DP ~ Sperry BHA, strap same. Change out ~ ,grabber dies & saver sub on top drive. ~~~ RIGUP 'Fin. loading pipe shed with 72 jts (24 stds) 5" DP and Sperry Suns tools and strapping same, RU DP spinners and 5" handling tools RIGUP PU, torqued up and stood back 19 stds of 5" DP I, RIGUP Function tested diverter from main koomey unit and tested gas detectors. RIGUP ,Fin PU, torquing up and standing back 5" DP, 24 stds total RIGUP Loaded pipe shed with 20 jts of 5" HWDP and jars, strapped same ',RIGUP Function tested diverter and knife valve from rig floor remote panel and j performed accumulator drill, initial Koomey pressure 2,800 psi, 1,550 psi after functioning diverter, achieved 200 psi recovery after 20 'seconds and full recovery after2 min 20 sec., 4-nitrogen bottles ave ' ;1,900 psi, NOTE:John Crisp with AOGCC witnessed test. DRILL PULD !RIGUP I PU, torqued up and stood back 7 stds of 5" HWDP and jars DRILL SFTY RIGUP j Held pre-spud mtg at camp with rig crew, service co. personnel and drlg eng. DRILL OTHR !RIGUP ~~ Loaded 73 jts of 9 5/8" 40#, L-80, BTC csg into pipe shed, removed DRILL 3.001 DRILL ICI thread protectors, and strapped casing. OTHR SURFAC ~ Hold PJSM. PU & MU 12-1/4" bit, Sperry Mud Motor, float sub, stabilizer, & XO. RIH on stand of HWDP, tag bottom at 90'. Fill ~~ conductor with water and circulate while crew did walk grounds to verify ~, no leaks in system. Clean out conductor from 90' to shoe at 110'. ~~ Prepare to swap over to spud mud. DRLG SURFAC 'Drill out shoe at 110'. Swap over to spud mud while drilling and drill to i 219. 2.06 ART/ADT, 5K-10K WOB, 50 RPM Rot+74 RPM Motor, 168 Ii SPM, 500 GPM, 350 psi-570 psi, 32K PU, 32K SO, 32K Rot. 03:00 - 03:30 0.50'', DRILL I CIRC ,;SURFAC 1 Circulate hole clean. 03:30 - 04:00 0.50 ~!, DRILL TRIP :SURFAC '', POH to 11-1/2" Stabilizer above Mud Motor. 04:00 - 07:30 3.501 DRILL PULD '.SURFAC ''i PU MWD tools. Upload MWD. PU 8" NM Flex Drill Collars. RIH on 1st 07:30 - 00:00 16.501 DRILL '~, stand HWDP to bottom. DRLG 'i SURFAC I Continue drilling 12-1/4" hole from 219' to 1141'MD (1140' TVD) per ~~ ~ directional plan. 7.28 ART, 6.17 AST, 13.45 ADT. 5K-20K WOB, '; 700-2100 ft-Ib Torque on btm, 100-400 ft-Ib Torque off btm, 70K PU, I, '~, ~ 70K SO, 70K Rot. Wt., 170 SPM, 507 GPM, 1200 psi. Printed: 5/4/2006 3:44:24 PM ConocoPhillips Alaska Operations Summary Report Legal Well Name: 1 H-North Common Well Name: 1H-North Event Name: ROT -DRILLING Start: 2/26/2006 Contractor Name: n1433@conocophillips.com Rig Release: 3/11/2006 Rig Name: Nordic 3 Rig Number: 3 Date 3/1 /2006 From - To Hours ' Code Sub _ _ Code 00:00 - 14:00 14.001 DRILL DRLG 14:00 - 15:00 15:00 - 17:00 17:00 - 17:30 '' 117:30 - 18:30 I~ :18:30 - 00:00 3/2/2006 ', 00:00 - 04:30 I i i 04:30 - 05:00 05:00 - 05:30 05:30 - 06:30 06:30 - 07:00 07:00 - 08:00 08:00 - 08:30 08:30 - 10:00 10:00 - 10:30 1,10:30-13:30' '113:30 - 16:00 !, ;16:00-18:30' 18:30 - 21:00 21:00 - 21:30 ', 21:30 - 23:30 3/3/2006 23:30 - 00:00 00:00 - 03:30 03:30 - 04:00 04:00 - 05:00 1.00 2.00 0.50 1.00 5.50 DRILL ',CIRC Page 2 of 5 Spud Date: 2/28/2006 End: 3/11 /2006 Group: Phase ', Description of Operations SURFAC ~ Continue drilling 12-1/4" surface hole from 1141' to 2031' MD (1995' TVD). 15K-25K WOB, 50 RPM Rot + 76 RPM Motor, 1550 psi, 170 SPM, 506 GPM, 2250 ft-Ib Torque on btm, 1600 ft-Ib Torque off btm. 16.17 hr ART, 4.63 hr AST, 10.80 hr ADT. SURFAC Pump weighted hi-vis sweep & circulate around to clean hole. Blow down top drive. DRILL 'WIPR !~ SURFAC POOH on elevators for wiper trip to 70', inside conductor shoe. RIGMNT'; RSRV ;SURFAC Service top drive. Clean rig floor. DRILL 'WIPR 'SURFAC RIH to bottom at 2031' MD. DRILL !.DRLG ;SURFAC Drill surface hole to 2409' MD (2355' TVD) & drilling ahead. 15K-20K 4.50'1 DRILL ' i DRLG 0.50' DRILL CIRC 0.50" DRILL DRLG 1.00 DRILL I CIRC 0.50'i DRILL OBSV 1.00 ~~, DRILL WIPR 0.501 DRILL WIPR 1.501 DRILL CIRC 0.50 3.00 2.50 2.50 2.50 DRILL I SURV DRILL DRILL CASE CASE 0.50 j CASE 2.00' CASE 0.50:` CASE 3.50 CASE 0.50', CASE 1.00', CASE 05:00 - 07:30 ' 2.50 WOB, 50 RPM Rot + 76 RPM Motor, 1500 psi, 170 SPM, 506 GPM, 2600 ft-Ib Torque on btm, 2000 ft-Ib Torque off btm, 3.61 hr ART, 2.01 hr AST, 5.63 hr ADT. SURFAC Drilf 12-1/4" surface hole from 2409' MD to 2740' MD (2673' TVD). 15K-20K WOB, 50 RPM Rot. + 76 RPM Motor, 1520 psi, 172 SPM, 510 I, GPM, 3300 Tq on btm, 2250 Tq off btm. 3.36 hr ART, 0 hr AST, 3.36 ~, hr ADT, 103K PU, 93K SO, 97K Rot. Wt. SURFAC 11 Circulate bottoms up for cuttings samples. SURFAC ',Drill from 2740' to 2780' MD (2711' TVD). 0.43 hr ART, 0 hr AST, 0.43 hr ADT, 103K PU, 93K SO, 97K Rot Wt. SURFAC 'Circulate to condition mud & hole. Catch cuttings samples to verify TD 8~ Shoe in "shale". SURFAC ;Blow down top drive. Monitor well for flow check, OK. SURFAC '~ POOH to 2031' for wiper trip. SURFAC i RIH to bottom at 2780'. SURFAC ~I Break circulation. Pump weighted hi-vis sweep and circulate around to clean hole. 170 SPM, 506 GPM, 1350 psi. SURFAC Blow down top drive. Drop Sperry ESS survey tool and let fall to bottom. -:TRIP !.SURFAC POOH to Non-Mag Flex DC. PULD ;SURFAC LD BHA. Download MWD. RURD SURFAC Clean rig floor. RU GBR to run 9-5/8" surface casing. RUNC i SURFAC I PU & MU float joints. Break circulation & check floats OK. Run 9-5l8" CIRC RUNC CIRC CIRC RURD CIRC PUMP X140#, L-80, BTC Surface Casing to 1500'. SURFAC ~I, Break circulation & circulate casing volume, 3 BPM, 300 psi. SURFAC ',Continue running 9-5/8" surface casing. MU FMC Gen V casing hanger & landing joint. Ran 66 joints of casing. RD Frank's fill up tool. MU 'swedge & lines to LJ. Land casing, shoe at 2767 MD. SURFAC ',Break circulation, work casing, stage rate up to 85 SPM, 6 BPM, 200 'psi. Circulate to condition mud & hole for cementing casing. SURFAC ;Continue circulate & condition mud and hole for cementing, 'reciprocating pipe. 7 BPM, 300 psi. 122K# PU, 100K# SO Wt. SURFAC ;Land hanger. Break out circulating head. Load plugs & make up ,cementing head and lines. SURFAC ', Resume circulating & conditioning mud, reciprocating pipe. 7 BPM, 300 psi. 9.6 ppg, 55 Vis in. 9.6 ppg 57 Vis out. Circulated 1750 Bbls I total. Held PJSM with crew, Dowell, ASRC truck foreman, Mud i Engineer. Stop circulating. Swap lines over to Dowell. SURFAC I Cement 9-5/8" surface casing. Dowell pump 10 Bbls CW 100, Test li lines to 3500 psi, pump 40 Bbls more CW 100, 4 BPM, 175 psi. Mix & pump 39 Bbls 10.5 ppg Mud Push with red dye, 4 BPM, 125 psi. Drop bottom plug. Mix & pump 350 Bbls 10.7 ppg Arctic Set Lite lead cement, 7 BPM, 130 psi to 250 psi. Mix & pump 69 Bbls 12.0 ppg Printed: 5/4/2006 3:44:24 PM ConocoPhillips Alaska Operations Summary Report Page 3 of 5 Legal Well Name: 1 H-North Common Well Name: 1 H-North Spud Date: 2/28/2006 Event Name: ROT -DRILLING Start: 2/26/2006 End: 3/11/2006 Contractor Name: n1433@conocophillips.com Rig Release: 3/11/2006 Group: Rig Name: Nordic 3 Rig Number: 3 Date From - To ~'~, Hours "~ Code ' Sub ' Phase Code, 3/3/2006 05:00 - 07:30 ! 2.50 CEMENTf PUMP SURFAC 07:30 - 10:00 10:00 - 13:00 i 13:00 - 18:00 3/4/2006 3/5/2006 18:00 - 22:00 22:00 - 23:30 23:30 - 00:00 00:00 - 02:30 ! 02:30 - 10:00 ' 10:00 - 11:30 11:30 - 15:00 ' 15:00 - 15:30 '15:30-16:00 1,16:00-19:00 19:00 - 19:30 19:30 - 21:30 21:30 - 22:30 22:30 - 22:45 22:45 - 23:30 23:30 - 00:00 00:00 - 00:30 i 00:30 - 02:30 02;30 - 04:00 04:00 - 05:00 05:00 - 00:00 2.50'~~CEMENTRURD IISURFAC 3.001' WELCTL~ NUND i SURFAC 5.00 ! WELCTL NUND SURFAC 4.00'!, WELCTIJ NUND SURFAC 1.501 RIGMNTOTHR SURFAC 0.501 WELCTL NUND SURFAC 2.501 WELCTL~ NUND SURFAC 7.501 WELCTL BOPE SURFAC 1.50 ~! DRILL ~ RIRD SURFAC 3.501 DRILL I PULD SURFAC 0.50 i DRILL 1 OTHR SURFAC 0.50 i DRILL ', PULD SURFAC 3.00 ~ DRILL !,TRIP SURFAC 0.50 ~ DRILL I CIRC I SURFAC 2.001 CASE I MIT SURFAC '! ll ', 1.001 CEMENTDSHO (SURFAC 0.2511 DRILL ', DRLG SURFAC 0.75! DRILL (CIRC SURFAC 0.501 DRILL I CIRC !SURFAC 0.50 ! CEMENT RURD !IISURFAC 2.001 CEMENTOTHR SURFAC 1.501 CEMENT CIRC (SURFAC 1.00 CEMENT LOT SURFAC 19.00!, DRILL DRLG I PROD Description of Operations Deep Crete tail cement, 6 BPM, 350 psi. Drop top plug and chase with 20 Bbls water. Swap to rig pump and continue displacement with mud, 7 BPM, 600 psi to 800 psi. Slowed rate to 6 BPM, 700 psi for last 15 Bbls. Bumped plug at calculated displacement at 0715 hrs. Saw signs of red dye at surface about 10 Bbls into tail slurry. Had good cement returns to surface, estimate 165 Bbls of 10.7+ ppg AS Lite returns. Bumped plug up to 1500 psi, OK. Bled off and checked floats, OK. Cement in place @ 0730 hrs, 3/3/06. Reciprocated casing until good cement returns to surface. RD cement head & lines. RD casing elevators. Break out & LD landing joint. Remove tools from rig floor. RD diverter line. ND riser. RU diverter lift plate. Pump out stack. ND diverter stack and set on skid. Install FMC Gen V Casing head and spool. Orient and lockdown head. Install lift plate on 11" BOP stack. Test metal to metal seal on FMC head, OK. RD torque tube bushing, replace teflon. Change out wash pipe. Load & strap 60 joints of 5" DP in shed. Bring in Sperry tools. NU 11" 5 Ksi BOP stack. Change upper pipe rams to 5". Slip & cut drilling line. Adjust drawworks brakes. Continue NU choke & kill lines to stack. Continue NU choke & kill lines. Test ROPE. All rams & annular to 250 psi & 3000 psi. Choke manifold, choke and kill lines and valves, upper and lower top drive valves, floor safety valves to 250 psi & 3000 psi. Accumulato capacity test: 3000 I psi initial system pressure, 1900 psi after closure, rebuilt 200 psi in 15 sec., full pressure in 1 min. 26 sec. Tested gas and pit alarms. Test witnessed by Jeff Jones, AOGCC Field Inspector. RU bails. Set wear ring. PU tools for BHA. MU 8-1/2" bit and Mud Motor. PU & MU BHA. Upload MWD. Perform shallow pulse test. PJSM. Load nuclear sources & initialize MRIL. PU & MU 3 non-mag Flex DC. RIH with 7 stands HWDP & jars. Continue RIH PU 60 joints of 5" DP. RIH to 2573'. Circulate to balance out mud for casing test. 7 BPM, 800 psi, 9.5 ppg in & out. RU lines. Break circulation to clear air out of lines. Close pipe rams. Pressure up at 7 SPM, 1/2 BPM, to 3040 psi. Test casing for 30 minutes, lost 30 psi, OK. Bleed off pressure. Rig down & blow down lines. RIH rotating and circulating, tag plugs at 2682'. Drill out plugs, float collar, cement, and float shoe. Clean out rat hole to 2780' MD. Drill 20' of new hole to 2800' MD (2730' TVD). 105K# PU, 85K# SO. Circulate bottoms up to clean hole and catch cuttings samples. ! Displace to Flo-Pro mud. Pump 10 Bbls water spacer, followed by 35 ~I Bbls Hi-vis Flo-Pro pill, followed by 9.0 ppg Flo-Pro mud. RU lines for formation integrity test. Clean pits and shakers for Flo-Pro mud. ,Circulate to condition and even out Flo-Pro mud, 9.0+ ppg in and out. Perform formation integrity test. Leak off at 700 psi with 9.0+ ppg mud, 1,14.0 ppg EMW. Bleed off and blow down lines. MU top drive. Break circulation. Directionally drill 8-1/2" hole from 2800' to 4091'MD (3948' TVD) and drilling ahead. Limit ROP to 100 Printed: 5/4/2006 3:44:24 PM ConocoPhillips Alaska Operations Summary Report Legal Well Name: 1 H-North Common Well Name: 1 H-North Event Name: ROT -DRILLING Contractor Name: n1433@conocophillips.com Rig Name: Nordic 3 Date From - To '; Hours ' Code Code' Phase 3/5/2006 1 05: 00 - 00: 00 3/6/2006 00: 00 - 08: 30 19.00 II DRILL ' DRLG PROD 8.50 DRILL I DRLG PROD 08:30 - 09:30 !; 1.001 DRILL 1 CIRC PROD ~ ! 09:30 - 11:00 1.50 DRILL I WIPR PROD 11:00 - 12:00 1.00 DRILL WIPR PROD 12:00 - 13:00 1.00 DRILL ''CIRC PROD 13:00 - 13:30 13:30 - 17:00 ~I 17:00 - 21:00 3/7/2006 21:00 - 23:00 23:00 - 00:00 00:00 - 01:30 01:30 - 02:00 02:00 - 03:00 03:00 - 04:00 04:00 - 06:30 06:30 - 09:00 09:00 - 09:30 09:30 - 10:00 10:00 - 12:00 12:00 - 13:00 13:00 - 13:30 13:30 - 14:30 14:30 - 15:45 I ' 0.50 DRILL SURV 3.50 DRILL TRIP 4.00 DRILL !:PULD 2.00 1.00 1.50 0.50 1.00 1.00 2.50 2.50 0.50 0.50 2.00 1.00 0.50 1.00 1.25 LOG 'RURD LOG I ELOG LOG;OTHR LOG ' ELOG LOG '..PULD LOG ?RURD LOG :.PULD LOG i DLOG LOG ;CIRC LOG DLOG LOG ' ELOG LOG DEOT LOG ELOG LOG !CIRC LOG j ELOG LOG ELOG LOG DLOG LOG DLOG RIGMNT RGRP RIGMNT RGRP LOG ! DLOG LOG DEOT LOG '.PULD LOG ' DLOG LOG 'CIRC LOG DLOG LOG I ELOG LOG I DLOG LOG ', DLOG 15:45 - 16:30 0.75 !i 16:30 - 17:00 I 0.50 ;17:00 - 00:00 7.00 3/8/2006 100:00 - 03:00 '', 3.00 3/9/2006 03:00 - 13:30 ~I 10.50 1;13:30 - 14:30 ~; 1.00 14:30 - 20:00 I 5.50 20:00 - 21:00 '; 1.00 21:00 - 22:00 1.00 22:00 - 22:30 'I 0.50 22:30 - 22:45 '' 0.25 22:45 - 00:00 ' 1.25 00:00 - 00:30 ', 0.50 00:30 - 16:00 '' 15.50 PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD PROD 'PROD PROD ~ PROD PROD PROD 'PROD '!PROD ;PROD 'PROD PROD PROD 'PROD Page 4 of 5 Spud Date: 2/28/2006 Start: 2/26/2006 End: 3/11/2006 Rig Release: 3/11/2006 Group: Rig Number: 3 Description of Operations i FPH for MWD logs and cuttings sampling. 5K-10K WOB, 70 RPM + 168 RPM Mud Motor, 1790 psi, 171 SPM, 509 GPM, 4650 ft-Ib Tq on btm, 4600 ft-Ib Tq off btm, 11.23 hr ART, 2.41 hr AST, 13.64 hr ADT. !;130K# PU, 105K# SO, 115K# Rot Wt. 9.0+ ppg MW, 9.9 ppg ECD. Continue drilling 8-1/2" hole from 4091' to 4630'MD (4458' TVD). Limit ROP to -100 FPH for MWD logs and cuttings sampling. 5K-10K WOB, 65 RPM + 168 RPM Mud Motor, 1950 psi, 171 SPM, 509 GPM, 6000 !, ft-Ib Tq on btm, 4700 ft-Ib Tq off btm, 6.28 hr ART, 0 hr AST, 6.28 hr ADT. 145K# PU, 110K# SO, 125K# Rot Wt. 9.0+ ppg MW, 10.3 ppg 'ECD. ':Pump 30 Bbl hi-vis sweep and circulate around to clean hole, 172 SPM, 512 GPM, 1850 psi, work and rotate pipe, 80 RPM. POOH on elevators to casing shoe at 276T, OK. !RIH to bottom at 4630', OK. ,Pump 30 Bbl hi-vis sweep. Circulate 3 bottoms up while rotating and ', reciprocating pipe to clean hole. 80 RPM, 173 SPM, 515 GPM, 1750 ', psi. 127K# PU, 122K# SO, 123K# Rot. Wt. ',Blow down top drive. Drop ESS survey tool and allow to fall. I POOH, stand back DP & HWDP. LD non-mag flex DC. Download MWD. Remove RA sources. Download MWD. Finish LD BHA. ~ PJSM. RU Schlumberger E-line and logging tools. SWS RIH with logging tools. RIH and perform Dipole SoniGFMI log from 2,767' MD to 4,630' MD. ~ POOH with SWS Dipole Sonic tools. ~~ LD Dipole Sonic tools. Re-head a-line for wet connect MDT run. PJSM, PU MDT tools and test, tools tested OK. RIH with MDT on 5" DP to 2,760'. Circ one string volume at 3 bpm, 200 psi. '; Cont RIH with MDT on 5" DP from 2,760' to 3,108'. RU SWS and side entry sub, RIH with wet connect. I~ Sting in wet connect and attempt to test tools, tools not testing. POOH with wet connect and RD side entry sub. Circulate at 2 bpm, 120 psi while recip 100K up wt, 85K dwn wt. RU SWS and side entry sub, RIH with wet connect, stung in and attempted test. No test. 1 POOH with wet connect and RD side entry sub. I POOH with 5" DP from 3,108' to 2,476' and lost SCR power to draw-works. Trouble shoot rig SCR problem. Located SCR components in Prudhoe. Wait on delivery. Install SCR components, cont trouble shooting. POOH w/ 5" dp & Logging tools from 2,476' to rig floor. Change out logging tool & test same-test failed-bring more tools from Deadhorse. 1 MU MDT assembly and test, test OK. RIH with 5" DP to 2,767'. Circulate one string volume at 3 bpm, 200 psi. Cont RIH from 2,767' to 3,108'. MU side entry sub and RIH with a-line, latch up and test, test OK. it PJSM with new crew, cont RIH with 5" DP and a-line. Obtained MDT pressure and fluid data from 3,508' to 4,328', and back Printed: 5/4/2006 3:44:24 PM ConocoPhillips Alaska Page 5 of 5 Operations Summary Report Legal Well Name: 1 H-North Common Well Name: 1 H-North Spud Date: 2/28/2006 Event Name: ROT -DRILLING Start: 2/26/2006 End: 3/11/2006 Contractor Name: n1433@conocophillips.com Rig Release: 3/11/2006 Group: Rig Name: Nordic 3 Rig Number: 3 Date 3/9/2006 3/10/2006 3/11 /2006 From - To Hours Code ,Code Phase Description of Operations 00:30 - 16:00 15.50 i LOG DLOG I 1 PROD 11 up to 3,900'. 16:00 - 17:30 ~1 LOG DLOG 1.50 PROD POOH with 5" DP from 3,900' to 3,108'. 17:30 - 18:00 0.50 LOG ELOG PROD Unlatch wet connect and POOH with a-line, RD side entry sub. 18:00 - 20:00 2.00 1 LOG '~ DLOG PROD Cont POOH with 5" DP to MDT tools. 120:00 - 22:00 2.00 ~, LOG PULD PROD I POOH, LD MDT logging tools. 22:00 - 00:00 . 2.00 i LOG PULD ~! PROD I RD sheave and re-head a-line, PU sidewall core tool. 00:00 - 01:30 1.50 LOG ELOG !PROD ' RIH with core gun on a-line. 101:30 - 03:00 ' 1.50 LOG OTHR ',PROD 'Obtain core samples at 4,322'. ':03:00 - 04:30 ~ 1.50' LOG ELOG ~ PROD ,POOH with a-line, LD and RD SWS. 04:30 - 06:00 1.50 ~I LOG RURD PROD Clear rig floor, RU tubing tongs and handling equip. ~ 06:00 - 07:00 j 1.00 j CEMEN TRIP ~ PROD PU and RIH with 3 1/2" tubing for cement string. 107:00 - 07:30 0.501 CEMEN RURD PROD RD ECKLE tubing tongs, RU DP spinners and 5" elevators. 07:30 - 09:00 1.50 CEMEN TRIP PROD Cont RIH with cement string on 5" DP, from 994' to 4,616'. 09:00 - 13:00 4.00 CEMENT CIRC PROD Circ and cond mud for cement job at 7 bpm, 670 psi, up wt 100K, dwn wt 87K. ' ' 13:00 - 17:00 4.00 CEMENT PUMP PROD Spot 1st cement plug at 4,630 , POOH to 3,925 and circ pipe clean at 7.5 bpm, 680 psi, spot 2nd plug at 3,925', POOH to 2,115' and circ pipe clean at 7 bpm, 530 psi. 17:00 - 18:00 1.00 CEMENTTRIP PROD ~~, POOH from 2,115' to 992'. 18:00 - 18:30 0.50 CEMENT RURD PROD I RD DP spinners and elevators, RU ECKLES for tubing. ',18:30 - 20:30 2.00 CEMENTTRIP !PROD POOH stud back 5 studs tubing, LD 16 juts tubing and MS jut. 20:30 - 21:00 0.50 i CEMENT RURD ~~ PROD RU handling equip for 5" DP. 21:00 - 22:45 '~ 1.75, CEMENTTRIP 'PROD I MU Baker cement retainer and RIH on 5" DP to 2,711'. 22:45 - 23:00 0.251 CEMENTOTHR i PROD Set retainer and weight test at 2,711', up wt 77K, dwn wt 70K. 23:00 - 00:00 ~ 1.00 CEMENT(PUMP PROD , RU Dowell, PJSM, press test surface lines, spot 170' cement below ~ ', retainer. ', 00:00 - 00:30 ' 0.501 CEMEN OTHR '~, PROD ! Unsting from retainer and POOH slow from 2,711' to 2,583' spotting 50' I ~, cement on top of retainer. '; 00:30 - 01:00 I 0.50!.. CEMEN CIRC I PROD ', CBU at 5.5 bpm, 370 psi. 01:00 - 02:30 I 1.50 j CEMEN TRIP ~I PROD '1 POOH with 5" DP. '102:30 - 03:00 'i 0.50 ~ CEMENT RURD ~ ~~ PROD LD retainer running tool, RU and pull wear ring. 03:00 - 04:00 I 1.00 ' CEMEN TRIP I PROD RIH with 3 1/2" tubing to 500'. 04:00 - 04:30 '~~ 0.501, CEMENl~CIRC PROD Spot 15 bbls Hi-Vis Pill from 500' up to 300'. 04:30 - 05:00 0.50 CEMENTTRIP PROD POOH 2 studs and RU to cement. 05:00 - 06:00 1.00 CEMENli PUMP PROD .PJSM, Pump and spot 36 bbls cement to surface. ~ ii 06:00 - 07:00 ~ 1.00'~i CEMENTTRIP PROD POOH slow, stud back 3 1/2" tubing, flush well head and BOP stack 1 with water. 07:00 - 08:00 ' 1.00 ' CEMENT PULD PROD 1 LD 5 studs 3 1/2" tubing from mousehole. 08:00 - 12:00 4.00 ABANDN NUND ABANDN ND flow riser, kill and choke lines, stud back BOP stack, prep to remove well head. II 12:00 - 13:00 1.00 ABANDN WLHD ABANDN I~ Remove well head for re-use, prep cellar for move. ;13:00 - 14:00 1.00 j MOVE ;MOVE MOVE 'Clean pits, move service shacks and tanks, back rig off well. RIG '~ 'i RELEASED at 14:00 hrs. Printed: 5/4/2006 3:44:24 PM • Halliburton Company Global Report ('iunp:mv: ConoroPhillips Alaska Inc- Ilnle: 414i200e 1'iun~: 15:56.04 I'a~e I I~irlrl: Kupar~~k River Unit Cu-unlin:+tc1Al.l R ctcrcner: We!I: 1H-North, T rue North tiitr: NEWS ICEPAD ~~crtical i h~~DI Rrf crcucc: 1H-North 64 a ~~ ell: 1 H-Nodh tieciinu (~5~ Refere nce: Well (O OON 0-OOE .33 52Azii 1lrllp:uh: 1H-North Sun~cv(~alcul;ilion ~tcthiid: Minimum Curvatu re Ub: Oracle Survey: Start Date: Company: Engineer: Tool Tied-to: Field: Kuparuk River Unit North Slope Alaska United States Map System:US State Plane Coordinate System 1 927 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic M odel: bggm2005 Site: NEWS ICEPAD Site Position: Northing: 5994294 .00 ft Latitude: 70 23 42.363 N From: Map Easting: 554537 .00 ft Longitude: 149 33 22.510 W Position Uncertainty: 0.00 ft North Reference: True Ground Level: 0.00 ft Grid Convergence: 0.42 deg Well: 1 H-North Slot Name: WeII Position: +N/-S 6.45 ft Northing: 5994300 .58 ft ' Latitude: 70 23 42.427 N +E/-W 18.47 ft Easting : 554555 .42 ft ' Longitude: 149. 33 21.969 W Position Uncertainty: 0.00 ft -- -- - Wellpath: 1 H-North Drilled From: Well Ref. Point 500292329400 Tie-on Depth: 30.00 ft Current Datum: 1 H-North: Height 64. 60 ft Above System D atum: -Mean Sea Level Magnetic Data: 2/17/2006 Declination: 24.22 deg Field Strength: 57572 nT Mag Dip Angle: 80.86 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ft ft ft deg 30.00 0.00 0.00 33.52 Survey Program for Definitive Wellpa th Date: 1/17/2006 Validated: No Version: 1 Actual From To Survey Toolcode Tool Name ft ft 194.82 4591.00 1 H-North ( 194.82-4591.00) MWD MWD -Standard Survey \1l) lucl ;Mini l~~l) tiny Ril Siff F.r11 1t;i~A~ )lapl_~ ~I'~~ol ft deg deg ft ft ft ft ft ft 30.00 0.00 0.00 30.00 -34.60 0.00 0.00 5994300.58 554555.42 TIE LINE 194.82 0.69 145.69 194.82 130.22 -0.82 0.56 5994299.76 554555.99 MWD 286.99 0.54 156.50 286.98 222.38 -1.68 1.05 5994298.91 554556.48 MWD 376.01 0.71 150.14 376.00 311.40 -2.54 1.49 5994298.05 554556.93 MWD 465.87 1.22 125.13 465.84 401.24 -3.57 2.55 5994297.03 554557.99 MWD 556.55 1.42 145.45 556.50 491.90 -5.05 3.97 5994295.56 554559.43 MWD 646.63 1.10 142.78 646.56 581.96 -6.66 5.13 5994293.96 554560.60 MWD 737.63 0.69 60.53 737.55 672.95 -7.09 6.14 5994293.54 554561.61 MWD 831.54 0.98 25.68 831.45 766.85 -6.09 6.98 5994294.55 554562.44 MWD 926.37 2.29 29.86 926.24 861.64 -3.71 8.27 5994296.93 554563.72 MWD .1021.90 4.28 35.00 1021.61 957.01 0.86 11.27 5994301.53 554566.68 MWD 1115.75 9.82 35.77 1114.71 1050.11 10.23 17.96 5994310.94 554573.30 MWD 1210.81 13.24 36.46 1207.84 1143.24 25.57 29.17 5994326.36 554584.40 MWD 1306.28 13.90 35.05 1300.64 1236.04 43.75 42.25 5994344.63 554597.35 MWD 1398.00 14.74 33.46 1389.51 1324.91 62.51 55.01 5994363.48 554609.97 MWD 1492.97 15.91 34.52 1481.11 1416.51 83.31 69.05 5994384.38 554623.85 MWD 1588.00 15.35 34.10 1572.62 1508.02 104.46 83.48 5994405.63 554638.13 MWD 1683.04 15.70 34.32 1664.19 1599.59 125.49 97.79 5994426.77 554652.28 MWD 1776.60 15.75 34.30 1754.25 1689.65 146.44 112.08 5994447.82 554666.42 MWD • Halliburton Company Global Report ('ompam: ConocoPhillips Alaska Inc. Datc _ ~1/4~2Q06 l'inic: 15:55:04 I':~r. FicliJ: Kuparuk River Unit Cu-u rdin:~tc1AI') R cfcrcucr. Well: 1H-North. Tr ue North 1i~c NEWS ICEPAD ~'crli cal f I~ U~ ilcf crcncc: 1H -North 64-b ~1'cll: 1 H-North ``ecti en I~~~l Refcrc ncc: We ll i0.00N.0 00E.~3 52Azi) ~1 ellp:uh: 1 H-North tiur< <~ (~slculation iVJcthu~l: Mi nimum Curvatu re Ilh: Oracle Gn~~ c~ ~~~) ~Illt ~/1111 T~ ~) l~ti t` ~) ~'ti ~',; ~~' ~~~1 ~1~~ ~~:i ~7 ~', ~flfl~ ft deg deg ft ft ft ft ft ft 1870.70 17.72 31.57 1844.36 1779.76 169.19 126.77 5994470.68 554680.94 MWD 1958.51 19.39 28.43 1927.61 1863.01 193.40 140.71 5994494.98 554694.70 MWD 2058.89 19.39 28.73 2022.29 1957.69 222.66 156.65 5994524.36 554710.43 MWD 2152.24 19.36 28.21 2110.36 2045.76 249.89 171.42 5994551.69 554724°99 MWD 2248.32 17.04 26.51 2201.63 2137.03 276.52 185.23 5994578.42 554738.61 MWD 2341.89 16.38 25.98 2291.24 2226.64 300.65 197.13 5994602.63 554750.33 MWD 2437.61 16.53 33.19 2383.05 2318.45 324.18 210.50 5994626.26 554763.53 MWD 2531.64 16.40 32.10 2473.23 2408.63 346.62 224.87 5994648.80 554777.74 MWD 2626.25 16.56 31.50 2563.95 2499.35 369.43 239.02 5994671.71 554791.71 MWD 2712.23 16.69 33.43 2646.34 2581.74 390.18 252.22 5994692.56 554804.76 MWD 2760.48 16.80 33.88 2692.54 2627.94 401.75 259.92 5994704.18 554812.38 MWD 2819.23 18.50 34.37 2748.52 2683.92 416.50 269.92 5994719.00 554822.27 MWD 2915.13 19.17 33.22 2839.29 2774.69 442.23 287.14 5994744.85 554839.29 MWD 3010.63 18.55 34.43 2929.66 2865.06 467.88 304.31 5994770.62. 554856.28 MWD 3104.21 19.54 32.71 3018.12 2953.52 493.32 321.19 5994796.19 554872.97 MWD 3199.52 19.27 33.50 3108.01 3043.41 519.85 338.48 5994822.84 554890.07 MWD 3295:19 19.34 34.45 3198.30 3133.70 546.08 356.16 5994849.19 - "554907.55 MWD ~~ 3386:28 19.41 32.76 3284.24 3219:64 571.24 372.88 5994874.47 554924.08 MWD 3482.50 20.00 31.96 3374.82 3310.22 598.65 390.24 5994902.00 554941.24 MWD 3575.85 19.78 31.28 3462.60 3398.00 625.69 406.89 5994929.16 554957.70 MWD 3671.29 19.02 34.13 3552.63 3488.03 652.37 424.00 5994955.96 554974.61 MWD 3765.06 18.97 33.64 3641.29 3576.69 677.70 441.02 5994981.42 554991.44 MWD 3859.16 20.17 33.73 3729.95 3665.35 703.93 458.50 5995007.77 555008.73 MWD 3952.46 19.98 34.32 3817.58 3752.98 730.47 476.42 5995034.44 555026.45 MWD 4047.11 19.78 34.47 3906.59 3841.99 757.03 494.60 5995061.13 555044.44 MWD 4140.56 19.59 33.40 3994.58 3929.98 783:15 512.18. 5995087.37 555061.82 MWD 4236.14 19.28 32.35 4084.72 4020.12 809.86 529.44 5995114.20 555078.88 MWD 4331.47 18.56 33.59 4174.90 4110.30 835.79 546.26 5995140.25 555095.51 MWD 4425.77 18.31 32.03 4264.36 4199.76 860.85 562.41 5995165.43 555111.48 MWD 4519.76 18.10 32.43 4353.64 4289.04 885.69 578.07 5995190.38 555126.96 MWD 4591.00 17.74 32.25 4421.43. 4356.83 904.21 589.80 5995208.98 555138.55 MWD ~ 4630.00 17.74 32.25 4458.57 ~ 4393.97 914.26 596.14 5995219.08 ' 555144.82 'PROJECTED to TD • • P&A Summary for 1 H-North 1H-North: Excavated conductor and 9 5/8 inch casing on 4/19/06. Cut off conductor and 9 5/8 inch casing 3 feet below ground level on 4/20/06 Melted ice out of 9 5/8 inch casing from 3 feet to 23 feet below ground level on 4/21 /06 Cemented 9 5/8 inch casing to top of casing stub with SWS AS 1. Cement top witnessed by Chuck Sheve (AOGCC) on 4/21/06. Welded identification plate on casings 4/21 /06 Buried conductor and 9 5/8 inch casing with soils removed from the excavation and conductor setting process on 4/22/06. • • ay 4.b _ s'~ ate. ,~y~~F~' +~. 'o.. Y. ,.,r:. a.~ f `- Y ~ ~ ~ ~ ~ti . ~ s ~ __ ~.~ ~. °+~.~ r- •~~ .~I~1l~'.r ~ ~ ~ _~, ~;~ .. .~ i ~ __ ~3 ..~ _ r.. .~"!S~.y''~' f 9y may..:. '}'~.~ ~, ~~tQ. ~ , _~• ~ , ~ 4' __ r. `.~.,yj ,~~~ ~ F ~ ~ c~ ~ ~ :. ;+"~i' ~ ". Z jT ~ ~4 Y - 4 a.,~dl~- F3, -~ ar r'~j .r@'.. . J s,¢ :'te'a ~ if 'g'" _ ... . ~. _ ~ r. y -, a -•~ d I v,.. ;.~_ _ ~ ~ , ~• ~ .~ ~ +r-- Yip ~ ~- ~~. { ... ~N r ~,L ~ `i-s 3 +f- _ ~' • • ' _ ~ _,^'y~,... ~ r ;~~x 7°~.-~'- a ~Se.• ~-"'~„~_..u ~ ~-' ~` ~ -~,N~~' '.. g s ~' ,. ~ i N ~ ~ ,mow _ L "'~.. t `„~~` 'std, V~ ~ ;.v ~ - .... ' - ... _ - ~"_ ~~ ;. 'rc- w %~` ' ~ ..dam; 'ri1'- 1 ~~ ' l ~ .,k '*~r...'' ~ ~ '~~ ~. ,~ ~..~„ :.- r r .. ~ _ _ c- ~ ~. ~, . ~.. . ,~ - ~ ~ ~ ~ I~' ~~,~,. w~ ~ .~ "~...L.r f~ '~ .K D,n, V '~ _ .. s ..,, _. _- _ .. _ ~.. ~,s .. _ ; r _ '~ r .. :- - ' ~~ ~ ~. er..' "' .~>. ~~nt. ~ .,w ~ .tea' I ~~ ~ ~ r ~ ~~ ~,~.„ , r , _ -,, ~ ~ ,~ ~~ ~s" Y +.. ~ ~ ~~~ _ & ~£ ~~ ~ - ". ;'^ ~ 3' -: ,ti° ~ ~ ~* ~~~, s ~, ;, s5 ~s ~~ ~ 'y~3,ps„„ M: r'.C' s u ,,,n.~ s .. ~. a"`~..' ,~,~ ~'_^h -~~ i ~ ~'foa ~9 j~~~R~a ~~~ ~ zya ~z a. ,, ~ err ,r' ~ '~ ,~ ,' ~a r : y `~ ~ -t 4 • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg, '-' -, ' ~ ~- DATE: April 21, 2006 P. I. Supervisor ~( FROM: Chuck Scheve, Petroleum Inspector SUBJECT: Surface Abandonment 1 H North. PTD # 205-209 Friday, April 21,2006: I traveled to the Conoco Phillips 1 H North exploratory location to inspect the casing cut off and abandonment of this well. All casing strings were cut off at approximately 4' below original ground level and all were found to be full of cement. A 3/4" thick marker plate was welded to the conductor casing with the required information bead welded to it. SUMMARY: I inspected the casing cut off depth, and the P&A marker plate on the 1 H North Well and found all to be in order. Attachments: 1 H North plate.JPG 1 H North cut off.JPG • • KRU 1 H-North (ConocoPhillips) Surface Abandonment Inspection Photos from Chuck Scheve, AOGCC April 21, 2006 Casing Cut-off Marker Plate • ~ NEWS Wells Status Report 3/17/06 1H-North Well Status Report `~ ~ S ~ ~~~1 Spud 1H-North at 0000 hrs 2/28/06. Directionally drilled 12-1/4" hole to 2780' MD/2711' TVD. Ran & cemented 9-5/8" 40.0 ppf L-80 BTC casing to 2767' MD/2699' TVD with 350 bbls (457 sx) of ARCTICSET Lite lead slurry plus 69 bbls (172 sx) of DeepCRETE tail slurry. Full returns during the job, reciprocated pipe until good cement returns to surface, and estimated 165 bbls of 10.7 ppg slurry back to surface. ND diverter NU 11" 5000 psi BOPE stack. Tested to 250 psi low and 3000 psi high. PU 8-1/2" BHA, RIH to 2573' MD, tested casing to 3000 psi-OK. Drilled out shoe track, drilled 20' of new hole to 2800' MD, circulated and conditioned mud. Changed over to 9.0 ppg Flo-Pro mud system performed LOT to 14.0 ppg EMW and drilled to 4630' MD and TD. Made wiper trip and RU SWS. Ran Dipole Sonic/FMI from 2767' to 4630' MD-POOH. PU drill pipe conveyed MDT tools. Had problems with the wet connect and lost SCR power to draw works on the way out. Repaired SCR components, POOH with MDT tools and replaced the wet connect-RIH. Obtained fluid samples in the "B" & "D" sands. Unable to obtain fluid sample from the Ugnu "N" sands. POOH. PU sidewall core gun and RIH. Retrieved 44 of 45 shots and RD SWS. PU 3-1/2" cement stinger and RIH for P&A plugs. Spot two bottom plugs in 700' lifts- estimated top of cement at 3225' MD. POOH. PU cement retainer, and set at 2711' MD. Weight test-OK. Pump 170' of cement below retainer and spot 50' on top. POOH and lay down setting tool. RIH with 3-/12" tubing and spot 15 bbls viscosified pill from 500' to 300' MD. Spot cement plug back to surface and flushed wellhead & BOP stack. ND BOPE stack and wellhead. Rig released to 1R- East at 1400 hrs 3/11/06. • ~ ,~.. ~ ~ ~ ~~ '~ '~ ;fix ;~'~~ ~ ,~~ ~°`. j ALASKA OIL A1~TD GAS COI~TSER~A'TIO1~T CO1rIIrIISSIOIQ Randy Thomas GKA Drilling Team Leader ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, 1 H-North Sundry Number: 306-079 Dear Mr. Thomas: ~~ 1~ FRANK H. MURKOWSKI, GOVERNOR ~4 ~ 333 W. T" AVENUE, SUITE 100 ~~'~ ANCHORAGE, ALASKA 99501-3539 ~' PHONE (907) 279-1433 FAX (907) 276-7542 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided ~in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considere06-Od timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, ~i~` DATED this~~~ay of March, 2006 Cathy P. Foerster Commissioner Encl. .1 ~ COt't000~11~~IrS Post Office Box 100360 Anchorage, Alaska 99510-0360 March 7, 2006 Commissioner State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue Suite 100 Anchorage, Alaska 99501 (907) 279-1433 • ~E~EIVED MAR 0 7 2006 Alaska Oil & Gas Cons. Commission Anchorage Re: Application for Sundry approval to P&A Conoco Phillips 1 H-North Surface Location: 2276' FNL, 946' FEL, Sec. 15, T12N, R10E, UM or ` ASP4, NAD 27 coordinates of X=554,555 & Y=5,994,301 Target Location: 1385' FNL, 355' FEL, Sec. 15, T12N, R10E, UM BHL: 1357' FNL, 336' FEL, Sec. 15, T12N, R10E, UM CONFIDENTIAL Dear Commissioner: ConocoPhillips Alaska, Inc. would like to P&A the 1 H-North West Sak wellbore, located in the Kuparuk River Field/West Sak Oil Pool. Nordic 3 spud this well on 2/28/06 and TD'd the well on 3/6/06. The attached Sundry and back-up information describes the P&A procedure for the existing wellbore. If you have any questions or require any further information, please contact me at 265-6377 or Randy Thomas at 265-6830 Si cerel ~~ Tom Brassfield Staff Drilling Engineer _.~~ ~. 3f11m~ • ~ STATE OF ALASKA /~ `' MAR 0 7 2006 ALA OIL AND GAS CONSERVATION COMM~N APPLICATION FOR SUNDRY APPROVALS Alaska Oil & Gas Cons. Comniasion 20 AAC 25.280 Anchorage 1. Type of Request: Abandon ~ Suspend Operational shutdown Perforate Waiver Other Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development ^ Exploratory ~ 205-209 3. Address: Stratigraphic ^ Service ^ 6. API Number: P.O. Box 100360 Anchorage, AK 99510-0360 50-029-23294-00 7. KB Elevation (ft): 9. Well Name and Number: 30' RKB + 34.6' to top of pad 1 H-North 8. Property Designation: 10. Field/Pools(s): ADL 025636 Kuparuk River Field/West Sak Oil Pool- Exploration 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 4630' 4459' Casing Length Size MD ND Burst Collapse Structural Conductor 80' 16" 110' MD 110' TVD 3280 630 Surface 2737' 9-5/8" 2767' MD 2699' TVD 5750 3090 Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): None None na na na Packers and SSSV Type: None Packers and SSSV MD (ft): None 12. Attachments: Description Summary of Proposal ~ 13. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory^ Development ^ Service ^ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/9/2006 Oil ^ Gas ^ Plugged ^ Abandoned ^ 16. Verbal Approval: Date:. WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: Tom Maunder 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tom Brassfield @ 265-6377 Printed Name Randy Thomas Title GKA Drilling Team Leader 1 Signature , t Phone 265-6830 Date 3/7/2006 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity '~ BOP Test ^ Mechanical Integrity Test ^ Location Clearance `~ Other: ~ ~~~~ ~,J CDT ~E V \~~ tp~~ '~ 'l~`~N^.S ~N'~COC~ h~~~ ~~ °' r° ~ ~' S~~ P Q S F ~~ Subsequent Form Required: ~~ ~ ~~~- Mql, s~ 20Q6 APPROVED BY Q ~ COMMISSIONER THE COMMISSION Date: ~ , .. (p Approved by: Form 10-403 Revised 07/2005 O ~ I i -~' 1 \1 (~ .3'~'~ ~~/~ Submit in Duplicate ,. 1 H-North P&A • Revised 3/6/06 by TJB Summary: The 1 H-North well spud 0000 hrs on 2/28/06 and TD'd on 3/6/06. After running a-line logs, drill pipe conveyed MDT's and possibly percussion sidewall cores the well will be P&A'd. Please see the attached wellbore schematic for details. 1. Notify AOGCC 24 hours in advance of all pressure testing and well suspension operations. Hold pre-job meeting with all personnel to discuss objectives, as well as safety and environmental issues. 2. Mobilize and rig up D/S for well P&A operation. Spot balanced cement plugs from TD @ 4630' MD to 3230'MD (approx. 170' above top of the Ugnu @ 3400' MD). These plugs will be laid in two 700' intervals. Total cemented interval is approx. 1400' in length. Cement volumes will be based on 8-1/2" hole diameter plus 25%. Total volume is approximately 690 cu ft or 590 sx of slurry. This will cover the West Sak interval from TD to the top of the hydrocarbon bearing Ugnu. Note: not required to tag plugs (setting from TD) as long as the cementing i/ operations go "as planned". 4. By the down squeeze method through a retainer set 70' above the shoe (or approx. 2697' MD) pump cement plug #2 as per AOGCC regulations. Pump sufficient cement through the retainer to extend 170' below (70' of casing volume plus 100' of open hole) and lay a 50' cement cap on top of the retainer. Cement volume in open hole will be based on 8-1/2" hole diameter plus 25%. Total volume is approximately 101 cu ft or 109 sx of slurry. Weight test retainer before pumping cement. Not required to tag the plug. Leave 9.0 ppg mud below the plug.(Weight of mud needed to TD the hole). 52~~ ~ ~~`~d.c~c- cac~~~~s~~~ ~~ `'~3h,~~ NOTE: Contact AOGCC inspector for option to witness setting the retainer. 5. POOH standing back 500' of the 3-1/2" stringer (to be used for surface plug) and laying down 5" DP. 6. Spot a 15 bbl viscosified mud gel pill from 500' to 300'. Spot a balanced Arctic Set 1 cement plug #3 from 300' to surface. 7. PU 3-1/2" tubing and RU to circulate water down to top of the 9-5/8" casing hanger. Flush ID of wellhead to clean-up any residual cement. Clear lines and shut down pumps. Rig down cementing unit and clean up. 8. ND BOPE's and remove Gen V wellhead. Send wellhead to shop for cleaning and any repairs- to be used on the next NEWS well. 9. Release rig to 1 R-East. 10. After Rig completes the third well on the ice pad (1 H-South) the Kuparuk Toolhouse Techs will cut off wellhead and all casing strings at 3 feet below ground level. The casing head with stub will be sent to Materials for repair / re-dressing. NOTE: Contact AOGCC inspector for option to witness P&A work prior to welding-on the cover plate. TJB 3/6/06 ` • • 1 H-North P&A Revised 3/6/06 by TJB 11. A cover plate will be welded (at least 18" in diameter and %4" thick) over all casing strings with the following information bead welded into the top: Conoco Phillips Alaska, Inc. 1 H-North PTD# 205-209 API# 50-029-23294-00 12. Remove cellar. Back fill cellar with gravel as needed. Back fill remaining hole to ground level with gravel. Clear ice pad location and demob all materials and equipment. TJB 3/6/06 File: 1 H-North Tom Brass i Staff Drilling Engine TJB 3/6/06 .~ .~. 300' Cement surface P8~A plug per AOGCC Regs Wellhead: FMC Gen V Conductor: 16" set at 110' MD 1 H North NEWS Well Schematic Nordic Rig 3 Floor RKB=30' Fluid: 9.0 to 9.1 ppg Kill Weight Mud in Casing 50' Cement plug on top of retainer per AOGCC regs TD 12'/4' Surface Hole. Shoe of 9-5/8" 40 ppf L-80 BTC casing @2767'MD/2699' TVD `'~~ Cement retainer set at approx 2697' MD ~~ with enough cement pumped to fill to _A,rF~._.~:?_ 2867' MD and 50' dumped on top. ~ ~ ~ ~ ~ ~ TD 8-1/; 4630'MD/4459' TVD as indicated in Directional Plan ment Plug(s) across drocarbon bearing zones ~m TD at 4630' MD to 170' ove Ugnu at 3400'D. TOC t @ 3230' MD- two 700' s. Fluid: Drilling mud @ +/- 9.0 to 9.1 ppg ', ConocoPhilli 5 1 H-North NEWS Well sheet ~ of ~ p P&A Schematic modified by TJB Alaska sisizoos r 205-209 ~`~ f i ~ ~ Y i ry /~ ~~ ~~' ~ ~ ~ ~,~ a , ~ ~ > FRANK H. MURKOWSK/, GOVERNOR 7 ~T~+y~ ~t~~1~ 0~ ~ ~-7 r'~ 333 W. 7"' AVENUE, SUITE 100 Co~SFjRsA~O~ CO1rII-II53IO1Q ~' ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Randy Thomas GKA Drilling Team Leader Conoco Phillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: 1 H-North Conoco Phillips Alaska, Inc. Permit No: 205-209 Surface Location: 2276' FNL, 946' FEL, Sec. 15, T 12N, R l0E Bottomhole Location: 1357' FNL, 336' FEL, Sec. 15, T12N, R10E Dear Mr. Thomas: Enclosed is the approved application for permit to drill the above referenced exploration well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty- four (24) hours notice for a representative of the Commission to witness any 20~-209 required test. Contact the Commission's petroleum field inspector at (907) 659- 3607 (pager). DATED thi~~day of December, 2005 cc: Department of Fish 8s Game, Habitat Section w/ o encl. Department of Environmental Conservation w/o encl. Conoco~hillips ~ Alaska Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Email: Randy.L.Thomas~conocophillips.com December 22, 2005 Alaska Oil and Gas Conservation Commission 333 West 7"' Avenue Suite 100 Anchorage, Alaska 99501 Re: Applications for Permit to Drill, West Sak Exploration Well iH-North Dear Commissioners: a~ ~~~~~ ~~~ , AI~$k~ pil ~ ~~~ l~s~n~ »r~~1m~~io~ A~Ghpr~g ConocoPhillips Alaska, Inc. hereby applies for Permits to Drill an onshore exploration well thru the West Sak sands. This well will be designated 1H-North. As shown iri t e attached docume- nts, t~i`ree West Sak wells will be drilled from the same ice pad located NE of Kuparuk's 1H Pad. The three wells will be P&A'd after drilling and logging. Please find attached for the review of the Commission forms 10-401, and the information required by 20 ACC 25.005 for this well. The expected spud date of 1H-North is February 1, 2006. If you have any questions or require any further information, please contact me at 265-6377 or Randy Thomas at 265-6830. Sincerely, ~~ Tom Brassfield / Senior Drilling Engineer tp~y~ C i ~ ~ 8~ i~ i STATE OF ALASKA `~~~~~ AL OIL AND GAS CONSERVATION COM~I N~ ~EC ~ ~ ~~~~ PERMIT TO DRILL ~~-r1 20 AAC 25.005 Alaska Oil & Gas Corns. Carrlmissiort 1a. Type of Work: Drill ~ Redrill Re-entry ~ 1b. Current Well Class: Exploratory Q Development Oil An~riple Zone Stratigraphic Test ~ Service ~ Development Gas ~ Single Zone Q 2. Operator Name: Conoco Phillips Alaska, Inc. 5. Bond: Blanket Q Single Well ~ Bond No. 59-52-180 ~ 11. Well Name and Number: 1 H-North 3. Address: PO Box 100360, Anchorage, AK, 99510-0360 6. Proposed. Depth: MD: 4,645' ND~ 4,463' ~ 12. Field/Pool(s): Kuparuk River Field 4a. Location of Well (Governmental Section): Surface: 2276' FNL,946' FEL,Sec 15,T12N,R10E ~ 7. Property Designation: . ADL 025636 - West Sak Oil Pool- Exploration Top of Productive Horizon: 1385' FNL,355' FEL, Sec 15,T12N,R10E 8. Land Use Permit: LE 931811 13. Approximate Spud Date: 1-Feb-06 Total Depth: 1357' FNL,336' FEL,Sec 15, T12N, R10E ' 9. Acres in Property: 2560 14. Distance to Nearest Property: 336' 4b. Location of Well (State Base Plane Coordinates): Surface:x- 554555 " y- 5,994,301 ' Zone- 4 10. KB Elevation (Height above GL): 30 feet 15. Distance to Nearest Well Within Pool: None 16. Deviated wells: Kickoff depth: 1000 feet - Maximum Hole Angle: 19.5 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 1965 Surface: 1485 18. Casing Program: Size Specifications Setting Depth Top Bottom Quantity of Cement c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 24" 16" 63 B Welded 80' 30' 30' 110' 110' ~ 200 sxAS1 12-1/4" 9-5/8" 40 L-80 BTC 2715' 30' 30' 2745' - 2672' 460sxASLite+ 160 sx DeepCRETE 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch Drilling Program ~ Time v. Depth .Plot Shallow Hazard Analysis ~ Property Plat ~ Diverter Sketch ~ Seabed Report ~ Drilling Fluid Program ~ 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date 12/22/2005 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tom Brassfield@265-6377 Printed Name Randy Thomas Title GKA Drilling Team Leader Signature ~ Phone 265-6830 Date 12/22/2005 Commission Use Only Permit to Drill ., ,.gyp Number; ZOS' L~-T/ API Number: 50- ~ Z 9^ Z 3 29 ~ ~dd Permit Apr I Date: t t See cover letter for other requirements. Conditions of approval Sam es requ' ed Yes ~ No ~ Mud log required Yes '~ No Hy ro s ide measur ~ Yes ~ No ~ Directional survey required Yes ~ No Other: ~ .