Drilling Program SALMAN-1. Block 12, Iraq

Transcription

1 REVIEWED APPROVED S Nikolay Seregin Bashneft International B.V. South Oil Company Drilling Program SALMAN-1 Block 12, Iraq Scott Marquess Regional Well Engineering and Project Team Lead Weatherford Signature Date Evgeny Nikolishin Project Manager Iraq, Block 12 Bashneft International B.V. Signature Date

2 30-Mar-16, Rev.4.5 Weatherford Well Engineering and Project Management (WEPM) Rev.4.5, 26 Feb 2016 Page 1

3 Distribution List: Weatherford Alek Ozegovic Pat York Scott Marquess Alex Ngan Bashneft International B.V. Evgeny Nikolishin Vasily Levochkin Zaid Khamdavi Nikolay Seregin Rev.4.5, 26 Feb 2016 Page 2

4 Legal Statement 2016 Weatherford International Inc. and affiliates ( Weatherford ). All Rights Reserved. This document, the results intellectual property, and any information contained herein or related to this program are strictly confidential and the sole property of Weatherford. Any reproduction or distribution, in whole or in part, without written permission of Weatherford is prohibited. All trademarks, service marks, and logos used or referred to in this program are trademarks or service marks of Weatherford and shall remain the property of Weatherford. Weatherford shall be entitled to any legal and or equitable remedy available at law or in equity (including attorney's fees and court costs) to redress any breach of the provisions in this document. The program is prepared using Weatherford s best judgment based on its experience. Any interpretation of test or other data, and any recommendation based upon interpretations, are opinions based upon inferences from measurements and empirical relationships and assumptions, which inferences and assumptions are not infallible, and with respect to which professional engineers and analysts may differ. Accordingly, Weatherford does not warrant the accuracy, correctness or completeness of any such interpretation or recommendation, which interpretations and recommendations should not, therefore, under any circumstances be relied upon as the sole or main basis for any drilling, completion, well treatment, production or financial decision. UNDER NO CIRCUMSTANCES INCLUDING BUT NOT LIMITED TO UNDER LAW, TORT, CONTRACT, STRICT LIABILITY OR OTHERWISE, SHALL WEATHERFORD BE LIABLE TO ANYONE FOR ANY DAMAGES RESULTING FROM ACCESS OR USE OF THIS STUDY OR ANY INFORMATION CONTAINED HEREIN OR RELATED TO THE STUDY REGARDLESS OF WHETHER THEY ARE DIRECT, INDIRECT, SPECIAL, INCIDENTAL, PUNITIVE OR CONSEQUENTIAL DAMAGES OF ANY CHARACTER, INCLUDING BUT NOT LIMITED TO DAMAGES FOR LOST PROFITS, LOSS OF PRODUCTION OR FOR ANY CLAIM OR DEMAND BY ANY THIRD PARTY, REGARDLESS OF THE JOINT, CONCURRENT OR SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF WEATHERFORD. Rev.4.5, 26 Feb 2016 Page 3

5 TABLE OF CONTENTS Legal Statement General Data Well Summary Units of Measurement Well Objectives Offset Well Data Subsurface Well Data Seismic Data Directional Profile Geological Prognosis Pore Pressure, Fracture Gradient and Temperature Gradient Predictions Lithology Description and Drilling Hazards Drilling Time Evaluation Requirements Mud Logging Wireline Logging Coring Drill Stem Testing Well Design Design Parameters and Load Case Evaluation Triaxial Safety Factors Metallurgy Selection Casing Design Summary Wellhead Design Schematic Pre-Spud Preparations Rig Requirements Pile Drive 30 Conductor and Install Diverter System Hole Section [ mmd] Operational Outline Drilling Fluids Bit, Drill String Design and Hydraulics Rev.4.5, 26 Feb 2016 Page 4

6 11.4 Drilling Procedures Open Hole Logging Casing and Cementing Install 21-1/4 Casing Head Housing BOP Stack Installation Equipment List /2 Hole Section [ mmd] Operational Outline Drilling Fluids Bit, Drill String Design and Hydraulics Drilling procedures Open Hole logging Casing and Cementing BOP Stack Installation Equipment List /4 Hole Section [ mmd] Operational Outline Drilling Fluids Bit, Drill String Design and Hydraulics Drilling Procedures Open Hole Logging /8 Casing and Cementing BOP Stack Installation Equipment List /2 Hole Section [ mmd] Operational Outline Drilling Fluids Bit, Drill String Design and Hydraulics Drilling Procedures Open Hole Logging Liner and Cementing Equipment List Hole Section [ mmd] Operational Outline Drilling Fluids Rev.4.5, 26 Feb 2016 Page 5

7 15.3 Bit, Drill String Design and Hydraulics Drilling Procedure Open Hole Logging Liner and Cementing Equipment List Cement Plug and Abandon Schematic Procedures P&A Procedure If No Formations Are Cased-Hole Production Tested HSE Emergency response Fire Prevention and Protection Environmental Protection Personnel Safety H 2 S and CO Induction Training Communication Contact List Appendix 1 Offset Well Information Appendix 2 BOP & Wellhead Design Summary Appendix 3 Well Testing Program Appendix 4 Wireline Logging Program Appendix 5 Cementing Program Appendix 6 Drilling with Casing Appendix 7 Well Control & Contingency Plans Appendix 8 Solid Expandable Contingency Appendix 9 Minimum Standard Requirements for Security Appendix 10 Casing Specification Sheets Rev.4.5, 26 Feb 2016 Page 6

8 List of Figures Figure 1: Basemap and Well Data for Block Figure 2: Offset Wells Location Map Figure 3: Pressure Profile Estimation and Rock Strength for SALMAN Figure 4: Estimated Temperature Profile Figure 5: SALMAN-1 Drilling Curve Estimate Figure 6: Sumitomo Material Selection Chart Figure 7: Wellhead Schematic Figure 8: Hydraulics Summary for 26 Hole Section Figure 9: Cement Job Simulation Summary for 20 Casing Figure 10: Hydraulics Summary for 17-1/2 Hole Section Figure 11: Cement Job Simulation Summary for 13-3/8 Casing Figure 12: Hydraulics Summary for 12-1/4 Hole Section Figure 13: Cement Job Simulation Summary for 9-7/8 Casing Figure 14: Hydraulics Summary for 8-1/2 Hole Section 17.5 ppg MW Figure 15: Cement Job Simulation Summary for 7 Liner Figure 16: Hydraulics Summary for 6 Hole Section Figure 17: Cement Job Simulation Summary for 4-1/2 Liner Figure 18: Well Barrier Schematic for P&A Figure 20: PPE Matrix Figure 21: H 2 S Toxicity Levels Rev.4.5, 26 Feb 2016 Page 7