` ~ Ca4 p `V~~ APPROVED BY Approv b : THE COMMISSION Date: ~~~ ~+~ ~' Form1 vis 06/2004 - Submit inDuplicate ~~x~~~~ ~ _~~. .., • ~tion for Permit to Drill, Well 1 Q-101 Revision No.O Saved: 22-Dec-05 Permit It -West Sak Well #1 H North •~°~ r.^ +'l Application for Permit to Drill Document; IIt~V~~ll Mdxirriix~ 1M~11 VQlue Table of Contents 1. Well Name .................................................................................................................. 2 Re uirements of 20 AAC 25.005 ............................................:...................... 2 2. Location Summary ................................................................................................... 2 Requirements of 20 AAC 25.005(c)(2) .....................•-•...............................................................---•........ 2 Requirements of 20 AAC 25.050(b) ...........................................................................................•--••....... 3 ~. 3. Blowout Prevention Equipment Information ......................................................... 3 Requirements of 20 AAC 25.005(c)(3)..........•••••.•••-• .......................•••••••-•-•............................................ 3 4. Drilling Hazards Information ................................................................................... 3 Requirements of 20 AAC 25.005 (c)(4) .............................................................................•--••••-............. 3 5. Procedure for Conducting Formation Integrity Tests ........................................... 3 Requirements of 20 AAC 25.005 (c)(5) .................................................................................................. 3 6. Casing and Cementing Program ............................................................................ 4 Requirements of 20 AAC 25.005(c)(6) ................................................................................................... 4 7. Diverter System lnformation ................................................................................... 4 Requirements of 20 AAC 25.005(c)(7) ......................................•••••••...................................................... 4 8. Drilling Fluid Program ............................................................................................. 4 Requirements of 20 AAC 25.005(c)(8) ................................................................................................... 4 Intermediate Hole Mud Program (extended bentonite) .......................................................................... 4 9. Abnormally Pressured Formation Information ..................................................... 5 Requirements of 20 AAC 25.005 (c)(9) ...................................................................•••............................ 5 10. Seismic Analysis ..................................................................................................... 5 Requirements of 20 AAC 25.005 (c)(10) ...................•-•-••••-••••••••••••••••-•-•-•-•............................................ 5 11. Seabed Condition Analysis ..................................................................................... 5 Requirements of 20 AAC 25.005 (c)(11) ................•••••••••-•••-.................................................................. 5 12. Evidence of Bonding ............................................................................................... 5 Requirements of 20 AAC 25.005 (c)(12) .............................................••••••••••••••••••-•••-••••--...................... 5 1H-North PERMIT IT 12 21 05.doc Page 1 of 6 Printed: 22-Dec-05 ~~~~~~~~ • ~tion for Permit to Drill, Well 1Q-101 Revision No.O Saved: 22-Dec-05 13. Proposed Drilling Program ..................................................................................... 5 Requirements of 20 AAC 25.005 (c)(13) ................................................................................................ 5 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ....................... 5 Requirements of 20 AAC 25.005 (c)(14) ................................................................................................ 6 15. Attachments ............................................................................................................. 6 Attachment 1 Doyon 14 West Sak 2004 3ksi BOP Configuration ......................................................... 6 Attachment 2 Directional Plan........----•• ...................................•-----•-•-•-------•-•-••-•-•----.............................. 6 Attachment 3 Drilling Hazards Summary .............................................................................................. 6 Attachment 4 Cement Data ................................................................................................................... 6 Attachment 5 Well Schematic ........................................................................•-•---•--.............................. 6 1. Well Name Requirements of 20 AAC 25.005 (i) Each we!/ must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC25. f340(b). For a wel/ with multip/e we!/branches, each branch must simi/oily be identified by a unique name and API number by adding a suffix to the name designated for the welPby the operator and to the number assigned to the wel! by the commission. The well for which this Application is submitted will be designated as 1H-North. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An app/ication for a Permit to Drif/ must be accompanied by each of the following items, except for an item a/ready an fi/e with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed /ocation of the we// at the surface, at the top of each objective formation, and at late/ depth, referenced to governmenta/section lines (B) the coordinates of the proposed location of the we/I at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the wet/ at the top of each objective formation and at tote/ depth; Location at Surface 2276' FNL, 946' FEL, Section 15, T12N, R10E ASPZone 4NA027Coordinates RKB E/evat%on 80' AMSL Northings; 5,994,301 Eastings; 554,555 Pad Elevation 50' AMSL Location at Top of Productive Interval ASP Zone 4 NAD 17 Coordinates Northings; 5,995,074 Eastings; 555,059 1385' FNL, 355' FEL, Section 15, T12N, R10E Measured De th RKB.• 4,109' Tote/ t/ertica/De th, RKB.• 3,958' Tote/ ~ertica/ De th, SS.• 3 878' Location at Total De th 1357' FNL 336' FEL, Section 15, T12N, R10E ASP Zone 4 NAD 27 Coordinates Measured De th RKB; 4, 645' Northings; 5,995,224 Eastings.• 555,157 Total l/ertica/De th RKB.• 4 463' Tote/ ~ertica/ De th, SS.• 4383' and (©) other information required by ZOAAC25.05®(b); 1H-North PERMIT IT 12 21 05.doc Page 2 of 6 Printed: 22-Dec-05 ~~..~ ~tion for Permit to Drill, Well 1Q-101 Revision No.0 Saved:22-Dec-05 Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviated, the application for a Permit to Oril/ (Form 10-401) must (1) include a plat, drawn to a suitab/e scale, showing the path of the proposed we//bore, including af! adjacent we/tbores within 200 feet of any portion of the proposed well; Please see Attachment 1: Directional Plan and (2) for a!/ we!/s within 200 feet of the proposed we//bore (A) list the names of the operators of those wells, to the extent that those names are known or discoverab/e in pubfie records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the on/y afi acted owner. The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Dri// must be accompanied by each of the following items, except for an item a/ready on file with-the commission and identified in the application: (3) a diagram and description of the blowout prevention equipment (BQPE) as required by 20 AAC 25.03s, 20 AAC25.036, or 20 AAC25.037, as applicab/e; An API 11" x 5,000 psi BOP stack (RSRRA) will be utilized to drill well iH-North. For all operations the stack will be equipped with 2-7/8" to 5" variable bore rams in the uppermost ram cavity, blind rams in the middle cavity, and 5" DP rams in the lowermost cavity. BQPE diagrams on file for Nordic 3. Due to the formation pressures being far less than the rating of the BQPE, CPAI requests that the stack be operated under the 30l~psi BOP guidelines. 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by each of the fo/%wmg items, except for an item a/ready on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that maybe encountered, criteria used to determine it, and maximum potential surface pressure based on a methane gradient; The expected reservoir pressures in the West Sak sands in the iH-North area vary from 0.43 to 0.45 psi/ft, or 8.3 to 8.6 ppg EMW (equivalent mud weight). The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11) and the deepest planned vertical depth of the West Sak A2 sand formation is 4,367 feet giving a MPSP of 1,485 psi, calculated thusly: MPSP = (4,367 ft)*(0.45 -.0.11 psi/ft) = 1,485 psi (B) data on potential gas zones; The well bore is not expected to penetrate any gas zones. See attached pore pressure/shallow hazards analysis report. and (C) data concerning potential causes of hole problems such as abnorma//y geo pressured strata, lost circa/anon zones, and zones that have a propensity for differentia/sticking; Please see Attachment 2: 1H-North Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to Drill must be accompanied by each of the fol/owing items, except for an item already on file wr`th the commission and identified in the app/ication: 1H-North PERMIT 11" 12 21 05.doc Page 3 of 6 Printed: 22-Dec-05 a~~L A~tion for Permit to Drill, Well 1Q-101 Revision No.O Saved:22-Dec-05 (5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(1); iH-North will be not be completed ,and will be P&A'd after wellbore evaluation. The 9-5/8"shoe track. will be drilled out and a formation integrity test will be performed in accordance with the "Formation Integrity Test Procedure" that ConocoPhillips Alaska placed on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An app/icatian for a Permit to Drill must be accompanied by each of the fo/(owing items, except for an item already on Trle with the commission and identified in the application.• (6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted /iner, pre- perforated liner, or screen to be insta/led; Casing and Cementing Program See also Attachment 3: Cement Summa Hole Top Btm Csg/Tbg Size Weight Length MD/TVD MD/T1/D OD in in Ib/ft Grade Connection ft ft ft Cement Pro ram 16" 24"" 63 B Welded 80 30 / 30 110 / 110 Cemented to surface with 200sx ASl g_5/g" 12-i/4" 40 L-80 BTC 2,715 30 / 30 2745 /2672 Cemented to Surface w/ 460 sxs ASLite Lead + 160 sxs Dee CRETE Tail _. _ 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An app/ication for a Permit to Dri// must be accompanied by each of the fa//owing items, except for an r`tem already on fi/e with the commission and identified in the application: (7) a diagram and description of the diverter system as required by 20 AAC 25, 035, unless this requirement is waived by the commission under 20 AAC25.035(h)(2); On file with AOGCC. 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An app/ication for a Permit to Dri/! must be accompanied by each of the following items, except for an item already on file with the commission. and identified in the application: (8) a dri/ling fluid program, including a diagram and description of the dri/ling t7uid system, as required by 20 AAC 25.033; Drilling will be done with muds having the following properties over the listed intervals: Surface Hole Mud Program (LSND) Surface to 9-5/8" Casin Point Mud Properties Density (ppg) 9.2 - 9.5 ' Funnel Viscosity (seconds) 150-250 Yield Point (cP) 30 - 45 API Filtrate (cc / 30 min)) 4 - 6 Chlorides (mg/I) <600 pH 9.0 - 9.5 1H-North PERMIT IT 12 21 05.doc Page 4 of 6 Printed: 22-Dec-05 ORIGINAL • Production Hole Mud Program (FLOPRO NT Drill-in Fluid) ~tion for Permit to Drill, Well 1 Q-101 Revision No.0 Saved: 22-Dec-05 9-5/8"Casin Point to TD Mud Properties Density (ppg) 9.0 - 9.2 Plastic Viscosity 10 Yield Point (cP) 28-30 - 45 API Filtrate (cc / 30 min)) 4 - 6 Chlorides (mg/I) 15,000-17000 pH 9.0 - 9.5 Drilling fluid practices will be in accordance with appropriate regulations .stated in 20 AAC 25.033. Please see information on file with the Commission for diagrams and descriptions of the fluid system of Nordic #3. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Perrrtit to Drill must be accompanied by each of the fo/%wing items, except for an item a/ready on file with the commission and identified in the app/ication: (9) far an exp/oratory or stratigraphic test well, atabu/ation setting out the depths of predicted abnormal/y geo pressured strata as required by 20 AAC25.033(t); Please see attached geopressure and hazards analysis report. 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An app/ication for a Permit to Drill must be accompanied by each of the following items, except for an item a/ready on fi/e with the commission and identified in the application: (10) for an exploratory or stratigraphic test wel% a seismic refraction or reflection ana/ysis as required by 20 AAC 25.061(a); Please see attached geopressure and hazards analysis report. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An apply"cation for a Permit to Drill must be accompanied by each of the fo1/owing items, except for an item a/ready on file with the commission and identified m the application: (11) for a we// dri/led from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vess% an ana/ysis ofseabed conditions as required by 20AAC25.061(b); Not applicable: Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the fol%wing items, except for an item a/ready on fife widr the commission and identified m the application: (i2) evidence showing that the requirements of 20 AAC 25.025 {Banding}have been met; Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An app/ication for a Permit to Drill must be accompanied by each of the fo/%wing items, except for an item already on file with the commission and r"dentrfied in the application: The proposed drilling program for 1H-North is listed below. 1 H-North PERMIT / T 12 21 05. doc Page 5 of 6 !'"1 ~ ~ f1 ~ ~ ~ Printed: 22-Dec-05 ~tion for Permit to Drill, Well 1 Q-101 Revision No.O Saved: 22-Dec-05 1. Excavate cellar, install cellar box, set and cement 16" conductor to +/-110' RKB (2 joints). Install landing ring on conductor. 2. Move in /rig up Nordic #3. Install 21-114" Annular with 16" diverter line and function test. Notify AOGCC 24 hours prior to test. , 3. Spud and directionally drill 12-1/4" hole to casing point at +/- 2745' MD /2672' TVD as per directional plan. Run MWD/LWD (GR/RES)tools as required for directional monitoring. Mud log from base of the surface conductor to TD 4. Run and cement 9-518", 40 ppf, L-80, BTC casing to surface Displace cement with water base mud and, pressure test casing to 3000 psi for 30 minutes and record results. Perform top job if required. ~, 5. Remove diverter system, install 11" x 5,000 psi BOP's and test to 3000 psi (annular preventer to 1500 psi). Notify AOGCC 24 hrs before test. 6. PU 8-1/2" bit and drilling assembly, with MWD 8~ LWD (GR/Res/Neutron/Density). RIH, clean out cement to top of float equipment. Re-test casing if cement is tagged more than 100 feet above the float collar. 7. Drill out cement and between 20' and 50' of new hole. Perform formation integrity test to leak- off (or FIT if gradient reaches 16 ppg equivglent) recording results. Change over to the FLOPRO drill-in fluid. , 8. Directionally drill to TD at 4645' MD / 4463' TVD. Make short trip and condition hole/mud for E- line logs. 9. RU & run E-line logs per program. Currently planned are 1) a drill pipe conveyed MDT, 2) E-line conveyed Dipole Sonic/FMI and 3) percussion sidewall cores. 10. PU PS:A BHA, TIO and lay open hole cement plug§`acro s hydrocarbon bearing zones as discussed with AOGCC. ~{~~ ~~,~ r~ c~~~~ 11. Set cement retainer at 9-5/8" casing shoe and pump cement be ow and above the retainer per AOGCC regulations. 12. Set 300' cement surface plug per AOGCC regulations. 13. Nipple down the BOPE's and check top of cement. 14. Release rig to next well. 15. After drilling the three NEWS wells and the rig is released from the ice pad, the Toolhouse Techs will complete the surface P8cA's per AOGCC regulations, clean-up, and secure the ice pad. 14.Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An app/ication for a Permit to Drill mustc be accompanied by each of the following items, except for an item a/ready on file with the commission and identified m the application: (14) a genera/ description ofhow the operator p/ans to dispose ofdrilling mud and cu[tmgs and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular dispose/ operation m the weU.; Waste fluids generated during the drilling process will be disposed of by hauling the fluids to a KRU Class II disposal well. All cuttings generated will be disposed of by hauling to the Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well. 15.Attachments Attachment 1 Pre-Drill Seismic Fluid and Fracture Pressure Analysis for 1 H-North, 1 H-South, & 1 R-East Attachment 2 Directional Plan Attachment 3 Drilling Hazards Summary Attachment 4 Cement Data Attachment 5 Well Schematic Attachment 6 Proposed Ice Pad Configuration 1H-North PERMIT IT 12 21 05.doc Page 6 of 6 Printed: 22-Dec-05 ~~~~-~ . . i ~ i ) • i ._. ConocoPhillips Alaska ConocoPhillips Alaska (Kuparuk) Kuparuk River Unit NEWS ICEPAD Plan 1 H-N Plan: 1 H-N(wp01) Proposal Report 08 December, 2005 ~'~ ~ :~ S~perr~ ri~~in~ services ORIGINAL I~~p-S Al~aSk SHL@2276ftFNL&946ftFEL-Sec 15-T12N-R10E Project: Kuparuk River Unit Site: NEWS ICEPAD Well: Plan 1 H-N Wellbore: plan 1H-N Plan: 1 H-N(wpO1) KOP @ 1000ft MD, 1000ft TVD -Build @ 3°/100ft Sail @ 15°Inc & 33.52°Azi : 1500ft MD, 1494ft TVD Continue Build @ 3°/100ft , 1600ft MD, 1591ft TVD c_ O 0 t a N U r N N I- Base of Permafrost _ - - ~ - Sail @ 19.5° Inc : 1750ft MD, 1734ft TVD FORMATION TOP DETAILS NoNDPath MDPath Formation 1 1754.00 1771.09 Base of Permafrost 2 2672.00 2744.94 T3 + 675 3 3314.00 3426.00 Ugnu C 4 3601.00 3730.46 Ugnu B 5 3856.00 4000.98 K13 6 3956.00 4107.06 WSAK D 7 4017.00 4171.77 WSAK B 8 4107.00 4267.25 WSAK A3 9 4167.00 4330.90 WSAK A2 10 4367.00 4543.06 WSAK Base T3 + 675 CASING DETAILS No TVD MD Name Size 1 2672.00 2744.94 9518" 9-5/8 9 5/8" Casing @ 2745ft MD, 2672ft TVD 19° Ugnu C Ugnu B _ _ K13 WSAK D =-----------WSAKB --------------------------... Top West Sak @ 4109ft MD, 3958ft TVD 1H-N {Top WS}{wp01} -. , , -------------------------------------------- -- WSAK A3 WSAK A2 WSAK Base -1250 -1000 -750 -500 -250 0 250 500 750 1000 Vertical Section at 33.52' {5OQ ftlin) - TD @ 4645ft MD,4463ft TVD ' t.t.l t.J fi Sperr'Y Owtliing 8arvic+fss 1250 1500 1750 2000 2250 ~R~r~na~i__ ~~ i/1 ~ s INNINt i L Z >aZ=o r Yc?~=3 2cn maZ ~Wadr YZ-o N~ C dy~~ a .O a M ~O 1 1 1 1 II i /. i i i i i i i i i 1 0 T Y l0 N a F- n i a y I 1 in I w ~, `n cx. m ~ ~ ~ ~ S n a F' Z S OD N_ 1n f/1 W J ~ O a Z~ 0 ov U ~ °'• Z N N U ~ °o, n N Zr y Q A d C c+~ty ~ ~ p~Um OfaQQ N~ ~ ~ 1~7M Ci YA aM-~4~Q~Q~ o LLm~»x3333 O_ a~'a .®oohrr~ori h V N M O O h O M 7 C- ~ hh~hOr rN MIfS Q g rN M s~~ ~~ RR ~ ~ooooo00000 ~ ~oooaoo0oao u. a.~c~iv~idui~:r:rr ~Pf~OMN~O~f O~rM }rN MMMM'Q d' V V t2 rNM~t[f 10 ha001r N N G N I 1 ~ I I 11 1 I 1 \ II I (~!M 096) ~+)4~oN/t-)4~noS ~' V T M h O h r U C Qf (~ 1 1\ CQC L 0 0 r Q !M M C ~I N I 1 Z N_ H T I ~ I r '1 J W LL I ~ 1 ~ ~I ~ I I 1 J I Z I LL 1 ~+ I ~ I I N I N I I J I 1 N I I I I I I I I I I I I 1 I I I I 11 II I II II II I ~ II ~ 1 ~ 1 I 1 I ~ I I ~ 1 I ~ 1 I 1 1 I ~ 1 1 ~ I I ~ 1 I 1 I ~ 1 I ~ 1 I ~ 1 I ~ I I ~ I I ~ 1 I 1 1 I \ 1 I \ 1 I ~ 1 I 1 1 1 1 I 1 I I \ 1 I \ 1 I \ 1 I 1 I 1 I I L~ UF'~fO LLS p N d~~ 0 0 Z a LL ~ O N N ~N yn~~~ e= d~ ~cc~ ~o m~°' m $ Z ~ L Q ~~a~m ~d m0°°o s~ ~, ~ h O O N a0 h h ~ ~ ~ but O ~" M ~ ~~ _ ~ {~ v c_ 0 h M ~. N W °o ~% M N N N N h O r N O M h M _ . ~ Halliburton Energy Services C " 4 ~~1 PE" L ~. 11.1 (M flt lOC S 1 Planning Report -Geographic Alaska Sp~lrry M~dillf~tg S®rviCes Database: EDM 2003.11 Single User Db Local Co-ordinate Reference: Well Plan 1 H-N Company: ConocoPhillips Alaska (Kuparu k) TVD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) Project: Kuparuk River Unit MD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) Site: NEWS ICEPAD North Reference: True - Well: Plan 1H-N Survey Calculation Method: Minimum Curvature Wellbore: Plan 1 H-N Design: 1 H-N(wp01) Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor --- -- Well Plan 1 H-N Well Position +N/-S +E/-W Position Uncertainty --- 0.00 ft Northing: 5,994,301.00 ft 0.00 ft Easting: 554,555.00 ft 0.00 ft Wellhead Elevation: ft Latitude: Longitude: Ground Level: 70° 23' 42.431" N 149° 33' 21.982" W 50.00 ft Wellbore Plan 1 H-N Magnetics Model Name Sample Date Declination Dip Angle Field Strength BGGM2005 1/15/2006 24.253 80.854 57,571 Design 1 H-N(wp01) __-- - --_ Audit Notes: Version: Phase: PLAN Tie On Depth: 30.00 Vertical Section: Depth From (TVD) +N!-S +E/-W Direction (ft) (ft) lft) (°) 30.00 0.00 O.UO 33.52 Plan Summary Measured Vertical Dogleg Build Turn Depth Inclination Azimuth Depth +N/.g +E/-W Rate Rate Rate TFO (ft) (°) (°) (ft) (ft) (ft) (°I100ft) (°/100ft) (°/100ft) (°) 30.00 0.000 0.00 30.00 0.00 0.00 0.00 0.00 0.00 0.000 1,000.00 0.000 0.00 1,000.00 0.00 0.00 0.00 0.00 0.00 0.000 1,500:00 15.000 33.52 .1,494.31 54.25 35.94 3.00 3.00 0.00 33.520 1,600.00 15.000 33.52 1,590.90 75.83 50.23 0.00 0.00 0.00 0.000 1,749.95 19.498 33.52 1,734.07 112.89 74.78 3.00 3.00 0.00 0.013 4,109.18 19.498 33.52 3,958.00 769.38 509.68 0.00 0.00 0.00 0.000 4,545.19 19.498 33.52 4,369.00 890.70 590.05 0.00 0.00 0.00 0.000 4,645.19 19.498 33.52 4,463.27 918.53 608.48 0.00 0.00 0.00 0.000 12/8/2005 9:13:39AM Page 2 of 5 COMPASS 2003.11 Build 48 ~Ot"tOCQ~'~'11~~1 ~1S ~3S{t~3 Halliburton Ener Services 9Y Planning Report- Geographic Database: EDM 2003.11 Single User Db Company: ConocoPhillips Alaska (Kuparuk) Project: Kuparuk River Unit Site: NEWS ICEPAD Well: Plan 1H-N Wellbore: Plan 1H-N Design: 1 H-N(wp01) Planned Survey 1 H-N(wp01) ~~~~.e: Sperry ~rtlling Servfces Local Co-ordinate Reference: Well Plan 1H-N TVD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) MD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) North Reference: True Survey Calculation Method: Minimum Curvature MD Inclination Azimuth TVD SSTVD (ft) (°) (°) (ft) (ft) 30.00 0.000 0.00 30.00 -50.00 SHL@2276ftFNL8~946ftFEL-Sec 15-T12N-R10E 100.00 0.000 0.00 100.00 20.00 200.00 0.000 0.00 200.00 120.00 300.00 0.000 0.00 300.00 220.00 400.00 0.000 0.00 400.00 320.00 500.00 0.000 0.00 500.00 420.00 600.00 0.000 0.00 600.00 520.00 700.00 0.000 0.00 700.00 620.00 800.00 0.000 0.00 800.00 720.00 900.00 0.000 0.00 900.00 820.00 1,000.00 0.000 0.00 1,000.00 920.00 KOP @ 1000ft MD, 1000ft TVD - Build @ 3°/100ft 1,100.00 3.000 33.52 1,099.95 1,019.95 1,200.00 6.000 33.52 1,199.63 1,119.63 1,300.00 9.000 33.52 1,298.77 1,218.77 1,400.00 12.000 33.52 1,397.08 1,317.08 1,500.00 15.000 33.52 1,494.31 1,414.31 Sail @ 15°Inc & 33.52°Azi : 1500ft MD, 1494ft TVD 1,600.00 15.000 33.52 1,590.90 1,510.90 Continue Build @ 3°/100ft , 1600ft MD, 1591ft TVD 1,700.00 18.000 33.52 1,686.77 1,606.77 .1,749.95 19.498. 33.52 1,734.07 1,654.07 Sail @ 19.5° Inc : 1750ft MD, 1734ft TVD 1,771.09 19.498 33.52 1,754.00 1,674.00 Base of Permafrost Map Map +NI_S +E/_W Northing Easting DLSEV Vert Section (ft) (ft) (ft) (ft) (°I100ft) (ft) 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00. 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 0.00 0.00 5,994,301.00 554,555.00 0.00 0.00 2.18 1.45 5,994,303.19 554,556.43 3.00 2.62 8.72 5.78 5,994,309.76 554,560.71 3.00 10.46 19.60 12.98 5,994,320.70 554,567.84 3.00 23.51 34.79 23.05 5,994,335.96 554,577.79 3.00 41.74 54.25 35.94 5,994,355.51 554,590.54 3.00 65.08 75.83 50.23 5,994,377.19 554,604.67 0.00 90.96 99.51 65.91 5,994,400.98 554,620.18 3.00 119.36 112.89 74.78 5,994,414.42 554,628.95 3.00 135.41 118.77 78.68 5,994,420.33 554,632.80 0.00 142.47 1,800.00 19.498 33.52 1,781.25 1,701.25 126.82 84.01 5,994,428.42 554,638.07 0.00 152.12 1,900.00 19.498 33.52 1,875.51 1,795.51 154.64 102.44 5,994,456.37 554,656.30 0.00 185.50 2,000.00 19.498 33.52 1,969.78 1,889.78 182.47 120.87 5,994,484.33 554,674.53 0.00 218.87 2,100.00 19.498 33.52 2,064.04 1,984.04 210.30 139.31 5,994,512.29 554,692.76 0.00 252.25 2,200.00 19.498 33.52 2,158.31 2,078.31 238.12 157.74 5,994,540.24 554,710.98 0.00 285.63 2,300.00 19.498 33.52 2,252.57 2,172.57 265.95 176.17 5,994,568.20 554,729.21 0.00. 319.01 2,400.00 19.498 33.52 2,346.84 2,266.84 293.78 194.61 5,994,596.16 554,747.44 0.00 352.39 .2,500.00. 19.498 33.52 2,441.10 2,361.10 321.60 213.04 5,994,624.12 554,765.67 0.00 385.77 2,600.00 19.498 33.52 2,535.37 2,455.37 349.43 231.48 5,994,652.07 554,783.90 0.00 419.14 2,700.00 19.498 33.52 2,629.63 2,549.63 377.25 249.91 5,994,680.03 554,802.13 0.00 452.52 2,744.94 19.498 33.52 2,672.00 2,592.00 389.76 258.19 5,994,692.60 554,810.32 0.00 467.52 9 5/8" Casing @ 2745ft MD, 2672ft TVD -1616 ft FNL & 685 ft FEL -Sec 15 - T72N - R10E - T3 + 675 - 9 5/8" 2,800.00 19.498 33.52 2,723.90 2,643.90 405.08 268.34 5,994,707.99 554,820.36 0.00 485.90 2,900.00 19.498 33.52 2,818.16 2,738.16 432.91 286.78 5,994,735.95 554,838.58 0.00 519.28 3,000.00 19.498 33..52 2,912.43 2,832.43 460.73 305.21 5,994,763.90 554,856.81 0.00 552.66 3,100.00 19.498 33.52 3,006.69 2,926.69 488.56 323.65 5,994,791.86 554,875.04 0.00 586.03 3,200.00 19.498 33.52 3,100.96 3,020.96 516.38 342.08 5,994,819.82 554,893.27 0.00 619.41 3,300.00 19.498 33.52 3,195.22 3,115.22 544.21 360.51 5,994,847.77 554,911.50 0.00 652.79 3,400.00 19.498 33.52 3,289.49 3,209.49 572.04 378.95 5,994,875.73 554,929.73 0.00 686.17 12/8/2005 9:13:39AM Page 3 of 5 COMPASS 2003.11 Build 48 f E s Halliburton Energy Services CClilt~Ct~Phl~1~75 Planning Report -Geographic Alaska Database: EDM 2003.11 Single User Db Company: ConocoPhillips Alaska (Kuparuk) Project: Kuparuk River Unit Site: NEWS ICEPAD Well: Plan 1 H-N Wellbore: Plan 1H-N Design: 1H-N(wp01) i Planned Survey 1H-N(wp01) W1~.~~.~ ~ "N" ~k Sherry Drlrlltng Sgrvi~es Local Co-ordinate Reference: Well Plan 1 H-N TVD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) MD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) North Reference: True Survey Calculation Method: Minimum Curvature Map Map MD Inclination Azimuth TVD SSTVD +N/~ +E/_yy Northing Fasting (ft) (°) (°) (ft) (ft) (ft) (ft) (ft) lft) 3,426.00 19.498 33.52 3,314.00 3,234.00 579.27 383.74 5,994;883:00 554,934.47 Ugnu C 3,500.00 19.498 33.52 3,383.75 3,303.75 599.86 397.38 5,994,903.69 554,947.96 3,600.00 19.498 33.52 3,478.02 3,398.02 627.69 415.82 5,994,931.65 554,966.18 3,700.00 19.498 33.52 3,572.28 3,492.28 655.52 434.25 5,994,959.60 554,984.41 3,730.46 19.498 33.52 3,601.00 3,521.00 663.99 439.86 5,994,968.12 554,989.96 Ugnu B 3,800.00 19.498 33.52 3,666.55 3,586.55 683.34 452.68 5,994,987.56 555,002.64 3,900.00 19.498 33.52 3,760.81 3,680.81 711.17 471.12 5,995,015.52 555,020.87 4,000.00 19.498 33.52 3,855.08 3,775.08 738.99 489.55 5,995,043.48 555,039.10 4,000.98 19.498 33.52 3,856.00 3,776.00 739.27 489.73 5,995,043.75 555,039.28 K13 4,100.00 19.498 33.52 3,949.34 3,869.34 766.82 507.98 5,995,071.43 555,057.33 4,109.18 19.498 33.52 3,958.00 3,878.00 769.38 509.68 5,995,074.00 555,059.00 Top West Sak @ 4109ft MD, 3958ft TVD -1385 ft FNL & 355 ft FEL -Sec 15 -T12N - R1 OE -1 H-N (Top WS)(wp01) 4,171.77 19.498 33.52 4,017.00 3,937.00 786.79 WSAK B 4,200.00 '19.498 33.52 4,043.61 3,963.61 794.65 4,267.25 19.498 33.52 4,107.00 4,027.00 813.36 WSAK A3 4,300.00 19.498 33.52 4,137.87 4,057.87 822.47 4,330.90 19.498 33.52 4,167.00 4,087.00 831.07 WSAK A2 4,400.00 19.498 33.52 4,232.14 4,152.14 850.30 4,500.00 19.498 33.52 4,326.40 4,246.40 878.13 4,543.06 19.498 33.52 4,367.00 .4,287.00 890.11 WSAK Base 521.22 5,995,091.50 555,070.41 526.42 5,995,099.39 555,075.55 538.81 5,995,118.19 555,087.81 544.85 5,995,127.35 555,093.78 550.55 5,995,135.99 555,099.42 563.29 5,995,155.30 555,112.01 581.72 5,995,183.26 555,130.24 589.66 5,995,195.30 555,138.09 DLSEV Vert Section (°/100ft) (ft) 0:00 694.85 0.00 719.55 0.00 752.93 0.00 786.30 0.00 796.47 0.00 819.68 0.00 853.06 0.00 886.44 0.00 886.76 0.00 919.82 0.00 922.88 0.00 943.77 0.00 953.19 0.00 975.64 0.00 986.57 0.00 996.89 0.00 1,019.95 0.00 1,053.33 0.00 1,067.70 4,600.00 19.498 33.52 4,420.67 4,340.67 905.95 600.15 5,995,211.22 555,148.47 0.00 1,086.71 ~ 4,645.19 19.498 33.52 4,463.27 ~ 4,383.27 918.53 608.48 5,995,223.85 555,156.71 0.00 1,101.79 TD @ 4645ft MD, 4463ft TVD : 1357 ft FNL & 336 ftFEL -Sec 15 - T12N - R10E 12/8/2005 9:13:39AM Page 4 of 5 COMPASS 2003.11 Build 48 ~~~~'~ H I I' b r't E S , a i u on nergy ervices .~~~ Ct"i1"1000~'~'II~~t~?S Planning Report -Geographic Alaska Database: EDM 2003.11 Single User Db Company: ConocoPhillips Alaska (Kuparuk) Project: Kuparuk River Unit Site: NEWS ICEPAD Well: Plan 1H-N Wellbore: Plan 1 H-N Design: 1 H-N(wp01) Geologic Targets PIan1H-N Sperry flrillittg 5enr~ces Local Co-ordinate Reference: Well Plan 1H-N TVD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) MD Reference: Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) North Reference: True Survey Calculation Method: Minimum Curvature ND Tart~~~i~,ae +N/-S +E/-W Northing Easting j (ft) - Sha~~ ft ft (ft) (ft) ~ 4,369.00 111-N {Base WS}{~yp01} 769.38 509.68 5,995,074.00 555,059.00 - Point 3,958.00 1H-N {Tap S)(wp01} 769.38 509.68 5,995,074.00 555,059.00 - Point Prognosed Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter ~ {ft) {ft) {'~) {") 2,744.94 2,672.00 9-5/8 12-1/4 f Prognosed Form tion Intersection oints _ _ --- __ - Measured Vertical Depth Inclination Azimuth Depth +N/-E +E/•W Name I 1,771.09 19.50 33.52 1,754.00 118.77 78.68 Base of Permafrost 2,744.94 19.50 33.52 2,672.00 389.76 258.20 T3 + 675 3,426.00 19.50 33.52 3,314.00 579.27 383.74 Ugnu C 3,730.46 19.50 33.52 3,601.00 663.99 439.86 Ugnu B 4,000.98 19.50 33.52 3,856.00 739.27 489.73 K18 4,107.06 19.50 33.52 3,956.00 768.78 509.29 WSAK D 4,171.77 19.50 33.52 4,017.00 786.79 521.22 WSAK B 4,267.25 19.50 33.52 4,107.00 813.36 538.81 WSAK A3 4,330.90 19.50 33.52 4,167.00 831.07 550.55 WSAK A2 4,543.06 19.50 33.52 4,367.00 890.11 589.66 WSAK Base 12/8/2005 9:13:39AM Page 5 of 5 ~~ G ~~' ~~ COMPASS 2003.11 Build 48 • • ConocoPhillips Alaska ConocoPhillips Alaska (Kuparuk) Kuparuk River Unit NEWS ICEPAD Plan 1 H-N Anticollision Summary 08 December, 2005 ~~ ~~~~.. ~~E'Ct'°~ ~ri~~111~ ~!r1fIC~S- ~ ~n <~ _ ; ~,,.. ~•-' • Halliburton Ener Services ~" ConoCt~-Phli~'t ~ 9Y ~~ a Anticollision Report Company: ConocoPhillips Alaska (Kuparuk) Project: Kuparuk River Unit Reference Site: NEWS ICEPAD Site Error: O.OOft Reference Well: Plan 1 H-N Well Error: O.OOft Reference Wellbore Plan 1 H-N Reference Design: 1 H-N(wp01) Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: ~.~"~` - Sperry prilffng Serv"tcss Well Plan 1 H-N Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) Initial Plan RKB @ 80.OOft (Nordic 3 (30+50)) True Minimum Curvature 2.00 sigma EDM 2003.11 Single User Db Offset Datum Reference 1 H-N(wp01) Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referE Interpolation Method: MD Interval 50.OOft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Trav, Cylinder North Results Limited by: Maximum center-center distance of 661.52ft Error Surface: Elliptical Conic Warning Levels evaluated at: 0.00 Sigma Survey Tool Program Date 12/8/2005 From To (ft) (ft) Survey (Wellbore) Tool Name Description 30.00 4,645.19 1 H-N(wp01) (Plan 1 H-N) MWD MWD -Standard Summary Site Name Offset Well -Wellbore -Design NEWSICEPAD Plan 1 H-S -Plan 1 H-S - 1 H-S (wp01) Plan 1 R-E -Plan 1 R-E - 1 R-E (wp01) Reference Offset Centre to Measured Measured Centre Depth Depth Distance (ft) (ft) (ft) 349.99 350.00 20.62 299.99 300.00 '19.98 No-Go Allowable Distance Deviation Warning (ft) from Plan (ft) 5.87 14.74 Pass -Major Risk 5.07 14.91 Pass - MajorRisk CC -Min centre to center distance or covergent point, SF -min separation factor, ES -min ellipse separation 12/8/2005 9:34:39AM Page 2 of 2 COMPASS 2003.11 Build 48 ~~~ ~, ~~ SURVEY PROGRAM Date: 200512-O8T00:00:00 Validated: Yea Version: Depth From Depth T° Survey/Plan Tool 30.00 4645.19 1H-N(wp01) MR'D ConocoPhillips Alaska (Kuparuk) Drilling & Wells Slot West Sak Calculatlon Method: Minimum Curvature Enor System: ISCWSA Scan Method: Tnw. Cylinder North Error Surface: EIIipOcal Conic gg, Warning Method: Rules Based 330 30 25 Plan 1H i - 20 i ~~ 300 60 1 ~ i 1 i i 270 90 y. 5 ~ i i ', ~. ~ 1 ~ i i - M z7a ~. so 15 11240 120 i 3 i 2 ~ ~~ ~ '. - Plan 1R-E s ~ r f ~ 25 ~~ ~ ~ I 210 150 , 30 240 _ 90 ~ X ~_~. 120 l ~ 180 PI 1 H S Travelling Cylinder Az(muth (TFO+AZI) [°] vs Centre to Centre Separation [15 ft/in] 12 an F rom Colour To MD 15 30 250 210 '150 250 500 500 750 750 1000 180 1000 1250 1250 1500 1500 1750 1750 2000 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Centre to Centre Separation [75 ft/in] 2000 z25o 2250 ' 2500 2500 2750 2750 3000 3000 3250 3250 3500 REFERENCE INFORMATION 3500 3750 Coordinate (tUE) Reference: Well Plan 1H-N, True North 3750 4000 Vertical (ND) Reference: IniOal Plan RKB @ 80.OOk (NoMic 3 (30+50)) 4000 4250 Section (VS) Reference: Slot-(O.OON, O.OOE) 4250 4500 Measured Depth Reference: Initial Plan RKB ~ 80.OOR (Nordic 3 (30+50)) Calculatlon Method: Minimum Curvature 4500 4750 SECTION DETAILS Sac MD Inc Azi TVD +N/S +E/-W DLeg TFace VSec Target 1 30.00 0.000 0.00 30.00 0.00 0.00 0.00 0.000 0.00 2 1000.00 0.000 0.00 1000.00 0.00 0.00 0.00 0.000 0.00 3 1500.0015.000 33.52 1494.31 54.25 35.94 3.00 33.520 65.08 4 1600.0015.000 33.52 1590.90 75.83 50.23 0.00 0.000 90.96 5 1749.9519.498 33.52 1734.07 772.89 74.78 3.00 0.013 135.41 6 4109.1819.498 33.52 3958.00 769.38 509.68 0.00 0.000 922.88 1H-N (Top WS)(wp01) 7 4545.1919.498 33.52 4369.00 890.70 590.05 0.00 0.000 1068.41 8 4645.1979.498 33.52 4463.27 918.53 608.48 0.00 0.000 1101.79 NAD 27 ASP Zone 4 : WELL DETAILS: Plan 7 H-N ANTI-COLLISION SETTINGS Ground Level: 50.00 Interpolation Method: MD Interval: SOStations +WS +E/-W Northing EasOng Latittude Longitude Depth Range From: 30.00 To 4045.19 0.00 0.00 5994301.00 554555.00 TO°23'42.431N 149°33'21.982W Maximum Range:661.518646329611 Reference: Plan: 1H-N(wp01) • • 1_H-North Drilling Hazards Summary 12-1/4" Oaen Hole / 9-5/8" Casing Interval Hazard Risk Level Miti ation Strate Broach of Conductor Low Monitor cellar continuously during interval. Gas Hydrates Moderate Control drill, Reduced pump rates, Reduced drilling fluid temperatures, Additions of Driltreat. Running Sands and Moderate Maintain planned mud parameters, Gravels Increase mud weight, use weighted swee s. Hole swabbing on trips Moderate Trip speeds, Proper hole filling (use of trip sheets , um in out 8-1/2" Open Hole to TD Hazard Risk Level Miti ation Strate Running Sands and Moderate Maintain planned mud parameters, Gravels Increase mud weight, use weighted swee s. Stuck Pipe Low Good hole cleaning, Pretreatment with Lost Circulation Material, stabilized BHA, Decreased mud wei ht Abnormal Reservoir Low BOP training and drills, increased mud Pressure wei ht. Lost circulation Low Reduced um rates, mud rheolo , LCM Hole swabbing on trips Moderate Trip speeds, Proper hole filling (use of trip sheets , um in out 1H-North Drilling Hazards Summary prepared by TJB 12/21/05 ~~~rt CemCADE Preliminary Job Design. 9 5/8" Surface Casing on purposes Rig: Nordic 3 Location: NEWS Client: ConocoPhillips Alaska, Inc. Revision Date: 12/21/2005 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 263-4207 Mobile: (907) 748-6900 email: martin13@slb.com < TOC at Surface Previous Csg. < 16", 62.6# casing at 80' MD < Base of Permafrost at 1,772' MD (1,754'rvD) Volume Calculations and Cement Systems Volumes are based on 250% excess in the permafrost and 40% excess below the permafrost. The top of the tail slurry is designed to be at 1,945' MD. Lead Slurry Minimum pump time: 200 min. (pump time plus 90 min.) ARCTICSET Lite @ 10.7 ppg - 4.45 ft3/sk 0.7632 ft3/ft x (80') x 1.00 (no excess) = 61.1 ft3 0.3132 ft3/ft x (1772' - 80') x 3.50 (250% excess) = 1854.8 ft3 0.3132 ft3/ft x (1945' - 1772') x 1.40 (40% excess) = 75.9 ft3 61.1 ft3 + 1854.8 ft3+ 75.9 ft3 = 1991.8 ft3 1991.8 ft3 / 4.45 ft3/sk = 456.7 sks Round up to 460 sks Have 250 sks of additional Lead on location for Top Out stage, if necessary.. Tail Slurry Minimum pump time: 140 min. (pump time plus 90 min.) DeepCRETE @ 12.0 ppg - 2.52 ft3/sk 0.3132 ft3/ft x (2745' - 1945') x 1.40 (40% excess) = 350.8 ft3 0.4257 ft3/ft x 80' (Shoe Joint) = 34.1 ft3 350.8 ft3 + 34.1 ft3 = 384.9 ft3 384.9 ft3/ 2.52 ft3/sk = 152.7 sks Round up to 160 sks BHST = 54°F, Estimated BHCT = 67°F. (BHST calculated using a gradient of 2.6°F/100 ft. below the permafrost) PUMP SCHEDULE Pump Rate Stage Stage Time Cumulative Stage (bpm) Volume (min) Time (bbll (mint < Top of Tail at 1,945' MD < 9 5/8", 40.0# casing in 12 1/4" OH TD at 2,745' MD (2s7z' rvD) Y Mark of Schlumberger CW100 5.0 10.0 2.0 2.0 Pressure test lines 0.0 0.0 10.0 12.0 CW100 5.0 40.0 8.0 20.0 Drop bottom plug 0.0 0.0 5.0 25.0 MUDPUSH II 5.0 50.0 10.0 35.0 ASL 7.0 354.7 50.7 85.7 DeepCRETE 5.0 68.6 13.7 99.4 Drop top plug 0.0 0.0 5.0 104.4 Water 5.0 20.0 4.0 108.4 Switch to rig 0.0 0.0 5.0 113.4 Mud 7.0 173 24.7 138.1 Slow & bump plug 3.0 9 3 141.1 MUD REMOVAL Recommended Mud Properties: 9.6 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 10.5 ppg MudPUSH* II, Pv ? 17-21, Ty ? 20-25 Centralizers: Recommend 1 per joint across zones of interest for proper cement placement. 300' Cement surface P8~A plug per AOGCC Regs Wellhead: FMC Gen V Conductor: 16" set at 110' MD Fluid: Kill Weight Mud in Casing 1 H North NEWS Well Schematic Nordic Rig 3 Floor RKB=30' 50' Cement plug on top of retainer per 's ~. ~.~ ~(-~` Cement retainer ~~ ~, and plug across „~ .. ~ ~ ~ ~ ~ ~ ~ Fluid: Drilling mud TD 8-1 /: 4645'MD/4463' TVD = as indicated in Directional Plan Cement Plug(s) across hydrocarbon bearing zones ConocoPhilli $ Generic Off- Ice NEWS Wells Sheet 1 of 1 Schematic modified by TJB Alaska 12/21/2005 AOGCC regs TD 12'/<" Surface Hole drilled to 2745'MD/2672' TVD as indicated in Directional Plan S191NAL ~~ i REV DATE BY CK APP DESCRIPTION REV DATE BY .APP DESCRIPTION 3 w ,8 - ,7 ~ ° ,6 ,5 Pr os WE SA ;DS-1R ,~ `n1 4 19 •~ S 201 ~, 21 2 ~ 23 24 `yam N 29 'S 30 ~~~''~ % ~ ~a 27 26 25 5 1 36 ,I' 3, 32 33 34 35 36 S ~~ e T12N ~ KI ~ ~T11 N 6 DS-1A• 3 e Sak ' Pr ucti SCALE; " ' 2 MIN C ~ 7 e °CPF- ~~ ~. ADS 1C 9 „~ ,2 1 = 200 ~ `~ VICINITY MAP Scale: 1" = 2 Mile ~ -o 50° o 20 ~, 160 ~ o ~R~F 1y, ~ s ~y -o °X, 'N s ~~ti1~o J~psFec M~. 0 0 oWr o o va g~oW ~~r ~ go,\e:, J d ^ OO 1 ( w°stN ~R~~C o~y ~ 35' \ce I N N q Q~ ~~ ~~ ~ a ~ ~ ' ~A O o X ~o,F ~~ o~ 00 N NOTES: 1. Y,X COORDINATES ARE ASP, ZONE 4, NAD 27 . 2. GEODETIC COORDINATES ARE NAD 27. POINT Y X LATITUDE LONGITUDE 1R-E 5,994,294 554,537 70' 23' 42.36" 149' 33' .22.52" LOUNSBURY 1 H-N 5,994,301 - 554,555 70' 23' 42.43" 149' 33' 21.97" & nssoc><a~s, n1c. 1 H-S 5,994,308 554,574 70' 23' 42.49" . 