9 List of Tables Table 1: Well Data Summary Table 2: Units of Measurement Table 3: Offset Wells Summary Table 4: Predicted Stratigraphy for SALMAN Table 5: SALMAN-1 Drilling Sequence Table 6: Geological Sample Requirements Table 7: Drilling Parameters to be Measured Table 8: Casing Design for SALMAN Table 9: Casing Load Case Summary Table 10: Partial Pressure Estimates for CO 2 and H 2 S Based on Offset Wells Table 11: Casing Design Summary for SALMAN Table 12: Minimum Rig Loading Specification Requirements Table 13: Mud Properties Summary for 26 Hole Section Table 14: Drill String Summary for 26 Hole Section Table 15: Equipment List for 26 Hole Section Table 16: Mud Properties Summary for 17-1/2 Hole Section Table 17: Drill String Summary for 17-1/2 Hole Section Table 18: Equipment List for 17-1/2 Hole Section Table 19: Mud Properties Summary for 12-1/4 Hole Section Table 20: Drill String Summary for 12-1/4 Hole Section Table 21: Interval Coring Plan 12-1/4 Section Table 22: Equipment List for 12-1/4 Hole Section Table 23: Mud Properties Summary for 8-1/2 Hole Section Table 24: Drill String Summary for 8-1/2 Hole Section Table 25: Interval Coring Plan 8-1/2 Section Table 26: Equipment List for 8-1/2 Hole Section Table 27: Mud Properties Summary for 6 Hole Section Table 28: Drill String Summary for 6 Hole Section Table 29: Interval Coring Plan 6 Section Table 30: Equipment List for 6 Hole Section Rev.4.5, 26 Feb 2016 Page 8

10 1 General Data Bashneft International B.V. (BNI), a subsidiary of JSOC Bashneft, was granted exploration operator status for Block 12 in southwest Iraq and SALMAN-1 (initially called PEW 1) will be their first exploration well in Block 12 with the objective of hydrocarbon prospecting, exploration, and evaluation. Block 12 is located in the SW part of the Republic of Iraq, on the territory of Al Najaf and Al Muthanna provinces, 305 km south of the country s capital city Baghdad. The block has the shape of a parallelogram with an area covering 7,680 km 2. The landscape is dominated by desert, with natural water sources confined to the northern areas around the Euphrates River (considered to be the only source of surface water in Al Muthanna province). The terrain within Block 12 is almost flat with scattered buttes and plateaus. Maximum elevation (up to +300m) is in the western part of the block and it gradually decreases to approximately +100m to the east and northeast Figure 1: Basemap and Well Data for Block 12 The first exploration well (SALMAN-1) will be located in the crestal part of the Southern Prospect (Coordinates WGS-84: E, 44 44' N). The target depth with the commitment to drill 500 m from the top of the Kurra Chine is 4245 m. The well is expected to be drilled and tested in 220 days. The planned operation is intended to confirm the geological prognosis by drilling into the Triassic system (Kurra Chine formation) and evaluate the presence of hydrocarbons in Kurra Chine, Butmah, Mus, Sargelu, Najmah, Ratawi, Zubair, Nahr Umr, and Msa ad formations, amongst others. Determination of pore pressure profile, rates of production, and obtaining representative samples of rock and hydrocarbons from each interval are key requirements. Rev.4.5, 26 Feb 2016 Page 9

11 Due to the uncertainty of an exploration well, and the limited amount of offset data available, a five string design was selected with a 4.5 (114.3 mm) production liner included in the event of well production. The well is planned to be plugged and abandoned after TD is reached and well testing completed. Any changes to the drilling program are at the discretion of the Operator, subject to Management of Change (MOC) process and complete approval of all well partners. Rev.4.5, 26 Feb 2016 Page 10

12 1.1 WELL SUMMARY Well Name Location Coordinates WGS-84 (DMS): Location Coordinates WGS-84 (Deg.): Location Coordinates UTM Zone 38N: Area SALMAN E, 44 44' N North Lat., East Long. Y= ,785 X=475688,356 Iraq Prospect Area Block 12 Well Classification Operator Method of Construction Drilling Rig Well Profile Objective 2 Units of Measurement Exploration Bashneft International B.V. Individual Well TBA Vertical Discovery and Evaluation of HC Pools Table 1: Well Data Summary To maintain consistency with all operations in South Iraq, the list below is used to define the units of measurement utilized within this drilling program and what will be reported from the well site. Note: all depth references, with the drilling rig on location shall be made to the rotary table, unless otherwise specified. Measurement Measured Depth True Vertical Depth Pressure Temperature Outer/Inner Diameter (OD/ID) Rate of Penetration Mud Weight Flow Rate Hook Load / WOB Torque Total Gas Liquid Volume Gas Volume Unit* mmdrt (meters measured depth below rotary table) mtvdrt (meters true vertical depth below rotary table) psi (pounds per square inch) C (degrees Celsius) in (inches) m/hr (meters per hour) ppg (pound per gallon) gpm (gallons per minute) klbs (thousand pounds) ft-lbs (foot/pound) % (percentage) and / or ppm (parts per million) bbls (barrels) cuft (cubic feet) Table 2: Units of Measurement * Service Company reports will be a mixture of both Metric & Oilfield units. Rev.4.5, 26 Feb 2016 Page 11

13 3 Well Objectives The objective is to drill SALMAN-1 in Block 12 as an exploratory well to a projected TD of 4245m depending on confirmed stratigraphy. The criterion for well TD is a minimum depth of 4245m or 500m below the top of the Kurra Chine formation (Late Triassic). Objectives: Drill the well safely, with minimal environmental impact, and in compliance with BNI and SOC HSE legislation for operations in the region. Drill the well to planned TD within the anticipated drilling schedule and cost. Zero recordable injuries and environmental incidents. Minimize formation damage to stratigraphic zones of interest in order to successfully evaluate any potential hydrocarbon intervals. Test the potential plays in the Triassic (carbonates of the Kurra Chine), Jurassic (carbonates of the Butmah, Mus, Najmah, and Sargelu) and Cretaceous (carbonates of the Ratawi and Msa ad/mishrif/rumaila and sandstones of the Zubair and Nahr Umr) formations. Possible targets are also expected at the level of the Mus, Najmah and Yamama formations. Collect wireline logs, core samples, and fluid samples as per proposed plan to improve hydrodynamic model reliability and reduce uncertainty in future operations. This program shall be treated as a guideline to help and ensure that safe and efficient operations will be carried out. The respective drilling teams of the Operator and General Contractor will review the program and suggest appropriate changes to further enhance safety and efficiency. Any changes to the programmed activities shall follow appropriate Management of Change (MOC) process. Rev.4.5, 26 Feb 2016 Page 12

14 4 Offset Well Data There is limited offset well information due to the exploratory nature of Block 12 and surrounding fields in south-west Iraq. While exploration maturity of the Western Desert by seismic surveys is satisfactory, and will be enhanced through Block 12, exploration maturity by drilling is extremely low. There is one other well drilled within the block (Sw- 001) to a depth of 1784m into the Zubair formation. Due to the fact that a limited number of wells were drilled, and most being completed over 50 years ago, there was inconsistency with amount of data available for each well. All of the wells need to be analyzed to gain understanding of the drilling operation and important events encountered, whether planned or not. The main focus for well design was given to Diwan-1 and Shawiya-1 wells because of the increased amount of data available and close proximity to planned exploratory well, respectively. Figure 2: Offset Wells Location Map Some basic offset information is summarized in the below table to provide the most important offset trends in relation to Block 12. Rev.4.5, 26 Feb 2016 Page 13

15 Well Dn-001 Formation (Depth) Chia Zairi (5476 m) Year 1989 Open-Hole Testing Hartha ( m): 1m 3 formation water ρ=1.026 g/cc. 1199m = 13.6 MPa (1940 psi). Nahr Umr ( m): formation water + traces of heavy oil, FW ρ=1.089 g/cc m = 20.0 MPa (2845 psi). Ratawi ( m): 1 m 3 oil + gas with traces of mud m = 31.4 MPa (4460 psi). Najmah ( m): unsuccessful, packer not set; ( m): dry (no flow); ( m): 0.5 m 3 heavy oil m = 56.6 MPa (8055 psi). Cased-Hole Nahr Umr ( ; m): 14 m 3 oil, formation water and mud. Oil gravity 24.2 API, FW salinity ppm and ρ = 1.05 g/cc m = 19.9 MPa (2830 psi). Najmah ( ; m): no flow, tight. Sargelu ( m): 2 m 3 mud, gas by reverse circulation m = 65.8 MPa (9360 psi). Coring Interval m m m m m m m Sw-001 Zubair (1784 m) 1960 No testing due to lack of promising horizons (only staining of light brown oil in the Kifl and Rumaila, dark oil staining in the Nahr Umr) m m m Gh-001 Najmah ( m) 1960 Nahr Umr ( m): FW with asphalt and some oil, loaded with sand by reverse circulation, H 2 S in samples. SIBHP = 12.3 MPa (1785 psi), FBHP = initial 5.8 MPa (845 psi) to final MPa, BHT = 155 F (68.3 C). No testing m m Si-001 Muhaiwir ( m) 1960 No testing due to lack of promising horizons (only sporadic bitumen impregnations and viscous oil staining on cuttings from the Nahr Umr/Zubair and Yamama) m Sa-001 Ub-001 Butmah (3842 m) Zubair (1844 m) Ratawi /Yamama ( m): cushion water + dark heavy bituminous oil with S.G. of > 0.9, flow rate 400 bpd, draw-down = 13.8 MPa (2000 psi), SIBHP = 29.2 MPa (4235 psi). Gotnia ( m): dark oil S.G , flow rate 330 bpd, draw-down 1300 psi, SIBHP = 3950 psi, PI = 3.94 bpd/psi, SPI = 0.1 bpd/psi/ft. Najmah ( m): sulphurous water with ρ = g/cc and salinity of 172,000 ppm, SIBHP = 4450 psi; ( m): oil/water emulsion with less than 1% of oil, FW with S.G and trace of H 2 S, flow rate 1000 bpd, initial SIBHP 4000 psi, final FP 3690 psi. Alan ( m): attempts failed, SIBHP = 7300 psi, fluid rise of 192 m (630 feet) of gascut mud. Nahr Umr ( m): FW+gas (H 2 S smell), ρ = , TDS = 5000, reverse circulation 1463 m in 4 inch, 11.8 lb/ft drill pipe; 2 bean settings 8/64 & 16/64, FWHP 1200 & 850 psi, FBHP 2320 & 2110 psi, respectively. Table 3: Offset Wells Summary No testing No testing m N/A m m m Rev.4.5, 26 Feb 2016 Page 14