149' 33' 21.42" SURVEYORS 6NGINEBIt4 PLANNERS ~ `/ AREA: MODULE: UNIT: ConoeoPh i I I i s WEST SAK NEWS WELLS p GGRE ICE PAD Alaska, Inc. PROPOSED CONFIGURATION CALK601D623 9 8 05 DRAWING NO: NSK 6.O1-C16Z3 PART: 1 OF 1 REV:O C ~' PETROLEUM __ Alan R. Huffman, PhD President (281)-363-4903 (office) (281)-744-4338 (Cellular) December 14, 2005 David Sheley ConocoPhillips Alaska Anchorage, AK • TECHNOLOGIES I N C . Re: West Sak Geopressure and Hazards Project (#0033-05001) Dear David: 25231 Grogan's Mill Rd, Suite 175 The Woodlands, TX 77380 (281)-363-4657 (fax) huffman@fusiongeo.com EEIVE® SEC ~ 2005 Alaska Oil ~ Ors Gans. Commission Ancharag~ I am pleased to present to you the final report for the West Sak Geopressure. and Shallow Hazards Project. We have updated the report to show arbitrary lines through each of the 3 proposed well paths. Please feel free to call me or Dr. Rick Lahann if you have any questions regarding the report. I will be in the office during the holiday season, so I can be reached via email or at the phone numbers above. Sincerely, .,,._ Dr. Alan R. Huffman President Cc: Lisa Isaacson, Jeff Martin, file OR161NAL • • Subject: Pre-Drill Seismic Fluid and Fracture Pressure Analysis for Proposed NEWS 1H North,lH_South and 1R East Prospects Introduction• The purpose of this project is to provide 3D fluid and fracture pressure interpretation and shallow hazard analysis on a 3D velocity volume containing the NEWS prospects, in Alaska. The velocity and seismic volume contained the 1 H North, the 1 H_South and the 1R East prospects, as well as the 1H_105, the 1H_06, the 1R 07, the West Sak_25 and the MPU_S_15 wells. The MPU_S_15 well was reported by ConocoPhillips-Anchorage ~~ -ate! ~ to possibly have contained shallow hydrates, based on oral communications from the operator (BP), but no specific data regarding depths of occurrence for hydrate were provided. Ac~~`z~~ ~Q~~- ~~ ~~~~:`~~y S~c~~a. ~l~~-0~.. Summary: '^° Qcvh®~ ~s , M~~ ~v~ ~.3 ~o ~ . \ ` `,~.C~9yv~ ~a j~ »~ ~~c~.S~`~ o ~ ~. ~ M P \~ ~-.~ ~~\s ~ars..l cx~~ o o. PQL ~ - Interpretation of the velocity cube with calibrated velocity/stress functions showed no ' development of excess fluid pressure near the NEWS prospects within the proposed drilling depths. A small fluid pressure increase was interpreted between 5000 and 6000 -- feet and below 7500 feet. The three prospects have TD depths between 4200 and 4500 feet which are above the zone of minor pressure increase. The interval velocity, fluid pressure gradient and fracture pressure gradient interpretations along lines A-A' and B-B' (Figure 1) are shown on Figures 2-7. The velocity and reflection character of the seismic data were examined for any indications of shallow gas hazards or hydrate development. Two shallow zones with ' slightly anomalous amplitude character over a restricted number of seismic traces were observed near the NEWS_1H_South location (Figure 9). The amplitude anomalies were not confirmed by corresponding velocity anomalies. The presence of a fast and shallow permafrost interval overlying much slower water and hydrocarbon bearing intervals makes recognition of shallow, gas-bearing intervals very problematic. Such intervals could be hidden within the rapid velocity reduction between the base of the permafrost, +/- 1800 feet, and the top reservoir zone at +/- 3000 feet. Seismic Processing: The velocity volume was processed prior to delivery to Fusion by the AVEL interval velocity extraction program. Figures 9 and 10 display underlays of the original velocity data along lines A-A' and B-B'. Some regions within this data set had velocities substantially slower than the log data indicated were reasonable, for example velocities less than 5300 feet/second at a depth of .7 seconds. The data set also displayed narrow vertical streaks of velocities substantially different than nearby velocities along both strike and dip. Anomalously slow velocities were frequently underlain by anomalously fast velocities, which are commonly observed in seismic data sets where velocity picks ORIGINAL • • are not robust. These data quality issues extend throughout the data set. To address this issue, the original velocity set was conditioned by first clipping velocities below 6500 feet/second to a minimum value 6500 feet/second followed by a 33 x 33 CDP spatial filter to stabilize the trace to trace variations that appeared to be non-physical in character. The filtered velocity volume (Figures 2 and 3) was used as input to the fluid/fracture pressure and shallow hazard interpretation. Potential for the Presence of Shallow Gas, Gas Hydrates and Seismic Pressure Prediction The potential for shallow gas accumulation or gas hydrates at the prospect locations is considered low. Figures 2 and 3 show no anomalously fast or slow velocities near the prospects, which might suggest either gas accumulation or hydrate development. However, the rapid velocity decrease between 0.5 and 0.8 seconds (+/- 1800 and 3000 feet) makes recognition of velocity anomalies very difficult. The seismic reflection data at well MPU_S_15 shows poor continuity, which might suggest patchy gas accumulation and/or hydrate development. The erratic velocity distribution associated with such occurrences might prevent proper stacking of the data and disrupt reflector continuity. No such reflectivity break-ups are observed at the prospect locations. The good reflector continuity suggests no unusual fluid/cement occurrences near the prospects. The reflection character of the seismic data were examined for any indications of shallow gas hazards or hydrate development. Two shallow zones with slightly anomalous amplitude character over a restricted number of seismic traces were observed near the ' NEWS_1H_South location (Figure 9). The deeper of the two zones extends just over to the NEWS_1H_North location. The amplitude anomalies were not confirmed by corresponding velocity anomalies, so they could be lithologic or of some other origin. However, it is also possible that these shallow zones could contain some free gas. There _` is no evidence from either the velocity or reflectivity data that hydrates are present at the proposed drilling locations. Pressure Prediction Procedure Regional and local MDT data and mud weight profiles were used to constrain an interpretation of the fluid pressure profiles in the control wells (Figures 11 and 12). The fluid pressure data show a strong correlation with a hydrostatic pressure profile of .455 psi/foot (8.7 ppg), originating at sea level. The two local wells with MDT data, the W Sak 25 and the 1H_105 wells have MDT data within about 40 psi (+/- .2 ppg) of the regional gradient. At least part of the elevated pressure in these wells can be attributed to hydrocarbon displacement pressure and does not indicate an increased aquifer or shale fluid pressure. ORIGINAL • • The mud weight data indicate that the reservoir intervals, roughly 2800 to 4000 feet (see Figure 12), were drilled with mud weights between 9.2 and 10 ppg. These mud weights are consistent with the MDT data and indicative of near hydrostatic conditions in the region, down to a depth of at least 4000 feet subsea. The fluid pressure gradient for the aquifer is about .445 psi/foot (8.7 ppg). Well log density data (Figure 13) were used to generate alocally-calibrated overburden (vertical stress) profile (Figure 14). Vertical stress (OBG) in psi is represented as, (1) OBG = .00057*d^i.oss*1000, where d is depth in feet. Effective stress/depth profiles were generated at the control wells by assuming the vertical stress profile (Figure 14) and hydrostatic conditions (Figure 11) to a depth of at least 4000 feet. The conditioned seismic interval velocity data were used to establish interval velocity/effective stress relationships at the control wells. The velocity data were imported at 100% of their interpreted values, rather than the 90% procedure commonly employed. Comparison of interval velocity profiles with sonic log and check shot profiles indicates that the 100% interval velocity data ranged from good agreement with the sonic log (Figure 15, MPU S_15 well) to substantial disagreement (Figure 16, 1R 07 well). Figure 17 displays the time/depth relationship from the checkshot profile at the 1 R_071ocation, along with the time/depth relationship calculated from the 100% interval velocity data. The maximum depth deviation is about 100 feet which was considered an acceptable depth match. Figures 18 displays the checkshot and interval velocity depth-velocity profiles for the 1H_105 well. The velocity match is fair, but the time-depth profiles derived from the checkshot and interval velocity data (Figure 19) match quite well. The MDT data from the W_Sak_25 well (Figures 11 and 12) indicate near hydrostatic conditions between 3500 and 4000 feet in that well. The interval velocity profile for the TD location for the W_Sak_25 well is shown in Figure 20, along with two compaction. models (discussed below). The fluid pressure interpretation employing the red compaction profile and the vertical stress curve (Figure 14) is shown in red and green on the right panel of Figure 20. The sediments above 3500 feet and below 4000 feet match the red compaction model. However, the interpreted fluid pressure between 3500 and 4000 feet, with the red compaction model, is greater than 10 ppg, well in excess of the measured MDT data (cyan, right track of Figure 20) and also in excess of the mud weights employed in the well (blue data, right track of Figure 20). A zone of anomalously slow velocities between 2800 and 4000 feet can be recognized in most of the velocity profiles from the control well locations (Figure 21). The depth range of the anomalously slow zone corresponds to the depth range of high resistivities, presumably hydrocarbon-bearing zones, in Figure 13. The very slow velocities maybe • • due to pockets of gas contained within the hydrocarbon-bearing interval, or possibly due to very friable sandy units within this depth range, or a combination of these effects. A horizon (Base of Slow Zone, BSZ) was interpreted from an overlay of the seismic reflection data with the interval velocity data (Figures 2 and 3). The BSZ separates the anomalously slow data from the `normally compacting' data. This horizon was mapped to follow the base of the low velocity zone rather than a specific reflection event. Figure 22 displays a crossplot of interval velocity and effective stress data from below the BSZ down to about 6500 feet. The data were sampled at 500 foot intervals. A strong, clear relationship exists between interval velocity and effective stress; departures from a simple relationship to slow velocities would indicate development of excess fluid pressure; departures to fast velocities would indicate a change of fades or development of extensive cementation. Some slow departures were observed at depths of 6000 feet or greater and these values were removed from the plot so as not to influence the derived `hydrostatic' stress/velocity relationship. The relationship plotted in Figure 22 was accepted as a calibration model for interpretation below the BSZ. horizon. The placement of the calibration function near the center of the data trend allows interpretation of small amounts of excess pressure from the data plotted on Figure 22 (values slower than the trend function). Interval velocity data from above the BSZ horizon are shown on Figure 23. These data are either from or above the demonstrably hydrostatic interval (Figure 11). The trend to high velocities at very low effective stress is due to permafrost development near the sediment surface. The calibration function shown in Figure 23 in green was used to interpret fluid pressure above the BSZ horizon. The placement of this trend results in a hydrostatic interpretation for all the plotted data. The velocity/effective stress relationships described above were applied across the seismic volume and effective stress was determined as a function of time and depth. Fluid pressure was interpreted from the Terzhagi relationship, (2) Overburden =fluid pressure + effective stress. When the calculated fluid pressure from the interval velocity was less than hydrostatic pressure, the hydrostatic value was substituted for the calculated value. The calibration functions posted on Figures 22 and 23 do not constrain the interpretation to be hydrostatic at the prospect locations or other areas within the velocity volume. The points used for calibration were taken exclusively from the control wells where hydrostatic or near- hydrostatic conditions can be demonstrated or inferred. ConocoPhillips-Anchorage provided a regional database of leak-off test (LOT) data; this data is displayed on Figures 24 and 25. The data scatter is considerable and maybe due to variable drilling practice, inclusion of formation integrity tests along with leak-off / tests, variability in lithology/tensile strength of the tested formations and/or regional variations in the tectonic stress field. The data specifically identified as LOT's are not ORIGINAL • C7 systematically greater than the other tests. One reported LOT value is substantially greater than the calculated vertical stress, which suggests either substantial tensile strength or substantial horizontal tectonic stresses. Attempts were made to model the data with a Matthews and Kelly, stress-ratio approach. These attempts required an interpretation (or assumption) of fluid pressure at the test depth for all the data. Hydrostatic fluid pressure was assumed in all cases and resulted in a decreasing stress-ratio with depth which is counter-intuitive and contradicts industry experience. The absence of demonstrated excess pressure in the MDT data set provided by ConocoPhillips suggests that a Matthews and Kelly approach, which explicitly includes fluid pressure contribution to leak-off pressure, is not required for this data set. Further, any shallow zones with interpreted fluid pressure (from seismic velocities) may be due to lithology or fluid effects and a Matthews and Kelly model would calculate increased fracture pressure, whereas decreased fracture pressure is more likely. A model was generated (Figure 24) which relates LOT to a percentage of the vertical stress. The LOT model is expressed in ppg as a function of depth in Figure 25. The data below 4500 feet were removed from the calibration since the area of primary interest for this study is above 4500 feet. The resulting fracture pressure model, (3) fracture pressure = (.18 + (.074*d^.a63)*OBG, where d is depth in feet, was used to calculate fracture pressure for the velocity volume. This model may underestimate fracture pressure slightly in regions with `real' overpressure. Pressure Calibration from Offset Control Wells Figures 26-30 display the interpreted fluid and fracture pressures, mud weights, MDT and LOT data at the five control wells. Note that in all cases the interpreted pressures are near, but below the mud weight. Well 1H_105 (Figure 26) and W Sak 25 (Figure 29) display MDT data very near the interpreted fluid pressure. Wells 1 H_105 and 1 H_06 (Figure 26 and 27) display FIT data near the fracture pressure model. Seismic Fluid and Fracture Pressure Analysis for Proposed Wells NEWS 1H_North Figure 31 contains the fluid and fracture pressure interpretations for the surface and TD locations for the NEWS 1 H_North prospect. The interpretation indicates near hydrostatic fluid pressure down to a depth near 7800 feet. Figures 35 to 37 show seismic sections for velocity, fluid pressure gradient and fracture pressure gradient for an arbitrary line through the proposed well path. A reference map for this arbitrary line is shown in figure 34. ORIGINAL • • NEWS 1H_South Figure 32 contains the fluid and fracture pressure interpretations for the surface and TD locations for the NEWS 1H_South prospect. The interpretation indicates near hydrostatic fluid pressure down. to a depth near 7700 feet. Figures 38 to 40 show seismic sections for velocity, fluid pressure gradient and fracture pressure gradient for an arbitrary line through the proposed well path. Red arrows are shown on figure 38 for the same potential shallow gas hazards that were identified in figure 8 earlier in the report. A reference map for this arbitrary line is shown in figure 34. NEWS 1R_East Figure 33 contains the fluid and fracture pressure interpretations for the surface and TD locations for the NEWS 1R East prospect. The interpretation indicates near hydrostatic fluid pressure down to a depth near 7600 feet. Figures 41 to 43 show seismic sections for velocity, fluid pressure gradient and fracture pressure gradient for an arbitrary line through the proposed well path. A reference map for this arbitrary line is shown in figure 34. Seismic Fluid and Fracture Pressure Interpretation for Lines A-A' and B-B' The velocity distribution in Figure 2 shows a thickened zone of slow velocities between .4 and .7 seconds near the north (right) end of the line. The cause for this velocity shift is not known with certainty. The difficulty of obtaining reliable velocities beneath the permafrost makes any interpretation very speculative. The available MDT and mud weight data (Figure 12) do not support an interpretation of increased fluid pressure in this depth range. Below the BSZ horizon, the north (right) end of the line is slightly faster than the south end, which suggests lower pressures or the presence of hard/fast lithologies such as carbonate or cemented sands. The velocity profile from B-B' shows a patchy pattern of slower velocities directly below the permafrost at the east (right) end of the line, but with slower velocities directly above. the BSZ at the west (left) end of the line. The fast/slow zones do not appear to follow the stratigraphy. The section thickens and dips slightly from west to east across the section. The interval of relatively slow velocities (less than 8500 feet/second) is slightly thicker on the east end. The fluid pressure gradient interpretations, along the two seismic lines. are shown in Figures 4 and 5. Line A-A' (Figure 4) shows a small pressure increase just beneath the BSZ horizon across the length of the profile. Note that the scale for this underlay is from.. 8 to 13 ppg; relatively minor interpreted pressure increases appear are apparent at this scale. The anomaly below the horizon is due to the change of compaction models (see Figures 26, 27 and 29), rather than a systematic widespread distribution of a thin • ~ slow/overpressured interval. Locally, the anomaly (e.g. at the north end) thickens in association with. stronger reflectors. In these cases, the anomaly may be a fluid/lithology indicator. Figure 5, along line B-B', shows far less development of the anomaly just below the BSZ horizon. In one area the anomaly is substantially thickened in association with a series of strong reflectors. This anomaly is probably fluid/lithology related. A discontinuous zone with slightly increased fluid pressure is present between 1.1 and 1.4 seconds, dipping slightly to the east. This zone correlates with a seismic interval with few reflectors and probably indicates minor fluid pressure development. This zone probably corresponds to the high gamma interval between 5000 and 6000 feet (see Figure 13) and the small tendency toward increasing mud weight below 5000 feet (Figure 12). Small hints of increased fluid pressure are present on Figure 4 in the reflector poor interval between 1.2 and 1.4 seconds, but the indicators are less continuous than on the E- Wline. The approximate planned drilling depth for the prospect wells is shown. on Figures 4 and 5 in yellow. This depth occurs within the nearly hydrostatic depth interval and above the zone of slight fluid pressure increase. Figures 6 and 7 display the interpreted fracture pressure gradients along lines A-A' and B-B'. The fracture gradient increases continuously with depth, as required by the calibration model employed. Conclusions An interval velocity data cube was conditioned for interpretation of fluid pressure near 3 prospects in the NEWS area. A two-layer fluid pressure interpretation was calibrated to MDT, mud weight and interval velocity data from 5 control wells near the 3 prospects. The two-layer model was necessary to avoid (erroneous) high fluid pressure interpretations resulting from very slow interval velocity values between 2800 and 4000 feet, the depth. range of demonstrably near-hydrostatic fluid pressure. The very slow velocities are probably due to a combination of local gas accumulations and friable sand lithologies. A fracture pressure model, based on the depth and vertical stress, was developed and calibrated. The interpreted fluid pressures near the prospects indicate near hydrostatic conditions. The interval velocity distribution and reflection character were examined for evidence of shallow hazards and/or hydrate development. The rapid velocity reduction below the permafrost makes recognition of shallow gas accumulation problematic. The reflection character of the seismic data were examined for any indications of shallow gas hazards or ORIGINAL • • hydrate development. Two shallow zones with slightly anomalous amplitude character over a restricted number of seismic traces were observed near the NEWS_1H South location. The deeper of the two zones extends just over to the NEWS_1H_North surface location. These anomalies were also identified for the 1H_South projected well path. The amplitude anomalies were not confirmed by corresponding velocity anomalies, so they could be lithologic or of some other origin. However, it is also possible that these shallow zones could contain some free gas. There is no evidence from either the velocity or reflectivity data that hydrates are present at the proposed drilling locations. ORIGINAL • • Figure Captions Figure 1. Basemap showing. the outline of the interpreted velocity volume, the three prospect surface locations and the surface locations of the five control wells. Also displayed is the location of line A-A' which links well 1 H_06 with the prospect surface locations and terminates in well W Sak 25. Line B-B' links well 1R 07 with the prospect surface locations and terminates at well MPU S_15. Figure 2. Interval velocity profile along line A-A'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 3. Velocity profile along line B-B'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 4. Fluid pressure gradient along line A-A'. The BSZ horizon is shown in red; the yellow line is the approximate TD of the prospect wells. Figure 5. Fluid pressure gradient along line B-B'. The BSZ horizon is shown in red; the yellow line is the approximate TD of the prospect wells. Figure 6. Fracture pressure gradient along line A-A'. The BSZ horizon is shown in red. Figure 7. Fracture pressure gradient along line B-B'. The BSZ horizon is shown in red. Figure 8: Central section of line B-B' showing interval velocities and wiggle trace overlay. Red arrows show locations of potential shallow gas amplitude anomalies. Figure 9. Underlay of original interval velocity data along line A-A'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 10. Underlay of original interval velocity data along line B-B'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 11. Depth plot of MDT fluid pressure data from regional wells. The MDT data from the W Sak 25 and the 1H 105 wells are plotted in green and orange and conform closely to the plotted hydrostatic line. The hydrostatic pressure line has a slope of .455 psi/foot (8.7 ppg). Figure 12. Depth plot of mud weight data from the 1 R_07 well (blue), the W Sak 25 well (brown), the 1H_105 well (black), and the 1H 06 well (purple). Also posted are two LOT from the 1 H-06 and 1 H_105 wells (magenta), and MDT data from the W_Sak_25 and the 1H_105 wells (cyan) Figure 13. Depth plot of gamma ray, resistivity, neutron porosity, density and velocity logs from the 1H_105 (blue), W Sak 25 (orange), 1H_06 (brown/purple), MPU_S_15 (cyan) and the 1 R 07 (magenta) wells. ORIGINAL • • Figure 14. Density data from the 1H_105 (blue), W Sak 25 (orange), 1H_06 (purple), MPU_S_15 (magenta) and the 1R 07 (cyan) wells. The blue data in the right track is the integrated vertical stress (overburden) from the red points in the left track. The. red curve is a mathematical representation of the vertical stress. Figure 15. Sonic log (blue) from MPU_S_15 well plotted with surface (green) and TD location (red) .interval velocity profiles. Figure 16. Sonic log (blue) from the 1R 07 well plotted with surface (green) and TD location (red) interval velocity profiles. Figure 17. Time/depth relations calculated for the 1 R_07 well from the checkshot data (magenta) at that well and from the interval velocity profile nearest the surface location (blue). Figure 18. Depth/velocity relations calculated for the 1H_105 well from the checkshot data (magenta) at that well and from the interval velocity profile nearest the surface location (blue). Figure 19. Depth/time relations calculated for the 1H_105 well from the checkshot data (magenta) at that well and from the interval velocity profile nearest the surface location (blue). Figure 20. Interval velocity data from the TD location for the W Sak 25 well along with two compaction profiles (left track). The right track shows mud weight data and MDT. data from the control wells. The W Sak 25 MDT and mud weight data are in cyan and blue. The red line in the right track is fluid pressure interpretation from the red compaction model. Figure 21. Interval velocity data from the surface and TD locations of the control wells (blue, left track), along with three compaction models. The right track shows mud weight data and MDT data from the control wells. The W_Sak_25 MDT and mud weight data are in dark blue and orange. Figure 22. Effective stress/interval velocity data for the surface and TD locations for the 5 control wells (1H_105, blue; MPU_S_15, orange; 1H_06, purple; W_Sak 25, cyan; 1R 07, red/magenta) for depths below the BSZ surface. Figure 23. Effective stress/interval velocity data for the surface and TD locations for the 5 control wells (1H 105, blue; MPU_S_15, orange; 1H_06, purple; W_Sak 25, cyan; 1R 07, magenta) for depths above the BSZ surface. Figure 24. Depth plot of Leak-Off Tests (LOT) expressed as percentage of vertical stress. ORIGINAL • • Figure 25. Depth plot of Leak-Off Tests (LOT) expressed as pressure gradient, ppg. Data specifically characterized as LOT tests are highlighted in pink. Figure 26. Fluid and fracture pressure interpretation at the TD location of the 1H_105 well. The brown, blue_and pink stars indicate mud weight, MDT and FIT data from the well. Figure 27. Fluid and fracture pressure interpretation at the TD location of the 1H_06 well. The brown and pink stars indicate mud weight and FIT data from the well. Figure 28. Fluid and fracture pressure interpretation at the TD location of the 1R 07 well.. The brown stars indicate mud weight data from the well. Figure 29. Fluid and fracture pressure interpretation at the TD location of the W_Sak 25 well. The brown and blue stars indicate mud weight and MDT data from the well. Figure 30. Fluid and fracture pressure interpretation at the TD location of the MPU S_15 well. No mud weight or MDT data were available from the well. Figure 31. Fluid and fracture pressure interpretations at the surface (left) and TD (right) locations for the NEWS 1H North prospect location. Proposed TD is 4463 feet. Figure 32. Fluid and fracture pressure interpretations at the surface (left) and TD (right) locations for the NEWS 1H_South prospect location. Proposed TD is 4390 feet. Figure 33. Fluid and fracture pressure interpretations at the surface (left) and TD (right) locations for the NEWS 1R East prospect location. Proposed TD is 4267 feet. Figure 34. Map showing arbitrary lines through the projected well paths for all three PDL's. Figure 35. Interval velocity profile along line C-C' for the projected well path of PDL 1H-North. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 36. Fluid pressure gradient profile along line C-C' for the projected well path of PDL 1H-North. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 37. Fracture pressure gradient profile along line C-C' for the projected well path of PDL 1 H-North. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 38. Interval velocity profile along line D-D' for the projected well path of PDL 1 H-South. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Red arrows show the locations of potential shallow gas amplitudes shown in figure 8. ORIGINAL • • Figure 39. Fluid pressure gradient profile along line D-D' for the projected well path of PDL 1H-South. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 40. Fracture pressure gradient profile along line D-D' for the projected well path of PDL 1 H-South. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 41. Interval velocity profile along line E-E' for the projected well path of PDL 1R East. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 42. Fluid pressure gradient profile along line E-E' for the projected well path of PDL 1R East. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Figure 43. Fracture pressure gradient profile along line E-E' for the projected well path of PDL 1R East. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. ORIGINAL 1658300 1668300 1678300 ~~ ~~ ASO ~ 7A°p ~ ~'~~ ~~ \ ~~° / /~ 6010400 7r, /%. ',\ '~ 7)~ ~ / \ '~o° / 6000400 ~°~ , ~°°O ~ ..~.. ~ ~ A, ~ ~ ~ ' ~,, 5990400 do ~' ~\ . q ~ "~ ~~ i ~~+ ~ ~~ 1 g'` ~ c§° ?~: ~' ~ ~ 5980400 ~ ~o ti ti ~ ~O ti~ 1698300 1708300 o° oti ~o i ~ do ~~ O ~ / ~~h ak~2~ o ,~ I o°° / ~~ ~x\ ~O ti ~~~ ~~~ ~S~ ~~ rho k~ ~ n^ i Yn^ ~ 7~ /~, ;'~' '~ 0 1~H~ 05~~~;r;~~ _~ btu°° ~~ r. 0400 o ~ ~}~ \ °`~ y0 ~° 5970400 ~~ \ °° 5970400 1658300 1668300 16783 1688300 1698300 1708300 Figure 1. Basemap showing the outline of the interpreted velocity volume, the three prospect surface locations and the surface locations of the five control wells. Also displayed is the location of line A- A' which links well 1 H_06 with the prospect surface locations and terminates in well W_Sak_25. Line B-B' links well 1 R_07 with the prospect surface locations and terminates at well MPU_S_15. • • 1HFU[~105 PDLWBI~S7t81j012r1~ East West_Sak_25 w ti~ r'% lesT 0 o a 14700 n - n o 0 17729 n - 0 7 Lrr I ,9.0 ^F:J ip I. '~I~I 5L 1: 6. [I 2770 _' fo 9?u tnC' fs50 .Br'n :Ft'cll 4120 E'0 C JgF9C I:nau ,p4f0 `ICGO ~1'I Jt16i a"" Xlrr 11'tu i ? P50 ' 1,'4P~f_ lc^'f fl 1.'.42 1 ~ ~ b9 ~5' -740 1 tPil 140:u 4"; It "cQ .5u ~ s(ff 14>~CC 149pp 15"11 Ic ,,~ ~9a4, 557~- w , ~ fu'k' wan ,, y,~lC r +~9k ~y1'h. a~ , v°'^V" "» . "`g :.,,2 ",rte ~~.~'Iy~ - `.. D ~ +„~$ d~ ~~,, ~ Ptt4`y"W,,~`. _ ..~~~ ,rµN/ °~~ ~~ '~'~ ~~}°^T~~ ~~R °'-+W~~~ ~,~ 3 °' ''sr yy t,::w ° . * ~' ~' R"" ~' _ O 1 Cif r t»* ~,.^ti h r•r,r ~+ : ~ e Nw'& rJ , kl r " "r~~,, ~ 1 ~~~~,r+,~~M ~ ~ %,'*~'~ wwrk;° _-J 100 '~1 I ~ r~Y. ':! IN fr k •W~ J + 1,F n hl~f»ly,+ r Vv lw apt, ~t4F /ti u11. 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IryiUr ~''11r14 (IIII uPu,~ ~ 11j'41tlNb t4W1,. n ~ 1 11Hg1 rIIP III III I I, :' r. ~ r .... yr~l~rnln.n+an+l~~.,, I ., :.' I' u...a~f „mow!+ktl.MMr I' ',may n IIV quumm~HRNln = ,rr,r„ Irn In plp4nMr' ~ IIII r 1 '.'!rl r 1t r ~ rl 1 ,11.:,~-..-~1{H11 N! ~~*,~Mf111~1~ 1 Jri !111 Ir~ll~~Illr~l I~MMH1MWrrrs^~ ~~ N1flr 1 •IHN44N~/ Irll 111 rirl I 111114 - .., n ;eisryr.xhr .. t1411111µ1 - ''+""~, ,nihhuad, ,r~,µr .r,o,o» ' 11 IN1w,grll».I~flylyyjllGllw r•rrNllµllt1111µIlu:,I,r, ,,•rr ,:rr,, L~: ;lifll -1.500 "' ' . I - :.,. _. rNrrlr~IHWn~. ,~rrNl!If~ ... 1MIMY Mh~n',.~ _ wMnlLww~'~,'~,~. ... ._ I ...r,.. IRti .nu,n runNNllilpylyy~ w tf00 r I t. 1 rS» :~ t wr+.» '-rp., '.rrrurs ltiiiw ~. oY ~, ,~,,te. _.a~~•rvir '11~r»1M.xyentw 1 n I f I I -:1,00 t.r ` 1 ew r...a ~ ~,. ~ lw+ti.. ~ h» >r g1"M'~Mrrtrrr rrilrN p3, >+, `>r + t ~~S+M+N 14 r, r (iµln+M +rMki,Wr . "•{MTw rw N1yJ.Mt pM. e.` w M+I+M.I Nr Nr, I 1 hl"~M.){nlrW Iln ` ~ ~ N Mi 11kN1YgI, M I .,j...r~ 1 I '.1 r lib Jr 1H niin = I~ r +' ~rnibwli ! I ~11n i;~ fh it li Iii " » I' ~ r 1,11 r ukf~PIN1M '^ • .;~~t Irr rnll r ill" ~ I ~ Ir ~wir nl Et7400 r ~ r hr r f II tnr III . h rr I I ~ UI 1n+rrgpr•~, r It r v ! it I _ rrnm ,r III •. 'I ,; ,....r 1 ua!ldrr»1y rul !II W' ,•. .,,•nr ... „ ~~,'~ r ~ r ,.. ~ NL+ r 1 ..x I r (I. I Ht I N((tl1+ INYj ~ I• II h It . l III IIII ~ lllAgwlUnlrN j~Ry _ Mrr1 I+~UIi' 1hNlMr µl N IrrH rlnnl M I H r ' M11 1~ Ir j, I , r ~~r'r/+ 1MlMI r~,. ~ • ...HMS _rdMill, rr. r.rlr~ 1.,~ipw r r r ~IT4WI r4y.,n yel pliF1°'+Y10brar~y ~~~ II a '' ` _ I7 -0.500 + M~RrW~i n~t ~ ~t - ~ '- ~ ~,'!lh ~lr»M1M„'iMrfltv~M~~ ..MgIN I I { r tll rrl)~. MMyrn~ l( - qq(w b .ti ~ M1w yam, 1T1 M N '^wlio.l ' r pl ~, wbKjYHtiyl wr'A (pl rr r,ryiM 141 ~+Y.. nmr ~PtMN»AMMrtnrfHwM~ ~ i Ih•" I I rH~ III rrnr.itr nunrwa, ~ iwr +~~ tv~ r r Irw I aerewllr>kr» Ir r, ,.~ I,.. rr»~ -0.GDO I I»+ tll rl rrir 1 ~t I +I~I~j ~yr IIII .,i.r t r .,,,~,~.rJlq~ ~~ + tlu { 1 N rngw.~ ~ e .•,r~~rurp n ~ ~ • n,~'~ 'n+rAif! ..,rr+.+ h r»rrr r~tN~h'N~i , ~ r lrri~nwr{tlM ~1HHi; ~ -0]00 a inn r r r ., r!rkrlArll"II1+OI, r/, ... ~ rt r . ... :~~ r I 'q . `n~ trnp, I I. ~ l~j ! r f1,KrHrAfNr rlrriNMMr n>Vt1 ltrn~ I 'ii ~rrrlWM ~rlwr~~~ ~u U~ ~» N rrA»r ~I Fw. :I _ ~ ,.,,,., _ I ~. I I I I f( b r r ..r Ilr rNf ~rl r. .~ w• ., ~ I nlil •rr rm ur r rn r r jar. 11rrgnl{llltllul - • ,~. »na w n 14~Luut "'"' II ry nl i (,r nn1Mu -0.800 r r p ~ ~yHy, ~U}{Nfl lllHh) n; n " '~ r `f1 ~ 1U»W.'Y1n 14 'll ~ u~ •!n »lA~r n lu~p~Myll~ln ~»yw+ :_..~ _ r}p~'p.,r nwa„ ~ fu., 1 '. _ rr~ra I ,:II 'a1rq+lrr~M111~rn+w~lWNtl ~ 1 1 ~ •~Hllrrr~ ~i}.n i•n~n.,;.iMwW+1MM• 1MlM'wrr I , rtlM ,r ~. r1r rgrr ~~~rr.' ~'Ihur.rµ~tbw r . rp: _ 1000A 000 96`.•P.000 9 Ct CC-0 9 [ 0^ 940OC0D 9250 009 1 9160 C00 65 C GOD BB00 000 Bo C COD CC coo I ao C 600 I BOG COD BO C G4D 76C CO, T•.L COD j CD ce^ ' 7a C 00D 73CC C00 71 E C00 OC C00 ~+ L CL`D B OC C?1D s c LG ftCL C0u ,. t,l F2 GCGO • r1C0 CO" 3 C GLC LG eG~ ~ c GDu cc GGD c coo a C0.: `. CCC C00 • • Figure 2. Interval velocity profile along line A-A'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. 0 `~,~~~' V I z I'""-' 1 R_07 U 30 9 U 2993.0 2977D 2961.0 2945.0 PDL W9LH;F9LM~1hSouth MPU_S_15 4568ft o 0 0 12363ft a 2930.0 2914.0 2898.0 2883.0 2867.0 2851.0 2836.0 2810.0 2802.0 2794.0 2786.0 2779.0 ~9 277L0 2763A 2756-0 2747.0 2737.0 1530 0 1 X59 0 158$ 0 1616 0 164? 0 ~ ~,.+~1~et•;. ok~ i+~rr ~_~ ,; ~ j .w........ ~ .~... .. 109D6.000 58EA 09C 5700 OOp 8E80 090 960D OD0 5250 OOG 5f00A90 898U.DG9 8800.000 8550.096 8500.OD0 83W.000 ezao.ooD e9sa oao 75oD.coo 77~a_o9o 7soo.DOc 7a5D.09P 7;A0.000 1150.00D 700D 060 8850.090 5760 OD0 5550 09C 0400.000 f•2'.~0 000 8100.009 Spa Dog :soo.ooo s5:a.ooo e,.~oo.909 53SD.ODD SZDD.DOC '-0OD.009 • • 1.500 1.600 to ~) 1_ _T Figure 3. Velocity profile along line B-B'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. TO IV V -~~ r~ 1 I_ 1HH16105 IA o n + Ln: f ?CLn: 1 1.200= 1.300; 1 SDD 1 6D0 FDL FYE1L20i6t(91nA6t_East 4700 fl = 0 o r: - 17729 fl West_Sak_25 ~• c /~ 7 2706,0 2717.0 2729.0 2740.0 2752.0 2763.0 2775.0 2786.0 2797.0 2810.0 2835.0 2861.0 2686.0 2912.0 2938.0 2963.0 2989.0 3014.0 3040,0 3065.0 3091.0 3116.0 iiaan iircn iia~n iooin ionan io~r.n iznnn ~zaon ~o~an ~au~n ia~nn iaoen inrnn tA1nn 1AZ6n incnn inrsn iaaon inaan ir.ian iCOan 16nd0 t~l ~ li iT L' 06C lasso lzlon ~, EEG 12 a0c 1a asG u taG 1LBE4 11 800 11-85G 1 11.SOC 11 °.0 ~ 11200 ` 11 0.50 li 1 U.50G 10 75C 1 G 600 10.450 to +oo 1GtsG ~ 10 000 ~ 9.850 4.100 B. cA s.ano 8.25C 8.100 8.85C 8.800 8.6E-0 8.590 8]EO R 200 BA00 Figure 4. Fluid pressure gradient along line A-A'. The BSZ horizon is shown in red; the yellow line is the approximate TD of the prospect wells. T~ /V [~~~ V ~ ~~~ I-" 1 R 07 o f 14566ft RDL F'BL~L_I~biRhS~uth ~ v v a ~ 12363 h MPU_S_15 ~. o B ~ n: 29930 2977.0 2961.0 2945.0 2930.0 2914.0 2898.0 2883.0 2867.0 2851.0 2836.0 2810.0 2802.0 2794.0 2786.0 2779,0 2771.0 2763.0 2756.0 2747.0 2737.0 n: 1120.0 1146A 1171.0 1197.0 1222.0 1248.0 1273.0 1299.0 1325.0 1350.0 1375.0 1386.U 1414.0 1443.0 1472.0 1501.0 1530.0 1559.0 1568.0 1616.0 1641.0 1 1. 1. ti 'n li iT 13.009 tzeeG 12 700 12 560 12 600 12 250 12.100 11.656 11 BGG 11 650 11 SOU 11 350 11 200 11.0.'0 1c sDG 1 O 750 10 EGG 10 650 10 306 1015E 1G QOU 9.850 B.76D 9.55p 9.600 9259 9.100 6.8°,0 E 600 E.650 6.00 F'. `.C 5<UD 3 cOp s • Figure 5. Fluid pressure gradient along line B-B'. The BSZ horizon is shown in red; the yellow line is the approximate TD of the prospect wells. O ~~ V I D i Ln: c XLn: 1 9tUyy1~05 PDL_ffBl~$li6~lr~rt~l_Eas1 West_Sak_25 Yi '~ la i l 6 8 a 14700 ft - o v o 17729 ft - v /~ f f JC71 fl : i~90 ~'aC.G "'I "',.0 5D c'nf 1 :.; I lfli .,`Jl f1 r ~` ~ 9iL I~;.il I I; i ~~ _ Igll -,pglll iu_~. 1.:1 .ll:iJ /~ 16.000 :I 11 ` I 11':iil ~,lf 1.^~. 1 ,f'i 1 Ilrl _ 1 '~ I li~`~il 1 'q 11 'i la I 41':I -I ~C4 -1 I; I. 7 la ''I~ 1•li+ II `1~ 1` I. .I 11.10 17700 I ~ I ..I I I I,. .I,.. 17A00 17.100 ~:= 1s5no = 1s59o ,~ ~ J: r ~~ I f`nq~ 1 ~° •.. :„ t I r ~. 'r , •,:.~+, n I r r ~ I ` . J• .i ,. .. F I ~ r 1, ,~, r d~ } -- 18.200 i1i•: I I 1N H (A rj~hr ' I Ir Ir r. r I )>+"i / 111-~:°~:'~' !Y V - ~ 'm II rI ~'-M ,>ti' Nr~- y~ .;: pn"1}F ,y..'rY » . , ;~' b , 1 t rr, # ~r4< , -0.100 1`.500 I - rl 1 r+bp, I rklw.µµ~~,,,~~++~ rk ,II - W yabl, 4v Jr Ib ... rFdrlrN Mqn N.t i.yMR I J ~,~.rq# iWnflR w ~ .~ .; ~ ' err 1 7 _ 0000 » " !I" I ~~ •,h r :."r .'Lyh her. rn I r '.: ,fh ,,~ w ~ ~ A v ~ *'~h' ~kM"rpr.'h^h." r w.r: rr~ µvrlF~ r~ rr ul'r~ ~ ""fN ri _ 15'90 111( I ~ lrl ll>rMNIIrNIftiMtINwN1k HNr111 f,WHnfiM+N '.a.W r tih. 1. M+~.F'n ~ / i>'ni.. M(r:)~, m 1 .,: tIN64HWINMrrih 4, r h+ r, b ~ 1°.000 inl 1nr r+'YI~~~~T'IMNiIMII ~' x•~ I J~ ~yI w f # ~., ~, r +ur w ) •~ >~ n 5'' :. ;~ lln tl)~e' r -0.200 14.70C Ir I ); I lr »yul r'I Irr I ~,, k' t ~", 'h r Nrr ~ I t•I wM~411M ~1M11M.~1~WIMMNIy)Mw.NYtiiuf~ I y>•.W! C 14ACC 7 ; ; I p N r by )+rr+• ~~I a .' 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II 'r 'm»~' 1NN14 i'.al Nll ~~rllllllulll !;wrNrwp IrruUIIw~I111M1 Ilflllll I l11µ+r.ntl~pi~tiu!!Ir:.Ir~p~InNlll11H1~11i1iN Irrnrllulurr1111q i ~~IIIIfII1~~IIINMwgI',.yuu~.:., rNU:::._ _ _I:u»1rG.._ "^M1MM~ I~ r~{rlj~' I - '=1200 ~I~I`I I''~f I"~~)slj~' I 1 I -1.300 1 U~~f}{1'I`I~{Ili I uHUUgIpmH =_ I upu IlnninN __1 500 III 1111pgII11, 1 L.I'IltlllMtMIHN ~ u • Figure 6. Fracture pressure gradient along line A-A'. The BSZ horizon is shown in red. t. ~~k:f tsoao n 700 fl aoo 17 tCa 0 z D r ='P"'~ ~'~ 1E EUU 1s soo 1s zon 1s.9oo ~ tssoo 15.300 15.000 14.700 144GC ~ i 14.10(1 1 1 asoo 17..00 13.200 1<<"90U lzsoo 1z 7ao 1z.ono 11 70U 11 aoo i 11 100 ~ 1C 8UC ~ 105Ca 101a0 9.900 5.6a0 9.7ao 9 aoa saoo s aoo s o00 • Figure 7. Fracture pressure gradient along line B-B'. The BSZ horizon is shown in red. 1P. O7 PDL_WB~@i~tMi1i11South PdPU S_15 4 14559 h a r v 12363 fl o B ~ PDL ~R Eai008RPDL-o_NorthPUL_1~H_South Ln: 2501.0 2875.D 2850.0 262G.D 2804.0 2ra2.o 2~si o E ^~ N ...~ V l .~~ • Figure 8. Central section of line B-B' showing interval velocities and wiggle trace overlay. Red arrows show locations of potential shallow gas amplitude anomalies. .~...~ ..~~ 1HMEa05 RDLRpLSViB~lndit East West Sak 25 0 o a 14700 fl = o 0 0+ 17729 fl - o /~ 7 2692.0 2706.D 2717.0 2729.0 2740.0 2752.0 2?63.0 2775-0 2786.0 2757 0 2810.0 2635.0 2861 0 2886 0 2912 0 2938 0 2963.0 2989.0 3014.0 3040-0 3065.0 3091.0 3116.0 3143.0/~ 1112.0 1138.0 1165.0 1193.0 1221.0 1248.0 1276.0 1304.0 1332.0 1359.0 1385.0 1374.0 1388.0 1403,0 1419.0 1435A 1450.0 1486.0 1482.0 1498.0 1513.0 1529.0 1544.0 1557.0 ti ~' li sf _. 1CDGtl OGC 56;A.CGO 97GG.000 :~w,ooo '` '~ ~GO.GOG Goo Goc ~ 9~oG.coc Gs<o.occ seoG.ooe EESG.OOG i G-0GGGG i G35D.RGG Sitar GCG SG~•C.CGG I ~ 7900.GC~G { 77; C.GGC I 7F.Gtl.GGp ~ 7k,G.CPO 73UD.GCG 95C.GGG ~GCC.ocG FS5G.G00 e~ac GoG ! oS~C. GGG ~' e~GacuG E'_C GGG z<.', f1tGGUC E5@i:GGC ~_ccGCc =:e eoo ~: cs coG :ac.GGc srrG GGc ccrao-o~ Figure 9. Underlay of original interval velocity data along line A-A'. 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I rl~ y ylulirrlflltHhl ! ulplflu'' 1~ t{ 1 f 1 i ' I 1~ 1 / rs A~ 1"Hlr >!.. :' »ll ~xIl1JlS>l tl ~. ,I 111'liwl '~. r~Yll1!11N(yi NYHy1MM11~M~w! 111N11)11}}t!