16 5 Subsurface Well Data 5.1 SEISMIC DATA Initially, from 1949 to 1961, seismic reflection was the main method for exploring the deep subsurface structures of sedimentary cover. The structural geometry was mapped by two reflecting horizons: first corresponding to the bottom of the Lower Fars formation (Middle Miocene) and second to the top of the Shiranish formation (Upper Cretaceous). Seismic exploration within the Western Desert of Iraq has been carried out since the mid-1970s by both state and foreign companies. Six seismic vintages were recorded in Block 12: Bsyia Ubaid (BU) , Samawa Shawyia (SS) , Bsyia (BA) , Ghalaisan (First Stage) (1 Gn) , Tekhadid Safawi (T1) 1980, Ghalaisan (Second Stage) (4 Gn) There are 107 lines in SEG-Y, as tif sections and images. The line spacing was 2-6 km. In 2012 JSOC Bashneft performed express interpretation of the available seismic data related to Block 12. Seven (7) main events were picked and traced; the reflections were tied stratigraphically; three wells were used to generate the velocity model; however the results of the work could not be used to mature the identified leads to the drill-ready status. In PJSOC Bashneft acquired two 2D seismic lines of 192 line km total in Block 12 (and adjacent area to tie-in to Diwan-1) followed by 3D seismic survey in the scope of 1159 sq. km with the full fold area of 849 km 2. Digital processing of field 2D and 3D seismic data was carried out. The integrated interpretation of the 2D and 3D seismic was interpreted and 15 reflectors (or seismic events) were correlated at the stratigraphic levels of the Triassic, Jurassic and Cretaceous. The correlation was performed with the seismic volume in the time domain and 15 target horizons were mapped. The structural depth maps of all the reflectors were created with the help of observed time and average velocity maps. According to the current interpretation, all the mapped surfaces undergo monoclinal uplifting to the south-west as confirmed by the drilling results of Safawi-1 and Ghalaisan-1 to the west of Block 12. Against this regional tilting, local highs were mapped which differ in their size and relief. The integrated geological and seismic interpretation gave two seismic prospects with high HC potential which are recommended as drill-ready targets for deep exploration and appraisal wells on Block 12, including SALMAN DIRECTIONAL PROFILE The SALMAN-1 well is planned to a total depth of 4245m (penetration of Kurra Chine for at least 500m). The well profile is vertical. The maximum allowable deviation from vertical is 3. Deviation survey should be taken every 30m drilled and when tripping out of hole. Rev.4.5, 26 Feb 2016 Page 15

17 TRIASSIC LATE EARLY JURASSIC MID LATE MESOZOIC EARLY CRETACEUOUS LATE CENOZOIC PALEOGENE PALEOCENE EOCENE SALMAN-1 Drilling Program 5.3 GEOLOGICAL PROGNOSIS The stratigraphy represented below for SALMAN-1 is based on new 2D and 3D seismic survey, review of the available offset well information, and the detailed Petroleum Exploration and Appraisal Program Block 12 documented compiled for the client by BashNIPIneft in late Depth (m) Era Period Epoch Formation 0 Dammam 70 Rus 160 Umm Er Raduma 500 Tayarat 620 Shiranish 779 Hartha 1095 Sadi 1265 Tanuma 1280 Khasib 1310 Msa ad/kifl 1325 Mishrif 1335 Rumaila 1430 Ahmadi 1505 Mauddud 1530 Nahr Umr 1695 Shuaiba 1730 Zubair 2032 Ratawi 2257 Yamama 2361 Sulaiy 2400 Gotnia 2460 Najmah 2880 Sargelu Alan/ 3005 Mus/ Adaiyah 3365 Butmah 3745 (TD 4245 m) Table 4: Predicted Stratigraphy for SALMAN-1 Kurra Chine Rev.4.5, 26 Feb 2016 Page 16

18 Depth MD (m) SALMAN-1 Drilling Program 5.4 PORE PRESSURE, FRACTURE GRADIENT AND TEMPERATURE GRADIENT PREDICTIONS Geomechanical analysis was performed in order to estimate mainly the pore pressure and fracture gradient profiles of the planned well. Some qualitative rock property analysis was also performed in order to estimate a safe operating mud weight window. The output from the modeling informed the pressures which guided casing design, seat determination and mud weight to be applied to each hole section of the well. The pore pressure and fracture gradients (Matthews & Kelly method) were estimated and calibrated using mainly DST data from Diwan-1 and well event data from End of Well reports for Diwan-1, Nasiriyah-1 and Nasiriyah-3. Due to the exploratory nature of drilling, and lack of drilling data history, it is strongly recommended to ensure validation of the PP/FG curves through various means (i.e. LOTs, managed pressure drilling, pore pressure prediction analysis, etc.) in order to adjust the drilling strategy as required. EMW (ppg) Estimated FG Estimated PP Figure 3: Pressure Profile Estimation and Rock Strength for SALMAN-1 Rev.4.5, 26 Feb 2016 Page 17

19 Depth (m) SALMAN-1 Drilling Program The End of Well report for Nasiriyah-1 indicates that there was a gas flow from the porous limestone of the Gotnia formation, which required increasing the mud weight to ppg to control the flow. From other studies in the region, it is believed that the existence of a shale layer at the bottom of Sulaiy is a potential cause for increase in pore pressure (overpressure) in Gotnia up to a value of ppg ( psiapproximately). The End of Well report for Nasiriyah-3 indicates that a mud density of ppg must be used to drill through the Gotnia formation based on drilling experience. Mud losses were observed in the Sulaiy formation at a mud weight of ppg. The below temperature profile was estimated from offset DST data: 0 Temperature ( C) Figure 4: Estimated Temperature Profile 5.5 LITHOLOGY DESCRIPTION AND DRILLING HAZARDS Dammam Formation composed mainly of Dolomite and /or Limestone occasionally intercalation with very Minor streaks of Anhydrite, Claystone & Marl. Hazard: mud losses up to 14 bph (53 m 3 /day) Rus Formation composed mainly of Anhydrite intercalation with very minor streaks of Dolomite and/or Limestone. It is picked by appearance of Anhydrite with slow ROP. Hazard: mud losses up to no returns Umm Er Radhuma Formation composed mainly of Carbonates (Dolomite and/or Dolomitic Limestone and/or Limestone) interbedded with thin streaks of Anhydrite & Shale. It is picked by appearance of Carbonates (Dolomite and/or Dolimitic Limestone and/or Limestone) with increased ROP. Hazard: water influx up to 60 bph (228 m 3 /day); sulphurous water flows Tayarat Formation composed mainly of Dolomite interbedded with Limestone and Anhydrite layers. It is picked by appearance of a thin Shale layer at top with slow ROP. Rev.4.5, 26 Feb 2016 Page 18