~h 11 = 1111 Il ~ .~,,..y1M ~ ~ 1H1 :... ~ ~ '+Yr' - _ r 1 ' ~?lt ! . ... v~t++nn~~rRRn~°'' 1 1 kltU ,a ~s Nl) 11 ,rb .r. :., _lit)yy, ~ pll~ r rnr N~IMIMH - 500 y......6„u.,q+ it llt, {i~ltlr) 5 ,,, 1iMfl+e lnn ~ r ilr ,. _ ~,,,nap'MNHyy)h :,.1~'n1u ~ , I = ..,1:,., ~~~11 rxr ... ,r,., ~ r uN~~~h1HU i u i r ! rdH"tl i 1 _ ~ ,. .~ggNplNrrtn+.lar ) ' hdlt,., t _ r . w~,pi ~ui~,!}}}Y~"Mltrlpj19p,,., ~glkrt»Pl+n. '.I ~ `- 1. +~1r+.r1M~" ir„~„a....„:., ,,x:,. .~-1600 1 • Figure 10. Underlay of original interval velocity data along line B-B'. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. _~ z r- 2000.0 2500.0 a~ a~ ~` 3000.0 j 3500.0 H ~ 4000.0 a~ 0 4500.0 2200.0 RFT Formation Pressure, psi • All Data -Hydrostat W_Sak_25 0 1 H_105 5000.0 1000.0 1400.0 1800.0 Figure 11. Depth plot of MDT fluid pressure data from regional wells. The MDT data from the W_Sak_25 and the 1 H_105 wells are plotted in green and orange and conform closely to the plotted hydrostatic line. The hydrostatic pressure line has a slope of .455 psi/foot (8.7 ppg). • Pore Pressure (PPG) D e '~ P t h f t K ~-- B zoos 4000' 6000' 8000' is iz 1d 16 ~ ~ r_~+1rr 1H_1(1~_S N ~ ~~ A ~ 2 U 'zono '4000 D e P t h f t K B 6000 • '8000 Figure 12. Depth plot of mud weight data from the 1 R_07 well (blue), the W_Sak_25 well (brown), the 1 H_105 well (black), and the 1 H_06 well (purple). Also posted are two LOT from the 1 H-06 and 1 H_105 wells (magenta), and MDT data from the W_Sak_25 and the 1 H_105 wells (cyan). 0 .~' D e p t h f t M u d 1 i n e D e p t h f t M u d 1 i n e ~J • Figure 13. Depth plot of gamma ray, resistivity, neutron porosity, density and velocity logs from the 1 H_105 (blue), W_Sak_25 (orange), 1 H_06 (brown/purple), MPU_S_15 (cyan) and the 1 R_07 (magenta) wells. I~ I~ ~I~ I•~ D e P t h f t M u d 1 i n e D e P t }~ f t M u d 1 i n e • • Figure 14. Density data from the 1 H_105 (blue), W_Sak_25 (orange), 1 H_06 (purple), MPU_S_15 (magenta) and the 1 R_07 (cyan) wells. The blue data in the right track is the integrated vertical stress (overburden) from the red points in the left track. The red curve is a mathematical representation of the vertical stress. Velocity (it/s) z I" D e P t h f t M u d 1 i n e 6000 80 00 10 00 12 00 14 00 - -- PU_S 15_S Velocity DO 201 00 401 00 601 on 800 0 D • e P t h f i0 t M u d 1 i n e i0 90 Figure 15. Sonic log (blue) from MPU_S_15 well plotted with surface (green) and TD location (red) interval velocity profiles. Velocity (ft/s) z r^ D e p t h f t M Ll d 1 i n e D e P t h f t M u d 1 i n e • Figure 16. Sonic log (blue) from the 1 R_07 well plotted with surface (green) and TD location (red) interval velocity profiles. 00 5 1000 1 00 5 a~ ° ' 20 w- 00 O ~ ~ 2500 ~ ~, ____ ' 000 ~, ~ _ 3 ~ z 3500 4000 4 00 s 5 0 0. 2 0.4 0. 6 0. 8 1 time, sec - checkshot - GEOPRESS • Figure 17. Time/depth relations calculated for the 1 R_07 well from the checkshot data (magenta) at that well and from the interval velocity profile nearest the surface location (blue). ~_ z I- Figure 18. Depth/velocity relations calculated for the 1 H_105 well from the checkshot data (magenta) at that well and from the interval velocity profile nearest the surface location (blue). O .___. 0 1000 2000 .~ 3000 as a~ s 4000 ~ 5000 6000 7000 8000 time, sec - checkshot - seis S Figure 19. Depth/time relations calculated for the 1 H_105 well from the checkshot data (magenta) at that well and from the interval velocity profile nearest the surface location (blue). 0 0.5 1 1.5 ~-°© ~J ` _i~ Velocity (ft/s) n e P t h f t M u d 1 n e 1001 2001 3001 4001 500 600 U 1000 2000 3000 4000 5000 6000 n e p t h f t M u d 1 n e • Figure 20. Interval velocity data from the TD location for the W_Sak_25 well along with two compaction profiles (left track). The right track shows mud weight data and MDT data from the control wells. The W_Sak_25 MDT and mud weight data are in cyan and blue. The red line in the right track is fluid pressure interpretation from the red compaction model. Pore Fressmee (PPG) 60 00 80 00 10 00 12 00 14 00 0 4 6 ~r ,rr" i H 1;~^~ , ~J_Sak_MlJ_t ~d W SAK_25_S i I i i l I~~'~; t~i ralc ~_'~yl:_'S_h1IiT_t.~,,~j l~l__~Hf;_ ,r.,_= i i i i i 1 i I" D e p t h f t M LL d 1 1 n e Pore Pressure (PPG 1f1 1~ 1d 16 ~H_105_S_MW_tVd 1H_105_S ~l Sak 25_MDT_tud W SAK_25 S ~+ i U -2000 D e P t h f '4000 t '6000 -8000 M u d 1 1 n e • Figure 21. Interval velocity data from the surface and TD locations of the control wells (blue, left track), along with three compaction models. The right track shows mud weight data and MDT data from the control wells. The W_Sak_25 MDT and mud weight data are in dark blue and orange. 14000• 12aD~ v e 1 ° 10000- c _ 1 t ._.__ Y f 8000- t r~ s 6ooa 4DaQ 2 Effective Stress (3~si) 4 6 8 1 / / / / A~ ~/ ~~ 2 /" 14000 12000 .• e 1 100DD ° c i t Y 8000 f t s 6000 -4oaD Figure 22. Effective stress/interval velocity data for the surface and TD locations for the 5 control wells (1 H_105, blue; MPU_S_15, orange; 1 H_06, purple; W_Sak_25, cyan; 1 R_07, red/magenta) for depths below the BSZ surface. 14000' 12000- v e 1 ° 10000' c ~~ i t ...~.~ Y f 800D' ~-a°, t s 6000 4000 2 Effective Stress (l~si) 4 6 8 1 i i i ~~ ~~ .,' 3 // . ~~ ~ ~ t ~i /~ '14000 '12000 .• e 1 '1000D ° c i t Y 8000 f t s 6000 • 4000 Figure 23. Effective stress/interval velocity data for the surface and TD locations for the 5 control wells (1 H_105, blue; MPU_S_15, orange; 1 H_06, purple; W_Sak_25, cyan; 1 R_07, magenta) for depths above the BSZ surface. O ____ ~..0 J C~ m O 0 c 0 L O J 1 .20 1 .00 0.80 0.60 0.40 0.20 0.00 • • • ~ • • 0 1,000 2,000 3,000 4,000 Depth, Feet TVDSS 5,000 6,000 Figure 24. Depth plot of Leak-Off Tests (LOT) expressed as percentage of vertical stress. 0 -1, 000 -2, 000 -3, 000 cv y ""` a -4, 000 ~' -5, 000 r~ -6, 000 -7, 000 ~ ~- ©- • p 0 I I ~ • D 8.0 10.0 12.0 14.0 16.0 18.0 Pressure Gradient, ppg • All Data ^ LOT Series3 20.0 • • Figure 25. Depth plot of Leak-Off Tests (LOT) expressed as pressure gradient, ppg. Data specifically characterized as LOT tests are highlighted in pink. ~~ .~ ~- D e P t }~ velocity (it/s) Yore Pressure (YPU) 6000 8000 10 OD 12 00 14 DO D 4 6 -, 1 uin n.t,t~ -qr i - - i i ~I ~;L~~~ t.l~l r,y~~. I i I I 2001 X000 e P t h f 1000 t f t 400 M u d 1 i n e 600 800 M u d 1 i n e 6000 • 8000 Figure 26. Fluid and fracture pressure interpretation at the TD location of the 1 H_105 well. The brown, blue and pink stars indicate mud weight, MDT and FIT data from the well. 200 D e p t h f ~~ t 400 Tt u ~°~ d 1 i n e 600 Velocity (it/s) 800 Pore Pressure (PPG) 60 00 80 00 10 00 12 00 14 00 0 4 6 y.;~, ir~t _tr„_ try ;F;'n 1r,r.~ ~:rr,~ I E~L'~,+ t.~~irak i i i X000 Di e P t h f 4000 t M u d 1 i n e 6000 • B000 Figure 27. Fluid and fracture pressure interpretation at the TD location of the 1 H_06 well. The brown and pink stars indicate mud weight and FIT data from the well. `,/ -.~. `--~- ~~ U 2000- 400 6000' u 2000 • D e P t h f 4000 t M u d 1 i n e '6000 • 800 ~ 8000 Figure 28. Fluid and fracture pressure interpretation at the TD location of the 1 R_07 well. The brown stars indicate mud weight data from the well. Velocity {ft/s) ~nnn annn lnnnn 1~nnn ldnnn Pore Pressure (PPG) ifl 17 1d 1F a~,, ~l ~dir,t smnot.l~~ 2902 31~3G nr_~ne I 1 i i i I fiL'd r~,~ ~,F. i i I i I i 6000 200Q D e P t h f t 4000 Z M u d ~~ 1 i n e 6000 u 2000 D e p t h f 4000 t M u d 1 i n e 6000 800 I 8000 Figure 29. Fluid and fracture pressure interpretation at the TD location of the W_Sak_25 well. The brown and blue stars indicate mud weight and MDT data from the well. Velocity {ft/s} Pvre Pressure (PPG} 8000 10000 12000 14000 10 12 14 16 a~::el ~,:int. smootl•~ 2 - - - 302 14U none - ` !, i Ii FLU_t.w eak I i ~~ I I j '~4 `4 ~...J ...r .~... r- 200 D e p t h f t 400' M u d 1 i n e 600 800 velocity (ft/s) Pore Pressure (PPG} 6000 80 00 10 00 12 00 14 00 0 4 6 I RL'.' t~a Fyk Figure 30. Fluid and fracture pressure interpretation at the TD location of the MPU_S_15 well. No mud weight or MDT data were available from the well. u 2000 4000 6000 8000 D • e P t h f t M u d 1 i n e ~~ D e P t h f t M u d 1 i n e D e P t h f t M u d 1 i n e D e P t }~ f t M u d 1 i n e r~ ~J f ~J Figure 31. Fluid and fracture pressure interpretations at the surface (left) and TD (right) locations for the NEWS 1H_North prospect location. Proposed TD is 4463 feet. Velocity (ft/s) Pore Pressure (PPGj Velocity (ft/s) Pore Pressure (PPG) D e P t h f t .~..- ~. M u _ d a 1 1 n e Velocity (ft/s} Pore Pressure (PPG) coon noon ~nnnn ~onnn ~rnnn ~n i~ ie ~c ~ U ;'it y.fr~,i ~~,_ Y.I1 °[_. . °jl,ll''~ "~i p'iF i I i I I 200 'I I I 2000 _t~~~ak, i 400 i, ~ I { 9000 6D0 on l ~ i i i 6000 onn D e p t h f t M u d 1 1 n e D e P t }~ f t M u d 1 1 n e • Figure 32. Fluid and fracture pressure interpretations at the surface (left) and TD (right) locations for the NEWS 1 H_South prospect location. Proposed TD is 4390 feet. Yelocitv (ft/s) Pore Pressure (PPG) D e P ~~ h f t '~~ M u d 1 ~"~ i n e Yelocity (ft/s) Pore Pressure (PPG) rnnn Donn ~nnnn ionnn i~nnn ~ in in ~~ ~c i ~1 ' - int. _n~c - rh ~E~ - - ~ run e i { I I u 200 ~ ~~~ 2000 _ t.aieak. - i I 400 ~~ i i I I f i 1 ~ 4000 600 I i 6000 i i non noon D e P t h f t M u d 1 i n e Velocity {ft/s] Pore Pressure (PPG) 6000 8000 10 00 12 DO 14 DD 0 4 6 _ _ - - _:~ i u 2DD E'~L'~+ troeak . I 2DDD 400 ~ 4000 600 non 6DOD Donn Figure 33. Fluid and fracture pressure interpretations at the surface (left) and TD (right) locations for the NEWS 1 R_East prospect location. Proposed TD is 4267 feet. Di e P t }~ f t M u d 1 i n e • 0 z • Figure 34. Map showing arbitrary lines through the projected well paths for all three PDL's. T~ /V °°V~~/ 'G. y+ I t=' ~-~ 1. _t 10000.000 4850 CCO 4700.000 9CFO 000 S.cG can 5zeo.6aD gtbC 000 545-0.000 6806,000 P;frO CCO Ef OG 000 635Q000 8200 CCC 8q°0.060 7506 CCO 7T0.060 ;ECO.CCO 74.°P•ODUO 7 OQUUO 7+. SG 060 rooa Dca 5850.000 5700.600 &' S0 000 5x00.000 5250 CD0 6100.000 59.0 006 5800 000 F5q COG SSOO CCO 5?50 000 `260 000 sgga b6c • • Figure 35. Interval velocity profile along line C-C' for the projected well path of PDL 1 H-North. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. ci' ~ li Et 13.000 12.850 12 700 12.550 12A00 `"j 12.250 12.100 11.850 - ~ 11.800 ~ 11.650 . -I 11.500 11.350 t 1.200 11.OSn 10.900 10 7so 1n 600 1o aso 1n 3oa 1n 15c 10 San 9.650 • 9 700 5 5°G 5 r, 0 :C G C Figure 36. Fluid pressure gradient profile along line C-C' for the projected well path of PDL 1 H- North. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. \i / ~~~ c-~ `' 1~ z? t6.00F t 7.7CC ,7saa 1. t0a 16 BOC ib S00 16.200 1 `..4aC 15606 2GC S.OGC to 700 14 dOC 11.100 t 3 6C0 ^, ., SpC, 3.200 12 §CC 12 600 12300 t 2.000 t 1.700 +, eac ,, ,aa 1 o.eab 1osa6 to zac §.900 5 600 5 300 § G00 6.700 B.OOa 8.000 • • Figure 37. Fracture pressure gradient profile along line C-C' for the projected well path of PDL 1 H-North. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. PDL 1H IVo?thPDL 1H Notth o =~-0 tl ~- n - ~ ~ Ln. 2842.0 2834.0 2827.0 2820.0 2814.0 2808.0 2802.0 N ....... ~..i ' ..~~ ~~ 1 1G000.OCO 56°O OCC 5)CC.OOU ~.;..-y o~°C.UOC SaUf.OUD 92~C.000 51 OO OOC 69`.C.OOU aBDC ooc Bsec ooc i BSOQC00 BU°-0.000 ~ 5200 OOU i SUSG Q06 I 7900 COC ))SC ODC )fi0F000 )aec.oeo- l ,soc coc ~ 7vueoc '~ 7DUC.000 g'0.000 f7CC.U00 i:C ODC =Cf RUC -zef nou e : ~u cae =u o00 foa -=f coo =oe o00 ='e-0 ooc szoc.ooo =occ ooc Figure 38. Interval velocity profile along line D-D' for the projected well path of PDL 1 H-South. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. Red arrows show the locations of potential shallow gas amplitudes shown in figure 8. • • ti' ~ li ~t ,a.oao 12.850 12.700 12.550 12 400 i 12.250 ~ ~~ ~ 12.160 j 71.956 ~ 11.860 t 1650 ---; 11.500 11.350 11.200 11.050 10.900 io 7s6 io.s6o 10.450 10.300 10.150 10.000 9.BSC 9.700 9.550 9.400 9 250 5 I GO ~.C 30C ', ^~,C =CG _'0 =C C 8.000 Figure 39. Fluid pressure gradient profile along line D-D' for the projected well path of PDL 1H- South. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. 0 `Y l~ ~.0 ~# ~A 74`I -. 18000 1 i.7CC 7? a00 „~~ - i7 ion - 'I 1E844 1f.E4U 100 t€2o4 15.900 ie =.44 i a 344 ~ e 400 200 ia7oc to a40 i 14.1L•0 r eco 300 , ~; 544 ~3zc4 r 94e 12f 00 A00 i~ :.cC n eco 11 700 ti 4a4 500 '~ ~~ ~oC usoo ~r..o0 ~ c zoo soa 9.9e4 4 5L`0 9.340 9.400 700 8.74C 8 400 ~ d :'[F. .800 .900 .000 700 .200 .300 ,400 .500 • Figure 40. Fracture pressure gradient profile along line D-D' for the projected well path of PDL 1 H-South. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. PDL_1H_Souih PDL_1H_South PDL_1H_Nortl'i ~~^.~~.. `.~ J I- t1~;~1~r faaoo oaa 98.a OOG 970nAGn 950 OGO 9400.000 j 92`.'r aoD 910G-000 69..O.GCD RROn.06n 86.0 UGO 850n OGn ~.SO.UOn R200.0DD I ROSO.U00 79or.nnn ~ ~ n.,n aon 76aa aaa ~ 7a, C_OnG ~ 7300 6D'b ~ I 7150.x00 7000.UUO 68..n.000 6700 D00 655C 000 ~ 6x00 UG0 °+x'~^4' 625-0.000 6106.ORD 5950.000 5anaaoo :850 UOn 5500 000 5350 Goo 5200 OOC 5000 QOC • • Figure 41. Interval velocity profile along line E-E' for the projected well path of PDL 1 R_East. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. TO N I- 1.'. 1. PDLP~L H~tEasi PDL 1 R East PDL 1 H IVorth _U -r, =~, ft = U . '"464 ft = O to ~ ~~ s L'ACU ~ 1 < 7 C U '~ ~'_ ~ I 72 °EL' ~ : ! 12.4Un __.. - ~ i '.. 50 ~J 100 ~ 12-~n(o . - 11.450 _ 11 eao _ i- 115~.U ~= -0 200 11 you . 11.:1.n ~_ 11.2 L'G 11.0`0 ~ ~= 1C BUU i ~ ~~.3nn t ' 1U.7E~U ' 1C5UU ~ 1UA5U i- ~' 10.3CG ~-0.400 ! ': 10.t5n ~_ 1a onn ' 5.650 I- j I scOU -0.500 4 00 ; < s zso ~.1on ?-0 60n B.aso j= B.B00 j. 6.65n ~_ s soo -070ii e2oo I c B o00 -0.800 i_ -0.900 1- 1= 1. =1.000 r i_ ~= -'=1.100 =1200 =1.300 1.400 • Figure 42. Fluid pressure gradient profile along line E-E' for the projected well path of PDL 1 R_East. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. V ~~~~ <~} ,~+~ I'" tai '[`; 1= c~- _.......... _. 1B.G00 17.7UG 17.400 17 t0G 16 BOU 16.60(1 1fi20U ( 15$00 1 Efi00 1 E 300 L.GCO ~ ~ 14.7CU 19.400 I 14.100 ~ 13.600 13500 13.200 12.900 ~ I 12.600 j 12.300 12.000 ~ 11.700 11.400 11.100 t0.S0U 10.500 G' 2UU x.900 5.600 9._<UG 9A0U 6'00 -CC :-0C • • Figure 43. Fracture pressure gradient profile along line E-E' for the projected well path of PDL 1 R_East. A horizon marking the base of an anomalously slow zone (BSZ) is shown in red. • • SHARON K. ALLSUP-DRAKE... 1 f24 CONOCOPHILLIPS AT01530 ~1 700 G ST. DATE ~ ( EGc~iLLt `~ 1441 ANCHORAGE AK 99y5"~~-011 ~ ~L}~/{} PAYTOTHE. ~~~/ ~ (~ ~~. ~t~/ 1 -~-~ l ~I~~`.. Q`. //Y"7 ORDER OF t ~ I/ s J+ (VLF, p, '~~ ~ - GW~ LCD ti..._~ .~.~d Cs~ARS LJ a ' _ . JPMorganChase~ j vai~duProsooo~onars JPMorgan Chase Bank, N.A. ~ ` Columbus, OH y7 ,f/ ? ~ /1 ' MEMO __~(\'I--- -~~-~~--C--~~, --~' - -- ~.0 ~~ 11~ - ~ - --- 441L55LL.528747L90792? L324 _ a _ ~~,.~~, • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLtiDED IN TRANSMITTAL LETTER ~~~ ~~ ~~~ WELL NAME PTD# ~ S 'r C~~1~0 C~.~~ ~ ~~~E 1~ CHECK WHAT i ADD-ONS APPLIES ~ (OPTIONS) ~ i MULTI i LATERAL (If API number last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well , Permit No, API No. Production should continue to be reported as a function of the original API number stated above. PILOT HOLE ~ In accordance with 20 AAC 25.005(f), all (per records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PIT) and API number (SO - 70/80) from records, data and togs acquired for well (name on permit). SPACING ~ The permit is approved subject to full EXCEPTION I compliance with 20 AAC 25.05. Approval to perforate and produce/infect is contingent upon issuance of a conservation order ~! approving a spacing exception. (Company Name) assumes ~ the liability of any protest to the spacing j exception that may occur. DRY DITCH ~ All dry ditch sample sets submitted to the SAMPLE ~ Commission must be in no greater than 30' j sample intervals from below the permafrost j or from where samples are fcrst caught and 10' sample intervals through target zones. Rev: 04/01/05 C\jody\transmittal_chec klist WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, WEST SAK OIL -490150 Well Name: KUPARUK RIV U WSAK 1H-NORTH Program EXP Well bore seg ^ PTD#:2052090 Company CONOCOPHILLIPS ALASKA INC Initial Classffype EXP! PEND GeoArea 890 Unit 111.60 On/Off Shore On____ Annular Disposal ^ Administration 1 Permit_feeattached____________________________________ ________ Yes-_ _-__----_-_-----_..--_----_._ 2 Lease number appropriale_-_-- _..______________________ ________ Yes_ _____ ----------------------------------------------------------------- 3 Uni_quewell.nameandnumber-- -- -- -- - - ----- ~ ---- -- Yes - - -- - -- -- -- --------------------- 4 Well located in_a defined-pool- - _ . - - - - - Yes . Section. 15, T12N, R10E.lies within West Sak Oil Pool as defined_in C_O.406B._ --------------------- 5 Well located proper distance-f[om drilling unit_boundary_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes . _ - . - - -Well will be located. 1500' fr9m KRU-boundaryry_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 6 Well located proper distance. from other wells. Yes Nearest well_in West Sak sand equivalent are _M_PU_H-07A, H-07AL1-which-are -4,500'-away .. . . . . . .. . . . . 7 Sufficient acreage available in_drillinq unit- - _ - - - _ Yes - - - - - - - - - - - - - - - - - - - - - - 8 If deviated,is_wellboreplat.included_________________ Yes-- ------.--._---_--___,_.- 9 Operatoronlyaffectedparty_ _____________________________ _____ ___Yes-- --.-_ -- -- 10 Operatorhas_appropriate-bond in force- ---------- -- - - - - Yes-- ----- -- -- ------ ~- - --- -- --- -- - ----- -- -- -- - -- 11 Permit can be issued without conservation order Yes Appr Date 12 Permitcan be issued without administrativ_e_approval _ _ _ _ _ _ - _ _ .. _ Yes . - SFD 12/2712005 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by_ Injection Orde[ # (putlQ# in-comments)-(For. NA. 15 All wells within 114_mile area of review jdentified (Far service well only) . .. . . . . . .... . . NA- _ - _ _ _ - - _ 16 Pre-produced injector; duration of preproduction Less than 3 months_(For ervice well only) NA- -------------------------------------------- ACMP-Findingof Consistency_hasbeenissuedforthisproject___________ _________ NA._. -_--.._--_.___-__--_.------_--_-_______.-_._________-______________ ___- Engineering 18 _C_onductor sting-provided - - - - - Yes - - - - - - 19 Surface casing_protectsallknownUSDWs---------------_---_ -_. __-._ NA_ ____Allaquifersexempted,40CFR_147.102_(b~(3).__..---.._---_-----_-.--.__-___-._.__-- 20 CMT_vol.adequ.ate-tgcirculate-onconductor&surf_csg_______________ _________Yes-- ________________-_______ ------------------------------------------------ 21 CMT vol_adequate-to tie-in long string to surf csg_ - - - - - - - - - - - - - NA_ No production_casing planned. _P&A is pl_ann_ed after evaluation. - - _ - . , _ - _ - _ . - _ - _ _ - - _ _ _ . _ 22 CMT.will coyer_all kno_wn_pro_ductiye horizons. _ - - _ _ - Yes - - . - - - .Productive-horizons will be covered as required during P&A, 23 Casing designs adequatefo[C,TB&_permafrost------------------ --- Yes-- ----------------------.----------.--.-----------.--.--.-------._---- 24 Adequate tan_kage_or reserve pit - - - - - - - - - - - - - Yes - - - - - - -Rig is-equipped with steel-pits.-No reserue_pitplanned, All waste to approved disposal_wells._ 25 If_a_re-drill,has_a_1.0-403forabandonmentbeenapproved_____-.__-_- -_-.___-_ NA--- _________________ ------------------------------------------------------- 26 Adequatewellboreseparation-proposed________________________ _________Yes__ ._.,.Nootherwells_inarea.._--_-_-_.._-.__- 27 If_diverterrequired,doesitmeetregulations_________,.__------- --------- Yes__ ____________________-____ - - - Appr Date 28 Drilling fluid_program schematic & equip list adequate. - _ - _ _ - - - _ - _ -Yes _ Maximum expected formation pressure 8,6_EMW._ Planned MW up to_9.5 ppg, TEM 12!27/2005 29 BOPEs,dotheymeetregulation______-___________________ _________Yes__ _____-_-__.________,--_ .___-___--_-_--_-__--__.__.___________ ---_ ~,, /~ ~(~, " 30 BOPE-press rating appropriate; test to-(put prig i_n comments). Yes - - .. - - . MA$P calculated at 1484 psi, 3000_psi-8OP testproposed, , V \ {(~~ 31 Choke.manifold comp_Iiesw/APtRP-53 (May 84) - Yes - - - - - - 32 Work will occur without operation shutdown______________________ _________Yes__ -__-.--.-..__-,_-,__---,.-,----_-.---.--_--_---______,_______________- 33 Is presence. of H2S gas. probable _ - - - - - No_ - No H2S has been reported in_the WS in the area.. - - - ..... - - _ - . - 34 Mechanical condition of wells within AOR verified (For service well only) NA_ _ - - _ - - - - _ Geology '35 Permitcan be issued wlo hydrogen. sulfide measures.. - . - . - - - Yes - . - . - No [eport of_H2S on S-Pad in MPU 2004 H2S Well Sampling report provided. by CPAI to AOGCC. 36 l)ata_presented on_potential oyerpressur_e zones. - .. - - - -Yes - - Expected reseruoirpressure is 8,3-8.6 ppg_E_MW; will be_drilled_with 9,2-9.5 ppg mud_ _ _ _ _ _ _ _ _ _ _ _ _ __ _ Appr Date 37 Seismic analysisofshallow gas_zones- - - - .. - - .. Yes - - - - - - . Geopressureand-Hazards investigation concluded no excess-fluid_pressure near well location. Lowpotential SFD 12127!2005 38 Seabed condition surve if off.-shore - - . - - Y( ) NA- _ _ - _ _ - .for shallow. as accum, or_gas h drates- Miti ation strafe ies discu_ssed_in Drillin Hazards Summa g Y 9 9 9 ry• 39 Contact namelphone far weekly-progress reports. [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - Randy Thomas_265-6830 Geologic Engineering P 'c Date: Date ~ Date West Sak test well in NE portion of Kuparuk River Unit, which lies within defined boundaries of the West Sak Pool. Well is Commissioner: Commissioner: oner r/ ~y~/~,, 1Z'7 ~~ C ~ likely structurally separated from MPU West Sak equivalent production 1-2 miles to the NE, Since well is being drilled to determine the extent! producibility of the West Sak Pool, well is best termed a delineation well, which according to 20 AAC i GC~ ' '~'~''/ ~ ~Z'2~'~ 25 990(25) is classified as exploratory SFD12/2712005 , . , . • 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 APPENDIX. No special effort has been made to chronologically organize this category of information. • Sperry-Sun Drilling Services LIS Scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Fri Jun 16 15:07:31 2006 ~~ilb Reel Header Service name .............LISTPE Date .....................06/06/16 Origin ...................STS Reel Name ................UNKNOWN Continuation Number......01 Previous Reel Name.......UNKNOWN Comments .................STS LIS Writing Library. Scientific Technical Services Tape Header Service name .............LISTPE Date .....................06/06/16 Origin ...................STS Tape Name ................UNKNOWN Continuation Number......01 Previous Tape Name.......UNKNOWN Comments .................STS LIS Writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER Kuparuk River MWD/MAD LOGS WELL NAME: iH-North redo API NUMBER: 500292329400 OPERATOR: Conoco Phillips Alaska Inc. LOGGING COMPANY: Sperry Sun TAPE CREATION DATE: 16-JUN-06 JOB DATA MWD RUN 1 MWD RUN 2 MWD RUN 0 JOB NUMBER: MW-000422928 MW-000422928 MW-000422928 LOGGING ENGINEER: E. QUAM E. QUAM R KALISH OPERATOR WITNESS: P. WILSON. D. HEIM SURFACE LOCATION SECTION: 15 TOWNSHIP: 12N RANGE: l0E FNL: 2276 FSL: FEL: 946 FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: .00 DERRICK FLOOR: 64.60 GROUND LEVEL: 34.60 WELL CASING RECORD OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 1ST STRING 12.250 16.000 80.0 2ND STRING 8.500 9.625 2767.0 3RD STRING PRODUCTION STRING REMARKS: 1. THIS FILE IS A RE-DO OF THE .TIF FILE DATED 5/26/06, AND IS DONE IN ORDER TO SUBMIT VERTICAL RESISTIVITY ENHANCEMENT (VRE) DATA. THIS FILE SUPERCEDES ALL PREVIOUS SUBMISSIONS. ~ - ao9 2. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE • • NOTED. 3. ALL DATA CURVES ARE SMOOTHED TO A STEP OF 0.5 FT, WITH A WINDOW OF 0.6 FT, EXCEPT FOR ROP AND GAMMA RAY, WHICH ARE BOTH SMOOTHED TO A 1.1 FT WINDOW. 4. MWD RUNS 1 & 2 ARE DIRECTIONAL WITH DUAL GAMMA RAY (DGR ) UTILIZING GEIGER-MUELLER TUBE DETECTORS, AND ELECTROMAGNETIC WAVE RESISTIVITY PHASE-4 (EWR-4) MWD RUN 2 ALSO COMPRISES COMPENSATED NEUTRON POROSITY (CTN) WITH ACOUSTIC CALIPER (ACAL), AND AZIMUTHAL LITHO-DENSITY (ALD) RESISTIVITY DATA IN RUN 1 IS CORRECTED FOR HOLE SIZE AND MUD SALINITY. 5. VERTICAL RESISTVITY ENHANCEMENT (VRE) PROCESSING WAS PERFORMED ON RESISTIVITY DATA FROM 3350'MD TO 4580'MD, AND OUTPUT IS PRESENTED AS MWD RUN 99. 6. MWD DATA IS CONSIDERED PDC PER THE E-MAIL FROM M. WERNER OF CONOCOPHILLIPS ALASKA, INC. TO R. KALISH OF SPERRY DRILLING SERVICES DATED 1/05/06. 7. MWD RUNS 1&2 REPRESENT WELL 1H-NORTH WITH API #: 50-029-23294-00. THIS WELL REACHED A TOTAL DEPTH (TD) OF 4630'MD, 4459'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED. SEXP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA SHALLOW SPACING). SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (SHALLOW SPACING). SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM SPACING). SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP SPACING). SFXE = SMOOTHED FORMATION EXPOSURE TIME (EWR). TNPS = SMOOTHED COMPENSATED THERMAL NEUTRON POROSITY (SS MATRIX, VARIABLE HOLE SIZE). CTFA = SMOOTHED AVERAGE OF FAR NEUTRON DETECTOR'S COUNT RATE. CTNA = SMOOTHED AVERAGE OF NEAR NEUTRON DETECTOR'S COUNT RATE. SBD2 = SMOOTHED BULK DENSITY - COMPENSATED (LOW-COUNT BIN). SCO2 = SMOOTHED STANDOFF CORRECTION (LOW-COUNT BIN). SNP2 = SMOOTHED NEAR DETECTOR PHOTOELECTRIC ABSORPTION FACTOR (LOW-COUNT BIN). ACAL = ACOUSTIC CALIPER (CALIBRATION FACTOR OF VEXP = SMOOTHED INVERSION MODELING-ENHANCED PHASE RESISTIVITY (XS SPACING). VESP = SMOOTHED INVERSION MODELING-ENHANCED PHASE RESISTIVITY (S SPACING). VEMP = SMOOTHED INVERSION MODELING-ENHANCED PHASE RESISTIVITY (MED SPACING). VEDP = SMOOTHED INVERSION MODELING-ENHANCED PHASE RESISTIVITY (DEEP SPACING). MEXP = SMOOTHED FORWARD-MODELED PHASE RESISTIVITY (QC CURVE) XS SPACING. MESP = SMOOTHED FORWARD-MODELED PHASE RESISTIVITY (QC CURVE) S SPACING. MEMP = SMOOTHED FORWARD-MODELED PHASE RESISTIVITY (QC CURVE) MED SPACING. :~ • MEDP = SMOOTHED FORWARD-MODELED PHASE RESISTIVITY (QC CURVE) DEEP SPACING. PARAMETERS USED IN POROSITY LOG PROCESSING: HOLE SIZE: VARIABLE (ALD "CALIPER"), BIT SIZE 8.5" MUD WEIGHT: 9.2-9.3 PPG MUD SALINITY: 21,000 - 23,000 PPM CHLORIDES FORMATION WATER SALINITY: 12,500 PPM CHLORIDES FLUID DENSITY: 1.0 G/CC MATRIX DENSITY: 2.65 G/CC LITHOLOGY: SANDSTONE File Header Service name............ Service Sub Level Name.. Version Number.......... Date of Generation...... Maximum Physical Record. File Type ............... Previous File Name...... Comment Record FILE HEADER .STSLIB.001 .1.0.0 .06/06/16 .65535 .LO .STSLIB.000 FILE NUMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH ROP 115.5 4630.5 FET 170.5 4577.5 RPX 171.0 4577.5 RPS 171.0 4577.5 RPM 171.0 4577.5 RPD 171.0 4577.5 GR 178.5 4585.0 GALA 2750.0 4538.0 NPHI 2757.0 4535.0 NCNT 2757.0 4535.0 FONT 2757.0 4535.0 PEF 2757.0 4548.5 DRHO 2767.0 4548.5 RHOB 2767.0 4548.5 VEDP 3350.0 4579.5 BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH MERGED DATA SOURCE PBU TOOL CODE MWD MWD MWD BIT RUN NO MERGE TOP MERGE BASE 1 115.5 2780.5 2 2780.5 4630.5 0 3350.0 4579.5 REMARKS: MERGED MAIN PASS. Data Format Specification Record Data Record Type ..................0 Data Specification Block Type.....0 Logging Direction .................DOwn Optical log depth units...........Feet Data Reference Point ..............Undefined Frame Spacing .....................60 .lIN Max frames per record .............Undefined Absent value ......................-999.25 Depth Units ....................... Datum Specification Block sub-type...0 • • Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 RPX MWD OHMM 4 1 68 12 4 RPS MWD OHMM 4 1 68 16 5 RPM MWD OHMM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 FET MWD HRS 4 1 68 28 8 NPHI MWD PU-S 4 1 68 32 9 FONT MWD CNTS 4 1 68 36 10 NCNT MWD CNTS 4 1 68 40 11 RHOB MWD G/CM 4 1 68 44 12 DRHO MWD G/CM 4 1 68 48 13 PEF MWD B/E 4 1 68 52 14 GALA MWD IN 4 1 68 56 15 VEDP MWD OHMM 4 1 68 60 16 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 115.5 4630.5 2373 9031 115.5 4630.5 ROP MWD FT/H 0 496.41 98.0185 9031 115.5 4630.5 GR MWD API 10.53 130.23 69.8092 8814 178.5 4585 RPX MWD OHMM 0.37 332.91 21.2437 8762 171 4577.5 RPS MWD OHMM 0.35 1774.76 35.512 8762 171 4577.5 RPM MWD OHMM 0.44 2000 64.227 8762 171 4577.5 RPD MWD OHMM 0.27 2000 90.1291 8762 171 4577.5 FET MWD HRS 0.23 72.23 1.17545 8743 170.5 4577.5 NPHI MWD PU-S 13.17 79 39.6106 3557 2757 4535 FONT MWD CNTS 422 2822 736.425 3557 2757 4535 NCNT MWD CNTS 91855 176859 114940 3557 2757 4535 RHOB MWD G/CM 1.322 2.642 2.17233 3564 2767 4548.5 DRHO MWD G/CM -0.107 0.258 0.0160968 3564 2767 4548.5 PEF MWD B/E 0.18 11 1.94192 3584 2757 4548.5 GALA MWD IN 8.12 12.46 8.98909 3577 2750 4538 VEDP MWD OHMM 0.111 1980.39 40.0798 2460 3350 4579.5 First Reading For Entire File..........115.5 Last Reading For Entire File...........4630.5 File Trailer Service name ..... ........STSLIB.001 Service Sub Level Name... Version Number... ........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ........ ........LO Next File Name... ........STSLIB.002 Physical EOF File Header Service name .............STSLIB.002 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH • ROP 115.5 2780.5 FET 170.5 2730.5 RPD 171.0 2730.5 RPX 171.0 2730.5 RPS 171.0 2730.5 RPM 171.0 2730.5 GR 178.5 2738.5 S LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY EWR4 ELECTROMAG. RESIS. 4 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: 02-MAR-06 Insite 6.02 Memory .0 19.4 TOOL NUMBER 216261 59672 12.250 80.0 • Native/Spud Mud 9.50 160.0 9.3 600 .0 4.600 74.0 4.253 80.6 4.000 74.0 4.700 74.0 Data Format Specification Re cord Data Record Type ......... ..... ... .0 Data Specification Block Type. ... .0 Logging Direction ........ ..... ... .DOwn Optical log depth units.. ..... ... .Feet Data Reference Point ..... ..... ... .Undefined Frame Spacing ............ ..... ... .60 .lIN Max frames per record .... ..... ... .Undefined Absent value ............. ..... ... .-999.25 Depth Units .............. ..... ... . Datum Specification Block sub-type...0 Name Service Order Units Si ze Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWDO10 FT/H 4 1 68 4 2 GR MWDO10 API 4 1 68 8 3 RPX MWDO10 OHMM 4 1 68 12 4 RPS MWDO10 OHMM 4 1 68 16 5 RPM MWDO10 OHMM 4 1 68 20 6 • RPD MWDO10 OHMM 4 1 68 24 7 FET MWDO10 HRS 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 115.5 2780.5 1448 5331 115.5 2780.5 ROP MWDO10 FT/H 0 225.17 96.4051 5331 115.5 2780.5 GR MWDO10 API 10.53 109.9 64.2193 5121 178.5 2738.5 RPX MWDO10 OHMM 0.4 99.65 30.9631 5120 171 2730.5 RPS MWDO10 OHMM 0.35 419.61 50.3708 5120 171 2730.5 RPM MWDO10 OHMM 0.44 2000 96.0718 5120 171 2730.5 RPD MWDO10 OHMM 0.27 2000 139.815 5120 171 2730.5 FET MWDO10 HRS 0.23 5.6 0.979758 5121 170.5 2730.5 First Reading For En tire File..... .....115.5 Last Reading For Ent ire File...... .....2780. 5 File Trailer Service name ..... ........STSLIB.002 Service Sub Level Name... Version Number... ........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ........ ........LO Next File Name... ........STSLIB.003 Physical EOF File Header Service name .............STSLIB.003 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.002 Comment Record FILE HEADER FILE NUMBER: 3 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 2739.0 4585.0 CALA 2750.0 4538.0 NPHI 2757.0 4535.0 FCNT 2757.0 4535.0 NCNT 2757.0 4535.0 RPD 2757.0 4577.5 PEF 2757.0 4548.5 RPX 2757.0 4577.5 RPS 2757.0 4577.5 RPM 2757.0 4577.5 RHOB 2767.0 4548.5 DRHO 2767.0 4548.5 FET 2767.0 4577.5 ROP 2781.0 4630.5 LOG HEADER DATA DATE LOGGED: 06-MAR-06 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 6.02 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): C TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY EWR4 ELECTROMAG. RESIS. 4 CTN COMP THERMAL NEUTRON ALD Azimuthal Litho-Den BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN) 8.500 DRILLER'S CASING DEPTH (FT) 2767.0 BOREHOLE CONDITIONS MUD TYPE: Polymer MUD DENSITY (LB/G) 9.05 MUD VISCOSITY (S) 59.0 MUD PH: 9.5 MUD CHLORIDES (PPM): 21000 FLUID LOSS (C3) .0 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT) .220 MUD AT MAX CIRCULATING TERMPERATURE: .151 MUD FILTRATE AT MT: .180 MUD CAKE AT MT: .240 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Re cord Data Record Type ......... .... ... ..0 Data Specification Block Type ... ..0 Logging Direction ........ .... ... ..Down Optical log depth units.. .... ... ..Feet Data Reference Point ..... .... .....Undefined Frame Spacing ............ .... ... ..60 .lIN Max frames per record .... .... ... ..Undefined Absent value ............. .... ... ..-999.25 Depth Units .............. .... ... .. Datum Specification Block sub -type...0 Name Service Order Units Si ze N sam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 RPX MWD020 OHMM 4 1 68 12 4 RPS MWD020 OHMM 4 L 68 16 5 RPM MWD020 OHMM 4 1 68 20 6 RPD MWD020 OHMM 4 1 68 24 7 FET MWD020 HRS 4 1 68 28 8 NPHI MWD020 PU-S 4 1 68 32 9 FCNT MWD020 CNTS 4 1 68 36 10 NCNT MWD020 CNTS 4 1 68 40 11 RHOB MWD020 G/CM 4 1 68 44 12 DRHO MWD020 G/CM 4 1 68 48 13 PEF MWD020 B/E 4 1 68 52 14 GALA MWD020 IN 4 1 68 56 15 Name Service Unit Min Max Mean Nsam 16.8 20.2 TOOL NUMBER 119546 145654 1844674407370955 143789 66.0 99.0 69.0 70.0 First Last Reading Reading DEPT FT 2739 4630.5 3684.75 3784 2739 4630.5 ROP MWD020 FT/H 4.94 496.41 100.343 3700 2781 4630.5 GR MWD020 API 23.15 130.23 77.5606 3693 2739 4585 RPX MWD020 OHMM 0.37 332.91 7.58004 3642 2757 4577.5 RPS MWD020 OHMM 0.43 1774.76 14.6231 3642 2757 4577.5 RPM MWD020 OHMM 0.47 2000 19.4589 3642 2757 4577.5 RPD MWD020 OHMM 0.81 2000 20.2795 3642 2757 4577.5 FET MWD020 HRS 0.42 72.23 1.45214 3622 2767 4577.5 NPHI MWD020 PU-S 13.17 79 39.6106 3557 2757 4535 FCNT MWD020 CNTS 422 2822 736.425 3557 2757 4535 NCNT MWD020 CNTS 91855 176859 114940 3557 2757 4535 RHOB MWD020 G/CM 1.322 2.642 2.17233 3564 2767 4548.5 DRHO MWD020 G/CM -0.107 0.258 0.0160968 3564 2767 4548.5 PEF MWD020 B/E 0.18 11 1.94192 3584 2757 4548.5 CALA MWD020 IN 8.12 12.46 8.98909 3577 2750 4538 First Reading For Entire File..........2739 Last Reading For Entire File...........4630.5 File Trailer Service name .............STSLIB.003 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.004 Physical EOF File Header Service name .............STSLIB.004 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.003 Comment Record FILE HEADER FILE NUMBER: 4 RAW MWD Curves and log header data for each bit r un in separate files. BIT RUN NUMBER: 0 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH VEXP 3350.0 4579 .5 MEMP 3350.0 4579 .5 MESP 3350.0 4579 .5 MEXP 3350.0 4579 .5 VEDP 3350.0 4579 .5 VEMP 3350.0 4579 .5 VESP 3350.0 4579 .5 MEDP 3350.0 4579 .5 LOG HEADER DATA DATE LOGGED: 16-JUN-06 SOFTWARE SURFACE SOFTWARE VERSION: VRE DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): Processed TD DRILLER (FT): TOP LOG INTERVAL (FT) 3350.0 BOTTOM LOG INTERVAL (FT) 4580.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: .0 MAXIMUM ANGLE: .0 • • TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT) 2767.0 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G) .00 MUD VISCOSITY (S) .0 MUD PH: .0 MUD CHLORIDES (PPM): 0 FLUID LOSS (C3) .0 RESISTIVITY (OHMM) AT TEMPE RATURE (DEGF) MUD AT MEASURED TEMPERAT URE (MT) .000 .0 MUD AT MAX CIRCULATING T ERMPERATURE: .000 .0 MUD FILTRATE AT MT: .000 .0 MUD CAKE AT MT: .000 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Record Data Record Type .............. ....0 Data Specification Block Type. ....0 Logging Direction ............. ....Down Optical log depth units....... ....Feet Data Reference Point .......... ....Undefine d Frame Spacing ................. ....60 .lIN Max frames per record ......... ....Undefine d Absent value .................. ....-999.25 Depth Units ................... .... Datum Specification Block sub- type...0 Name Service Order Units Size Ns am Rep Code Offset Channel DEPT FT 4 1 68 0 1 VEXP MWD099 OHMM 4 1 68 4 2 VESP MWD099 OHMM 4 1 68 8 3 VEMP MWD099 OHMM 4 1 68 12 4 VEDP MWD099 OHMM 4 1 68 16 5 MEXP MWD099 OHMM 4 1 68 20 6 MESP MWD099 OHMM 4 1 68 24 7 MEMP MWD099 OHMM 4 1 68 28 8 MEDP MWD099 OHMM 4 1 68 32 9 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3350 4579.5 3964.75 2460 3350 4579.5 VEXP MWD099 OHMM 0.101 386.491 9.29006 2460 3350 4579.5 VESP MWD099 OHMM 0.102 1501.71 24.7387 2460 3350 4579.5 VEMP MWD099 OHMM 0.101 1929.14 36.9523 2460 3350 4579.5 VEDP MWD099 OHMM 0.111 1980.39 40.0798 2460 3350 4579.5 MEXP MWD099 OHMM 0.1 70.159 7.60456 2460 3350 4579.5 MESP MWD099 OHMM 0.098 254.523 11.265 2460 3350 4579.5 MEMP MWD099 OHMM 0.11 328.558 13.6916 2460 3350 4579.5 MEDP MWD099 OHMM 0.117 273.296 13.9417 2460 3350 4579.5 First Reading For Entire File..........3350 Last Reading For Entire File...........4579.5 File Trailer • • Service name .............STSLIB.004 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/06/16 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.005 Physical EOF Tape Trailer Service name .............LISTPE Date .....................06/06/16 Origin ...................STS Tape Name ................UNKNOWN Continuation Number......01 Next Tape Name...........UY3KNOWN Comments .................STS LIS Writing Library. Scientific Technical Services Reel Trailer Service name .............LISTPE Date .....................06/06/16 Origin ...................STS Reel Name ................UNKNOWN Continuation Number......01 Next Reel Name...........UNKNOWN Comments .................STS LIS Writing Library. Scientific Technical Services Physical EOF Physical EOF End Of LIS File Schlumgerger ~ Schlumberger Fluid Analysis of MDT Samples ConocoPhillips ~~~°~'~"n g Field: West Sak We11:1 H North ,_ ~. r, ~._ b~ Black Oil Full PVT Study Report °- F.. Prepared for ;.~~ Y+,.. Michael Werner / Dennis Wegener ~..} ConocoPhillips _ . .~3 • Standard Conditions Used: Pressure: 14.696 psia Temperature: 60°F R~c~~vE Prepared by: Stefan Smuk JAN 2 2 2oa7 Schlumberger WCP Oilphase-DBR ~&~sCo-~s.C~ Anchorage 16115 Park Row, Suite 150 Houston, Texas, 77084 (281) 285-6370 • I Date: 06/30/2006 Report #200600050 ~ ! ~a 3~! 5 5o-oeg - 23~`~ ~f -ov-oo Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Schlumberger Installation: - Job #: 200600050 . Table of Contents List of Figures .................. _.._.. ..................._........................._......................... ........................................... 2 List of Tables ..................... ................................................................................. ............................................ 3 EXECUTIVE SUMMARY ....................................................................................... ............................................ 4 Objective ................................................................................ ............................................ 4 Introduction ....................................................................................................... ............................................ 4 Scope of Work .......................................................................................................... ............................................ 4 Results .......................................................................................................... ............................................ 4 Y -Y ...................................................................... PVT Study Data. Qualit .Check Summa s ............................................ Sequence of Events ................................................................................................... ............................................ s Chain of Sample.Cusiady ............................................................................................ ............................................ s RESULTS AND.DIS.CUS.SIO.NS ............................................................................... ............................................ ~ fluids Preparation and Analysis ................................................................................. ............................................ ~ Reservoir Fluid.Analysis ............. _.............................................................................. ............................................ ~ PVT Analysis on Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD .... ............................................ 30 Constant Composition Expansion at Tres ........................... ............................................ 30 Reservoir Oil Viscosity at Tres ................................................................................ ............................................ 32 Multi-Stage Separation Test ............................ 34 PVT Analysis oa Sampl.e.1..D9,.1.10 ,&.1.1.1;.Cylinder.CSB.7356-MA;. Depth 4068.ft.. MD ......... ............................................ 4z Constant Composition Expansion at Tres ..................................................................... ............................................ 42 Reservoir Oil Viscosity ............................................................................................... ............................................ 45 Multi-Stage Separation.Test ....................................................................................... ............................................ 53 • APPendix A: N.omenclature..and.Definitions ........................................................ ............................................ 5s Appendix B: Molecu.lar.Weights.and.D.ensities.Use.d ........................................ ............................................ 57 Appendix C: EQU.tPMENT ...................................................................................... ............................................ 5s fluid Preparation.and.Yalidatinn ................................................................................. ............................................ 58 Fluid Vo/umetric.lPVTI and.Viscasity.Equipment ........................................................... ............................................ 5s Appendix D: PROCED.URE .................................................................................... ............................................. st Fluids Preparation and.Validatian .............................................................................. ............................................. 6t Constant Composition Expansion Procedure ............................................................... ...............:............................. st Differential VaparizationProcedure ........................................................................... ............................................. st Multi-Stage Separation.Test ...................................................................................... ............................................. st Liquid Phase Viscosity.and.Density.dReasurements.During.QV.Step ............................... ............................................. 62 Stock-Tank Oil.(STD) .Viscosity. and.Qensity Measurements .......................................... ............................................. s2 Asphaltene, Wax.and.Sulfur.ContentMeasurements .................................................... ............................................. s2 SAR/PJAAnalysis ..................................................................................................... ............................................. s2 Nigh-Temperatwe High.Pressure.Filtration.Test .......................................................... ............................................. 63 Oilphase-DBR 1 Job #: 200600050 Client: ConocoPhillips Well: 1 H North Field: Sand: West Sak B & D Schlumberger Installation: - Job #: 200600050 . List of Figures Figure 1: Stock Lank Dil.Chromatogram (Sampl.e.1..D9) .................................................................. Figure 2: k-Plot.for. Equilibrium.Check.(Sample.1.09)..... •. •.. •..... • ..................... •.... • •....... • • •.. •.. •. •..... Figure 3: Stock Tank Oil. Chromatogram (Sample.l...10) .................................................................. Figure 4: k-Plot.for. Equilibrium.Check.(Sample.1.1.0) .................................................................... Figure 5: Stock Tank Dil. Chromatogram (Sample.1_i].) .................................................................. Figure 6: k-Plot.for.Equilibrium.Check.(Sample.l.].1) .................................................................. Figure 7: Stock Tank Oil. Chromatogram (Sample.1...12) ......................................... _...................... Figure 8: k-Plot.for. Equilibrium.Check.(Sample.1.12) ..................................................................... Figure 9: Stock Tank Oil. Chromatogram (Sampl.e.1.13) ................................................................. Figure 10: k-PloifocEquilibrium.Check.(Sampte.1.13- ......................................._.......................... Figure 11: Stock.Tank.Oil.Chromatagram.(Sample.1.15) ................................................................. Figure 12: k-Ploifor.Equilibrium.Check.(.Sampte.1.15- ................................................................... Figure 13: ConstaniCompasitian.Expansion.at.79.0.°.F.-.Relative.V.ol.ume.(Sample. 1.15- ..................... Figure 14: Reservoir. Fluid Viscosity .79'F. (Sample.1._15) ................................................................ Figure 15: k-Ploifor.Equilibrium.Check.(Sample.1.09,1.1D.&.1.11.- ................................................... Figure 16: Constant Composition Expansion at 81.0°F -Relative Volume (Sample 1.09,1.10 & 1.11-.... Figure 17: Reservoir. Fluid Visc~sityat.81.°.F.(Sample.1.09,.L.10.&.1.1..1) ............................:................ Figure 18: Reservoir. Fluid Viscosity. at.1.50'E.(Sample '1.09, .1.1.0.&. ]..11.) ........................................... Figure 19: Reservoir Fluid Viscosity. at.90'.F.(Sample.1.09,.1._1D &.1.1.1- ............................................. Figure 20: Reservoir. Fluid Viscosity. at.60.°.F.(Sample.1.09,.1._10 &.1.1.1- ............................................. • 13 13 16 16 19 19 22 22 25 25 28 28 31 33 40 43 45 a7 49 51 Oilphase-DBR 2 Job #: 200600050 ,~ u Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Installation: - Job #: 200600050 Schlumberger List of Tables Table 1: Well and.Sampl.e.1.dentification ................................................................ Table 2: Well Position Data .................................... . .......................................... Table 3: Sampling aad Transfer Surnmary .............................................................. Table 4: ReservoirFluid Properties ...................................................................... Table 5: Stock-T.ank.QiJ. P.roperties ..................................................................... . Table 6: C36+Composition,.GOR,'API,.b..y.Zero-.Flash.(Sample.l_09.) ...................................... Table l: Calculated.Fluid.P.raperties ..........................................................................:....... Table 8: C36+Cnmposition,.GOR,'APl,.by.Zero-.Flash.(Sample.1.10.) ...................................... Table 9: Calculated.Fluid.P.raperties .................................................................................. Table 10: C36+ Composition,. GO.R,.'AP1, byZero-Flash.(Sample .1.1.1- .................................... Table 11: Calculated.Fluid.Properties ................................................................................ Table 12: C36+ Composition,. GD.R,.°API, by Zero-Flash.(Sample.1.12- ................................... Table 13: Calculated. Fluid.Properties ................................................................................ Table 14: C36+ Composition,. GD.R,. °API, byZero-Flash.(Sample .1.13- ................................... . Table 15: Calculated. Fluid. Properties ............................................................................ Table 16: C36+ Composition,. G.O.R,.'AP1, byZero-Flash.(Sample.1.15) .................................... Table 17: Calculated. Fluid. Properties ................................................................................ Table 18: Summary.of.Results.of.Sample.1.15 ..................................................................... Table 19: Constant Composition.Expansion.at.79.0'.E.(Sample.1.1.5) ....................................... Table 20: Reservoir. Fluid Viscasity..79'F..(Sample.1.15- ........................................................ Table 21: Multi-.Staye.Separation Test.Vapor.&.LigLid.Properties..(Sample.1.15- ................... Table 22: Multi-.Stage.Separator.Test.Vapar. Composition. (mal %- ........................................ Table 23: Multi-.Stage.Separator.Test.Residual Liquid. Composition.(moJ. °!o- .......................... Table 24: C30+ C.omposition,. G.O.R,.°AP.I, by Zera-Flash.(Sample.1.09,.1.1.0.& 1.11) ................... Table 25: Calculated. Fluid. Properties ................................................................................ Table 26: Summary.of.Results.of.Sample.1.09,.1.1.0.&1.11 .................................................... Table 27: Constant Composition. Expansion. at.81.0'.F.(Sample.1.09,.1.10. &.1.1.1- ...................... Table 28: Reservoir. Fluid Viscosity at.81'.F.(Sample.1.09..1..10 &.1.1..1- .................................... Table 32: Multi-.Stage.Separation.Test.Vapor.&. Liquid.Praperti.es.(Sample.1.09,.1.1.0.&.1..11.)... Table 33: Multi,Stage.Separator.Test.Vapor. Composition. (mo.l. %- ........................................ Table 34: Multi-.Stage.Separator.Test.Residualliquid.Composition.(moJ.°!o- .......................... Oilphase-DBR ~: s 8 9 10 10 11 12 14 15 17 18 20 21 23 24 26 27 29 30 32 35 36 37 38 39 41 42 44 53 54 55 Job #: 200600050 Client: ConocoPhillips Well: 1 H North Field: Sand: West Sak B & D Sehlumberger Installation: - Job #: 200600050 . EXECUTIVE SUMMARY Objective To evaluate the compositions and phase behavior of bottomhole fluid samples collected during modular formation dynamics testing (MDT. Introduction At the request of ConocoPhillips, Oilphase has conducted a fluid analysis study on bottomhole fluid samples collected during the modular formation dynamics testing (MDTf of Well 1 H North drilled in the field West Sak. Scope of Work Homogenize bottomhole hydrocarbon fluid samples at the reservoir conditions with rocking for five days. • Conduct preliminary evaluation on bottomhole hydrocarbon samples that include single-stage flash Gas- Oil Ratio (GORE, reservoir fluid composition, stock-tank oil (STO) and monophasic fluid properties. • Select representative samples for PVT studies. Results The following bullets summarize the PVT analysis conducted on the bottomhole hydrocarbon and water samples: • Six bottomhole samples were used for validation purposes. They were homogenized at the reservoir conditions for five days. • The zero flash GOR was determined to be from 185 - 245 SCF/STB, and the STO density to be from 0.9302 to 0.9496 g/cc. • Samples 1.09,1.10 and 1.11, D Sand, were settled in a vertical position, and the top portions of the fluid were transferred to a single new cylinder and de-emulsified for a full PVT study. Sample 1.09, 1.10 & 1,11; Cylinder CSB 7356-MA; Depth 4068 ft. MD, D Sand FLASHING OPERATION CUMULATIVE GOR ~scf/stb) API GRAVITY Gas Relative Density (air=1) FVF at Pres/Tres FVF at Psat~fres Zero Flash 238 20.62 0.661 1.103 1.105 DL Flash @ Tres - - - - - SeparatorTest 214 21.26 0.624 1.093 1.095 • Sample 1.15, B Sand, was used for complete PVT analysis, including constant-composition expansion and multi-stage separation testing. Sample 1.15; Cylinder SS818535-QA; Depth 4154 ft. MD, 8 Sand FLASHING OPERATION CUMULATIVE GOR (scf/stb) API GRAVITY Gas Relative Density fair=1) FVF at Pres/Tres FVF at Psat/Tres Zero Flash 186 17.54 0.613 1.069 1.070 DL Flash @ Tres - - - - - SeparatorTest 182 17.62 0.606 1.067 1.068 Oilphase-DBR 4 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 • Quality Assurance Process Oilphase-DBR Schlumberger is committed to providing unsurpassed services in bottom hole reservoir fluid sampling and fluid property analyses while maintaining high standards of safety and quality. Our objective is to deliver the most accurate and reliable sampling processes and fluid property measurements available in the industry. This objective requires persistent innovation and ongoing development of state-of-the-art technologies and equipment. A rigorous quality assurance program, continuous employee training and enforcement of strict safety standards maintain our compliance with Quality, Health, Safety and Environment (QHSE) requirements. Proactive integration of QHSE objectives and management goals at every level supports the communication and implementation of QHSE policies and standards. Schlumberger requires that qualified engineering technologists perform all laboratory measurements according to specified analytical procedures designed for obtaining accurate and reliable data. Rigorous quality assurance programs and instrument calibration protocols are in place to ensure and maintain the validity of the procedures. Details of these programs are available upon request. The lab-generated data undergoes the following five levels of quality checks to establish the integrity of the reported results. a) Establish quality of measurement during data generation. b) Establish quality of processed data as per checklist during data processing by Data Quality Engineer. c) Data Duality Supervisor confirms the overall quality of the processed data and ensures cross correlative consistency d) The responsible Project Engineer confirms consistency of reported data el Engineering Project Manager review the results/report for overall consistency Hence the completion of each project requires that a qualified and experienced team of engineers perform a variety of independent review of all technical data to confirm the consistency and accuracy of the report as per pre-established Quality checklists designed for each operation and based on the level of complexity. All property measurements and calculation procedures are maintained in company archives for a period of 1 year. This information is available for review by clients upon request. The file and laboratory records information are listed below to provide access reference to all records related to this project. For any questions, please do not hesitate to contact the undersigned Project Engineer. file No.:200600050 Laboratory Records: 200600050 • Data Quality Suyu Ye Data Quality Engineer • Data Reporting Meisong Yan Project Engineer Overall Report Quality Clay Young Clay Young Oilphase-DBR Operation Manager, NGC Oilphase-DBR 5 Job #: 200600050 I~ _ - Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 • Sequence of Events 04/03/06 Samples arrived and client informed. 04/18/06 Project work scope discussed. 04/18/06 Work agreement approved. 04/19/06 Prelim PVT tests request for all six samples issued. Chain of Sample Custody The samples collected from the well 1 H North were sent to Oilphase-DBR in Houston, Texas. The samples were used to preliminary measurements and subsequent PVT studies. The measurement details are in the following text. Samples remaining after measurements are stored in Oilphase-DBR storage unless otherwise instructed. • Oilphase-DBR 6 Job #: 200600050 Client: ConocoPhillips Field: WesT Sak Schlumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 • RESULTS AND DISCUSSIONS Fluids Preparation and Analysis Six bottomhole samples collected during the MDT were transferred to Oilphase-DBR. The well and formation data with their respective reservoir conditions for the bottomhole samples are summarized in Table 1. The quality check for the bottomhole samples were conducted and the results are summarized in Table 2. After 5-days of homogenization, sample validation tests were conducted to evaluate the validity of the samples. It was determined that all the samples needed de-emulsification prior to conducting PVT analysis. The reservoir fluid and stock-tank oil properties for all the samples are presented in Tables 4 and 5. Reservoir Fluid Analysis The gas and liquid phases from the single-stage flash were subjected to chromatography and their compositions were determined. These compositions were recombined mathematically according to single-stage flash Gas-Oil Ratio (GORE to calculate the reservoir fluid composition. The reservoir fluid analysis is summarized in Table 6, 8, 1 D, 12, 14 and 16. The molecular weight of the stock-tank oil (STO) was measured. Other properties such as the plus fraction properties and heat content for the flash gas were calculated from the compositions and are listed in Tables 7, 9, 11, 13, 15 and 17. After quiescent restoration in a vertical position, the top portions of samples 1.09,1.10 and 1.11 were transferred into a single cylinder, and underwent de-emulsification. Afterwards the sample was flashed, and GOR, API and compositional data were found to be consistent with the data for original sample. The Base Sediment and Water were also measured for the blended sample, and found to be close to zero. BS&W checks of samples 1.13 and 1.15 showed that both fluids had very little water and sediment content, making them appropriate for PVT testing without further treatment. Sample • 1.15 was selected for PVT testing because of its large volume. The scope of PVT testing included constant composition expansion and viscosity experiments at reservoir temperature, and a multistage separation test. The blended sample was also subjected to viscosity measurements at three additional temperatures. • Oilphase-DBR 7 Job #: 200600050 • Client: ConocoPhillips Well: 1 H North Installation: - Field: West Sak Sand: B & D Job #: 200600050 Schlumberger Table 1~ Well and Sample Identifit:ation Client: ConocoPhillips Job# 200600050 Field: Beechy Point Well: 1 H North Sample ID Chamber # Zone Sampling Date Opening Pres. Reservoir Conditions in the field Pressure Temperature Depth (psia/°F) (psia) (°F) (ft) 1.09 MRSC 182 D Sand D3/O9/06 915/26 1,720 81 4068 1.10 SPMC 451 D Sand 03/09/06 6515/49 1,720 81 4068 1.11 SPMC 450 D Sand 03/09/06 6515/49 1,720 81 4068 1.12 SPMC 443 D Sand 03/09/06 6515/51 1,720 81 4068 1.13 SPMC 441 B Sand 03/09/06 6315/53 1,707 79 4154 1.15 SPMC 444 B Sand 03/09/06 6515/51 1,707 79 4154 1.09,1.10 & 1.11 - D Sand - - 1,735 81 4068 Table 2: Well Position Data • • Well Name Strat Name Latitude Longitude X Loc Y Loc 1H-NORTH SURFACE 70.394828853 -149.559222785 1694586.97 5994052.42 1 H-NORTH WEST SAK D 70.396903765 -149.555190463 1695077.43 5994814.88 1 H-NORTH WEST SAK B 70.396963574 -149.555067093 1695091.76 5994836.51 Oilphase-DBR 8 Job #: 200600050 • r • Client: ConocoPhillips Well: 1H North Installation: - Field: West Sak Sand: B & D Job #: 200600050 Schlumberger Table 3: Samalina and Transfer Summary Opening Transfer Closing Opening Transferred Sample ID Chamber # conditions Cylinder conditions conditions Water Content Sample in the field ID in the field in the Lab Volume (Psia/°F) (psia/°FI (Psia/°F) (wt%) loo) 1.09 MRSC 182 915/26 CSB 7720-QA 815/65 1015/75 2.3 600 1.10 SPMC 451 6515/49 SSB 18532-DA 6015/65 6265/75 1.7 245 1.11 SPMC 450 6515/49 SSB 18537-QA 6015/65 6265/75 1.3 240 1.12 SPMC 443 6515/51 SSB 18540-DA 6015/65 6515/75 2.6 245 1.13 SPMC 441 6315/53 SSB 18538-OA 6015/65 7265/75 0.7 220 1.15 SPMC 444 6515/51 SSB 18535-QA 6015/65 6765/75 0.4 245 1.09,1.10 & 1.11 - - CSB 7356-MA - - Nil 600 Oilphase-DBR Job #: 200600050 • Client: ConocoPhillips Well: 1 H North Installation: - Table 4: Reservoir Fluid Properties Zero Flash Saturation Molar Mass of Monophasic Sample ID Cylinder # Depth GOR* Bo** Pressure monophasic fluid*** OBM at Tres fluid contamination {ft) (scf/stb- (psia) % (w/w) 1.09 CSB 7720-QA 4,068 232 205.6 - 1.10 SSB 18532-QA 4,068 245 195.8 - 1.11 SSB 18537-QA 4,068 242 195.0 - 1.12 SSB 18540-QA 4,068 239 197.4 - 1.13 SSB 18538-QA 4,154 185 244.2 - 1.15 SSB 18535-QA 4,154 186 242.9 - 1.09, 1.10 & 1.11 CSB 7356-MA 4,068 238 1.105 1544 194.7 - * flashed gas volume (scf) per barrel of stock tank liquid L 6U"h ** Volume of live oil at it's bubble point pressure per flashed stock tank liquid volume @ 60°F *** Calculated from oil-based mud contamination in STO Field: West Sak Sand: B & D Job #: 200600050 Table 5: Stock-Tank Oil Properties Schlumberger STO Properties Sample iD Cylinder# Depth Molar Mass Density API* OBM Contamination Iftl 19/cc) % Iw/wl 1.09 CSB 7720-QA 4,068 315.8 0.9329 20.2 - 1.10 SSB 18532-QA 4,068 301.3 0.9309 20.5 - 1.11 SSB 18537-QA 4,068 296.6 0.9314 20.4 - 1.12 SSB 18540-QA 4,068 301.3 0.9315 20.4 - 1.13 SSB 18538-QA 4,154 365.0 0.9496 17.5 - 1.15 SS818535-QA 4,154 363.1 0.9494 17.5 - 1.09, 1.10 & 1.11 CSB 7356-MA 4,068 293.6 0.9302 20.6 - * API =141.5/Density -131.5. • Oilphase-DBR 10 Job #: 200600050 • • • Client: ConocoPhillips Field: West Sak Well: i H North Sand: B & D Table 6: C36+ Composition, GOR, °API, by Zero-Flash (Sample 1.09) Sample 1.09; Cylinder CSB 7720-OA; Depth 4068 ft. MD Schlumberger Component MW Flashed Gas Flashed liquid Monophasic fluid (g/motel WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.23 0.10 0.00 0.00 0.01 0.04 Hydrogen Sulfid 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 1.93 1.33 0.00 0.00 D.07 0.49 Methane 16.04 76.06 91.00 0.00 0.00 2.64 33.80 Ethane 30.07 2.20 1.41 0.00 0.00 0.08 0.52 Propane 44.10 4.32 1.68 0.00 0.03 0.15 0.72 I -Butane 58.12 2.79 0.92 0.02 0.09 0.11 0.40 N -Butane 58.12 4.20 1.39 0.04 0.22 0.18 0.65 I -Pentane 72.15 2.90 0.77 0.12 0.53 0.22 0.62 N -Pentane 72.15 1.40 0.37 0.08 0.33 0.12 0.35 C6 84.00 1.72 0.39 0.43 1.60 0.47 1.15 M-C-Pentane 84.16 0.27 0.06 0.14 0.53 0.14 0.35 Benzene 78.11 0.04 0.01 0.03 0.11 0.03 0.07 Cyclohexane 84.16 0.27 0.06 0.19 0.73 0.20 0.48 C7 96.00 0.68 0.14 0.75 2.45 0.74 1.59 M-C-Hexane 98.19 0.24 0.05 0.35 1.11 0.34 0.72 Toluene 92.14 0.07 0.02 0.20 0.68 0.20 0.44 C8 107.00 0.37 0.07 1.27 3.74 1.24 2.38 E-Benzene 106.17 0.01 0.00 0.18 0.55 0.18 0.35 M/P-Xylene 106.17 0.02 0.00 0.40 1.18 0.38 0.74 0-Xylene 106.17 0.01 0.00 0.14 0.42 0.14 0.26 C9 121.00 0.17 0.03 1.38 3.60 1.34 2.27 C10 134.00 0.06 0.01 2.28 5.38 2.20 3.38 Cl1 147.00 0.02 0.00 2.17 4.66 2.09 2.93 C12 161.00 0.00 O.DO 2.49 4.88 2.40 3.07 C13 175.00 0.00 0.00 2.71 4.89 2.61 3.07 C14 190.00 0.00 0.00 2.78 4.61 2.68 2.90 C15 206.00 0.00 0.00 2.89 4.43 2.79 2.78 C16 222.00 2.72 3.86 2.62 2.43 C17 237.00 2.69 3.59 2.60 2.26 C18 251.00 2.29 2.88 2.21 1.81 C19 263.00 2.45 2.94 2.36 1.85 C20 275.00 2.42 2.78 2.34 1.75 C21 291.00 2.08 2.26 2.01 1.42 C22 300.00 1.98 2.08 1.91 1.31 C23 312.00 1.90 1.92 1.83 1.21 C24 324.00 1.77 1,72 1.70 1.08 C25 337.00 1.69 1.58 1.63 0.99 C26 349.00 1.66 1.50 1.60 0.94 C27 360.00 1.61 1.41 1.55 0.89 CZ8 372.00 1.67 1.42 1.61 0.89 C29 382.00 1.75 1.44 1.69 0.91 C30 394.00 1.41 1.13 1.36 0.71 C31 404.00 1.13 0.88 1.09 0.56 C32 415.00 1.21 0.92 1.17 0.58 C33 426.00 0.88 0.65 0.85 0.41 C34 437.00 1.04 0.75 1.00 0.47 C35 445.00 0.96 0.68 0.93 0.43 C36+ 819.70 43.70 16.84 42.18 10.58 Total 100.00 100.00 100.00 100.00 100.00 100.00 MN/ 19.19 315.83 205.64 MOLE RATIO 0.3715 0.6285 Oilphase-DBR 11 Job #: 200600050 • Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & 0 Table 7: Calculated Fluid Properties Sample 1.09; Cylinder CSB 7720-QA; Depth 4068 ft. MD Schlumberger Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 2.23 0.44 99.32 97.20 95.95 61.26 C12+ 0.00 0.00 89.85 72.06 86.73 45.29 C20+ - - 68.84 39.97 66.45 25.12 C30+ - - 50.32 21.86 48.58 13.74 C36+ - - 43.70 16.84 42.18 10.58 Molar Mass C7+ 96.86 322.71 322.11 C12+ 161.00 393.79 393.79 C20+ - 543.90 543.90 C30+ - 727.25 727.25 C36+ - 819.70 619.70 Density C7+ - 0.9358 - C12+ - 0.9565 0.9565 C20+ - 1.0006 1.0006 C30+ 1.0516 1.0516 C36+ 1.0755 1.0755 Fluid at 60°F 0.9329 Gas Gravity (Air =1) 0.663 Dry Gross Heat Content (BTU/scf) 1,156 Wet Gross Heat Content (BTU/scf 1,136 OBM Contamination Level (wt%) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+ Properties MW 315.83 315.83 819.70 Density (g/cm31 0.9329 - 1.0755 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 232 - STO Density (g/cm3) 0.9329 - STO API Gravity 20.2 - OBM Density (g/cm3) Q60°F - Oiilphase-DBR 12 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B &D Schlumberger Figure 1: Stock Tank Oil Chromatogram (Sample 1.09- Sample 1.09: Cvlinder CSB 7720-QA: Depth 4068 ft. MD • fID1 A, (E~2t DATAV11~000501CY7720,D) Norm. 200600050 CONOCOPHILLIPS 1.09 CSB 7720-QA T00 D/F CYLINDER 800 500 400 300 m 200 ~ U ~ U~ ~~ ° m n c o u c 100 m ~~ u ~~ }' ~ ~ N m~ N~ h~~ 0 NNNNNNfh~N~V~~ U ~ ~ U U U C ~ C C CCCC CC CCCC ~C C C IUC ~ ~ 1Iry ~`~ f'Y'1I ~lDI ~ ll~ ' ~ ~ ~ ~ U 1 , ~ . , ~ _ PYfiNIfr ~I.;,P' ...A,l~,~ ,-"~,1~ 5~df61~Y : ~ddA~Wwd.~I~L.E6 0 0 5 10 15 20 25 30 35 mi Figure 2: k-Plot for Equilitbrium Gheck (Sample 1.09) Sample 1.09; Cylinder CSB 7720-QA; Depth 4068 ft. MD 4 3 2 c Y 1 I ~ O J Q -1 -z -4 -3 -2 -1 0 1 2 3 F • C4 ~ ~t~5 /~ . C6 . ca I . c1o Oilphase-DBR 13 Job #: 200600050 r~ ~J • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 8: C36+ Composition, GOR, °API, by Zero-Flash Sample 1.10) Sample 1.10: Cylinder SSB 18532-QA: Depth 4068 ft. MD Schlumberger Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.23 0.10 0.00 0.00 0.01 0.04 Hydrogen Sulfitl 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.23 0.16 0.00 0.00 0.01 0.06 Methane 16.04 77.86 92.28 0.00 0.00 2.82 34.47 Ethane 30.07 2.20 1.39 0.00 0.00 0.08 0.52 Propane 44.10 4.26 1.84 0.00 0.01 0.16 0.69 I -Butane 58.12 2.74 0.90 0.01 0.06 0.11 0.37 N -Butane 58.12 4.17 1.36 0.03 0.15 0.18 0.60 I -Pentane 72.15 2.92 0.77 0.11 0.46 0.21 0.58 N -Pentane 72.15 1.38 0.36 0.07 0.28 0.11 0.31 C6 84.00 1.75 0.40 0.44 1.58 0.49 1.14 M-C-Pentane 84.16 0.27 0.06 0.15 0.55 0.16 0.37 Benzene 78.11 0.04 0.01 0.03 0.12 0.03 0.08 Cyclohexane 84.16 0.28 0.06 0.21 0.75 0.21 0.49 C7 96.00 0.69 0.14 0.84 2.64 0.83 1.70 M-C-Hexane 98.19 0.24 0.05 0.37 1.12 0.36 0.72 Toluene 92.14 0.08 0.02 0.21 0.68 0.20 0.43 C8 107.00 0.36 0.06 1.44 4.06 1.40 2.57 E-Benzene 106.17 0.01 0.00 0.20 0.58 O.ZO 0.36 M/P-Xylene 106.17 0.02 0.00 0.43 1.23 0.42 0.77 0-Xylene 106.17 0.05 0.01 0.15 0.44 0.15 0.28 C9 121.00 0.13 0.02 1.58 3.94 1.53 2.47 C10 134.00 0.07 0.01 2.58 5.81 2.49 3.64 C11 147.00 0.02 0.00 2.46 5.05 2.38 3.17 C12 161.00 0.01 0.00 2.81 5.25 2.70 3.29 C13 175.00 0.00 0.00 3.03 5.22 2.92 3.27 C14 190.00 0.00 0.00 3.08 4.88 2.96 3.06 C15 206.00 0.00 0.00 3.16 4.62 3.05 2.90 C16 222.00 3.07 4.16 2.96 2.61 C17 237.00 2.59 3.30 2.50 2.07 C18 251.00 2.65 3.18 2.55 1.99 C19 263.00 2.64 3.03 2.55 1.90 C20 275.00 2.63 2.88 2.53 1.80 C21 291.00 2.39 2.47 2.30 1.55 C22 300.00 1.95 1.96 1.88 1.23 C23 312.00 2.10 2.03 2.02 1.27 C24 324.00 1.70 1.58 1.64 0.99 C25 337.00 1.66 1.49 1.60 0.93 C26 349.00 1.47 1.27 1.42 0.80 C27 360.00 1.64 1.38 1.58 0.86 C28 372.00 1.38 1.12 1.33 0.70 C29 382.00 1.45 1.14 1.40 0.72 C30 394.00 1.07 0.82 1.03 0.51 C31 404.00 1.01 0.75 0.97 0.47 C32 415.00 1.11 0.80 1.07 0.50 C33 426.00 0.87 0.62 0.84 0.39 C34 437.00 1.03 0.71 0.99 0.45 C35 445.00 0.93 0.63 0.89 0.39 C36+ 816.64 41.25 15.22 39.75 9.53 Tota! 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.02 301.28 195.84 MOLE RATIO 0.3735 0.6265 Oilphase-DBR 14 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 9: Calculated Fluid Properties Sample 1.10; Cylinder SSB 18532-QA; Depth 4068 ft. MD Schlumberger Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 2.27 0.45 99.34 97.46 95.82 61.23 C12+ 0.01 0.00 88.67 70.50 85.45 44.17 CZO+ - - 65.64 36.86 63.26 23.09 C30+ - - 47.27 19.55 45.55 12.25 C36+ - - 41.25 15.22 39.75 9.53 Molar Mass C7+ 96.74 307.08 306.51 C12+ 162.18 378.92 378.92 C20+ - 536.50 536.50 C30+ - 728.48 728.48 C36+ - 816.64 816.64 Density C7+ - 0.9336 - C 1 Z+ - 0.9570 0.9570 C20+ - 1.0085 1.0085 C30+ 1.0674 1.0674 C36+ 1.0934 1.0934 Fluid at 60°F 0.9309 Gas Gravity (Air =1) 0.657 Dry Gross Heat Content (BTU/scf) 1,166 Wet Gross Heat Content (BTU/scf 1,146 OBM Contamination Level (vvt°/,) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+ Properties MW 301.28 301.28 816.64 Density (g/cm3) 0.9309 - 1.0934 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 245 - STO Density (g/cm3) 0.9309 - STO API Gravity 20.5 - OBM Density (g/cm3) Q60°F - Oilphase-DBR 15 Job #: 200600050 Client: ConocoPhillips field: West Sak Schlumberger Well: 1 H North Sand: B & D • Figure 4: k-Plot for Equilibrium Check (Sample 1.10) Sample 1.10; Cylinder SSB 18532-DA; Depth 4068 ft. MD 4 3 2 c = 1 0 J -1 -Z -4 -3 -2 -1 0 1 2 3 F • • C3 • n~dC4 ~ ~i~5 r • C6 ~ C8 -~_ z-p • C10 ~ lr Oilphase-DBR 16 Job #: 200600050 Figure 3: Stock Tank Oil Chromatogram (Sample 1.10) Sample 1.10; Cylinder SSB 18532-QA; Depth 4068 ft. MD ., .~ • • Client: ConocoPhiiiips Field: West Sak Well: 1H North Sand: B & D Table 10: C36+ Composition, GOR, °API, by Zero-Flash (Sample 1.11) Sample 1.11; Cylinder SSB 18537-QA; Depth 4068 ft. MD Schlumberger Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.26 0.12 0.00 0.00 0.01 0.04 Hydrogen Sulfid 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.19 0.13 0.00 0.00 0.01 0.05 Methane 16.04 76.28 91.64 0.00 0.00 2.76 33.59 Ethane 30.07 2.32 1.49 0.00 0.00 0.08 0.55 Propane 44.10 4.60 2.01 0.03 0.17 0.19 0.85 I -Butane 58.12 2.98 0.99 0,05 0.23 0.15 0.51 N -Butane 58.12 4.46 1.48 0.11 0.55 0.27 0.89 I -Pentane 72.15 3.11 0.83 0.21 0.85 0.31 0.84 N -Pentane 72.15 -1.48 0.40 0.14 0.57 0.19 0.50 C6 84.00 1.86 0.43 0.55 1.96 0.60 1.40 M-C-Pentane 84.16 0.29 0.07 0.17 0.59 0.17 0.40 Benzene 78.11 0.05 0.01 0.04 0.14 0.04 0.09 Cyclohexane 84.16 0.30 0.07 0.23 0.81 0.23 0.54 C7 96.00 0.75 0.15 0.78 2.40 0.78 1.57 M-C-Hexane 98.19 0.26 0.05 0.42 1.28 0.42 0.83 Toluene 92.14 0.08 0.02 0.25 0.82 0.25 0.52 C8 107.00 0.39 0.07 1.4Z 3.94 1.38 2.5Z E-Benzene 106.17 0.02 0.00 0.12 0.34 0.12 0.22 M/P-Xylene 106.17 0.03 0.01 0.35 0.97 0.34 0.62 0-Xylene 106.17 0.01 0.00 0.18 0.49 0.17 0.31 C9 121.00 O.Z1 0.03 1.66 4.06 1.60 2.58 C10 134.00 0.06 0.01 2.54 5.61 2.45 3.56 C11 147.00 0.00 0.00 2.45 4.94 2.36 3.13 C12 161.00 0.00 0.00 2.75 5.08 2.66 3.22 C13 175.00 0.00 0.00 2.83 4.79 2.72 3.03 C14 190.00 0.00 0.00 3.03 4.73 2.92 2.99 C15 206.00 0.00 0.00 3.23 4.65 3.11 2.94 C16 222.00 2.86 3.82 2.75 2.42 C17 237.00 2.63 3.29 2.54 2.09 C18 251.00 2.57 3.03 2.47 1.92 C19 263.00 2.59 2.92 2.49 1.85 C20 275.00 2.35 2.54 2.27 1.61 C21 291.00 2.22 2.26 2.14 1.43 C22 300.00 2.12 2.09 2.04 1.33 C23 312.00 1.97 1.87 1.90 1.19 C24 324.00 1.86 1.70 1.79 1.08 C25 337.00 1.72 1.51 1.66 0.96 C26 349.00 1.61 1.37 1.55 0.87 C27 360.00 1.59 1.31 1.53 0.83 CZ8 372.00 1.57 1.25 1.52 0.79 C29 382.00 1.55 1.21 1.50 0.76 C30 394.00 1.50 1.13 1.44 0.71 C31 404.00 1.28 0.94 1.23 0.60 C32 415.00 1.22 0.88 1.18 0.55 C33 426.00 0.98 0.68 0.94 0.43 C34 437.00 0.95 0.65 0.92 0.41 C35 445.00 0.85 0.57 0.82 0.36 C36+ 800.00 40.50 15.02 39.03 9.51 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 19.27 296.63 194.96 MOLE RATIO 0.3666 0.6334 Oilphase-DBR 17 Job #: 200600050 • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 11: Calculated Fluid Properties Sample 1.11; Cylinder SSB 18537-QA; Depth 4068 ft. MD Schlumberger Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 2.44 0.49 98.92 95.67 95.43 60.78 C12+ 0.00 0.00 88.33 69.28 85.13 43.88 C20+ - - 65.85 36.98 63.46 23.42 C30+ - - 47.29 19.86 45.57 12.58 C36+ - - 40.50 15.02 39.03 9.51 Molar Mass C7+ 96.66 306.71 306.10 C12+ 166.68 378.19 378.19 C20+ - 528.23 528.23 C30+ - 706.38 706.38 C36+ - 800.00 800.00 Density C7+ - 0.9362 - C 12+ - 0.9600 0.9600 C20+ - 1.0114 1.0114 C30+ 1.0722 1.0722 C36+ 1.1036 1.1036 Fluid at 60°F 0.9314 Gas Gravity (Air =1) 0.666 Dry Gross Heat Content (BTU/scf) 1,180 Wet Gross Heat Content (BTU/scf 1,159 OBM Contamination Level (wt%) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+ Properties MW 296.63 296.63 800.00 Density (g/cm3) 0.9314 - 1.1036 Single Stage flash Data Original STO De-Contaminated GOR (scf/stb) 242 - STO Density (g/cm3) 0.9314 - STO API Gravity 20.4 - OBM Density (g/cm3) @60°F - Oilphase-DBR 18 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D Figure 5: Stock Tank Oil Chromatogram (Sample 1.11 ~ Sample 1.11; l;yllnder SSIi 1 ~53i-Wa; ueptn 4uba n. Ivlu fIP1;3, (F:@ID.ATAIOOfi00050'+CY18507.01 Noim. JOB 200600050 CONOCO PHILLIPS 1.11 SSB 18537-QA RF FLASH CYLINDER 250 200 950 to U ~' v 100 _° ~' ~ o o ~ ~ a R-~ ~N V 50 C G h 3 p ~- ~~' ~ ~~ ~ U ~l N h,fO~O~NP1Vtp(Lh~ ~ N ~ [ ~~,-~UNNNNNNNyNy U U Nom U o ~ ~ U U U U c UUUUUUW ((yyVV11 ~ U U C C CCC CCCCCCC C C U C C ; l i G ail I, !I l i ~ l i ~-~ti c 0 :.; ~ ~~,,, 0 5 10 15 20 25 30 35 Figure 6: k-Plot for Equilibrium (:heck (sample 1.1~) Sample 1.11; Cylinder SSB 18537-QA; Depth 4068 ft. MD 2.5 • C3 Z - - -- - --__ _ _ ---- - --------- - - -- • iC4 • nC4 1.5 - • 5 1 - c 0.5 Y Oi ~ D 5 -0 - ----- ~~ - - . - -1.5 ---- • C10 -2 i -4 -3 -2 -1 0 1 Z 3 F • Oilphase-DBR 19 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 12: C36+ Composition, GOR, °API, by Zero-Flash (Sample 1.12) Sample 1.12; Cylinder SSB 18540-QA; Depth 4068 ft. MD Schlumberger Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.29 0.12 0.00 0.00 0.01 0.05 Hydrogen Sulfitl 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.26 0.18 0.00 0.00 0.01 0.07 Methane 16.04 78.13 92.33 0.00 0.00 2.76 33.98 Ethane 30.07 2.21 1.39 0.00 0.00 0.08 0.51 Propane 44.10 4.28 1.84 0.03 0.17 0.18 0.79 I -Butane 58.12 2.74 0.89 0.05 0.24 0.14 0.46 N -Butane 58.12 4.10 1.34 0.11 0.57 0.25 0.85 I -Pentane 72.15 2.85 0.75 0.21 0.88 0.30 0.83 N -Pentane 72.15 1.36 0.36 0.14 0.58 0.18 0.50 C6 84.00 1.67 0.38 0.56 2.02 0.60 1.41 M-C-Pentane 84.16 0.26 0.06 0.17 0.60 0.17 0.40 Benzene 78.11 0.04 0.01 0.04 0.14 0.04 0.09 Cyclohexane 84.16 0.26 0.06 0.23 0.83 0.23 0.55 C7 96.00 0.65 0.13 0.78 2.44 0.77 1.59 M-C-Nexane 98.19 0.22 0.04 0.42 1.29 0.41 0.83 Toluene 92.14 0.07 0.01 0.26 0.85 0.25 0.54 CS 107.00 0.33 0.06 1.40 3.94 1.36 2.51 E-Benzene 106.17 0.01 0.00 0.12 0.34 0.12 0.21 M/P-Xylene 106.17 0.02 0.00 0.34 0.96 0.33 0.61 0-Xylene 106.17 0.01 0.00 0.17 0.49 0.17 0.31 C9 121.00 0.16 0.02 1.60 3.99 1.55 2.53 C10 134.00 0.05 0.01 2.42 5.45 2.34 3.45 C11 147.00 0.02 0.00 2.32 4.76 2.24 3.01 C12 161.00 0.00 0.00 2.62 4.91 2.53 3.10 C13 175.00 D.00 0.00 2.90 5.00 2.80 3.16 C14 190.00 0.00 0.00 3.04 4.83 2.94 3.05 C15 206.00 0.00 0.00 2.64 4.16 2.74 2.63 C16 222.00 2.80 3.79 2.70 2.40 C17 237.00 2.68 3.41 2.59 2.16 C18 251.00 2.59 3.10 2.49 1.96 C19 263.00 2.35 2.69 2.27 1.70 C20 275.00 2.30 2.52 2.21 1.59 C21 291.00 2.21 2.29 2.13 1.45 C22 300.00 2.13 2.14 2.06 1.35 C23 312.00 1.84 1.77 1.77 1.12 C24 324.00 1.74 1.62 1.68 1.02 C25 337.00 1.70 1.52 1.64 0.96 C26 349.00 1.58 1.36 1.52 0.86 C27 360.00 1.54 1.29 1.49 0.82 C28 372.00 1.54 1.25 1.49 0.79 C29 382.00 1.53 1.21 1.47 0.76 C30 394.00 1.43 1.09 1.38 0.69 C31 404.00 1.23 0.92 1.18 0.58 C32 415.00 1.16 0.84 1.12 0.53 C33 426.00 1.12 0.79 1.08 0.50 C34 437.00 0.96 0.66 0.93 0.42 C35 445.00 0.90 0.61 0.87 0.39 C36+ 805.00 41.91 15.68 40.43 9.91 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 18.96 301.28 197.39 MOLE RATIO 0.3680 0.6320 Oilphase-DBR 20 Job #: 200600050 • • C Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 13: Calculated Fluid Properties Sample 1.12: Cylinder SSB 18540-QA; Depth 4068 ft. MD Schlumberger Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 2.10 0.41 98.91 95.53 95.48 60.53 C12+ 0.00 0.00 88.63 69.45 85.50 43.89 C20+ - - 66.80 37.56 64.44 23.74 C30+ - - 48.70 20.60 46.98 13.02 C36+ - - 41.91 15.68 40.43 9.91 Molar Mass C7+ 96.45 311.91 311.38 C12+ 167. T 5 384.50 384.50 C20+ - 535.92 535.92 C30+ - 712.41 712.41 C36+ - 805.00 805.00 Density C7+ - 0.9364 - C1Z+ - 0.9594 0.9594 C20+ - 1.0083 1.0083 C30+ 1.0641 1.0641 C36+ 1.0925 1.0925 Fluid at 60°F 0.9315 Gas Gravity (Air =1) 0.655 Dry Gross Heat Content (BTU/scf) 1,162 et Gross Heat Content (BTU/scf 1,142 OBM Contamination Level (wt°/a) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+Properties MW 301.28 301.28 805.00 Density (g/cm3) 0.9315 - 1.0925 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 239 - STO Density (g/cm3) 0.9315 - STO API Gravity 20.4 - OBM Density (g/cm3) Q60°F - Oilphase-DBR 21 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumherger Well: 1H North Sand: B & D • .7 Figure 7: Stock Tank Oil Chromatogram (Sample 1.12) Samnla 1 17~ Cvlinder SSB 18540-DA: Depth 4068 ft. MD FID1 A, (F:~2 IDATAU70600060'+CY185~O.D) Nmm. JOB 200600050 CONOCO PHILIPS 1.12 SSB 18540-QA 250 RF FLASH CYLINDER 200 150 m U ~ ~ 100 ~ ~ g o ~' ~ o ' y, ~ Q; m ~~ U QI 3 N ~' ~ ~ N 0 - 50 ~~ 0 ~ CO ~ X ~ N ma~nr~r~a N tD r` m ~ ~ m U ~ ~ ~ ~ C N NNNNNNN~N(''ST1~ U U Nom O ~ ~ `" U U U U C U UUUUDU(X~JW~ C C (~ ~ ~ U C C C C C CCCCCCCCCCCCCCC ` ~!.I ' ~~' II I~; ~ I; ~ ly i. il . i 0 0 5 10 15 20 25 30 35 mi Figure 8: k-Plot for Equilibrium Check ISample 1.1z- Sample 1.12; Cylinder SSB 18540-DA; Depth 4068 ft. MD 2.5 2 1.5 1 n. 0.5 0 -0.5 -1 -1.5 -2 -4 -3 -2 -1 0 1 2 3 F • C3 • iC4 - -~ -nC55 ----- ---- ------ ---~ C~- - - _ - -_ -_ - . ----_-r E7---- --- -- -- - - --- ~-Cg---- ---- -- -------- -- - --- ---- - - i C3 --- ---- • C10 Oilphase-DBR Job #: 200600050 • • C Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table ]4: C31i+ Composition, GOR, °API, by Zero-Flash (Sample 1.13) Sample 1.13; Cylinder SSB 18538-QA; Depth 4154 ft. MD Schlumberger Component MW flashed Gas Flashed Liquid Monophasic fluid Ig/mole) WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.26 0.11 0.00 0.00 0.01 0.04 Hydrogen Sulfid 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 26.01 0.09 0.06 0.00 0.00 0.00 0.02 Methane 16.04 84.64 94.28 0.00 0.00 2.15. 