20 Hazard: cavings, sloughing, washouts; mud losses up to 60 bph (228 m 3 /day); sulphurous water flows Shiranish Formation composed mainly of Limestone interbedded with thin layers of Marl. It is picked by appearance of highly argillaceous Limestone grading to Marl with slow ROP. Hazard: cavings, sloughing, washouts Hartha Formation composed mainly of Limestone interbedded with Dolomite & occasionally intercalation with streaks of Shale. It is picked by appearance of Chalky Limestone and/or Dolomite with slow ROP. Hazard: water influx potential; mud losses up to no returns Sadi Formation composed mainly of Limestone. It is picked by appearance of Chalky Argillaceous Limestone with increased ROP. Tanuma Formation composed mainly of Shale occasionally intercalation with very minor streaks of Limestone. It is picked by appearance of Shale with increased ROP. Khasib Formation composed mainly of Argillaceous Chalky Limestone intercalation with very thin beds of Shale. It is picked by appearance of Argillaceous Chalky Limestone with slow ROP. Mishrif Formation composed mainly of Limestone occasionally with very thin stingers of Shale. It is picked by appearance of Limestone with slow ROP. Hazard: potential H 2 S Rumaila Formation composed mainly of Argillaceous Chalky Limestone occasionally with very minor streaks of Shale. It is picked by appearance of Argillaceous Chalky Limestone or highly calcareous Shale with slow ROP. Hazard: oil shows Ahmadi Formation composed mainly of Shale & Limestone interbeds. It is picked by appearance of Shale followed by Argillaceous Limestone with increased ROP. Hazard: cavings, sloughing, washouts Mauddud Formation composed mainly of Limestone occasionally with very thin stingers of Shale. It is picked by appearance of Limestone occasionally with increase of background gas with increased ROP. Nahr Umr Formation composed mainly of Sandstone interbedded with streaks of Shale, Siltstone & Limestone. It is picked by appearance of Sandstone and/or Shale occasionally with increase of background gas with increased ROP. Hazard: cavings, sloughing, washouts, mud cake; mud loss up to 20 bph (77 m 3 /day); oil and gas shows; potential H 2 S Shuaiba Formation composed mainly of Carbonates (Limestone and/or Dolomite). It is picked by appearance of Limestone and/or Dolomite with increased ROP. Hazard: mud losses up to 70 bph (266 m 3 /day) Zubair Formation composed mainly of Sandstone & Shale intercalation with minor streaks of Limestone & Siltstone. It is picked by appearance of Sandstone and /or Shale with slow ROP. Rev.4.5, 26 Feb 2016 Page 19

21 Hazard: cavings, sloughing, washouts, mud cake; oil shows Ratawi Formation composed mainly of Shale & Limestone interbeds. It is picked by appearance of Shale with slow ROP. Hazard: oil shows Yamama Formation composed mainly of Limestone. It is picked by appearance of Limestone which is below the last Shale streak at bottom of Ratawi Formation with a relatively fast ROP. Hazard: oil shows; potential H 2 S Sulaiy Formation coomposed mainly of Limestone with some Shale streaks at its base. It is picked by appearance of Limestone with slow ROP relative to the previous formation top (Yamama formation). Hazard: mud losses Gotnia Formation composed mainly of Anhydrite & Salt intercalation with minor streaks of Limestone & Shale. Upper part of Gotnia Formation: occasionally called Hith formation, it is composed mainly of Anhydrite intercalation with minor streaks of Limestone & Shale. It is picked by appearance of Anhydrite with slow ROP. Lower part of Gotnia Formation: It is composed mainly of Salt & Anhydrite intercalation with minor streaks of Limestone & Shale. It is picked by appearance of Salt with increased ROP. Hazard: potential overpressure; potential H 2 S Najmah Formation composed mainly of Limestone & Shale interbeds. It is picked by appearance of Limestone with increase of background gas with increased ROP. Hazard: oil and gas shows; potential H 2 S Sargelu Formation composed mainly of Limestone & Shale interbeds. It is picked by appearance of Argillaceous Limestone with slow ROP. Hazard: oil and gas shows Alan / Mus / Adaiyah Formation composed mainly of Limestone with minor streaks of Anhydrite at its base. It is picked by appearance of Limestone occasionally with increase of background gas. Hazard: oil shows; potential H 2 S Butmah Formation composed mainly of Limestone & Anhydrite interbeds & minor streaks of Shale. It is picked by appearance of Shale and/or Anhydrite with slow ROP. Hazard: cavings, sloughing, washouts Kurra Chine Formation composed mainly of Anhydrite followed by salt layer interbedded with Shale and Anhydrite with beds of Limestone. It is picked by appearance of Shale with increased ROP. Hazard: cavings, drilling mud salination Rev.4.5, 26 Feb 2016 Page 20

22 Measured Depth SALMAN-1 Drilling Program 6 Drilling Time 0 Drill 26" Hole Run & Cement 20" Casing Days versus Depth (Base Case) Bashneft, Salman Drill 17-1/2" Hole 1,000 Run & Cement 13 3/8" Casing 1,500 2,000 Drill, Core & Test 12-1/4" Hole 2,500 Run & Cement 9 7/8" Casing 3,000 Drill, Core & Test 8 1/2" Hole 3,500 Run & Cement 7" Liner Drill, Core& Test 6" 4,000 Run & Cement 4 1/2 Liner Cased Hole Testing Plug Back 4, Days from Spud Figure 5: SALMAN-1 Drilling Curve Estimate Rev.4.5, 26 Feb 2016 Page 21

23 Phase Operation SALMAN-1 Drilling Program Depth (m) Planned Time (hrs) Planned Cum. Time (days) Drill 26" Surface Hole and Set 20" Surface Casing Drill 17-1/2" Hole and Set 13-3/8" Int. Casing P/U & M/U Drill Pipe & Rack back stand on derrick M/U 26" BHA & Clean 30" Conductor Drilling 26" hole to casing point [190m] Circulate hole clean Make wiper trip RIH back to bottom Circulate hole clean POOH to surface L/D bit and BHA R/U Wireline Unit Run logs as per Logging program prior to landing surface casing R/D Wireline Unit R/U for running 20" casing. PJSM RIH 20" casing to bottom Circulate clean and condition mud R/D Circ. Head. RIH cement stinger to stab-in shoe & break circulation to confirm return. R/U CMT head, cmt lines, pre job meeting, test cement lines Cement 20" casing as per program Sting-out and Trip out of hole with cement stinger & L/D same. WOC (Perform other offline job). Rough cut 30" Conductor Pipe & 20" Csg, L/D cut joint and diverter. Final cut 20" casing. N/U & install casing head housing, BOP & diverter system, kill lines, etc Pressure test BOP Retrieve test plug and install wear bushing P/U & M/U Drill Pipe & Rack back stand on derrick M/U the 17-1/2 BHA and RIH to bottom Drill Float equipment and 3M Fm Circulate hole clean and perform FIT/LOT Drill 17-1/2" hole into Khasib (1300m) Circulate/condition mud Perform wiper trip to 20" casing shoe POOH bit to surface L/D 17-1/2" BHA R/U Wireline Unit Run logs as per Logging program prior to landing intermediate casing R/D Wireline Unit Retrieve wear Bushings Rig up casing handling equipment. PJSM RIH 13 3/8" Casing to bottom Cement 13-3/8" casing as per program Rev.4.5, 26 Feb 2016 Page 22

24 Drill 12-1/4" Hole and Set 9-7/8" Production Casing Displace cement and bump plug. Pressure test casing WOC. Jet & Clean Wellhead Install Casing Hanger. Cut 13-3/8" casing. N/D 21 1/4 BOP & Drilling Adapter Pick Up 13 5/8" 15K BOP and N/U Same P/U Test plug, Test BOP, Pipe Rams, Blind Ram, Annular, choke & kill line valves Retrieve test plug and install wear bushing P/U & M/U Drill Pipe and rack back in derrick. M/U 12-1/4" BHA RIH 12-1/4" BHA to bottom RIH & drill floats + 3 m formation Circulate hole clean and perform FIT/LOT Drill 12-1/4" hole to core depth of 1320m (Msa'ad/Mishrif formations) Circulate hole clean POOH to surface & L/D 12-1/4" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 1320m to 1350m POOH core barrel assembly to surface M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Deepen 12-1/4" hole by 50m to 1400m Circulate hole clean POOH to surface & L/D 12-1/4" BHA Rig Up OH Well Testing Equipment ( 13 3/8" Casing Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Continue drilling 12-1/4" hole to core depth of 1580m (Nahr Umr formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface & L/D 12-1/4" BHA M/U & RIH core barrel system & RIH to bottom Cut cores from 1580m to 1620m POOH core barrel assembly to surface M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Deepen 12-1/4" hole by 50m to 1670m Circulate hole clean POOH to surface & L/D 12-1/4" BHA R/U Wireline Unit Rev.4.5, 26 Feb 2016 Page 23

25 Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment ( 12 1/4" Open Hole Compression Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Continue drilling 12-1/4" hole to top Zubair formation (1735m) for logging Circulate hole clean to check for "shows". Core for "shows" POOH to surface & L/D 12-1/4" BHA M/U & RIH core barrel system & RIH to bottom Cut cores from 1735m to 1765m POOH core barrel assembly to surface Test BOP M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Deepen 12-1/4" hole by 50m to 1815m Circulate hole clean POOH to surface & L/D 12-1/4" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment ( 12 1/4" Open Hole Compression Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Continue drilling 12-1/4" hole to core depth of 1870m (Base Zubair formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface & L/D 12-1/4" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 1870m to 1890m POOH core barrel assembly to surface M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Deepen 12-1/4" hole by 50m to 1940m Circulate hole clean Rev.4.5, 26 Feb 2016 Page 24

26 POOH to surface & L/D 12-1/4" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment ( 12 1/4" Open Hole Compression Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Continue drilling 12-1/4" hole to core depth of 2045m (Ratawi formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface & L/D 12-1/4" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 2045m to 2075m (Ratawi Formation - Core One) POOH core barrel assembly to surface M/U & RIH core barrel system & RIH to bottom Cut core from 2075m to 2105m (Ratawi Formation - Core Two) POOH core barrel assembly to surface M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Deepen 12-1/4" hole by 50m to 2155m Circulate hole clean POOH to surface & L/D 12-1/4" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Test BOP Rig Up OH Well Testing Equipment ( 12 1/4" Open Hole Compression Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Continue drilling 12-1/4" hole to core depth of 2257m (Yamama formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface & L/D 12-1/4" BHA M/U & RIH core barrel system & RIH to bottom Rev.4.5, 26 Feb 2016 Page 25

27 Cut core from 2257m to 2287m. (Yamama) POOH core barrel assembly to surface M/U & RIH 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Deepen 12-1/4" hole by 50m to 2337m Circulate hole clean POOH to surface & L/D 12-1/4" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment ( 12 1/4" Open Hole Compression Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U 12-1/4" BHA RIH 12-1/4" drilling BHA to bottom Continue to drill 12-1/4" hole to base Circulate and condition mud Continue to drill 12-1/4" hole to selected casing point at top of Gotnia formation or base of Gotnia if no overpressure exits Circulate and condition mud Perform wiper trip to 13-3/8" casing shoe POOH bit to surface L/D 12-1/4" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Retrieve 13-5/8" wear bushing R/U handling equipment for 9-7/8" casing. PJSM Run 9-7/8" casing to bottom Connect circulating head. Circulate hole clean Perform space out, M/U Casing hanger into casing and land. R/D Circ. Head, R/U CMT head, cmt lines, Held pre job meeting, Tested lines to 4000 psi Cement 9-7/8" casing as per program Displace cement and bump plug. WOC N/D BOP & Drilling Adapter N/U & install casing head housing, BOP & diverter system, kill lines, etc RIH Test Plug. Test BOP Retrieve test plug. Install wear bushing Rev.4.5, 26 Feb 2016 Page 26