32.80 Ethane 30.07 2.80 1.66 0.00 0.00 0.07 0.58 Propane 44.10 4.33 1.75 0.03 0.24 0.14 0.77 I -Butane 58.12 1.97 0.60 0.03 0.19 0.08 0.33 N -Butane 58.12 2.52 0.77 0.06 0.37 0.12 0.51 I -Pentane 72.15 1.33 0.33 0.06 0.42 0.12 0.39 N -Pentane 72.15 0.55 0.14 0.05 0.23 0.06 0.20 C6 84.00 0.65 0.14 0.20 0.87 0.21 0.62 M-C-Pentane 84.16 0.09 0.02 0.05 0.21 0.05 0.14 Benzene 78.11 0.04 0.01 0.03 0.14 0.03 0.10 Cyclohexane 84.16 0.08 0.02 0.06 0.26 0.06 0.18 C7 96.00 0.25 0.05 0.26 0.98 O.Z6 0.65 M-C-Hexane 98.19 0.06 0.01 0.08 0.32 0.08 0.21 Toluene 92.14 0.04 0.01 0.14 0.55 0.14 0.36 C8 107.00 0.14 0.02 0.43 1.47 0.42 0.97 E-Benzene 106.17 0.01 0.00 0.05 0.17 0.05 0.11 M/P-Xylene 106.17 0.01 0.00 0.10 0.35 0.10 0.23 0-Xylene 106.17 0.00 0.00 0.06 0.21 0.06 0.14 C9 121.00 0.07 0.01 0.56 1.69 0.55 1.11 C10 134.00 0.04 0.00 0.98 2.67 0.96 1.75 C11 147.00 0.02 0.00 1.26 3.13 1.23 2.04 C12 161.00 0.01 0.00 1.76 3.99 1.72 2.60 C13 175.00 0.00 0.00 2.17 4.52 2.11 2.95 C14 190.00 0.00 0.00 2.48 4.76 2.41 3.10 C15 206.00 0.00 0.00 2.72 4.81 2.65 3.14 Cl6 222.00 2.82 4.64 2.75 3.03 C17 237.00 2.97 4.57 2.89 2.98 C18 251.00 2.88 4.18 2.80 2.73 C19 263.00 2.85 3.96 2.78 2.58 C20 275.00 2.74 3.64 2.67 2.37 C21 291.00 2.66 3.33 2.59 2.17 C22 300.00 2.6Z 3.19 2.56 2.08 C23 312.00 2.29 2.68 2.23 1.75 C24 324.00 2.16 2.43 Z.10 1.58 C25 337.00 2.15 2.32 2.09 1.5Z C26 349.00 2.00 Z.09 1.95 1.36 C27 360.00 1.97 1.99 1.92 1.30 C28 372.00 1.95 1.92 1.90 1.25 C29 382.00 1.91 1.83 1.86 1.19 C30 394.00 1.78 1.65 1.73 1.07 C31 404.00 1.58 1.42 1.54 0.93 C32 415.00 1.44 1.27 1.40 0.83 C33 426.00 1.39 1.19 1.36 0.78 C34 437.00 1.32 1.10 1.28 0.72 C35 445.00 1.21 1.00 1.18 0.65 C36+ 935.00 43.69 17.05 42.57 11.12 Total 100.00 100.00 100.00 100.00 100.00 100.00 MW 17.87 364.97 244.22 MOLE RATIO 0.3479 0.6521 Oilphase-DBR 23 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 15: Calculated Fluid Properties Sample 1.13; Cylinder SS618538-QA; Depth 4154 ft. MD Schlumberger Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 0.86 0.16 99.55 97.68 97.04 63.75 C12+ 0.01 0.00 95.49 85.53 93.06 55.78 C20+ - - 74.85 50.10 72.94 32.67 C30+ - - 52.40 24.68 51.07 16.09 C36+ - - 43.69 17.05 42.57 11.12 Molar Mass C7+ 98.25 371.97 371.74 C 12+ 161.00 407.45 407.45 C20+ - 54525 545.25 C30+ - 775.00 775.00 C36+ - 935.00 935.00 Density C7+ - 0.9519 - C 12+ - 0.9609 0.9609 C20+ - 1.0010 1.0010 C30+ 1.0612 1.0612 C36+ 1.0955 1,0955 Fluid at 60°F 0.9496 Gas Gravity (Air =1 ~ 0.617 Dry Gross Heat Content (BTU/scf) 1,106 Wet Gross Heat Content (BTU/scf 1,087 OBM Contamination Level (wt%) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+ Properties MW 364.97 364.97 935.00 Density (g/cm3) 0.9496 - 1.096 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 185 - STO Density (g/cm3) 0.9496 - STO API Gravity 17.5 - OBM Density (g/cm31 Q60°F - Oilphase-DBR 24 Job #: 200600050 ~i Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Figure 9: Stock Tank Oil Chromatogram (Sample 1.13- Sample 1.13; Cylinder SSB 18538-QA; Depth 4154 ft. MD Schlum6erger f101 A, (f:~21 DATA~p08000501CY18538.0) Nolm. JOB 200600050 CONOCO PHILLIPS 1.13 SSB 18538-QA P50 RF FLASH CYLINDER 200 150 100 m v U U m ~~ m 50 ( ~NNNNNN f~~n ~ ~ ~ ~~ u 7 '~ ~ ~ N m ~ ~ W~ U U ~ U UUUUUU C C CCCCCCCCCCC O ~ ~ I` U U U C C C F W XU CCCC ~ C~ C ~O U C C .: i I 1 is 1 1 i ~~i'fl ( C C ~ I' !N i: I I hl ~ 0 5 10 15 20 25 30 35 mi L Figure 10: k-Plot for Equilibrium Check (Sample 1.13) Sample 1.13; Cylinder SSB 18538-QA; Depth 4154 ft. MD 2.5 2 - • iC4 1.5 - 1 ---- n a. - o, 0.5 o -------- - -- - • C6 0 - ~ -0.5 --- - ----- i C8- ------- -- -1 -1.5 -4 -3 -2 -1 0 1 2 3 F i~ Oilphase-DBR 25 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 16: C36+ Composition, GOR, °API, by Zero-Flash (Sample 1.15) Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD Schlumberger Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.26 0.10 0.00 0.00 0.01 0.04 Hydrogen Sulfid 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.30 0.19 0.00 0.00 0.01 0.07 Methane 16.04 85.31 94.47 0.00 0.00 2.17 32.89 Ethane 30.07 2.77 1.64 0.00 0.00 0.07 0.57 Propane 44.10 4.09 1.65 0.03 0.22 0.13 0.71 I -Butane 58.12 1.78 0.55 0.03 0.19 0.07 0.31 N -Butane 58.12 2.28 0.70 0.06 0.36 0.11 0.48 I -Pentane 72.15 1.20 0.30 0.08 0.41 0.11 0.37 N -Pentane 72.15 0.51 0.13 0.05 0.23 0.06 0.19 C6 84.00 0.63 0.13 0.18 0.77 0.19 0.55 M-C-Pentane 84.16 0.09 0.02 0.05 0.21 0.05 0.14 Benzene 78.11 0.04 0.01 0.03 0.14 0.03 0.10 Cyclohexane 84.16 0.08 0.02 0.06 0.26 0.06 0.18 C7 96.00 0.25 0.05 0.27 1.01 0.27 0.67 M-C-Hexane 98.19 0.06 0.01 0.08 0.31 0.08 0.21 Toluene 92.14 0.05 0.01 0.14 0.54 0.14 0.36 C8 107.00 0.14 0.02 0.43 1.48 0.43 0.97 E-Benzene 106.17 0.01 0.00 0.05 0.17 0.05 0.11 M/P-Xylene 106.17 0.01 0.00 0.10 0.34 0.10 0.23 0-Xylene 106.17 0.01 0.00 0.06 0.21 0.06 0.14 C9 121.00 0.08 0.01 0.56 1.68 0.55 1.10 C10 134.00 0.04 0.00 0.99 2.68 0.97 1.75 C11 147.00 0.02 0.00 1.27 3.15 1.24 2.05 C12 161.00 0.00 0.00 1.79 4.03 1.74 2.63 C13 175.00 0.00 0.00 2.05 4.24 1.99 2.77 C14 190.00 0.00 0.00 2.66 5.09 2.60 3.32 C15 206.00 0.00 0.00 2.76 4.87 2.69 3.17 C 16 222.00 2.86 4.68 2.79 3.05 C17 237.00 2.91 4.46 Z.84 2.91 C18 251.00 2.95 4.27 2.87 2.78 C19 263.00 3.02 4.17 2.94 2.72 C20 275.00 2.79 3.69 2.72 2.40 C21 291.00 2.64 3.30 2.58 2.15 C22 300.00 2.55 3.09 2.49 2.01 C23 312.00 2.39 2.78 2.33 1.82 C24 324.00 2.30 2.58 2.24 1.68 C25 337.00 2.16 2.33 2.11 1.52 C26 349.00 2.03 2.11 1.98 1.38 C27 360.00 1.95 1.96 1.90 1.28 C28 372.00 1.93 1.89 1.88 1.23 C29 382.00 1.90 1.81 1.86 1.18 C30 394.00 1.85 1.70 1.80 1.11 C31 404.00 1.59 1.43 1.55 0.93 C32 415.00 1.46 1.Z8 1.43 0.83 C33 426.00 1.38 1.17 1.34 0.76 C34 437.00 1.16 0.96 1.13 0.63 C35 445.00 1.14 0.93 1.11 0.61 C36+ 933.00 43.26 16.83 42.16 10.97 Tota I 100.00 100.00 100.00 100.00 100.00 100.00 Min/ 17.77 363.07 242.87 MOLE RATIO 0.3481 0.6519 Oilphase-DBR 26 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 17: Calculated Fluid Properties Sample 1.15: Cylinder SSB 18535-OA; Depth 4154 ft. MD Schlumberger Properties Flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 0.87 0.16 99.58 97.83 97.07 63.83 C12+ 0.00 0.00 95.48 85.64 93.05 55.83 C20+ - - 74.49 49.85 72.59 32.50 C30+ - - 51.83 24.31 50.51 15.85 C36+ - - 43.26 16.83 42.16 10.97 Molar Mass C7+ 97.92 369.58 369.34 C12+ 162.56 404.78 404.78 C20+ - 542.55 542.55 C30+ - 774.15 774.15 C36+ - 933.00 933.00 Density C7+ - 0.9515 - C 12+ - 0.9606 0.9606 C20+ - 1.0015 1.0015 C30+ 1.0633 1.0633 C36+ 1.0981 1.0981 Fluid at 60°F 0.9494 Gas Gravity (Air =1) 0.613 Dry Gross Heat Content (BTU/scf) 1,099 Wet Gross Heat Content (BTU/scf 1,080 OBM Contamination Level h-t%) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C36+ Properties MW 363.07 363.07 933.00 Density (g/cm3) 0.9494 - 1.098 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stb) 186 - STO Density (g/cm3) 0.9494 - STO API Gravity 17.5 - OBM Density (g/cm3) C~60°F - Oilphase-DBR 27 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D • • Schlumberger Figure 11: Stock Tank Oil Chromatogram (Sample 1.15) Sample 1.15' Cylinder SSB 18535-QA; Depth 4154 ft. MD fID1 A, (F 1't1 DATAV]0900050try1e535.D} Norm. JOB 200600050 CONOCO PHILLIPS ]00 1.15 SSB 18538-OA RF FLASH CYLINDER 600 500 400 300 200 ~ m U~ U ~ ~~ 100 , D 0 C ~ ~~ ° m ~I' ~ ~ N m y U7 C4 h 0~ 0 ~ N~1vU7mM731o~-NrAIUI ,- ~ ~ ~ N N NNNNNNi,Nf~fTT~ ~ ~ -a, 0 ~, ~ ~ q ~ C C ~W~, ~ CCCCCC ! ~ C~ ~ C V-CC ~ C C C C C C C C ~ ,: A.J.rti~..++~...R i i : ;i ~ ; D p 5 10 15 20 25 30 35 mi Figure 12: k-Plot for Equilibrium Check (Sample 1.151 Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD 2.5 2 --- - ------ _• 3---- ---- - __ ._. --- - _ _ - -- ---- - ------ -- --- • iC4 1.5 1 --- -- • n n. of 0.5 J • 6 ~ l.r ~ -0.5 -.__.._ - __ _- -_ ---------- ~ CB-- - -------------- -1 -L5 -4 -3 -2 -1 0 1 2 3 F I Oilphase-DBR 28 Job #: 200600050 ~- - J • Client: ConocoPhillips field: West Sak Well: 1 H North Sand: B & D Table 18: Summary of Results of Sample 1.15 Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD Schlumberger Reservoir Conditions: Pressure: 1707 psia Temperature: 79 °F Summary of Fluid Properties: OBM Contamination: - Wt% STO Basis OBM Contamination: - Wt% RF Basis Bubble Point Pressure At Tres 1,440 psia At 130°F psia At 100°F psia Gas-Oil Ratio Single-stage Flash: 186 scf/stb Tota! Differential Liberation: - scf/stb Total Separator Flash: 182 scf/stb Properties at 60°f STO °API Gas Gravity (Average) Single-stage STO: 17.54 0.613 Differential Liberation STO: - - Separator STO: 17.62 0.606 Properties at Reservoir Conditions Viscosity: .107.08 cP Compressibillity (Cod: 4.7 10-6/psi Density: 0.9115 g/cc Properties at Saturation Conditions Viscosity: 102.16 cP Compressibillity iCo~: 4.7 106/psi Density: 0.9104 g/cc Formation Volume Factor @Pres & Tres @Psat & Tres Single-stage Flash: 1.069 1.070 Total Differential Liberation: - - Total Separator Flash: 1.067 1.068 Note: Standard conditions are 14.696 psia and 60°F • Oilphase-DBR 29 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D PVT Analysis on Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD Constant Composition Expansion at Tres The CCE study was initiated by charging asub-sample of live reservoir fluid into the PVT cell at a reservoir temperature of 79.0°F and at a pressure of 10,015 psia. Sequential pressure decrease in steps and the corresponding volume changes are presented in Table 19. The pressure-volume (P-V) plots of the CCE data are presented in Figure 13. The intersection of the single-phase and two-phase lines in the P-V plot and the visual observation was used to define the bubblepoint. For the subject fluid, the bubblepoint was determined to be 1,440 psia at the reservoir temperature of 79.0 °F. Also, calculated relative volume and oil compressibility is presented in Table 19. As seen in the table, the compressibility of this oil is 4.7 x 10e-61/psia at the saturation pressure. Table 19: Constant Composition Expansion at 79.0°F (Sample 1.15) Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD • • Pressure (psia) Relative Vol (Vr=V/Vsat) % Liquid (VI/Vsat) % Liquid (VI/Vtotal) Liquid Density (g/cm3) Y function Compressibility (10-6/psia) 1 10015 0.9660 96.6 100.0 0.9425 3.4 2 9015 0.9693 96.9 100.0 0.9392 3.5 3 7015 0.9765 97.6 100.0 0.9323 3.8 4 5015 0.9843 98.4 100.0 0.9249 4.1 5 4015 0.9684 98.8 100.0 0.9210 4.3 6 3015 0.9928 99.3 100.0 0.9170 4.5 7 2015 0.9973 99.7 100.0 0.9129 4.6 Pi 1707 0.9987 99.9 100.0 0.9115 4.7 9 1670 0.9989 99.9 100.0 0.9114 4.7 Pb 1440 1.0000 100.0 100.0 0.9104 4.7 11 1207 1.0242 99.3 96.9 8.0 12 1098 1.0398 99.0 95.2 7.8 13 943 1.0696 98.7 92.2 7.6 14 842 1.0960 98.5 89.9 7.4 15 650 1.1702 98.2 83.9 7.1 16 479 1.2891 98.0 76.0 6.9 17 268 1.6681 97.8 58.6 6.5 18 169 2.1750 97.7 44.9 6.4 Oilphase-DBR 30 Job #: 200600050 Client: ConocoPhillips Field: West Sak schlumberger Well: 1 H North Sand: B & D • Figure 13: Constant Composition Expansion at 79.0°F -Relative Volume (Sample 1.15) Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD • 2.4 2.2 2.0 - 1.6 a a E 1.6 0 d a .~ d O0 1.4 1.Z 1.0 0.8 0 2000 4000 6000 8000 10000 Pressure (psia) Oilphase-DBR 31 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Schlumberger • Reservoir Oil Viscosity at Tres The liquid phase viscosity was measured at the reservoir temperature of 79°F. These values as a function of selected pressure steps are summarized in Table 20. The liquid phase viscosity values are graphically presented in Figure 14. As seen in the figures and as expected, the viscosity values decrease with decreasing pressure up to the bubblepoint and increase with further reduction in pressure below the bubblepoint. The resported reservoir-fluid viscosities at reservoir temperature are considered to be high relative to associated 1 H- North data, however, the results were confirmed through duplicate testing. Table Z0: Reservoir Fluid Viscosity 79°F (Sample 1.15) Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD • Pressure Viscosity @ Tres (psia) (cP) 1 10060 459.9 2 9047 383.5 3 8034 318.2 4 7055 264.6 5 6022 211.4 6 4995 177.4 7 4013 148.6 8 3010 126.8 9 2015 108.9 Pi 1707 102.0 Pb 1440 97.8 12 1274 122.7 13 1166 135.2 14 1077 153.2 STO 15 524.0 Oilphase-DBR 32 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D Figure 14: Reservoir Fluid Viscosity 79°F (Sample 1.15) Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD soo a y 300 500 400 0 N_ • • 200 100 0' 0 1D00 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 Pressurelpsia) Oilphase-DBR 33 Job #:200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D • Multi-Stage Separation Test Multi-stage separation test results are presented in Tables 21 - 23. The fluid properties (i.e., GOR, density and oil formation volume factor) are presented in Table 21. Multi-stage separation test conditions are: STAGE 1 105 psia 125 °F STAGE 2 75 psia 185 °F STAGE STO 14.696 psia 60 °F As seen in Table 21, the GOR value obtained from the multi-stage separation test is 182 SCF/STB and the formation volume factor is 1.068. The compositional analyses of separator gas and tank gas are summarized in Table 22 and the composition of tank liquid is tabulated in Table 23. The total dry gross heat content of the separation gases is calculated to be 1,088 BTU/scf whereas the total wet gross heat content is calculated to be 1,069 BTU/scf. With reference to the assumption made in "The Properties of Petroleum Fluids" (McCain,1990~, the assumption made in generating reservoir fluid properties from a PVT study is that at pressures below the bubblepoint, the process in the reservoir can be mimicked by differential vaporization, while the process in the wellbore is simulated by the separator test. Hence, fluid properties at pressures below saturation pressure can be calculated by combining the data from the differential vaporization and a separator test. • • Oilphase-DBR 34 Job #: 200600050 • Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 21: Multi-Stage Separation Test Vapor & Liquid Properties (Sample 1.15) ~amnla 1 1 F• Cvlinrfar SCR 18535-DA' Depth 4154 ft. MD PROPERTY STAGE Pb STAGE 1 STAGE 2 STAGE STO Pressure(psia) 1440 105 75 14.696 Temperature (°F) 79 125 185 60 Liq. Den (g/cm3) 0.9103 0.9294 0.9180 0.9384 Vap. Gravitya 0.604 0.668 0.641 Vap. M,,,,, 17.48 19.33 18.58 Vap Heat Val.b 1083 1180 1143 GOR° 170 4 8 GORd 167 3 8 Sep. FVFe 1.068 1.022 1.034 1.011 Schlumberger ai Calculated, at 6U"h lair=11 bl Calculated, ury oasis ~ i u/sct cl sct gas/poi or on at a i u wnaiuuns d) scf gas/bbl of oif at separator conditions e- fluid volume at sep conditions/fluid volume at STD conditions Residual oil density at standard conditions 0.9489 g/cc Sep gas gravity (average) S9 = ERjSgj/ERj 0.606 Where: R: GOR (scf gas/bbl of oil at STD conditions), j: separator stages Sep gas gross heating value ~a~ L° =ERi*L°i/ERi 1088 BTU/scf (dry basis) Where: R: GOR (scf gas/bbl of oil at STD conditions), j: separator stages J SEPARATION TEST SUMMARY aTotal Separation Test GOR 182 Separation Test STO Gravity 17.62 bSeparation Test FVF 1.068 a) scf gas/bbl of condensate at J I U conditions b) Fluid volume at Psat & Tres/Fluid volume at STD • Oilphase-DBR 35 Job #: 200600050 • • Client: ConocoPhillips field: West Sak Well: 1 H North Sand: B & D Table 22: Multi-Stage Separator Test Vapor Composition (mol %) Sample 1.15; Cylinder SSB 18535-QA; Depth 4154 ft. MD Schlum6erger Component MW (g/mol) Mole STAGE 1 STAGE 2 STAGE STO Carbon Dioxide 44.01 0.10 0.28 0.16 Hydrogen Sulfide 34.08 0.00 0.00 0.00 Nitrogen 28.01 0.21 0.09 0.03 Methane 16.04 95.29 89.95 90.97 Ethane 30.07 1.46 2.57 3.38 Propane 44.10 1.36 3.00 3.06 I -Butane 58.12 0.42 1.12 0.80 N -Butane 58.12 0.52 1.54 0.89 I -Pentane 72.15 0.21 0.57 0.32 N -Pentane 72.15 0.20 0.53 0.12 C6 84.00 0.08 0.22 0.11 M-C-Pentane 84.16 0.02 0.03 0.02 Benzene 78.11 0.00 0.00 0.01 Cyclohexane 84.16 0.02 0.02 0.02 C7 96.00 0.08 0.05 0.03 M-C-Hexane 98.19 0.01 0.01 0.01 Toluene 92.14 0.02 0.02 0.01 C8 107.00 0.01 0.00 0.02 E-Benzene 106.17 0.00 0.00 0.00 M/P-Xylene 106.17 0.00 0.00 0.00 0-Xylene 106.17 0.00 0.00 O.DO C9 121.00 0.00 0.00 0.01 C10 134.00 0.00 0.00 0.00 C11 147.00 0.00 0.00 0.00 C 12 161.00 0.00 0.02 0.00 C13 175.00 0.00 0.00 0.00 C14 190.00 0.00 0.00 0.00 C15 206.OD 0.00 0.00 0.00 C16 222.00 0.00 0.00 0.00 C17 237.00 0.00 0.00 0.00 C18 251.D0 0.00 0.00 0.00 C19 263.00 0.00 0.00 0.00 Czo z75.oo o.oo o.oo o.Do C21 291.00 0.00 0.00 0.00 C22 300.00 O.OD 0.00 0.00 C23 312.00 0.00 0.00 0.00 C24 324.00 0.00 0.00 0.00 C25 337.00 0.00 0.00 0.00 C26 349.00 0.00 0.00 0.00 C27 360.00 0.00 0.00 0.00 C28 372.00 O.OD 0.00 0.00 C29 382.00 O.OD 0.00 0.00 C30+ 774.15 0.00 0.00 0.00 Total 100.00 100.00 100.00 MW 17.48 19.33 18.58 Relative Density (air=1~ 0.603 0.667 0.641 Dry Gross Heat Content (BTU/scf~ 1083 1180 1143 Oilphase-DBR 36 Job #: 200600050 • • • Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 23: Multi-Stage Separator Test Residual Liquid Composition (mol %) Sample 1.15; Cylinder SSB 18535-OA; Depth 4154 ft. MD Schlum6erger COMPONENT MW (g/mol) Residua ~mol %) Carbon Dioxide 44.01 0.00 Hydrogen Sulfide 34.08 0.00 Nitrogen 28.01 0.00 Methane 16.04 0.00 Ethane 30.07 0.00 Propane 44.10 0.47 I -Butane 58.12 0.35 N -Butane 58.12 0.64 I -Pentane 72.15 0.61 N -Pentane 72.15 0.30 C6 84.00 1.07 M-C-Pentane 84.16 0.25 Benzene 78.11 0.17 Cyclohexane 84.16 0.31 C7 96.00 1.05 M-C-Hexane 98.19 0.37 Toluene 92.14 0.64 C8 107.00 1.59 E-Benzene 106.17 0.19 M/P-Xylene 106.17 0.38 0-Xylene 106.17 0.22 C9 121.00 1.69 C10 134.00 2.46 C11 147.00 2.86 C12 161.00 3.62 C13 175.00 4.06 C14 190.00 4.45 C15 206.00 5.01 C16 222.00 4.48 C17 237.00 4.21 C18 251.00 4.18 C19 263.00 4.04 C20 275.00 3.57 C21 291.00 3.32 C22 300.00 3.15 C23 312.00 3.22 C24 324.00 2.38 C25 337.00 2.42 C26 349.00 1.55 C27 360.00 2.26 C28 372.00 2.36 C29 382.00 1.65 C30+ 762.34 24.48 Total 100.00 MW 359.79 Oilphase-DBR 37 Job #: 200600050 C: • • Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 24: C3O+ Composition, GOR, °API, by Zero-Flash (Sample 1.09,1.10 & 1.11) Sample 1.09. 1.10 & 1.11: Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumberger Component MW Flashed Gas Flashed Liquid Monophasic Fluid (g/mole) WT % MOLE % WT % MOLE % WT % MOLE Carbon Dioxide 44.01 0.21 0.09 0.00 0.00 0.01 0.03 Hydrogen Sulfid 34.08 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen 28.01 0.27 0.19 0.00 0.00 0.01 0.07 Methane 16.04 77.01 91.91 0.00 0.00 2.73 33.14 Ethane 30.07 2.Z5 1.43 0.00 0.00 0.08 0.52 Propane 44.10 4.50 1.96 0.03 0.21 0.19 0.84 ! -Butane 58.12 2.94 0.97 0.05 0.25 0.15 0.51 N -Butane 58.12 4.35 1.43 0.13 0.65 0.28 0.93 I -Pentane 72.15 2.99 0.79 0.23 0.94 0.33 0.89 N -Pentane 72.15 1.39 0.37 0.16 0.66 0.21 0.55 C6 84.00 1.73 0.39 0.71 2.49 0.75 1.73 M-C-Pentane 84.16 0.27 0.06 0.17 0.61 0.18 0.41 Benzene 78.11 0.04 0.01 0.05 0.18 0.05 0.12 Cyclohexane 84.16 0.27 0.06 0.27 0.93 0.27 0.61 C7 96.00 0.69 0.14 1.11 3.39 1.09 2.22 M-C-Hexane 98.19 0.24 0.05 0.42 1.26 0.42 0.83 Toluene 92.14 0.11 0.02 0.29 0.92 0.28 0.60 C8 107.00 0.36 0.06 1.63 4.47 1.58 2.88 E-Benzene 106.17 0.01 0.00 0.12 0.34 0.12 0.22 M/P-Xylene 106.17 0.03 0.01 0.34 0.94 0.33 0.61 0-Xylene 106.17 0.01 0.00 0.19 0.54 0.19 0.34 C9 121.00 0.20 0.03 1.86 4.51 1.80 2.89 C10 134.00 0.09 0.01 2.88 6.32 2.78 4.04 C11 147.00 0.03 0.00 2.53 5.06 2.44 3.24 C12 161.00 0.00 0.00 2.92 5.32 2.82 3.41 C13 175.00 0.00 0.00 3.16 5.31 3.05 3.39 C14 190.00 0.00 0.00 3.24 5.01 3.13 3.20 C15 206.00 0.00 0.00 3.14 4.47 3.02 2.86 C16 222.00 2.75 3.64 2.65 2.33 C17 237.00 2.61 3.23 2.51 2.07 C18 251.00 2.25 2.64 2.17 1.69 C19 263.00 2.27 2.53 2.18 1.62 C20 275.00 2.05 2.19 1.98 1.40 C21 291.00 1.63 1.84 1.76 1.18 C22 300.00 1.70 1.67 1.64 1.07 C23 31 Z.00 1.44 1.36 1.39 0.87 C24 324.00 1.37 1.24 1.32 0.79 C25 337.00 1.28 1.12 1.24 0.72 C26 349.00 1.18 0.99 1.13 0.63 C27 360.00 1.10 0.90 1.06 0.58 C28 372.00 1.11 0.87 1.07 0.56 C29 382.00 1.10 0.84 1.06 0.54 C30 394.00 1.04 0.78 1.00 0.50 C31 404.00 0.84 0.61 0.81 0.39 C32 415.00 0.75 0.53 0.72 0.34 C33 426.00 0.71 0.49 0.68 0.31 C34 437.00 0.56 0.37 0.54 0.24 C35 445.00 0.58 0.38 0.56 0.24 C36+ 791.00 45.85 17.02 44.23 10.88 Tota I 100.00 100.00 100.00 100.00 100.00 100.00 MN/ 19.15 293.62 194.67 MOLE RATIO 0.3605 0.6395 Oilphase-DBR ~7 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D • • • Schlumberger Table 25: Calculated Fluid Properties Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Properties flashed Gas Flashed Liquid Monophasic Fluid Cn+ Composition Mass % Mole % Mass % Mole % Mass % Mole C7+ 2.36 0.46 98.69 94.81 95.27 60.79 C12+ 0.00 0.00 86.82 65.35 83.74 41.79 C20+ - - 64.48 33.20 62.19 21.23 C30+ - - 50.32 20.18 48.54 12.90 C36+ - - 45.85 17.02 44.23 10.88 Molar Mass C7+ 97.34 305.64 305.07 C 1 Z+ 165.63 390.09 390.09 C20+ - 570.25 570.25 C30+ - 732.27 732.27 C36+ - 791.00 791.00 Density C7+ - 0.9360 - C12+ - 0.9637 0.9637 C20+ - 1.0185 1.0185 C30+ 1.0645 1.0645 C36+ 1.0815 1.0815 Fluid at 60°F 0.9302 Gas Gravity (Air =1) 0.661 Dry Gross Heat Content BTU/scfl 1,173 Wet Gross Heat Content (BTU/scf 1,153 OBM Contamination Level (wt%) - STO Basis - Live Oil Basis Stock Tank Oil Properties at Standard Conditions: Measured Calculated C30+Properties MW 293.62 293.62 791.00 Density (g/cm3 0.9302 - 1.081 Single Stage Flash Data Original STO De-Contaminated GOR (scf/stbl 238 - STO Density (g/cm3) 0.9302 - STO API Gravity 20.6 - OBM Density (g/cm3) Q60°F - Oiilphase-DBR 39 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Schlumberger Figure 15: k-Plot for Equilibrium Check (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD 2.5 ~ Z ~ • C3 • iC4 1.5 --- -__..-~-nC4--------- - --_ _ -__- - -- -- - -------------- ----- ~ iC5 1 ----- ------ - ~ .x 0.5 • C6 o ~ J -0.5 -1.5 -2 -4 -3 -Z -1 0 1 2 3 F • • Oilphase-DBR 40 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 26: Summary of Results of Sample 1.09,1.10 & 1.11 Sample 1.09,1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumberger Reservoir Conditions: Pressure: 1735 psia Temperature: 81 °F Summary of Fluid Properties: Bubble Point Pressure At Tres 1, 544 psia Gas-Oil Ratio Single-stage Flash: 238 scf/stb Total Differential Liberation: scf/stb Total Separator Flash: 214 scf/stb Properties at 60°F STO °API Gas Gravity (Average) Single-stage STO: 20.62 0.661 Differential Liberation STO: Separator STO: 21.26 0.624 Properties at Reservoir Conditions Viscosity: 20.1 cP Compressibillity (Co): 9.4 10-6/psi Density: 0.8741 g/cc Properties at Saturation Conditions Viscosity: 19.9 cP Compressibillity (Co): 9.6 106/psi Density: 0.8725 g/cc Formation Volume Factor @Pres & Tres @Psat & Tres Single-stage Flash: 1.103 1.105 Total Differential Liberation: Total Separator Flash: 1.093 1.095 Note: Standard conditions are 14.696 psia and 60°F • Oilphase-DBR 41 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Schlumberger • PVT Analysis on Sample 1.09,1.10 & 1.11; Cylinder CSB 1356-MA; Depth 4068 ft. MD Constant Composition Expansion at Tres The CCE study was initiated by charging asub-sample of live reservoir fluid into the PVT cell at a reservoir temperature of 81.0°F and at a pressure of 10,015 psia. Sequential pressure decrease in steps and the corresponding volume changes are presented in Table 27. The pressure-volume ~P-V) plots of the CCE data are presented in Figure 16. The intersection of the single-phase and two-phase lines in the P-V plot and the visual observation was used to define the bubblepoint. For the subject fluid, the bubblepoint was determined to be 1,544 psia at the reservoir temperature of 81.0 °F. Also, calculated relative volume and oil compressibility is presented in Table 27. As seen in the table, the compressibility of this oil is 9.6 x 10e-61/psia at the saturation pressure. Table 27: Constant Composition Expansion at 81.0°F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Pressure (psia) Relative Vol (Vr=VNsat) % Liquid (VlNsat) % Liquid (VlNtotal) Liquid Density 19/cm3) Y Function Compressibility (10-6/psia) 1 10015 0.9526 0.9159 3.0 2 9015 0.9557 0.9129 3.5 3 8016 0.9593 0.9095 4.0 4 7016 0.9634 0.9056 4.6 5 6014 0.9682 0.9012 5.3 6 5014 0.9737 0.8961 6.0 7 4015 0.9800 0.8903 6.9 8 3015 0.9872 0.8838 7.9 9 2015 0.9956 0.8763 9.0 10 1816 0.9974 0.8747 9.3 Pi 1735 0.9982 0.8741 9.4 Pb 1544 1.0000 100.0 100.0 0.8725 9.6 13 1495 1.0067 99.9 99.2 4.9 14 1390 1.0234 99.6 97.4 4.7 15 1241 1.0549 99.3 94.1 4.5 16 1090 1.0969 99.1 90.3 4.3 17 977 1.1412 98.8 66.6 4.1 18 834 1.2191 98.6 80.9 3.9 19 713 1.3105 98.3 75.0 3.8 20 569 1.4796 98.1 66.3 3.6 21 439 1.JZ95 98.0 56.6 3.5 22 327 2.1039 97.8 46.5 3.4 Note on compressibi/itydata. the reported compressibilities are considered to be significantly high for the temperature and fluid typology in question. The CCE at reservoir temperature was repeated using extended stabilisation times, and the results of the duplicate test were closely similar to the original data, as reported. We conclude that the resolution of volumetric data, for very heavy oils, in the current configuration of the visual PVT cell is insufficient to permit more accurate delineation of compressibilities. Thus, the reported Pr data should be considered as approximate and likely overestimated. .7 Oilphase-DBR 42 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D • Figure 16: Constant Composition Expansion at 81.0°F -Relative Volume (Sample 1.09,1.10 & 1.11) Sample 1.D9, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD 2.2 2.0 1.8 a a 1.6 d E 0 0 .~ 1.4 ~o m • 1.2 1.0 • Oilphase-DBR 0.8 ~ 0 2000 4000 6000 5000 Pressure (psia- 43 10000 12000 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D • Reservoir Oil Viscosity The liquid phase viscosity was measured at the reservoir temperature of 81°F, as well as at 150°F, 90°F and 60°F. These values as a function of selected pressure steps are summarized in Table 28. The liquid phase viscosity values are graphically presented in Figure 17. As seen in the figures and as expected, the viscosity values decrease with decreasing pressure up to the bubblepoint and increase with further reduction in pressure below the bubblepoint. Table 28: Reservoir Fluid Viscosity at 81 °F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD • • Pressure Viscosity @ Tres (Psia) IcP- 1 10045 63.5 2 9002 55.9 3 7995 46.9 4 6990 42.1 5 6002 36.1 6 5004 31.0 7 4019 27.4 8 3167 24.2 9 2453 22.3 10 1926 21.1 Pi 1735 20.1 Pb 1544 19.9 13 1353 21.9 14 1264 22.5 15 1124 24.1 16 1014 25.8 17 919 27.7 18 641 28.9 19 719 30.8 20 556 37..6 STO 15 125.5 Oilphase-DBR 44 Job #: 200600050 Client: Well: ConocoPhillips Field: 1H North Sand: West Sak Schlumberger B & D • Figure 17:Reservoir Fluid Viscosity at 81°F (Sample 1.09,1.10 & 1.11- Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD 14D 120 100 a : 80 y O V N_ ~ 0 40 20 • 0 0 2000 4000 6000 8000 10000 12000 Pressurelpsia) Oilphase-DBR 45 Job #:200600050 • • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 29: Reservoir Fluid Viscosity at 150°F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumberger Pressure Viscosity @ Tres Ipsia) ICPI 1 10066 13.37 2 9016 11.86 3 8001 10.61 4 7000 9.51 5 6006 8.48 6 5014 7.58 7 4025 6.81 8 3500 6.44 9 3184 6.21 10 2994 6.10 11 2745 5.92 12 2497 5.76 13 2243 5.59 14 2010 5.44 15 1901 5.38 16 1708 5.27 17 1499 5.39 18 1382 5.39 19 1215 5.80 ZO 1085 6.19 21 920 6.96 22 750 7.84 23 490 11.97 24 287 16.15 STO 15 22.50 Oilphase-DBR Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D C • • 25 Oilphase-DBR Figure 18: Reservoir Fluid Viscosity at 150°F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD 20 15 a v .y O V H 7 10 5 0 0 2000 4000 6000 8000 10000 12000 Pressure~psia) 47 Job #:200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 30: Reservoir Fluid Viscosity at 90°F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumberger Pressure Viscosity @ Tres (psia) IcP) 1 10081 48.74 2 9044 42.18 3 8040 37.20 4 7052 33.72 5 6040 29.39 6 4992 26.10 7 4030 23.50 8 3494 20.80 9 3231 20.28 10 3041 19.78 11 2549 18.41 12 2279 17.92 13 1834 16.87 14 1592 16.17 15 1516 16.05 16 1437 16.14 17 1388 16.80 18 1269 17.86 19 1039 19.72 20 959 20.32 21 842 21.64 22 670 23.19 23 500 24.81 24 287 32.55 STO 14.696 93.13 Oilphase-DBR 48 Jab #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D • Figure 19: Reservoir Fluid Viscosity at 90°F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD so 60 a U .y O U N 40 • • 100 Oilphase-DBR 20 0 0 2000 4000 6000 8000 10000 12000 Pressurelpsia) 49 Job #:200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 31: Reservoir Fluid Viscosity at 60°F (Sample 1.09,1.10 & 1.11) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumberger Pressure Viscosity @ Tres (psia) IcP- 1 9999 104.56 2 9087 84.35 3 7999 69.17 4 7006 60.04 5 6004 50.60 6 5011 44.11 7 3987 38.15 8 3535 35.77 9 3244 34.24 10 3000 33.22 11 2752 32.19 12 2502 31.18 13 2255 30.16 14 2001 29.09 15 1750 28.24 16 1506 27.40 17 1337 29.44 18 1259 30.90 19 1183 33.88 20 1078 35.91 21 997 38.15 22 920 39.51 23 767 58.51 STO 15 236.14 Oilphase-DBR 50 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & 0 • Figure 20: Reservoir Fluid Viscosity at 60°F (Sample 1.09,1.10 & 1.11- Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD 2so 240 220 200 180 160 a 140 .y y 120 100 80 60 40 • 20 n 0 2000 4000 6000 8000 Pressure~psia) Oilphase-DBR 51 10000 12000 Job #:200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1H North Sand: B & D . Multi-Stage Separation Test Multi-stage separation test results are presented in Tables 32 - 34. The fluid properties (i.e., GOR, density and oil formation volume factory are presented in Table 32. Multi-stage separation test conditions are: STAGE 1 105 psia 125 °F STAGE 2 75 psia 185 °F STAGE STO 14.696 psia 60 °F As seen in Table 32, the GOR value obtained from the multi-stage separation test is 214 SCF/STB and the formation volume factor is 1.095. The compositional analyses of separator gas and tank gas are summarized in Table 33 and the composition of tank liquid is tabulated in Table 34. The total dry gross heat content of the separation gases is calculated to be 1,116 BTU/scf whereas the total wet gross heat content is calculated to be 1,096 BTU/scf. With reference to the assumption made in "The Properties of Petroleum Fluids" (McCain, 1990, the assumption made in generating reservoir fluid properties from a PVT study is that at pressures below the bubblepoint, the process in the reservoir can be mimicked by differential vaporization, while the process in the wellbore is simulated by the separator test. Hence, fluid properties at pressures below saturation pressure can be calculated by combining the data from the differential vaporization and a separator test. • • Oilphase-DBR 52 Job #: 200600050 Client: Well: ConocoPhillips 1 H North Field: Sand: West Sak B & D Schlumberger • Table 32: Multi-Stage Separation Test Vapor & Liquid Properties (Sample 1.09,1.10 & 1.11) Sample 1.09. 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD PROPERTY STAGE Pb STAGE 1 STAGE 2 STAGE STO Pressure(psia) 1544 105 75 14.696 temperature (°F) 81 125 185 60 Liq. Den 19/cm3) 0.8725 0.9043 0.8843 0.9262 Vap. Gravitya 0.619 0.727 0.717 Vap. M,,,,~ 17.92 21.06 20.75 Vap Heat Val.b 1107 1277 1259 GOR` 203 6 5 GOR" 198 6 5 Sep. FVFe 1.095 1.026 1.048 1.000 a) Calculated, at 6U"F lair=~ i bi t;alcwatea, ury oasis u i u/sct c~ scr gas/poi of un ai a ~ u cunuiuuiis d) scf gas/bbl of oil at separator conditions e) fluid volume at sepconditions/fluid volume at STD conditions Residual oil density at standard conditions 0.9263 g/cc Sep gas gravity (average) S9 = ERjSgj/ER 0.624 Where: R: GOR (scf gas/bbl of oil at STD conditions), j: separator stages Sep gas gross heating value (a L~ =ERi*lc~/ER~ 1116 BTU/scf (dry basis) Where: R: GOR (scf gas/bbl of oil at STD conditions), j: separator stages • SEPARATION TEST SUMMARY aTotal Separation Test GOR 214 Separation Test STO Gravity 21.26 eSeparation Test FVF 1.095 a) scf gas/bbl of condensate at 5 i u conditions b) fluid volume at Psat & Tres/Fluid volume at STD • Oilphase-DBR 53 Job #: 200600050 • • Client: ConocoPhillips Field: West Sak Well: 1H North Sand: B & D Table 33: Multi-Stage Separator Test Vapor Composition (mol %) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumperger omponent M (g/mol) o e °° A E 1 A E 2 Carbon Dioxide 44.01 0.09 0.12 0.15 Hydrogen SulfidE 34.08 0.00 0.00 0.00 Nitrogen 28.01 0.21 0.09 0.04 Methane 16.04 94.56 86.65 88.17 Ethane 30.07 1.27 2.34 1.88 Propane 44.10 1.55 3.94 3.70 I -Butane 58.12 0.56 1.62 1.59 N -Butane 58.12 0.74 2.21 2.21 I -Pentane 72.15 0.34 1.07 0.86 N -Pentane 72.15 0.19 0.59 0.42 C6 84.00 0.23 0.77 0.23 M-C-Pentane 84.16 0.03 0.09 0.01 Benzene 78.11 0.01 0.01 0.00 Cyclohexane C7 84.16 96.00 0.03 0.11 0.07 0.29 0.01 0.00 M-C-Hexane 98.19 0.03 0.05 0.00 Toluene 92.14 0.01 0.02 0.12 C8 107.00 0.04 0.04 0.00 E-Benzene 106.17 0.00 0.00 0.05 M/P-Xylene 0-Xylene C9 106.17 106.17 121.00 0.00 0.00 0.01 0.01 0.00 0.01 0.02 0.01 0.00 C10 134.00 0.00 0.01 0.05 C11 147.00 0.00 0.00 0.26 C12 161.00 0.00 0.00 0.21 C13 175.00 0.00 0.00 0.00 C14 190.00 0.00 0.00 0.00 C15 206.00 0.00 0.00 0.00 C16 222.00 0.00 0.00 0.00 C17 237.00 0.00 0.00 0.00 C18 251.00 0.00 0.00 0.00 C19 263.00 0.00 0.00 0.00 C20 275.00 0.00 0.00 0.00 C21 291.00 0.00 0.00 0.00 C22 300.00 0.00 0.00 0.00 C23 312.00 0.00 0.00 0.00 C24 324.00 0.00 0.00 0.00 C25 337.00 0.00 0.00 0.00 C26 349.00 0.00 0.00 0.00 C27 360.00 0.00 0.00 0.00 C28 372.00 0.00 0.00 0.00 C29 382.00 0.00 0.00 0.00 C30 394.00 0.00 0.00 0.00 C31 404.00 0.00 D.00 0.00 C32 415.00 0.00 0.00 0.00 C33 426.00 0.00 0.00 0.00 C34 437.00 0.00 0.00 0.00 C35 445.00 0.00 0.00 0.00 C36+ 790.00 0.00 0.00 0.00 Tota I 100.00 100.00 100.00 MW 17.92 21.06 20.75 Relative Density (air=1; Dry toss eat ontent sc , 0.619 1107 0.727 1277 0.716 1259 Oilphase-DBR 54 Job #: 200600050 • • L Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Table 34: Multi-Stage Separator Test Residual Liquid Composition (mol %) Sample 1.09, 1.10 & 1.11; Cylinder CSB 7356-MA; Depth 4068 ft. MD Schlumberger P N NT M V (g/mol) Residua L~qui (mol %) Carbon Dioxide 44.01 0.00 Hydrogen SulfidE 34.08 0.00 Nitrogen 28.01 0.00 Methane 16.04 0.00 Ethane 30.07 0.00 Propane 44.10 0.53 I -Butane 58.12 0.49 N -Butane 56.12 0.99 I -Pentane 72.15 1.18 N -Pentane 72.15 0.78 C6 84.00 2.15 M-C-Pentane 84.16 0.61 Benzene 78.11 0.15 Cyclohexane 84.16 0.91 C7 96.00 2.71 M-C-Hexane 98.19 1.28 oluene 92.14 0.90 C8 107.00 4.38 E-Benzene 106.17 0.34 M/P-Xylene 106.17 0.91 0-Xylene 106.17 0.48 C9 121.00 4.75 C10 134.00 5.62 C11 147.00 4.80 C12 161.00 4.83 C13 175.00 4.67 C14 190.00 4.98 C15 206.00 4.10 Cl6 222.00 3.75 C17 237.00 3.34 C18 251.00 3.06 C19 263.00 2.88 C20 275.00 2.35 C21 291.00 2.24 C22 300.00 2.23 C23 312.00 1.78 C24 324.00 1.49 C25 337.00 1.50 C26 349.00 1.58 C27 360.00 1.23 C28 372.00 1.18 C29 382.00 1.19 C30 394.00 0.95 C31 404.00 0.84 C32 415.00 0.84 C33 426.00 0.53 C34 437.00 0.60 C35 445.00 0.26 C36+ 790.00 13.64 Tota I 100.00 281,02 Oilphase-DBR 55 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 Appendix A: Nomenclature and Definitions API Gravity American Petroleum Institute gravity Bg Gas formation volume factor Bo Oil formation volume factor CCE Constant composition Expansion DV Differential Vaporization GLR Gas Liquid Ratio GOR Gas Oil Ratio LO Live Oil n Number of moles OBM Oil Based Mud P Absolute pressure Pb Bubble point pressure PV Pressure-Volume Method Pi Initial Reservoir Pressure R Universal gas constant Rs Solution gas oil ratio T Temperature V Volume Vr Relative volume STL Stock Tank Liquid STO Stock Tank Oil • %, w/w Weight Percent Z Gas deviation factor Dry Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction at a standard temperature and pressure in which all water formed appears as liquid. Wet Gross Heating Value is defined as the total energy transferred as heat in an ideal combustion reaction of water saturated gas at a standard temperature and pressure in which all water formed appears as liquid. Molar masses, densities and critical values of pure components are from CRC handbook of Chemistry and Physics and those of pseudo components are from Katz data. Gas viscosity is calculated from the correlation of Carr, Kobayshi and Burrows as given in the "Phase Behavior of Oilfield Hydrocarbon Systems" by M.B. Standing Compressibility inconstant mass study is obtained from mathematical derivation of relative volume. Gas gravity is calculated from composition using the perfect gas equation (Gas deviation factor, Z=1) The Stiff and Davis Stability Index is an extension of the Langlier Index and is used as an indicator of the calcium carbonate scaling tendencies of oil field brine. • A positive index indicates scaling tendencies. • A negative index indicates corrosive tendencies. An index of zero indicates the water is in chemical equilibrium and will neither deposit nor dissolve calcium carbonates. Oilphase-DBR 56 Job #: 200600050 • Client: ConocoPhillips Well: 1 H North Installation: - Field: West Sak Schlumberger Sand: B & D Job #: 200600050 pendix B: Molecular We Components MW C02 44.01 H2S 34.08 N2 28.013 C1 16.043 C2 30.07 C3 44.097 1-C4 58.124 N-C4 58.124 I-C5 72.151 N-C5 72.151 C6 84 MCYC-C5 64.16 BENZENE 76.11 CYCL-C6 84.16 C7 96 'MCYCL-C6 98.19 TOLUENE 92.14 C8 107 C2-BENZEN 106.17 M&P-XYLEN 106.17 0-XYLENE 106.17 C9 121 C10 134 C11 147 C12 161 C13 175 C14 190 C15 206 C16 222 C17 237 C18 251 C19 263 C20 Z75 C21 291 C22 300 C23 312 C24 324 C25 337 C26 349 C27 360 C28 372 C29 382 Oilphase-OBR 57 and Densities Used Density (g/cc) 0.827 0.993 0.808 0.300 0.356 0.508 0.567 0.586 0.625 0.631 0.660 0.753 0.884 0.781 0.688 0.773 0.871 0.749 0.870 0.866 0.884 0.768 0.782 0.793 0.804 0.815 0.826 0.836 0.843 0.851 0.856 0.861 0.866 0.871 0.876 0.881 0.885 0.888 0.892 0.896 0.899 0.902 Job #: 200600050 Client: ConocoPhillips field: West Sak Well: 1H North Sand: B& D Schlumberger Installation: - Job #: 200600050 • Appendix C: EQUIPMENT Fluid Preparation and lalidation The opening pressure of the cylinder is measured using a Heise pressure gauge soon after the sample arrives in the laboratory. Subsequently, the sample bottle is pressurized to the reservoir pressure using water-glycol mixture at the bottomside of the piston cylinder. Custom made heating jacket is wrapped around the cylinder to heat the sample bottle to the reservoir temperature. The sample bottle is then placed into a rocking stand and rocked for 5 days to homogenize the reservoir fluid. Live reservoir fluid analysis is necessary in the sample validation process as well as during the completion of various fluid studies. A description of the experimental equipment used for these analysis follows. All live fluid analyses are completed with a JEFRI Gasometer. This unit in conjunction with GC analysis (see below) provides the full fluid compositional analysis, GOR, density at sampling P&T corrected to standard conditions. The JEFRI gasometer consists of amotor-driven piston in a stationary cylinder. The piston displacement is monitored to determine the swept volume of the cylinder. The cylinder pressure is automatically held at ambient pressure. Piston motion is tracked by a linear encoder, which is subsequently, converted to measure the gas volume in the cylinder. The total Gasometer volume is 10 L. The evolved gas can be re-circulated through the system to facilitate equilibrium at a maximum flow rate of 40 L/hr. The operating pressure of the Gasometer is ambient pressure (up to a maximum of 40 psia) and the operating temperature ranging from room temperature to 40°C. Following the flash of the live fluid sample to ambient conditions in the gasometer, compositional analysis of residual hydrocarbon liquid and evolved gas phase is conducted using gas chromatography (GC-. Analysis of hydrocarbon liquids is conducted using an HP6890 liquid injection gas chromatograph equipped with flame • ionization detector (FID-. In this system, separation of individual components is carried out in a 30m long, 530mm diameter "Megabore" capillary column made of fused silica with 2.6-micrometer thick methyl silicone as the stationary phase. The operating temperature range of the stationary phase is 60 to 400°C. Over this temperature range, the components eluted are from C, to C36 along with naphthenes and aromatics components. Based on the physical properties, these components are retarded in a segregated fashion by the stationary phase during the flow of carrier gas (helium) through the column. With prior knowledge of the amount of "retention" for known compounds contained in calibration standards, the same compounds can be identified in the unknown hydrocarbon sample by matching "retention" times. The relative concentration of each component is determined by the concentration of ions hitting the FID upon the elution of each component. The analysis of hydrocarbon gases is carried out using an HP6890 gas injection GC equipped with two separation columns. The first column is a combination of a 100 mesh packed column and 100 mesh molecular sieve using high purity helium as a carrier gas. The molecular sieve is used to achieve separation of the light gaseous components (nitrogen, oxygen, and methane- while the packed column serves to separate ethane, propane, butanes, pentanes, and hexanes along with carbon dioxide and hydrogen sulfides. The second column is a packed column as described previously in liquid analysis. This column is capable of achieving separation of components up to C12+, along with the associated naphthenes and aromatics that are lumped into the C6+ fraction during analysis and reporting. Components up to C4 are analyzed using a thermal conductivity detector (TCD) while the C5+ components are analyzed for using a FID detector. The instrument has programmable air actuated multiport valves that allow the flow of the sample mixture to be varied between the two columns, and hence, allowing for the correct separation and analysis of the injected gas. • Fluid f/olumetric (PU() and Viscosity Equipment Oilphase-DBR 58 Job #: 200600050 Client: ConocoPhillips Field: West Sak Well: 1 H North Sand: B & D Schlumberger Installation: - Job #: 200600050 The preliminary saturation pressure, constant composition expansion (CCE), differential vaporization (DV), multi-stage separation tests (MSST) are measured using apressure-volume-temperature (PVT) apparatus. The PVT apparatus consists of a variable volume, visual JEFRI PVT cell. The main component of the cell consists of a Pyrex glass cylinder 15.2-cm long with an internal diameter of 3.2 cm. An especially designed floating piston and a magnetically coupled impeller mixer are mounted inside the Pyrex cylinder to allow for mercury-free operation. The bottom section of the piston is furnished with o-rings to isolate the hydraulic fluid from the cell content. The piston allows liquid level measurements as small as 0.005 cc. The magnetically coupled impeller mixer, mounted on the bottom end cap of the PVT cell, allow quick equilibration of the hydrocarbon fluid. The effective volume of the cell is approximately 120 cc. The Pyrex