28 Drill 8-1/2" Hole and Set 7" Liner P/U & M/U Drill Pipe and rack back in derrick P/U 8-1/2 bit & M/U 8-1/2" Clean out BHA RIH 8-1/2" BHA to bottom Drill out cement, float shoe & 3m new formation. Circulate hole clean to check for "shows". Core for "shows" Perform the FIT/LOT POOH to surface M/U & RIH core barrel system & RIH to bottom Continue drilling 8-1/2" hole to core depth of 2460m (Najmah formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface and L/D 8-1/2" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 2460 m to 2480m POOH core barrel assembly to surface M/U & RIH 8 1/2" BHA RIH 8 1/2" drilling BHA to bottom Deepen 8 1/2" hole by 50m to 2530m Circulate hole clean POOH to surface & L/D 8 1/2" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment ( 9 7/8" Casing Packer) RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 8-1/2" BHA RIH 8-1/2" drilling BHA to bottom Continue drilling 8-1/2" hole to core depth of 2890m (Sargelu formation) Circulate hole clean to check for "shows". Core for "shows" Test BOP POOH to surface and L/D 8-1/2" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 2890m to 2910m POOH core barrel assembly to surface M/U & RIH 8 1/2" BHA RIH 8 1/2" drilling BHA to bottom Deepen 8 1/2" hole by 50m to 2960m Circulate hole clean POOH to surface & L/D 8 1/2" BHA R/U Wireline Unit Rev.4.5, 26 Feb 2016 Page 27

29 Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 8-1/2" BHA RIH 8-1/2" drilling BHA to bottom Continue drilling 8-1/2" hole to core depth of 3105m (Alan/Mus/Adaiyah formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface and L/D 8-1/2" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 3105m to 3125m POOH core barrel assembly to surface Test BOP M/U & RIH 8 1/2" BHA RIH 8 1/2" drilling BHA to bottom Deepen 8 1/2" hole by 50m to 3175m Circulate hole clean POOH to surface & L/D 8 1/2" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Rig Up OH Well Testing Equipment RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 8-1/2" BHA RIH 8-1/2" drilling BHA to bottom Continue drilling 8-1/2" hole to core depth of 3430m (Butmah formation) Circulate hole clean to check for "shows". Core for "shows" POOH to surface and L/D 8-1/2" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 3430m to 3445m POOH core barrel assembly to surface M/U & RIH 8 1/2" BHA RIH 8 1/2" drilling BHA to bottom Deepen 8 1/2" hole by 50m to 3495m Circulate hole clean POOH to surface & L/D 8 1/2" BHA R/U Wireline Unit Rev.4.5, 26 Feb 2016 Page 28

30 Drill 6" Hole and Set 4-1/2" Liner Run logs as per Logging program R/D Wireline Unit Test BOP Rig Up OH Well Testing Equipment RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment M/U & RIH 8-1/2" BHA RIH 8-1/2" drilling BHA to bottom Continue to drill 8-1/2" hole to casing point before entering Kurra Chine formation at ~3700m Circulate hole clean Perform wiper trip to 9-7/8" casing shoe POOH bit to surface L/D 8-1/2" BHA R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit R/U TRS equipment to run 7" liner. Hold PJSM M/U and RIH with 7" liner Pick up and M/U Hanger Assembly and run Liner on DP to bottom. (Max 5m/min) Rig Down TRS Equipment Circulate & condition well prior to cementing job. R/U cementing head & cementing line. Perform pressure tests. Set the liner hanger and function test liner hanger to confirm it set Cement 7" liner as per cementing program Bump plug and set packer. Sting out setting tool. Reverse out at top of liner L/D cementing head POOH and L/D setting tool. L/D excess DP Wash BOP and Wellhead RIH Test Plug. Test BOP Retrieve test plug. Install wear bushing P/U & M/U 3 1/2" Drill Pipe and rack back in derrick P/U 6 bit & M/U 6" BHA RIH 6" BHA to bottom Drill out cement, float shoe & 3m new formation Circulate hole clean. Perform the FIT/LOT Drill 6" hole to coring point of ~4000m (Kurra Chine formation) Circulate hole clean Rev.4.5, 26 Feb 2016 Page 29

31 POOH to surface and L/D 6" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 4000m to 4015m POOH core barrel assembly to surface Rig Up OH Well Testing Equipment (7" Casing Packer) Table 5: SALMAN-1 Drilling Sequence RIH with OH DST Assembly Perform Well Test POOH with OH DST Equipment Lay Down OH Well Test Equipment Test BOP M/U & RIH 6" BHA RIH 6" drilling BHA to bottom Continue drilling 6" hole to TD and final core depth of 4240m (Kurra Chine formation) Circulate hole clean and condition mud Perform wiper Trip to 7" Liner Shoe. Circ B/U at TD POOH to surface and L/D 6" BHA M/U & RIH core barrel system & RIH to bottom Cut core from 4240m to 4245m POOH core barrel assembly to surface R/U Wireline Unit Run logs as per Logging program R/D Wireline Unit Test BOP R/U TRS equipment to run 4-1/2" liner. Hold PJSM Run 4-1/2" liner Pick up and make up Liner Hanger tool R/D TRS equipment RIH with 4 1/2" Liner assembly Circulate & condition well prior to cementing job. R/U cementing head & cementing line. Perform pressure tests. Set the liner hanger and function test liner hanger to confirm it set Cement 4-1/2" liner as per cementing program Bump plug and set packer. Sting out setting tool. Reverse out at top of liner L/D cementing head POOH and L/D setting tool. L/D excess DP R/U Wireline Unit Run logs as per Logging program (CBL) Completion Well Testing Rev.4.5, 26 Feb 2016 Page 30