cylinder is housed inside a steel shell with vertical tempered glass plates to allow visual observation of the internal tube contents. A variable volume JEFRI displacement pump controls the volume, and hence, the pressure of the fluids under investigation by means of injection or withdrawal of transparent hydraulic fluid connected to the floating piston from the top of the JEFRI PVT cell. The same hydraulic fluid is also connected to the outer steel shell to maintain a balanced differential pressure on the Pyrex cylinder. The PVT cell is mounted on a special bracket, which can be rotated 360°. The bracket along with the PVT cell is housed inside a temperature controlled, forced air circulation oven. The cell temperature is measured with a platinum resistance thermal detector IRTD) and displayed on a digital indicator with an accuracy of 0.2°F. The cell pressure is monitored with a calibrated digital Heise pressure gauge precise to ± 0.1 % of full scale. The temperature and pressure ratings of this PVT system are 15,000 psi 1103 MPa) and 360°F 1182°C-. The fluid volume in the PVT cell is determined using a cathetometer readable to the nearest 0.01 mm. The cathetometer is equipped with ahigh-resolution video camera that minimizes parallax in readings and uses ahigh-resolution encoder producing both linear and volumetric readings. The height measurements by the cathetometer have been precisely • calibrated with the total cell volume prior to the start of the test. The floating piston is designed in the shape of a truncated cone with gradually tapered sides, which allows measurement of extremely small volumes of liquid (0.005 cc) corresponding to roughly 0.01 % of the cell volume. The viscosity of the live reservoir fluid is measured at the reservoir temperature and pressure conditions using Cambridge SPL440 electromagnetic viscometer, which consists of one cylindrical cell containing the fluid sample and a piston located inside the cylinder. The piston is moved back and forth through the fluid by imparting an electromagnetic force on the piston. Viscosity is measured by the motion of the piston, which is impeded by viscous flow around the annulus between the piston and the sample cylinder wall. Various sizes of pistons are used to measure the viscosity of various fluids having different levels of viscosity. The temperature is maintained at the experimental condition using a re circulating fluid heating system. The internal temperature is monitored using an internal temperature probe. The temperature rating of the viscometer is 190°C and pressure rating is 15,000 prig. The accuracy is ±1.5% of full scale for each individual piston range. The total volume of fluid sample required for viscosity measurement is 5 cc. A cylindrical piston cell (carrier chamber) with a maximum internal volume of 25 mL is attached at the top of the viscometer. The purpose of this cell is to allow the operator to conduct the differential vaporization pressure steps within the viscometer. The back and forth motion of the piston within a narrow clearance provides sufficient agitation to achieve phase equilibration and allow gases to escape and accumulate at the top of the carrier chamber. The heating jacket is wrapped around the viscometer and the carrier chamber and maintains experimental temperature uniformly throughout the system. • Oilphase-DBR 59 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 • The JEFRI PVT cell is also equipped with fiber optic light transmittance probes to measure the onsets of hydrocarbon solids nucleation ~OHSP) due to changes in the temperature, pressure and/or composition. These fiber optic probes are mounted across the windows of the visual cell. The principle behind the measurement is based on the transmittance of a laser light in the near infra red (NIR) wavelength through the test fluid undergoing temperature, pressure or the fluid composition changes. In this system, a computerized pump is controlled to maintain the system pressure during isobaric temperature sweeps for wax nucleation, isothermal pressure drop and/or isobaric injections of precipitating solvents for asphaltene nucleation studies. The process variables (i.e., temperature, pressure, solvent volume, time and transmitted light power level) are recorded and displayed from the detector. The fiber optic light transmittance system referred to here that detects the conditions of OHSP is termed as the light scattering system (LSS~. High pressure filters are also used during the asphaltene nucleation study to quantify the amount of asphaltene in the fluid at the specified conditions. The filter manifold used is rated for 10,000 psia. The filter assembly consists of two plates screwed together with the hydrophobic filter sandwiched between them. • • Oilphase-DBR 60 Job #: 200600050 Client: ConocoPhillips Well: 1H North Field: Sand: West Sak B & D Schlumberger Installation: - Job #: 200600050 • Appendix D: PROCEDURE Fluids Preparation and l/alidation After homogenizing, a small portion of the single-phase reservoir fluid is first subjected to a single stage flash experiment to determine flash Gas-Oil-ratio (GOR). The flashing is conducted from some pressure above the bubblepoint pressure at reservoir temperature into an atmospheric Gasometer and measuring the corresponding volumes of gas and liquid. The atmospheric flash also provides parameters such as GOR and stock tank oil density. The flashed fluids (gas and liquid) are then subjected to compositional analysis using gas chromatographic technique. Subsequently, live oil composition is calculated based on the measured gas and liquid compositions and GOR values. In addition, asub-sample taken from each cylinder is isobarically transferred into the PVT cell at the reservoir temperature. Subsequently, a quick P V relationship is established to determine the saturation pressure. Constant Composition Expansion Procedure A sub-sample of the test fluid is initially charged to the PVT apparatus and the system temperature stabilized at the reservoir temperature. The CCE experiment is then conducted by incrementally reducing the pressure from some pressure above the bubblepoint pressure to a pressure well below the bubblepoint pressure in a number of discrete steps. At each pressure step, the magnetic stirrer is used to make sure that the subject fluid achieved equilibrium. Total fluid volume (with visual observation of a single or two phase condition in the cell- is measured at each pressure stage, and subsequently, apressure-volume (P-V) plot is created identifying the phase state at each P-V condition. The intersection of the two lines plotted using the pressure and volume data above and slightly below the observed phase change corresponded to the measured saturation pressure of the fluid. In this manner, the P-V plot confirms the saturation pressure observed visually in the PVT cell. The measured pressure and volume data are then used to compute live oil compressibility above the bubblepoint pressure and relative oil volumes over the entire pressure range. • Differential l/apoiization Procedure Subsequent to the completion of the CCE experiment, another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. A differential vaporization (DV- experiment is then conducted by incrementally reducing the pressure in the PVT cell in discrete steps. In these steps, the pressure is reduced below the saturation pressure, and hence, allowing the gas phase to evolve. A typical pressure stage in a DV test is described below: • The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the DV test. • The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the DV test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. • The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure (see Fluid Analysis Equipment Section) • The previous two steps are repeated until either an atmospheric pressure or a predetermined abandonment pressure is reached. Multi=Stage Separation Test • Oilphase-DBR 61 Job #: 200600050 Client: ConocoPhillips Field: West Sak Schlumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 • Subsequent to the completion of the DV experiment, another sub-sample of the test fluid is charged to the PVT apparatus and the cell contents are then mixed with the magnetic mixer to allow for phase equilibration at the reservoir temperature and pressure conditions. Amulti-stage separation experiment is then conducted by incrementally reducing the pressure and temperature conditions in the PVT cell in discrete steps. In these steps, the pressure is reduced below the saturation pressure, and hence, allowing the gas phase to evolve. A typical pressure stage in a separation test is described below: • The pressure in the PVT cell is reduced to a pressure just above the bubblepoint pressure of the oil. This is the starting point of the separation test. • The temperature of the PVT cell are then reduced to the first-stage separation test temperature .and allowed the cell content to equilibrate. The pressure of the fluid is then reduced to the first pressure stage (below the bubblepoint pressure) of the separation test allowing free gas to evolve. The magnetic mixer is then used to achieve equilibration between the free gas and the pressurized liquid. • The evolved gas phase is then isobarically removed from the PVT cell into an evacuated pycnometer for gravimetric density and compositional analysis by the flash procedure (see Fluid Analysis Equipment Section) The previous two steps are repeated in five stages to stock tank conditions. Liquid Phase Viscosity and Density Measurements During OV Step Prior to measuring the viscosity, a suitable size piston is selected with the proper viscosity range and the electromagnetic viscometer is calibrated using a fluid with known viscosity. A portion of the live reservoir fluid used in the DV test is then transferred into ahigh-pressure high-temperature electromagnetic viscometer. The viscometer is initially evacuated and kept at the same temperature as that of the PVT • cell. During the transfer of approximately 15 cc of live hydrocarbon liquid to the evacuated viscometer, flashing of oil takes place, and hence, the viscometer system is flushed with live oil twice to make sure a representative live oil sample is taken. Subsequent to transfer of live reservoir fluid into the viscometer, the fluid system is allowed to achieve thermal and pressure equilibration. Then, the viscosity reading is taken. Following the viscosity reading, incremental pressure reduction steps are repeated as those used in DV steps. At each pressure point, the piston was allowed to run back and forth for sufficient time to achieve pressure equilibration and allow the liberated gas to migrate vertically upwards and accumulate at the top of the carrier chamber. Experiments are also conducted independently using a PVT cell for phase equilibration. The viscosity measurements donE on liquid sample transferred from the PVT cell after equilibration compares very well with the measurements done on liquid sample subjected to pressure steps within the viscometer. Stock-Tank Oil (STOJ Viscosity and Density Measurements A sample of STO is taken in a known capillary tube to measure the STO viscosity at a preset temperature. The temperature bath is maintained at the preset temperature. A small sample of the liquid is also transferred into the Anton Paar DMA45 densitometer to measure the density of the liquid phase. The viscosity and density measurements are repeated for data consistency check. Asphaltene, Wax and Sulfur Content Measurements Asphaltene content of stock-tank oil samples is conducted using the IP-143 (French Institute of Petroleum) procedure. In this procedure, the asphaltenes are characterized as the n-heptane insoluble fractions of the crude oil. Wax content of the STO is measured using UOP (Universal Oil Product) 46-64 procedure. The sulfur content of the STO is measured using ASTM D 2494 procedure.. All other STO analysis were measured according to industrial standards. SAR(PJA Ana/ysvs Oilphase-DBR 6Z Job #: 200600050 Client: ConocoPhillips Field: West Sak Schiumberger Well: 1 H North Sand: B & D Installation: - Job #: 200600050 • A spinning band distillation was carried out on the original sample to establish two fractions. The initial boiling point to 300°C fraction was then analysed using a supercritical fluid chromatographic (ASTM 5186-91) method to determine the saturates and aromatics content. The greater than 300°C fraction first subjected to a gravimetric analysis to determine the pentane insoluble content (asphaltenes). This method dissolves the fraction in an equal weight of toluene, then 40 volumes of pentane were added to precipitate the insoluble portion of the sample. The precipitate was filtered, dried and weighed. The solvent was removed from the soluble portion of the sample, which was referred to as the maltenes. The maltenes were then redissolved in pentane and were chromatographically separated into saturates, aromatics and resins (polars) fraction by elution from a column filled with activated alumina, using various solvents and solvent mixtures. The solvents were then removed from each fraction and the amount of material weighed. The data from the three methods were combined to determine the amount of each component type in the original sample. Mass balances were calculated throughout the procedure to assure accurate data. High-Temperature Hiqh Pressure Filtration Test During the filtration process, it is important that the monophasic fluid remains monophasic as it passes through the filter manifold. Hence, high pressure nitrogen is used on the back side of the filter so that the equal pressure is maintained on both sides of the filter. This procedure prevents any flashing of the fluid in the filter manifold and assures filtration of a representative fluid. • • Oilphase-DBR 63 Job #: 200600050 ~fbC~ RECEIVED JUN 0 9 2006 ,~~,w~ •~ , , ""°" ConocoPhdlips Alaska, lnc. FINAL WELL REPORT MUDLOGGING DATA ~_= ~~~ .~ ~.~~. '~ - ~. ,_ M: Provided by: €~ EPOCH Compiled by: Brian O'Fallon Ralph Winkelman Date: 3/6/06 2 0~, ~ DECEIVED JUN 0 9 2006 ConocoPhillips Alaska, lnc. FINAL WELL REPORT MUDLOGGING DATA 1 H-North • Provided by: [~ EPOCH SOH &Gas Cons. Cwnmissian Atiehorage Approved by: Bryn Clark Compiled by: Brian O'Fallon Distribution: Date: 3/10/06 • C011000~11~~Ip5 1 H-North TABLE OF CONTENTS • 1 MUDLOGGING EQUIPMENT & CREW .............................................................................................. . 2 1.1 Equipment Summary ..................................................................................................................... . 2 1.2 Crew .............................................................................................................................................. . 3 2 WELL DETAILS .................................................................................................................................... . 4 2.1 Well Summary ............................................................................................................................... . 4 2.2 Hole Data ...................................................................................................................................... . 4 3 GEOLOGICAL DATA ........................................................................................................................... . 6 3.1 Lithostratigraphy ............................................................................................................................ .6 3.2 Mudlog Summary .......................................................................................................................... . 7 3.3 Gas Samples (ISOTUBES) .......................................................................................................... 15 3.4 Connection Gases ........................................................................................................................ 16 3.5 Sampling Program /Sample Dispatch ......................................................................................... 17 4 PRESSURE /FORMATION STRENGTH DATA ................................................................................. 18 4.1 Formation Integrity/Leak Off Tests ............................................................................................... 18 4.2 Wire line Formation Tests ............................................................................................................ 18 4.3 Pore Pressure Evaluation Introduction ......................................................................................... 18 4.4 Pore Pressure Evaluation Conclusions ........................................................................................ 19 • 4.5 Pore pressure evaluation ............................................................................................................. 20 5 DRILLING DATA ................................................................................................................................. 25 5.1 Survey Data .................................................................................................................................. 25 5.2 Bit Record ..................................................................................................................................... 27 5.3 Mud Record .................................................................................................................................. 28 6 MORNING REPORTS ......................................................................................................................... 29 Enclosures 2"/100' Formation Log (MD) 2°/100' Gas Ratio Log 2"/100' LWD / Lithology Log U ~;POCH 1 l__ 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary • • `~ ConocoPhilllp5 1 H-North Parameter Equipment Type /Position Total Downtime Comments Ditch gas QGM Agitator (Mounted in possum belly) Flame ionization total gas & chromatography. Insulated umbilical with three of low lines. 0 Provided WITS feed to QUADCO system. Some problems in surface hole with clay cuttin sat shakers. Hook Load / Wei ht on bit H draulic ressure transducer 0 No roblems, no missin data. Rate of penetration Primary draw-works block position indicator O tical encoder on draw-works 0 No problems, no missing data. Mudlo in unit com uter s stem HP Com a Pentium 4 X2, DML & Ri watch 0 On UPS should ower shut down on ri Mudlo in unit DAC box In-unit data collection/distribution center 0 On UPS should ower shut down on ri Mud Flow In Derived from Strokes/Minute and Pum Out ut 0 see um stroke counters below Pum stroke counters 2 um s Ma netic roximit sensors 0 No roblems, no missin data. Quadco Well Monitorin Com onents QUADCO Com uter in Mudlo in Unit 0 On UPS should ower shut down on ri Mud Flow Out WITS feed from QUADCO: S ud -TD 0 No roblems, no missin data. Pit Volumes, Pit Gain/Loss WITS feed from QUADCO: S ud -TD 0 No roblems, no missin data. Pum Pressure WITS feed from QUADCO: S ud -TD 0 No roblems, no missin data. RPM WITS feed from QUADCO: S ud -TD 0 No roblems, no missin data. Tor ue WITS feed from QUADCO: S ud -TD 0 No roblems no missin data. An IP phone in the Epoch unit fed data into the Qaudco computer. A WITS feed was set up and provided a data stream between the Quadco Computer and the Epoch Rigwatch computer, with Rigwatch providing ditch gas to the Quadco system, and receiving various data (listed above) from Quadco. Depths were typically inaccurate and often not tracking on the Quadco system, however, Epoch was rigged up with an encoder, hookload sensor, and pump stroke counters, and all data from the Quadco WITS feed was recorded at an accurate depth. No data was missed, as the Quadco system was never down during drilling, and all the computers in the Epoch logging unit continued to operate on UPS when power would occasionally shut down briefly switching generators. Some problems with reading ditch gas in the surface hole, typical for the North Slope, were anticipated and dealt with as they occurred. The base plate on the gas trap allows mud into the trap through a 2" diameter hole. A %<" mesh screen covering the hole to prevent large rocks from entering the trap and breaking agitator prongs, was partially plugged by clay cuttings at approximately 800', restricting flow of mud into the trap. The screen and base plate were both removed, the base plate because rocks enter the 2"diameter hole, become trapped in the barrel of the trap, and subsequently break agitator prongs. Removing the base plate can reduce the efficiency of the trap, because the base plate helps induce a suction which draws mud into the barrel that exits through the hole on the side of the barrel, and therefore is less sensitive to mud level changes and flow volumes in the possum belly. Vigilant maintenance and adjustments had to be made at the possum belly to help maintain trap efficiency, including closing gates on the possum belly on the side opposite the gas trap to redirect flow into the trap, cleaning gates on the same side as the trap when clay accumulations were restricting flow, and jetting cuttings out of the possum belly. The base plate without the screen was reattached at 2800' in the 8'/" hole section, after the FIT and displacing the hole with Flo Pro mud. The screen was no EPC}CH • • • ConocoPhillips 1 H-North longer needed as large rock cuttings were no longer anticipated in subsequent drilling. The new mud more effectively dispersed clays, and the gas trap and flow into the possum belly were more easily maintained. Only briefly, from 3630-40', were gas readings missed, when after a connection there was no flow on the gas trap side of the possum belly. Also, two spare polyflow gas lines were utilized should freezing or plugging have occurred. One spare was rigged up to rig air to blowback lines to keep free of moisture and drilling mud. The second spare was kept as a back up gas line. Gas lines were occasionally switched, the unused line treated with gas line antifreeze (Heat), and blown back to remove any ice or moisture which may have accumulated. 1.2 Crew Unit Type Arctic Series 10 Skid Unit Number ML012 Mudloggers Years Da~s Sample Catchers Years Days Technician Days Trainees Days Brian O'Fallon 18 7 Edward Revollo 1 7 None Re uired Ral h Winkelman 15 7 James Kvidera 2 7 R' Years experience as Mudlogger '~ Days at well site between spud and total depth of well Additional Comments A technician is required to work on DAC box ~P~I~H COY10CfJ~'ll~~lp5 1 H-North • 2 WELL DETAILS Well: 1 H-North API Index #: 50-029-23294-00 Field: North East Wes Sak (NEWS) Surface Co-Ordinates: N: 5,994,301 E: 554,555 SEC 15 T12N R10E 2276' FNL 946' FEL Borough: North Slope Primary Target Depth: 4054' MD State: Alaska TD Depth: 4630' MD (4383' TVDSS Rig Name /Type: Nordic 3 /Arctic Triple Suspension Date: None Primary Target: West Sak Permit #: 205-209 Spud Date: 2/27/06 Ground Elevation: 34.6' AMSL Completion Date: 3/11/06 RT Elevation: 64.6' AMSL Completion Status: Cement Plug Secondary Target De the 3400' Classification: Exploration TD Date: 3/6/2006 TD Formation: Base West Sak Days Testing: None Days Drilling: 7 2.1 Well Summary 2.2 Hole Data Maximum Shoe Depth Depth Mud FIT Hole TD Deviation Corin Casing/ Section Mp TVDS Formation Weight ~°inc) g Liner MD TVDSS Fppg) lft) ft (pPg) 1ft) eft) Conductor 110 -45 Permafrost 9.2 0 NA 16° 110 -45 NA 12 '/." 2780 -2646 T3 9.5 16.69 NA 9 5/8" 2767 -2634 14.0 81/2" 4630 4383 Colville 9.0 17.74 NA Additional Comments Epoch personnel arrived in Kuparak on Februra 25, and rigged up the Epoch mudlogging unit for the 1 H- North well on February 27, following the move of the Nordic 3 drilling rig onto the ice pad. Surface hole spudded just after midnight on February 28 at 120' at the base of the conductor. A 12 114" surface hole was drilled with a 9.2 to 9.5 spud mud, directionally with occasional sliding to 2780'. Every stand was back reamed once, and surveys taken after the connection, the angle increasing gradually to as high as 19.39 degrees at 1958', and dropping off slightly to 16.8 degrees at 2760'. No connection gases were noted and only 61 units of wiper gas after casing depth, lagging surface to surface peaking with sweep returns. One previous wiper trip was conducted to the shoe at 2031', with no problems tripping, and only 29 units of wiper gas. Casing, 9 5/8°, was run to 2767'. The 8 '/" hole section began on March 4, and was drilled to 4630', with no problems, the only wiper trip at total depth. The spud mud was displaced with FloPro at 2800', and the intitial formation test failed due to air in the mud. After circulating and conditioning the mud, a successful FIT was performed to 14.0 ppg EMW. Occasional slides were necessary, maintaining a 17-20 degree angle, 17.74 degrees at total depth. Each stand was back reamed prior to each connection, and surveys taken after the connection. Mud weight was maintained at 9.2 ppg, and no connection gases were observed despite numerous oil sands and drill gas recorded as high as 1120 units. Wiper gas at total depth was only 108 units and of short duration lagging to bottom. COt1000~'tl~~lp5 1 H-North Logging was commenced on March 6 after the wiper trip, and three logging runs were conducted with one major delay. The first logging run, a vrireline combo, was run quickly without incident. While attempting to run the drill pipe conveyed pressure log the tool failed when plugged into at 3100'. While pulling out of the hole, power outages occurred at 2400', due problems with the SCR, and repairs were needed on the SCR. Repairs were completed on both the SCR and the logging tools and logging resumed. Wireline pressure testing was conducted without incident, and cementing procedures commenced on March 10. Trip gas prior to cementing was 618 units, peaking early (gas from the Ugnu and West Sak) and of long duration. • • ~~~~~,N COt'1000~'tl~~lp5 1 H-North 3 GEOLOGICAL DATA • L_J 3.1 Lithostratigraphy Drilling picks & actual wire line tops refer to provisional picks provided by the well site Geologist. PROGNOSED ACTUAL WIRELINE PICK HIGH/LOW FORMATION MDRT ft TVDSS ft MDRT ft TVD ft TVDSS ft (ft) Permafrost 30 +34.6 30 30 +34.6 GL Base Permafrost 1755 -1674 1822 1798 -1733 +59 T3 NA -1917 2028 1993 -1929 +12 K15-Marker NA NA 2338 2287 -2223 NA Casing Point (T3+675'TVD) 2730 -2592 2780 2711 -2646 -54 Ugnu C 3411 -3234 3400 3297 -3233 -1 Ugnu B 3716 -3521 3663 3545 -3480 -41 Ugnu A NA NA 3756 3633 -3568 NA K13 Marker 3986 -3776 3964 3828 -3764 -12 West Sak D 4093 -3878 4054 3913 -3849 -29 West Sak C NA NA 4096 3953 -3888 NA West Sak B 4157 -3937 4131 3986 -3921 -16 West Sak A4 NA NA 4182 4034 -3969 NA West Sak A3 4253 -4027 4243 4091 -4027 +0 West Sak A2 4317 -4087 4296 4141 -4077 -10 West Sak Al NA NA 4410 4249 -4185 NA Base West Sak 4529 -4287 4501 4336 -4271 -16 Total Depth 4631 -4383 4630 4459 -4394 +12 FPC~C',H CO11OC0~'11~~1~.15 1 H-North . 3.2 Mudlop Summary Numerous oil sands were observed beginning from 3300' to total depth. Oil in the upper sands was possibly less mature, beginning with a minor show in a basal sand above the Ugnu, and including shows in the Ugnu C and Ugnu B. Only methane was observed in show gases in the basal sand, while peak gases in the two Ungu sections had only methane, ethane, and traces of propane, suggesting an immature, less moveable oil requiring high permeability to flow. Show gases in the Ugnu A, West Sak, and in the rathole below the base of the West Sak, produced a full suite of gases, methane through pentane, indicating a more mature moveable oil. The best oil shows, mature or immature, occurred in the Ugnu C, B, and A. Good oil shows and high gas peaks were observed in the West Sak D and B, but the sands appeared to have less porosity. The West Sak A4 through A2 had some fair show gas, and gas dropped off substantially in the A1. Some good oil fluorescence below the base of the West Sak was observed in clay supported sands, but with a weak cut and very poor show gas. Permafrost to Base Permafrost First Returns 110' to 1822' MD (-45' to -1733` TVDSS) Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 158 5 79 80 0 15 The top of the permafrost down to 713' was dominantly conglomeratic sand and sand, sometimes grading to claystone or with some interbedded claystone. Soft clays began overloading the shakers and restricting flow into the gas trap immediately below these upper sands, and from 713' to 840' is dominantly claystone. From 840' to 1822' is mostly sand and conglomeratic sand, often gradational to interbedded with claystone, with the conglomeratic fraction noticeably decreasing approaching the base. A massive sand begins at 1708' and continues below the base of the permafrost, and is discussed in the next section. The base of the permafrost is marked by a sharp decrease in resistivity at 1822', due the transition from ice to water. No oil shows were observed, and only methane was recorded through this section. The sands were medium gray to some medium dark gray, with fine to coarse grains, and a variable very coarse to conglomeratic fraction which included pebbles up to 5mm, and scattered to common granules ranging up to 15 to 28mm. Grains were angular to subrounded in the finer fraction, and mostly rounded to subrounded in the very coarse and conglomeratic fraction, and overall with moderately high to low sphericity. The sands were estimated to be mostly moderately sorted with an inferred slight clay matrix, to locally increasing matrix gradational to claystone and conglomerate. Composition was 65-75% quartz, with higher percentages in the finer fraction and almost exlusively clear to translucent, and lower percentages in the very coarse to conglomerate fraction and opaque to yellowy to translucent. The remaining 35-25% included very dark gray to brownish black to dark gray to gray to amber to light amber to green grains, including chert, or hard siliceous lithics and metalithics, and silicates. Other constituents included wood and carbonaceous fragments, pyrite, and locally minor calcite and shell fragments. Also noted was some minor calcareous sandstone between 220' to 360', and minor dense siliceous sandstone from 360-600', the latter of similar composition to the sand and possibly of a fragment of the source for that sand. Traces of wood and possibly other plant matter, partially to completely altered to carbonaceous matter and increasingly carbonaceous with depth, occurred as disseminated flakes and micro fragments in sands throughout, locally as large wood splinters, and occasionally as low grade coal. Samples from 420-600', and to a lesser degree from 900-1380', had consistently 3-10% woody and carbonaceous matter. Some carbonaceous matter had traces to a sheen of micro pyrite. Pyrite sometimes occurred as accretions on grains, primarily the very coarse to conglomeratic fraction, with grains lightly to some moderately speckled or splattered with isolated micro crystals or clusters. Traces of • grainy loose pyrite clusters occurred throughout, and locally up to 3% of the sample, most notably in a sand ~P~1CH 7 COtl000~11~~1~?5 1 H-North • from 1550-1610'. Clay (claystone) was medium gray to medium light gray, often with faint brownish to brownish hues. The clays were structureless in the samples throughout, as were soluble to very soluble reacting to the water based mud, caking up on shakers as a soupy to pasty mush, or as pasty amorphous clumps, or simply in solution in the mud. Slight to very slight and locally moderate silts and fines persisted throughout, consisting of mostly quartz, very slight to minor carbonaceous matter, and minor non quartz grains of same composition as the finer fraction of associated sands. Clays are inferred to be gradational to sand, conglomeratic sand, and conglomerate, as these constituents persist throughout, and as suggested by MWD. Brownish hues are from the breakdown of carbonaceous matter to organic clay. Some medium light gray clays were considered ashy and occasionally grading to ash fall tuff, locally with slight to moderate angular silt to very fine shardlike grains. Clays were overall non to very slightly calcareous, exhibiting only minor pin point effervescence, and with only traces of calcite and shell fragments noted in samples. DEPTH GAS snits C9 m C2 m C3 m C4 m C5 m 1216 128 26365 0 0 0 0 AVE 15 2949 0 0 0 0 Base Permafrost to T3 1822' to 2028' MD (-1733' to -1929' TVDSS) Drill Rate ft/hr Total Gas units Maximum Minimum Averse Maximum Minimum Avers e 244 68 170 48 10 34 This interval begins as a massive sand continuing from the base of the permafrost, and grades to mostly claystone capping the T3. MWD suggests an overall coarsening upward sequence from the top of the sand at 1708' (in the permafrost) to the top of the T3, with some interbedded clayey sands. No oil shows were observed, and only methane was recorded through this section. • The sands were medium light gray. The upper sand (including 1708' to 1822' in the permafrost) was mostly moderately well sorted with medium to very fine upper grains, subangular to subrounded, and lightly scattered mostly rounded coarse grains and pebbles. The lower sands were mostly moderately sorted, with very fine to medium grains, especially fine to medium lower, and angular to subrounded. Composition was 70-75% clear to translucent quartz. The non quartz fraction included black to brownish black to dark gray to gray to amber to minor green grains, including hard grains, possibly siliceous lithics, chert, or other silicates, and minor carbonaceous lithics, more common in lower sands. The upper sand also included traces of rust colored grains and light brown interstitial matter. Grains were unconsolidated and likely mostly grain supported with some clay matrix, especially in the lower sands, inferred. Sands become gradational to claystone, mostly fining and with increasing silt and clay matrix. The matrix also appears to be ashy in part, locally grading to ash fall tuff. Clays (claystone) were medium gray to some medium light gray, some with faint brownish hues, appearing structureless in samples, as were soluble to very soluble reacting to the water based mud, caking up on shakers as a runny to pasty mush, as pasty amorphous clumps, or in solution in the mud. The medium light gray clays appear to be ashy, grading in part to ash fall tuff, with angular shard like silts and very fine grains. Clays overall were clayey to silty to fine sandy including mostly quartz silts and sands, very slight silts and minor fine clasts of carbonaceous matter, and minor non quartz grains of same composition as associated sands. Slight brownish hues were from the breakdown of carbonaceous matterto organic clay. Samples were mostly non calcareous with trace pin point effervescence. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 1844 48 9668 0 0 0 0 AVE 34 6809 0 0 0 0 ~PC)CH 8 COt1OC0~11~~1p5 1 H-North r T3 to Casing Point 2028' to 2780' MD -1929' to -2646' TVDSS Drill Rate ft/hr Total Gas (units Maximum Minimum Avera a Maximum Minimum Avera e 244 13 124 99 2 39 This section included sand and claystone, interbedded and gradational, including some fining downward sequences, and occasional thin beds of low grade coal. A persistant small fraction of pebbles and granules could indicate minor conglomerates or conglomeratic sand, or the washing out of earlier sections. An apparent fault occurs at 2655', indicated by asand-claystone contact, and a reverse resistivity spike suggesting fluids in the fault contact. No oil shows were observed, some outgassing was observed on coal, and only methane was recorded through this section. Sands are medium gray to light gray to locally brownish gray. Grains are mostly fine to medium, with varying very fine and coarse fractions, subangular to subrounded, and locally minor to common rounded to subrounded pebbles up to 10mm. Sands are mostly moderately well sorted and grain supported, to clay supported and gradational to claystone. Composition included approximately 80% clear to translucent quartz, and 20% dark gray to gray to black to minor greenish gray, and locally minor rose and rust grains. Non quartz grains are dominantly hard (silicates or siliceous) grains and minor carbonaceous lithics. Some minor pyrite and shell fragments were noted locally. Porosities are estimated at good to fair in grain supported sands. Clays (claystone) were light brown to brownish gray to grayish brown, with clayey to silty textures, and, as in upper clays reacting with the water based mud system, were structureless, amorphous, and soluble and soft in samples. Samples were essentially non calcareous. Slight to trace amounts of carbonaceous matter and minor wood were observed throughout. Coal was black with dark brown secondary hues, firm and pliable to moderately hard, with fibrous (woody) to gritty texture, earthy to vitreous luster, and platy to blocky habit with common planar fracture. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 2636 99 20450 0 0 0 0 AVE 39 7739 0 0 0 0 Surtace Casing to Ugnu C 2780' to 3400' MD (-2646' to -3233' TVDSSI Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 485 19 104 75 0 25 This interval includes sand and conglomeratic sand, with interbedded and gradational to claystone and some siltstone. A show of heavy immature oil occurred in the 3300-30' sample, and gas was slightly over background in sands from 3300-90'. The peak gas from 3300-30' was only 59 units of methane. Gas and resistivity peaked higher from 3330-90', the gas peaking at 75 units with a trace of ethane, but these samples had only a trace of fluorescence. Sandstone or Sand from 3300-90' was medium light gray, fine to coarse lower, subrounded to subangular with moderate to high sphericity, mostly unconsolidated in the samples, to some poorly consolidated and grain and matrix supported with a matrix of light gray clay and a trace of calcite. Grain composition was 75% clear to translucent quartz, and 25% black to dark gray to brownish black to gray to amber to rare green to grayish green, including mostly hard silicates, chert, or partially siliceous lithics, and minor carbon lithics. The sands ~PC~CH 9 COt'1000~'11~~Ip5 1 H-North • were interbedded with and gradational to claystone and siltstone, with an estimated fair to good porosity in some cleaner beds. Fluorescence from 3300-30' was an even dull to moderately dull yellow orange over 80% of the sample, with a good instantaneous to slight blooming white cut, brown residue with an orange ring under fluorescent light, and orange brown spotty oil residue in white light. claystone was medium gray to medium light gray with various brownish hues, often grading to siltstone of generally lighter shades to light gray. Samples are better preserved with the Flo Pro mud and exhibit some stucture, though moderately soft and slightly soluble to the mud system. Cuttings were subblocky to amorphous, with minor flakiness and some faint incipient fissility, an earthy luster, and a smooth to silty/gritty texture. Clays were non to slightly organic. Silts were dominantly quartz, often coarse to grading very fine sand, and commonly to locally mostly angular, exhibiting an ashy appearance and possibly grading ash fall tuff locally. Very slightly to slightly scattered silts and fine flakes and clasts of carbon matter occurred throughout. Traces to very lightly scattered micro flakes of mica were observed in the upper clays. Sand and sandstone other than the basal show sands above the Ugnu, was light gray to medium light gray to occasionally light brownish gray, and fine to coarse grained, especially medium to fine, with scattered pebbles and conglomeratic fragments. Grains were subrounded to angular, moderately well to poorly sorted, unconsolidated in sample, to poorly consolidated and grain and matrix supported in a light gray to white to light brownish clay, or slightly silty ashy clay matrix, with traces to slight calcite. Grain composition was 75-80% clear to translucent quartz, and 25-20% dark gray to black to grayish green to gray to rare amber to trace rust and rose, including mostly hard silicates, siliceous lithics, or chert, and minor carbon lithics. Porosities were estimated at mostly poor to fair due to clay matrix filling pore space. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 3308 59 12316 0 0 0 0 3364 75 15608 4 0 0 0 AVE 25 5067 .2 0 0 0 • Ugnu C to Ugnu B 3400' to 3663' MD (-3233' to -3480' TVDSS) Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 158 28 110 644 4 129 Oil shows occurred in nearly all sands, but appeared heavy and only methane and ethane was recorded. Two sands especially, from 3498-3520' and 3545-3555', had peak gases of 644 units and 406 units respectively, and numerous thin beds had lesser show gas. Overall the section included oil sands, interbedded with and gradational to siltstone and claystone. Sand was medium light gray to medium gray to light brownish gray, coarse lower to very fine upper, especially medium to fine, subrounded to subangular, moderately well sorted, and mostly unconsolidated in sample, rare poorly consolidated with clay and slight) calcite matrix. Grain composition included 75-80% clear to translucent quartz, and 25-20% black to gray to light gray to rare amber to grayish green, including hard siliceous lithics, silicates, and chert. Samples also include 1 % light brown to brown dense aphanitic siliceous to slightly calcareous fragments from possibly thinly bedded tuff (or siderite?}. The brown fragments are angular and not likely to be interstitial siderite, and are most likely bit broken fragments rather than grains. Porosity is estimated at good to some fair, while permeability is suspect do to immature nature of oil. Samples from 3420' to 3570' were lightly spotted with orange brown free oil, and oil fluorescence ranged from 60-90%. Only traces of free oil and fluorescence diminished sharply to 5-10% thereafter. Fluorescent cuttings had a good instantaneous to slow blooming white cut, and a dull brown fluorescent residue with orange ring. Residue under white light appeared as oily orange brown spots. Siltstone and claystone were medium light gray to light brownish gray, moderately soft, mushy to slightly ~PC~C;H 10 COt1000~11~~Ip5 1 H-North • crumbly, with very coarse silts to very fine grained sands predominantly matrix supported. Cuttings varied from clayey siltstone and silty clayey sandstone, grading to mostly silty and locally slightly silty claystone, and were a trace to slightly calcareous. Silts and grains were dominantly quartz, mostly angular, with traces to slight silts and fine flakes and clasts of carbonaceous matter. Fine to medium unconsolidated grains persisted, but gradually diminished after 3520' DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 3506 644 134181 68 3 0 0 3554 406 88215 46 5 0 0 AVE 129 27111 12 0.8 0 0 Ugnu B to Ugnu A 3663' to 3756' MD -3480' to -3568' TVDSS Drill Rate ftlhr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 418 27 110 945 49 431 The Ugnu B is a massive oil sand, apparently fining downward and resting uncomformably on the Ugnu A. Show gas peaked at 945 units, and again, the oil appeared immature, with only methane, ethane, and minor propane recorded. The Ugnu B Sand is nearly 100 foot thick, medium gray, moderately sorted, and coarser in the first 35 feet, and then light gray with light brown hues and well sorted fining downward from a 7 foot shale break. Grains were fine to coarse in the upper section, to fine and very fine upper below the shale break, subangular to subrounded overall, unconsolidated with very slight inferred clay and calcite matrix, to very loosely consolidated with increased matrix, to some matrix supported with light brownish gray clay, calcite, and silt matrix above the Ugnu A. Composition was dominantly clear to translucent quartz, with a slight non quartz fraction more prevalent as coarser grains in the upper section. The non quartz fraction included gray to dark gray to black and greenish gray grains throughout, and minor dusky red grains in the upper sand section. Porosity is estimated at mostly good in the upper section gradually diminishing in the lower section with increasing matrix. Show properties include a strong oil odor, 20-40% light to dark brown free oil, 50-90% yellow orange fluorescence, a strong instant yellow white cut, and bright yellow fluorescent residue ring. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 3687 945 194962 87 5 0 0 3722 634 129717 51 2 0 0 AVE 431 86967 38 1.2 0 0 Ugnu A to West Sak D 3756' to 4054' MD -3568' to -3849' TVDSS Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 187 36 107 888 22 139 The Ugnu A includes a well developed oil sand from 3900-3925', then overall grading downward to the West Sak, including a 10 foot oil sand from 3950-60' followed by mostly siltstone and claystone. Gas peaked at 888 units in the main sand, and 430 units in the thin bed, and unlike the Ugnu C and B, included a full suite of gases from methane through pentane. Above the main oil sand, the Ugnu A, from 3756-3900', includes clayey siltstone gradational to claystone and poorly developed sands with only minor shows. . Sand and sandstone from 3900-90' was light gray to light brown, very fine to rare medium lower, moderately ~l- Q~H 11 CO11OC0~'tl~~lPS 1 H-North sorted from 3900-3925', to poorly sorted and often grading coarse siltstone and silty claystone and overall fining downward to 3990'. Sands were unconsolidated with a slight inferred clay and calcite matrix, and slightly to moderately calcareous as grades to siltstone. Grains were dominantly clear to translucent quartz, with minor other constituents. Porosity is estimated at fair to good from 3900-3925', and mostly poor thereafter. Oil properties include a faint oil sheen with no free oil observed but with light brown color mostly due to oil staining of matrix, 70-90% bright yellow fluorescence, good instantaneous light yellow cut and faint straw cut, and bright yellow fluorescent ring. siltstone and claystone was light gray to light brownish gray with light to medium brown secondary hues, soft and amorphous, and slightly to moderately calcareous. Cuttings were dominantly siltstone with abundant clay matrix, often with coarse silts to grading very fine grained sandstone, or grading to silty to slightly silty claystone. Samples below the Ugnu B continue to carry 20-40% fluorescence with a trace of free oil, and blue 3990' to the top of the West Sak 10% fluorescence. Fluorescence was likely mostly carried from the above sands, but in part from thin zones and laminations of matrix and grain supported sand. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 3915 888 177429 230 9 106 68 3956 430 85537 155 102 101 40 AVE 139 27622 41 20 23 17 West Sak D to West Sak B 4054' to 4131' MD (-3849' to -3921' TVDSS) Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 128 26 108 804 93 348 This interval includes the top of the West Sak, the West Sak D Sand, with good oil staining and show gas up to 804 units, and the West Sak C, dominantly siltstone and claystone, with minor show gas. The West Sak D Sand, from 4054-4096', is light to medium brown to brownish gray, the brownish color due to oil staining, very fine lower grading to coarse silt, and lightly scattered very fine upper to fine lower grains, subangular overall, poorly to moderately sorted, and loosely to poorly consolidated and mostly matrix supported with a clay and calcite matrix. Composition is dominantly quartz. Porosity is estimated at mostly poor to locally fair. Oil indicators include good oil odor, abundant light to dark brown free oil spots in samples, apparent oil staining on clay matrix, 90% moderate to bright light yellow fluorescence, good instantaneous to moderately streaming light yellow cut, and bright yellow residual ring. The West Sak C, from 4096-4131', is light gray to light grayish brown, soft to slightly firm; with a mostly silty texture grading from clayey siltstone to silty claystone, to silty very fine grained sandstone, matrix and some grain supported with an abundant clay matrix. Silts and sand grains or generally subangular. Locally grades to slightly silty claystone exhibiting some shaliness. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 4059 804 136159 1476 2199 2399 1267 AVE 348 56786 671 1004 1128 645 West Sak B to West Sak A4 4131' to 4182' MD -3921' to -3969' TVDSS Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 125 27 101 1171 93 440 ~;PacH 12 COIIOCO~I1~~Ip5 1 H-North • The West Sak B is a very fine oil sand similar to the D Sand described above, except slightly diminishing brownish hues to occasionally light gray, and some siliceous cement. Minor dense siliceous sandstone identified in samples could be from a thin zone, 4136-39', as indicated by a reverse drilling break and reverse gas spike, and some grain supported sandstone is moderately consolidated with slight siliceous cement. Porosity is estimated at mostly poor to very poor when clay supported or grain supported with siliceous cement, to locally fair with grain support and loosely consolidated. Show gas was 1171 units, highest in the well. Oil properties included some free oil in samples, mostly light and some moderate oil staining on matrix; and fluorescence and cut similar to D sand above. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 4154 1171 196579 2784 3473 2817 1208 AVE 440 71924 1003 1256 1078 528 West Sak A4 to West Sak Al 4182' to 4410' MD -3969' to -4185' TVDSS Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 132 29 101 361 29 134 Background gas remained high through this interval of mostly siltstone, gradational to sandstone and claystone, before dropping off above the Al in a clayey interval. Gas increased locally to 361 units at 4194' and 310 units at 4317', from apparent. thin oil sands. Oil indicators diminish sharply through the A4, and are spotty through the A3 and A2. Sandstone is light gray to brownish gray, with very fine lower grains to coarse silt, subangular, poorly to locally moderately sorted, often grain supported and moderately to poorly consolidated with slightly siliceous cement, to poorly to loosely consolidated and grain and matrix supported with clay and calicite matrix and some slight calcareous cement. Composition is dominantly clear to translucent quartz, with slight black carbon lithics, and minor other constituents. Porosities are estimated at mostly very poor to locally poor to fair. Oil indicators include no free oil, various brownish hues on some sandstone due oil staining, 50-30% moderate to bright fluorescence in the A4, and 5-10% fluorescence thereafter, with a fair to good instantaneous and weak straw light yellow cut, and dull gold residue ring. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 4194 361 48634 643 759 775 576 4317 310 52130 740 419 427 364 AVE 134 20501 266 238 288 244 West Sak Al to Base West Sak 4410' to 4501' MD -4185' to -4271' TVDSS Drill Rate ft/hr Total Gas units Maximum Minimum Avera a Maximum Minimum Avera e 111 33 77 73 12 41 The Al to the base of the West Sak is siltstone, claystone, and clayey sandstone, with minor fluorescence and cut. claystone and siltstone from 4380' to 4440' is largely claystone and siltstone with occasional inter-bedded sandstone that are light gray to light grayish brown with secondary hues that were light brown. Soft to slightly ~~~CH 13 COf1000~'11~~Ip5 1 H-North . firm but irregular cutting that were fragile to pulverent fracture. Silty grading to slightly gritty texture, with a dull to earthy luster and moderately soluble. Trace of dull fluorescence spotty throughout zone. Pale yellowish cut with white cut fluorescence, exhibiting no visual cut or residual ring. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m) 4428 73 12516 102 52 85 94 AVE 41 7433 52 27 47 64 Base West Sak to TD 4501' to 4630' MD (-4271' to -4394' TVDSSI Drill Rate ftlhr Total Gas (units Maximum Minimum Avera a Maximum Minimum Avera e 125 30 86 66 9 34 The final interval includes claystone, siltstone, sandstone, minor shale, and some thin zones of hard calcareous concretions. Maximum gas was 66 units at 4516', but only the 4590-4620' sample had significant fluorescence, and gas peaked at only 49 units. Sandstone and siltstone was medium light gray to medium gray, very fine grained to silty, with traces to locally common fine grains, subrounded to subangular, poorly to locally moderately sorted, moderately soft to friable, and matrix and grain supported with an abundant clay and slight calcite matrix. Composition included 80% quartz, and 20% mostly black carbon silts and fines, some green grains possibly glauconite, minor silicates, and trace carbon streaks. Oil properties from 4590-4620' included 40% moderately bright to dull green yellow fluorescence on the overall sample observed on only sandstone and siltstone with a clay matrix, with a slight instantaneous to slow diffuse cut, and fair orange yellow fluorescent residue. claystone was medium gray to medium light gray, often with faint brownish hues, moderately soft and crumbly, earthy to variably silty grading to siltstone, with some incipient fissility in earthy claystone grading to shale, and slight pin point effervescence to occasionally moderately calcareous. Traces to slight silts and fine clasts of carbonaceous matter are pervasive throughout, and brownish hues are due slightly organic clays, or oil staining as grades to sandstone or in streaks on sandy laminations. DEPTH GAS units C1 m C2 m C3 m C4 m C5 m 4516 66 12217 63 15 30 66 4585 49 10855 37 12 16 31 AVE 34 7029 30 10 13 31 ~PCJCH 14 COtIOCO~II~~IpS 1 H-North • 3.3 Gas Samples (ISOTUBES) 1uni4 = n t1S% Ma4hanp Fnuivalpnf Sam le De th Units C1 C2 C3 iC4 nC4 iC5 nC5 # (feet) 1 u=0.05% M.E. (ppm) (ppm) (ppm) (ppm) (ppm) (ppm) (ppm) 1 1750 24 4718 0 0 0 0 0 0 2 2000 28 5510 0 0 0 0 0 0 3 2250 58 11332 0 0 0 0 0 0 4 2500 45 9861 0 0 0 0 0 0 5 2750 40 7961 0 0 0 0 0 0 6 3000 31 6337 0 0 0 0 0 0 7 3250 15 3206 0 0 0 0 0 0 8 3348 71 14852 3 0 0 0 0 0 9 3429 124 26074 10 2 0 0 0 0 10 3452 345 76729 27 2 0 0 0 0 11 3505 610 144362 77 3 0 0 0 0 12 3555 401 88215 46 5 0 0 0 0 13 3678 830 175504 81 7 0 0 0 0 14 3755 78 13403 6 0 0 0 0 0 15 3900 140 37327 42 2 6 2 25 7 16 3913 820 163640 221 8 18 11 61 0 17 4000 112 20877 43 37 18 21 18 6 18 4062 700 111779 1357 2055 907 1327 778 404 19 4096 250 35293 434 630 364 501 280 143 20 4141 544 88808 1284 1559 540 737 393 170 21 4154 1120 186172 2652 3297 1124 1509 754 327 22 4201 217 32847 445 597 193 297 213 113 23 4300 143 23603 300 204 108 160 149 86 24 4400 30 6069 33 14 5 10 12 3 25 4500 32 5772 29 18 9 17 32 17 26 4600 27 5889 22 11 2 6 15 8 ~,P(JCH 15 COt1000~'tl~~lp5 1 H-North 3.4 Connection Gases None noted. lunit . A_A~~/ MathanE± Fnuivalpnt Depth(TVD) feet Gas units/BG Depth(ND) feet Gas units/BG Depth(TVD) feet Gas units/BG • ~I)~~~ 16 COt'lOCO~')I~~IpS 1 H-North • Set T e / Pur ose Fre uenc Interval Dis atched to Bayview Warehouse Unwashed Biostratigraphy 60' ' 110' -1740` MD ' ' ConocoPhillips Alaska, Inc. ABV 100 A 30 MD - 4630 1740 8105 Eleusis Drive Set owner: CPAI 10' SNOWS Anchorage, AK 99502 Attn: D. P o'skUM. McCracken Bayview Warehouse Unwashed Biostratigraphy 60' ' 110' -1740` MD ' ' ConocoPhillips Alaska, Inc. ABV 100 B 30 MD 1740 - 4630 8105 Eleusis Drive Set owner: BP 10' SNOWS Anchorage, AK 99502 Attn: D. P o'skilM. McCracken Bayview Warehouse Washed, screened & 60' 110' - 1740` MD ConocoPhillips Alaska, Inc. ABV 100 C dried Reference Samples 30' 1740' - 4630' MD 8105 Eleusis Drive Set owner: CPAI 10' SNOWS Anchorage, AK 99502 ' ski/M. McCracken Attn: D. P o Bayview Warehouse Washed, screened 8~ 60' 110' -1740' MD ConocoPhillips Alaska, Inc. ABV 100 D dried Reference Samples 30' 1740' - 4630' MD 8105 Eleusis Drive Set owner: BP 10' SNOWS Anchorage, AK 99502 ' ski/M. McCracken Attn: D. P o Bayview Warehouse Washed, screened & 60' 110' -1740` MD ConocoPhillips Alaska, Inc. ABV 100 E dried Reference Samples 30' 1740' - 4630' MD 8105 Eleusis Drive Set owner: Unocal 10' SNOWS Anchorage, AK 99502 ' ski/M. McCracken Attn: D. P o Bayview Warehouse Washed, screened & 60' 110' -1740` MD ConocoPhillips Alaska, Inc. ABV 100 F dried Reference Samples 30' 1740' - 4630' MD 8105 Eleusis Drive Set owner: AOGCC 10' SNOWS Anchorage, AK 99502 ' ski/M. McCracken Attn: D. P o Isotube gas samples ' 1750' -3250` MD Inc Isotech Laboratories G Routine intervals and 250 3250' -4630` MD , . 1308 Parkland Court si nificant eaks above g p 100' and spots of interest Champaign, IL 61821 back round 3.5 Sampling Program /Sample Dispatch SETA & B: 3 BOXES -each 1 cubic foot (Do Not Freeze) SET C, D, E & F: 1 each 3-pack bundle 10"x10"x16" (total 4) SET G: 1 BOX - 8 %2° X 8'/z" X 10 %2" -Hazardous Gas, 26 metal Isotubes (warehouse to re-package) Total 11 boxes ~ ~PCIC;H 17 ,,~,r C011000P~'11~~1~?5 1 H-North • • 4 PRESSURE /FORMATION STRENGTH DATA 4.1 Formation Integrity/Leak Off Tests Cn~ ~i~iolcn+ m~ ~rl uicinh+ /FM\A/1 is r•alri datarl from rntarv tahlP - - - - -- MD ft TVDSS (ft) FIT l LOT EMW FORMATION 2800' -2244 14.00 T3 +717'TVD LOT (Leak Off Test) in bold italics. 4.2 Wire line Formation Tests HYDROS TATIC DEPTH TVD TVDSS Before After F Press Mobility PPG Calc Formation 3502.4 3393.52 3328.92 1638.5 1632 1513.78 426.6 8.74 UGNU C 3551.2 3439.41 3374.81 1664.5 1656 1537.42 39.7 8.76 3677 3558.02 3493.42 1721.49 1712.1 1575.15 443 8.67 UGNU B 3685 3565.59 3500.99 1726.23 1716.33 1578.6 .176.8 8.67 3714.1 3593.11 3528.51 1737.8 1727.8 1595.6 72.3 8.70 3752 3628.93 3564.33 1756.77 1748 1607.51 254.3 8.67 3788 3662.96 3598.36 1774.3 1765.4 1615.32 305.2 8.63 UGNU A 3911.9 3779.48 3714.88 1831.6 1822 1663.13 302.4 8.61 N SAND 3918.1 3785.32 3720.72 1832.3 1823 1665.41 345.9 8.61 4055.2 3914.2 3849.6 1896.4 1886.4 1724.85 36.2 8.62 WEST SAK D 4068.2 3926.45 3861.85 1903.4 1894 1728.8 262.1 8.61 4141 3995 3930.4 1935.6 1922.3 1756.6 8.59 WEST SAK B 4141 3995 3930.4 1920.23 1917.45 1756.54 45.6 8.59 4154 4007.26 3942.66 1943 1930 1761.6 80.1 8.59 4246.1 4094.11 4029.51 1986.6 1976.6 1788.02 134.1 8.53 WEST SAK A2 4316.1 4160.33 4095.73 2017.2 2002.3 1856.44 2.7 8.72 WEST SAK A3 4322 4171.6 4107 2021.15 2013 1957.28 0.9 9.16 4.3 Pore Pressure Evaluation Introduction Trend Indicators The following pore pressure parameters are considered to provide reliable indicators for pore pressure trends during the drilling of a well; Background Gas (BG) Trip Gas (TG) Downtime Gas (DTG) Mud Weight (MW) Resistivity (RES) Wiper Gas (WG) Corrected D exponent (DXC) Hole Conditions (HC) Connection Gas (CG) Pressure Test Wire line (PT) Survey Gas (SG) Pore Pressure (PP) Equivalent Circulating Density (ECD) Quantitative Methods The primary indicators used for PP evaluation were gas trends, including BG, CG, TG, WG, and DTG, El'O~jH 18 Cor~ocoF'hillips 1 H-North . and HC including flows and gas from swabbing or backreaming. Wireline pressure tests were conducted at various points through the Ugnu and West Sak. ECD, necessary for DXC calculations and provided by Sperry Sun, was not measured on the surface hole, and therefore DXC was only plotted for the 8'Iz" hole. Factors such as controlled drill rates, alternate sliding and rotating intervals, variations in angle building, PDC bits, and the absence of clean shale baselines to establish compaction trends, tend to make DXC plots unreliable. RES plots are reliable in determining a permafrost base, and suggesting compaction trends with depth, although the presence of hydrocarbons skews this data. However, generally, low RES and low gas indicate shaliness. 4.4 Pore Pressure Evaluation Conclusions For the well, pore pressure varied from a measured value of 8.53 ppg in the West Sak A2, to an estimated value of as high as 9.0 in the surface hole. Pore pressure was always estimated at well below mud weight since no connection gases were observed, even after high show gases. Mud weight varied from 9.2 to 9.5+ in the surface hole, and was maintained at 9.0 drilling the 8 %" hole. The results for the well are plotted in the PP,MW,ECD, and GAS vs ND plot below. 121/4" surface hole (MD: 2780'; TVD: 2711') The PP,MW,RES, and GAS vs ND -12'/." plot shows distinctively the base of the permafrost with a dramatic drop in resistivity through sands. Pore pressure results are less definitive. Some anomalously low resisitivity between 1100' and 1300' associated with slightly higher gas could suggest some higher pore pressure, and higher gas despite higher mud weights with relatively low resistivity from 2200' to 2600' could also suggest some higher pressures. Pore pressure is estimated to vary between 8.6 and 9.0 through the surface hole. 8'/z" production hole (MD: 4630'; TVD:4459') Plots for exclusively the 8 'h" hole include PP,MW,ECD,RES, and GAS vs ND - 8.5", and DXC and GAS vs TVD - 8.5". Wireline tests included pore pressure measurements at sixteen depths from 3393 to 4160', ranging from 8.53 in the West Sak A2 to 8.76 in the Ugnu C. Pore pressure was plotted by connecting these points. A sixteenth point, at 4171' measuring 9.16, also measured very poor mobility and the pressure data is unreliable. Resistivity, while everywhere responsive to hydrocarbons, shows a downward sloping trend without any abnormalities. DXC points tend to plot tightly grouped slightly below the trend line. However, the low DXC points mostly represent sandy intervals. The higher "shaley" points, from which pore pressure is normally determined, appear randomly scattered above the trend line. Because no connection gases were recorded, pore pressure is estimated not to have exceeded 8.8 through this section, with minor variations between 8.5 and 8.8 to correspond with subtle variations in DXC trends or "low value" resistivity trends. Gas increases and higher resistivity was far more reflective of the hydrocarbons through sandy intervals rather than the pore pressure. Pore pressure may be starting to increase below the base of the West Sak, as peak gas from the wiper trip after reaching total depth lagged to bottom. • ~PC~~H 19 • 4.5 Pore pressure evaluation e•' ConocoPhillips 1 H-North Primary Secondary Interval To s Pore Pressure EMW T d Source of Formation Interval Lithology (%) Lithology (°10) MD ft TVD ft Min Max Trend. ren Indicators Quantitative Estimate Permafrost Sd 60% CI st 30% 30 30 8.6 8.7 Flat BG RES Base Permafrost Sd 70% CI st 30% 1822 1798 8.7 9.0 Sli ht U BG RES,DXC To U nu "C" Sd 40% CI st 30% 3400 3297 8.6 8.7 Flat BG RES, DXC,PT To West Sak Sltst 40% Sd 30% 4054 3913 8.5 8.7 Flat BG RES,DXC,PT Base West Sak Sd 40% CI st 30% 4501 4336 8.7 8.8 Sli ht U BG RES, DXC TD NA NA 4630 4459 8.8 8.8 NA HC,TG RES NOTE: Clyst = Claystone/Clay, Sd =Sand, Sltst = Siltstone, Sh =Shale, Ss =Sandstone ~PC~CH 20 • • • ~.. COnOCO~'ll~~lp5 1 H-North 13 12.5 12 11.5 11 10.5 10 9.5 9 8.5 8 0 PP,MW,ECD, and GAS vs TVD ~~ EPOCH ^ PP(ppg) MW(PPg) ECD(ppg) 21 500 1000 1500 2000 2500 3000 3500 4000 4500 • • ConocoPhillips ~ H-North 10000 1000 100 10 1 PP,MW,RES, and GAS vs TVD - 12.25" ~~ EPOCH i GAS(me+1) ^ PP(ppg) • NIVV(pPg) ^ RES(deep) 22 0 500 1000 1500 2000 2500 3000 • .- ConocoPhillips ~ H-rvortn 10000 1000 100 10 1 PP,MW,ECD,RES, and GAS vs TVD - 8.5" ~~ ~POC;H • GAS(me+1) ^ PP(ppg) • MW(Ppg) i ECD(ppg) RES(deep) 23 2500 3000 3500 4000 4500 • • ConocoPhillips ~ H-Norm DXC and GAS vs TVD - 8.5" 2 1 0 L 2500 ^ ~ ^ ^ ~ ^ ~ ^ Ugnu C @ 3297' ^~ _. @ 4336' • ^ DXC Linear (DXC) ~~ EPOCH 24 3000 3500 4000 4500 COt1000~'II~~IpS 1 H-North 5 DRILLING DATA 5.1 Survey Data • Measured Deft; h Incl. (°) Azim. (°) True Vertical Depth ft Latitude (ft) Departure lft) Vertical Section (ftl Dogleg Rate (°/100ft} 0.00 0.00 0.00 0.00 0.00 N 0.00E 0.00 TIE-I N 194.82 0.69 145.69 194.82 0.97 S 0.66 E -0.44 0.35 286.99 0.54 156.50 286.98 1.83 S 1.15 E -0.89 0.21 376.01 0.71 150.14 375.99 2.69 S 1.59 E -1.36 0.21 465.87 1.22 125.13 465.84 3.72 S 2.65 E -1.64 0.72 556.55 1.42 145.45 556.50 5.20 S 4.08 E -2.09 0.56 646.63 1.10 142.78 646.56 6.81 S 5.23 E -2.79 0.36 737.63 0.69 60.53 737.55 7.24 S 6.24 E -2.59 1.34 831.54 0.98 25.68 831.45 6.23 S 7.08 E -1.29 0.61 926.37 2.29 29.86 926.24 3.86 S 8.37E 1.40 1.39 1021.90 4.28 35.00 1021.61 0.71 N 11.37E 6.87 2.10 1115.75 9.82 35.77 1114.71 10.08 N 18.06E 18.38 5.90 1210.81 13.24 36.46 1207.84 25.42 N 29.27E 37.36 3.60 1306.28 13.90 35.05 1300.64 43.60 N 42.35E 59.74 0.77 1398.00 14.74 33.46 1389.51 62.36 N 55.11E 82.42 1.01 1492.97 15.91 34.52 1481.10 83.16 N 69.15E 107.52 1.27 1588.00 15.35 34.10 1572.62 104.31 N 83.58E 133.12 0.60 1683.04 15.70 34.32 1664.19 125.35 N 97.89E 158.56 0.37 1776.60 15.75 34.30 1754.25 146.29 N 112.18E 183.91 0.05 1870.70 17.72 31.57 1844.36 169.04 N 126.88E 211.00 2.25 1958.51 19.39 28.43 1927.61 193.25 N 140.81E 238.87 2.22 2058.89 19.39 28.73 2022.29 222.52 N 156.76E 272.07 0.10 2152.24 19.36 28.21 2110.36 249.74 N 171.52E 302.92 0.19 2248.32 17.04 26.51 2201.62 276.37 N 185.33E 332.76 2.48 2341.89 16.38 25.98 2291.24 300.50 N 197.23E 359.44 0.72 2437.61 16.53 33.19 2383.05 324.03 N 210.60E 386.44 2.14 2531.64 16.40 32.10 2473.23 346.47 N 224.98E 413.09 0.36 2626.25 16.54 31.50 2563.95 369.28 N 239.12E 439.92 0.25 2712.23 16.69 33.43 2646.34 390.03 N 252.32E 464.51 0.66 2760.48 16.80 33.88 2692.54 401.61 N 260.03E 478.41 0.35 2819.23 18.50 34.37 2748.52 416.35 N 270.03E 496.22 2.90 2915.13 19.17 33.22 2839.29 442.08 N 287.24E 527.18 0.80 3010.63 18.55 34.43 2929.66 467.73 N 304.42E 558.05 0.77 3104.21 19.54 32.71 3018.12 493.17 N 321.29E 588.58 1.22 3199.52 19.27 33.50 3108.01 519.70 N 338.58E 620.25 0.40 3295.19 19.34 34.45 3198.30 545.93 N 356.26E 651.87 0.34 3386.28 19.41 32.76 3284.24 571.09 N 372.98E 682.09 0.62 3482.50 20.00 31.96 3374.82 598.50 N 390.34E 714.52 0.67 ~P~C~ 25 COI'IOCO~l1~~Ip5 1 H-North • Measured Deft' h Incl. (°) Azim. (°) True Vertical Depth ft Latitude (ft) Departure (ft) Vertical Section ~{t~ Dogleg Rate (°l100ft) 3575.85 19.78 31.28 3462.60 625.54 N 406.99E 746.26 0.34 3671.29 19.02 34.13 3552.63 652.22 N 424.11E 777.95 1.27 3765.06 18.97 33.64 3641.29 677.56 N 441.12E 808.47 0.18 3859.16 20.17 33.73 3729.95 703.78 N 458.60E 839.99 1.28 3952.46 19.98 34.32 3817.58 730.32 N 476.52E 872.02 0.30 4047.11 19.78 34.47 3906.59 756.88 N 494.70E 904.20 0.22 4140.56 19.59 33.40 3994.58 783.00 N 512.28E 935.67 0.44 4236.14 19.28 32.35 4084.72 809.71 N 529.54E 967.47 0.49 4331.47 18.56 33.59 4174.90 835.64 N 546.36E 998.38 0.87 4425.77 19.31 32.03 4264.36 860.70 N 562.52E 1028.20 0.59 4519.76 18.10 32.43 4353.64 885.54 N 578.18E 1057.55 0.26 4591.00 17.74 32.25 4421.43 904.06 N 589.90E 1079.47 0.51 4630.00* 17.74 32.25 4458.57 914.11 N 596.24E 1091.35 0.00 *Pro~ected ~1 ~P(JCH 26 5.2 Bit Record ~~ COtl000~11~~Ip5 1 H-North Type p Total Bit WOB PP Bit Make Serial # Jets / TFA MD / TVDSS Footage Hrs ROP (Klbs) RPM (psi) Wear BHA ft ft/hr 12 1/4" Hole 1 Smith PC5501 3X20 110' 2670' 34:16 77.91 5 -14 51 1480 2-3-WT-A-E-I-ER-TD 1 8 112" Hole 2 Smith M75HPX 7X11 2780 1850' 19:55 92.9 1 - 18 71 1800 0-2-CT-S-X-1-ER-TD 2 JT3797 ~PCJC~H 27 • 5.3 Mud Record Contractor :MI SWACO Mud Type :Spud mud to 2780'; Flo Pro to TD. ,~, COtlOCO~'ll~~lPS 1 H-North Date Dept h MW VIS s/ t PV YP Gels FL cc FC Sols % ONV Ratio Sd % MBT pH CI ml/l Ca ml/1 12 1/4" Surtace Hole Section 02/27/06 110 9.2 40 8 12 11/31/32 N/A 2 5 /95 Nil 25 9.2 2000 60 02/28/06 1096 9.2 180 12 48 38/14/48 N/A 3 6 /94 1 28 9.3 1500 60 03/01 /06 2314 9.5 160 22 46 28/43/48 6 2 7.5 /93 1 25 9.3 600 60 03/02/06 2780 9.5+ 145 19 55 27/45/49 6.2 2 7.5 /93 0.75 25 8.6 500 60 03/03/06 2780 9.6 55 20 25 10/12/20 6.2 2 7.5 /93 0.5 25 8.3 600 60 8 1/2" Production Hole Section 03/05/06 4000 9.0 59 10 28 9/10/12 4.4 1 4.5 1/95 0.2 2.25 9.5 21000 80 03!06/06 4630 9.0 69 14 32 11/14/15 4.1 1 4.75 TR/95 0.25 2.5 9.5 24000 80 03/07/06 4630 9.0 75 13 31 10/13/14 3.8 1 4.5 TR/96 0.25 2.5 9.5 24000 40 Abbreviations MW =Mud Weight Gels =Gel Strength Sd =Sand content WL = Water or Filtrate Loss CI =Chlorides VIS =Funnel Viscosity Ca =Hardness Calcium PV =Plastic Viscosity Sols =Solids YP =Yield Point ECD =Effective Circulating Density FC =Filter Cake O/V1l =Oil to Water ratio ~ ~PC~C:H 28 ConocoPhillips ~ Fi-Worth • • • MORNING REPORTS EPOCH 29 ~~ U ConocoPhllllps 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Wilson/ Bredeen Reusing Date: 2/28/06 Time: 03:30 Current Depth: 222 Operation: Make up BHA Yesterdays Depth: 110 24 hr Footage: .112 [~rillino Perameters ROP: Current: 0 Max: 120 Tor ue: Current: 0 Max: 420 WOB: Current 0 Max: 1.5 RPM: Current: 0 Max: 51 PP: Current: 0 Max: 550 La Strokes: Time: Circulation: Strokes: Time: ECD: Current: Max: Mud Properties MW: 9.2 FV: 40 PV: 8 YP: 12 FL: na Gels: 11/31/32 Sol: 5 H: 9.2 CI"~ 2000 Ca~~ 60 MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 0 Max: .975 De the 222 Gas Events Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Peaks De th TG C1 C2 C3 C41 C4N C51 C5N 222 .975 188 gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: 20% conglomerate sand,70% sand, 10 clay Current: Last 24 hrs: Opperational Summary: SPUD WELL, DRILL TO 222', POOH TO P/U BHA Calibrations: OK Failures: NONE ~PQ~H 30 • ConocoPhillips 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Wilson/ Bredeen Reusing Date: 3/01/06 Time: 04:00 Current Depth: 1325 Operation: DRILL Yesterdays Depth: 222 24 hr Footage: 1103 I~rillinn PPramPterc ROP: Current: 66 Max: 150 Tor ue: Current: 0 Max: 2580 WOB: Current 13 Max: 14 RPM: Current: 0 Max: 51 PP: Current: 1196 Max: 1200 La Strokes: 2338 Time: 14 min Circulation: Strokes: 9424 Time: 55 min ECD: Current: Max: M~ ir• PrnnarFias MW: 9.2+ FV: 180 PV: 12 YP: 48 FL: 20.8 Gels: 38/41/48 Sol: 6 H: 9.3 CI"~ 1500 Ca++~ 60 MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 30 Max: 79 De the 1258' C~ac Fvantc Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Paakc De th TG C1 CZ C3 C41 C4N C51 C5N 1194 57 11586 1258 79 15728 gas Sam yes No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: CLAY, SAND, CONGLOMERATE Current: SAND Last 24 hrs: Opperational Summary: DRILLING AHEAD AS PER DIRECTIONAL PLAN Calibrations: CHECKED OK AT RETURNS DEPTH 1213' -1217' Failures: NONE n • COnOCOPf'11111p5 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Wilson/ Bredeen Reusing Date: 3/2/06 Time: 04:00 Current Depth: 2710 Operation: Drill to csg point Yesterdays Depth: 1325 24 hr Footage: 1385 rlrillinn Pcr~mcficre ROP: Current: 64 Max: 244 Tor ue: Current: 3022 Max: 3738 WOB: Current 13 Max: 16 RPM: Current: 51 Max: 51 PP: Current: 1503 Max: 1525 La Strokes: 5472 Time: 33 Circulation: Strokes: 11135 Time: 66 ECD: Current: Max: Mi ir• Prnnarfiiac MW: 9.5 FV: 160 PV: 22 YP: 46 FL: 6 Gels: 28/43/48 Sol: 7.5 H: 9.3 CI"~ 600 Ca+`~ 60 MW Change: Depth: From: Mud Loss event: Depth: Volume: To: Reason: Gas Data Ditch Gas: Current: 42 Max: 99 De the 2337 (,mac Fvcnfic Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N 2031 29 6181 Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Paakc De th TG C1 C2 C3 C41 C4N C51 C5N 2098 88 17754 2337 99 19687 2636 99 20540 C~ac Samnlac No. De th TG C1 C2 C3 C41 C4N C51 C5N 1 1750 24 4718 2 2037 31 5510 3 2250 59 11332 4 2500 48 9861 Lithologies: Clay, coal/ carbonaceous material, sand, conglomerate Current: Sand/coarse sand Last 24 hrs: Opperational Summary: Drill to 2031', wiper trip, drill as per directional plan towards casing point Calibrations: Calibrations checked during wiper trip Failures: Gas trap plugged off/ frozen gastine, noted on mudlog ~POC~ 32 u • • COnOCOPh1111pS 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hiem/ Breeden Reusing Date: 3/3/06 Time: 02:00 Current Depth: 2780 Yesterdays Depth: 2710 24 hr Footage: 70 rlrillinn Pcrarr~tcrc Operation: Condition mud for cementing ROP: Current: 0 Max: 189 Tor ue: Current: 0 Max: 3557 WOB: Current 0 Max: 11 RPM: Current: 0 Max: 52 PP: Current: 289 Max: 1538 La Strokes: 3680 Time: Circulation: Strokes: 11676 Time: ECD: Current: 10.59 Max: Mi irl Prnnartias MW: 9.5+ FV: 145 PV: 19 YP: 55 FL: 6.2 Gels: 27/45/49 Sol: 7.5 H: 8.6 CI"~ 500 Ca++~ 60 MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 4 Max: 44 De the 2756 Tli Gas De th TG C1 C2 C3 C41 C4N C51 C5N 2780 61 12404 Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Paakc De th TG C1 C2 C3 C41 C4N C51 C5N Gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: SAND, CLAY Current: Last 24 hrs: Opperational Summary Calibrations: Failures: Drill to csg point, wiper trip, pooh, Id bha, rig up and run 9 5/8" csg, cond mud ~Pac,~ 33 • ~-' COnOCOPh1111pS 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hiem/ Breeden Reusing Date: 3/4/06 Time: 02:00 f)rillinn Paramatarc Current Depth: 2780 Yesterdays Depth: 2780 24 hr Footage: 0 Operation: Cont R/U choke 8~ Kill lines ROP: Current: Max: Tor ue: Current: Max: WOB: Current Max: RPM: Current: Max: PP: Current: Max: La Strokes: Time: Circulation: Strokes: Time: ECD: Current: Max: Mud Prnnartias MW: 9.6 FV: 55 PV: 20 YP: 25 FL: 6.2 Gels: 10/12/20 Sol: 7.5 H: 8.3 CI-~ 600 Ca++~ 60 MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: Max: De the (;ac Fvantc Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N PP9kS De th TG C1 C2 C3 C41 C4N C51 C5N Gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: NO DRILLING LAST 24 HOURS Current: Last 24 hrs: Opperational Summary: Calibrations: Failures: Cement csg @2770', remove diverter, install FMC starting head, nipple up bop €~ ~~oc,~ 34 • • Report for: Hiem/ Breeden Reusing Date: 3/5/06 Time: 04:00 rlrillinn Paramatarc Current Depth: 2800 Yesterdays Depth: 2780 24 hr Footage: 20 Operation: Cond mud for FIT ROP: Current: 0 Max: 484 Tor ue: Current: 0 Max: 4527 WOB: Current 0 Max: 2 RPM: Current: 0 Max: 50 PP: Current: 472 Max: 1839 La Strokes: 1986 Time: Circulation: Strokes: 2542 Time: ECD: Current: Max: Mud Pro erties MW: FV: PV: YP: FL: Gels: Sol: H: CI"~ Ca~~ MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 0 Max: 36 De the 2790 r,ac Fvantc Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Peaks De th TG C1 C2 C3 C41 C4N C51 C5N 2790 36 7628 C~ac Samnlac No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: Clay, sand Current: Clay, sand Last 24 hrs: Sand, clay Opperational Summary: Test BOP, m/u BHA, p/u 60 jnts pipe, press test csg, drill 20' new form, swap mud to FloPro, attempt FiT -failed -aired up mud, CBU. Calibrations: Gas system calibrated Sat afternoon while RIH. Failures: none COnOCOPhIIIIpS 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North ~PO~H 35 • • U ConocoPhillips ~ H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hiem/ Breeden Reusing Date: 3/6/06 Time: 04:00 Current Depth: 4369 Yesterdays Depth: 2800 24 hr Footage: 1569 r)rillinn Pararr~terc Operation: Drill ahead ROP: Current: 108 Max: 187 Tor ue: Current: 5653 Max: 6151 WOB: Current 14 Max: 19 RPM: Current: 67 Max: 71 PP: Current: 1774 Max: 1815 La Strokes: 3281 Time: 19.3 Circulation: Strokes: Time: ECD: Current: Max: nnua rro ertles MW: FV: PV: YP: FL: Gels: Sol: H: CI-~ Ca~~ MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 47 Max: 1172 De the 4154 C~ac Fventc Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Peaks De th TG C1 C2 C3 C41 C4N C51 C5N 4154 1172 196580 2784 3473 1193 1623 836 371 4059 804 135956 1473 2195 973 1421 838 416 3915 888 163640 221 8 18 11 0 62 C~ac Samnlac No. De th TG C1 C2 C3 C41 C4N C51 C5N 13 3678 830 175504 81 7 16 3913 820 163640 221 8 18 11 22 18 4062 700 111779 1357 2055 907 1327 778 404 21 4154 1120 186172 2652 3297 1124 1509 754 327 Lithologies: Claystone, siltstone, sandstone Current: Claystone, siltstone Last 24 hrs: Opperational Summary: Perform FIT= 14.00 EQMW, drill ahead as per directional plan. Calibrations: Checked at 17:30 hrs. Failures: none ~ EPOCH 36 • COnOCOPhllllpS 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hiem/ Breeden Reusing Date: 3/7/06 Time: 01:00 Current Depth: 4630 Operation: Wireline logging Yesterdays Depth: 4369 24 hr Footage: 261 r)rillinn Paramatarc ROP: Current: 0 Max: 125 Tor ue: Current: 0 Max: 6031 WOB: Current 0 Max: 12 RPM: Current: 0 Max: 68 PP: Current: 0 Max: 1956 La Strokes: 3467 Time: Circulation: Strokes: Time: ECD: Current: 9.6 Max: Mud Pro erties MW: FV: PV: YP: FL: Gels: Sol: H: CI-~ Ca~~ MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 0 Max: 150 De the 4373 (',ac Fvcn4e Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Wi er as 4630 106 17772 218 152 87 136 144 88 Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Paakc De th TG C1 C2 C3 C41 C4N C51 C5N 4373 150 21126 243 150 113 156 145 93 (,ac Samnlpc No. De th TG C1 C2 C3 C41 C4N C51 C5N 24 4400 32 6069 33 14 5 10 12 25 4500 32 5772 29 18 9 17 32 17 26 4600 27 5889 24 12 2 9 5 8 Lithologies: Siltstone, claystone, sandstone Current: Last 24 hrs: Opperational Summary: Drill to TD @ 4630', cbu, wiper trip to shoe, TIH, cbu 3x,drop ESS, POOH, download MWD, I/d bha, rig up wireline and log. Calibrations: Failures: none EPOCH 37 • • • COnOCOPhllllp5 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hiem/ Breeden Reusing Date: 3/8/06 Time: 02:00 Current Depth: Yesterdays Depth 24 hr Footage: I~rillina Parama_tPrs 4630 Operation: Wait on SCR parts ROP: Current: Max: Tor ue: Current: Max: WOB: Current Max: RPM: Current: Max: PP: Current: Max: La Strokes: Time: Circulation: Strokes: Time: ECD: Current: Max: nn. ~.~ pr~nprt~A~ MW: 9.0 FV: 75 PV: 13 YP: 31 FL: 3.8 Gels: 10/13/14 Sol: 4.5 H: 9.5 CI"~ 24000 Ca++~ 40 MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: Max: De the (,ac Fvantc Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Paakc De th TG C1 C2 C3 C41 C4N C51 C5N Gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: Current: NO DRILLING LAST 24 HOURS Last 24 hrs: Operational Summary: Wireline log, POOH, RIH w/ tools on drillpipe to 3108'. POOH to 2476', waiting on parts for SCR. Calibrations: Failures: ~l~ac~c 38 Reusing Date: 3/9/06 Time: 02:00 Current Depth: 4630 Operation: Log on drillpipe Yesterdays Depth: 4630 24 hr Footage: 0 ConocoPhillips ~ H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hieml Pederson rlrillinn Paramatcrc ROP: Current: Max: Tor ue: Current: Max: WOB: Current Max: RPM: Current: Max: PP: Current: Max: La Strokes: Time: Circulation: Strokes: Time: ECD: Current: Max: Mud Pro erties MW: FV: PV: YP: FL: Gels: Sol: H: CI-~ Ca~~ MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: Max: De the r_~~ F"o„t~ Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N PPakS De th TG C1 C2 C3 C41 C4N C51 C5N Gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: Current: NO DRILLING LAST 24 HOURS Last 24 hrs: Operational Summary: Repair SCR, cont POOH, repair logging tools, RIH, R/U side entry sub, latch up wireline, begin logging. • Calibrations: Failures: L' ~~~~ 39 L~ Reusing Date: 3/10/06 Time: 02:00 Current Depth: 4630 Operation: Sidewall cori Yesterdays Depth: 4630 24 hr Footage: 0 COnOCOPh1111pS 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: Hiem/ Pederson rlrillinn Pararriatarc ROP: Current: Max: Tor ue: Current: Max: WOB: Current Max: RPM: Current: Max: PP: Current: Max: La Strokes: Time: Circulation: Strokes: Time: ECD: Current: Max: Mud Pro ernes MW: FV: PV: YP: FL: Gels: Sol: H: CI-~ Ca~~ MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: Max: De the r_~~ F~~o.,+~ Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Peaks De th TG C1 C2 C3 C41 C4N C51 C5N Gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: Current: NO DRILLING LAST 24HOURS Last 24 hrs: Operational Summary: Finish drill pipe conveyed logging, POOH, Rig down side entry sub, cunt POOH, LD tools, rig up and do sidewall cores. • Calibrations: Failures: ~17~1~~ 40 • ~, LJ C011000Phllllp5 1 H-North ConocoPhillips Alaska Inc. Exploration Well 1 H-North Report for: HierrU Pederson Reusing Date: 3/10/06 Time: 02:00 Current Depth: 4630 Operation: Complete P&A Yesterdays Depth: 4630 24 hr Footage: 0 rlrillinn Paramatarc ROP: Current: Max: Tor ue: Current: Max: WOB: Current Max: RPM: Current: Max: PP: Current: Max: La Strokes: Time: Circulation: Strokes: Time: ECD: Current: Max: nnua rro ernes MW: FV: PV: YP: FL: Gels: Sol: H: CI"~ Ca~~ MW Change: Depth: From: To: Reason: Mud Loss event: Depth: Volume: Gas Data Ditch Gas: Current: 0 Max: 628 De the 4630 (,mac Fvcnte Tri Gas De th TG C1 C2 C3 C41 C4N C51 C5N 4630 628 Connection Gas De th TG C1 C2 C3 C41 C4N C51 C5N Paakc De th TG C1 C2 C3 C41 C4N C51 C5N Gas Sam les No. De th TG C1 C2 C3 C41 C4N C51 C5N Lithologies: Current: NO DRILLING LAST 24 HOURS Last 24 hrs: Operational Summary: Complete sidewall cores, POOH, Rig up for cementing to Plug and abandon as per well plan. Calibrations Failures: [~ ~PQCH 41