32 7 Evaluation Requirements The formation evaluation program for SALMAN-1 is planned with the following objectives: 7.1 MUD LOGGING to confirm the pre-drill lithology and stratigraphy of the section; to detect the HC bearing zones and evaluate possible oil and gasbearing reservoirs; to predict potential risks of drilling hazards and complications. Mud logging services should be in operation from the beginning of the drilling operation. Geological samples to be taken as follows (as confirmed by BNI and SOC): Depth Range (m) Sample Interval (m) 0 4,245 cuttings collected every 2m Table 6: Geological Sample Requirements Additional requirements: Continuous logging of total gas, H 2 S, CO 2, PVT and analysis of hydrocarbons gas and chromatography. Detailed cuttings analysis: description of drill cutting lithology, visual porosity estimation, and hydrocarbon determination. Geological evaluation of all data collected and computed by the logging unit. Correlation of drill cuttings lithology, gas analysis and hydrocarbon evaluation. Preparation of an up-to-date temperature data log utilizing mud temperature parameters. Sampling and analysis of recovered fluids/gas samples on request. Preparation of an up-to-date Pressure Analysis Log based on interpretation of the above parameters, detailed estimated pore pressure, equivalent circulating density, overburden gradient, and estimated fracture gradient. The following table shows additional parameters to be measured and analyzed during the drilling operation. Drill Bit Position Well Depth Rate of Penetration Drilling Tool Running and Hoisting Speed Rotary Table (Top Drive) Torque Slip Position Indicator Mud Density (In/Out) Hook Load / Weight on Bit Injection Pump (Standpipe) Pressure Pump Strokes Mud Temperature (In/Out) Rotary (Top Drive) Speed Annular Pressure Mud Level in Rig Tanks and Trip Tank Mud Resistivity Mud Flow Rate (In/Out) H 2 S Content CO 2 Content Gas Composition Bottom Hole Pressure Gamma Ray Table 7: Drilling Parameters to be Measured Rev.4.5, 26 Feb 2016 Page 31

33 Rev.4.5, 26 Feb 2016 Page 32

34 7.2 WIRELINE LOGGING Details of the logging requirements are provided for the target formations within the detailed hole sections of this program (Sections 12-16) and the wireline logging program has been provided in Appendix 4. The scope of work may change depending on formation visibility on the logged data and depths provided are only for reference and should be checked with recorded open hole logs and formation tops observed. Depths of the test points may be modified if there are thick shale layers in the interval. 7.3 CORING Controlling parameters while coring is very important to ensure good performance. Mainly flow rate, WOB and RPM need to be monitored very closely. All conventional coring will be done with barrels with lengths and parameters to be determined after a technical discussion with service provider and Bashneft Asset Team Members. Coring plan will be detailed in separate coring program. Anticipated coring intervals are described in the detailed hole sections of this program (Sections 14-16). In addition to the coring intervals mentioned with each hole section, coring is to be performed in all the intervals with HC shows based on positive evidence from mud logging and other formation evaluation data. Thus, the preliminary planned core recovery for SALMAN-1 (TD at 4245 m) is estimated at 305 m or 7.2% of the total section drilled. Sidewall coring (SWC) is planned as an option to be approved by Bashneft. Where applicable, up to 200 SWC samples are planned for SALMAN-1 with TD at 4245 m subject to the quantity and quality of the conventional cores recovered from the target formations. 7.4 DRILL STEM TESTING The testing program has been compiled with the objective of determining the presence, volume, and flow rate of testing the SALMAN-1 exploration well in Block 12 of South Iraq. Testing is designed to obtain information on fluid type, flow rates and pressures, determine formation connectivity and overall general potential reservoir performance. Drill stem testing requires test equipment to be available on site and therefore has to be ordered in advance. Test equipment will comprise a test separator, wellhead, tubing string and bottom hole assemble including quartz pressure gauges and remote operated valve. The well testing service company will supply all necessary equipment and ensure the operations are carried out safely. The DST in the open hole sections is to form the primary option for well testing and wireline formation testers are only to be used as a contingency, as required by SOC. No co-mingling of reservoir flow is allowed and so all potential targets are to be tested exclusively. Further details of the testing program can be found in Appendix 3. Rev.4.5, 26 Feb 2016 Page 33

35 8 Well Design Ensuring protection of Health, Safety and the Environment (HSE) is a primary driver of the SALMAN-1 well design. The proper selection of casing seats and provision for an adequate number of casing strings (including contingencies) provides a robust design that will allow the well to be drilled to the required total depth while maintaining the flexibility to fulfil the drilling and evaluation requirements. The casing design was analyzed with consideration of the well objectives given the exploratory nature of well construction to assess presence of hydrocarbons in Block 12. Optimized casing selection and design was performed without compromising exploration objectives and well integrity. The well design is based on the following inputs: Offset drilling data reports Geological prognosis Pore pressure and fracture gradient predictions (geomechanical assessment) Temperature gradient prediction Identification and assessment of drilling hazards Well evaluation and completion requirements Stipulation from SOC to design for 100% dry gas from Kurra Chine formation Note: Due to the exploratory nature of the intervals 5 and 6, a contingency plan should be considered. The geological conditions of real time drilling will determine the exact outcome, may require the final casing/liner design size to be between DESIGN PARAMETERS AND LOAD CASE EVALUATION The tables below summarize the SALMAN-1 well design and associated load cases evaluated. MD (m) Pipe Body Name Type OD ID Drift Wall Long Weight MYS Top Base Thickness Lead (in) (mm) (in) (mm) (in) (mm) (ppf) (ksi) (mm) Item Conductor Driven Surface Casing Intermediate Casing 0 1, / Yes Production Production Production Casing Liner Liner 750 1, / Yes 1,400 2, Yes 2,300 3, ,400 3, ,550 3, / ,900 4, Yes Rev.4.5, 26 Feb 2016 Page 34

36 Table 8: Casing Design for SALMAN-1 Name Type MD (m) Top Base Conductor Driven 0 30 Name Merlin D IF Connection Max OD Min ID (in) (mm) (in) (mm) (abs) (abs) (abs) (abs) Surface Casing BTC Green Green Cmt Cmt Intermediate Casing 0 1,300 BTC Displ. To Gas Displ. To Gas Tbg Tbg Leak Leak VAM Tbg Tbg Production Casing 750 1, TOP SD Leak Leak Tbg Tbg 1,400 2, Leak Leak TSH Production Liner W513 Tbg 3,550 3, TSH Leak Production Liner W563 Tbg 3,900 4, Leak Table 9: Casing Load Case Summary Safety Factors / Load Cases Triaxial Burst Collapse Initial Overpull Cond. 100k Lost Displ. To Returns Gas Evac P. Test Evac P. Test Evac Evac. 2,300 3, Evac P. Test Evac Evac. 3,400 3, Evac P. Test Evac Evac. Axial P. Test Evac Evac P. Test Evac Evac. Design Factors TRIAXIAL SAFETY FACTORS Production and drilling environments generate different loads as not all the tubulars will be exposed to fluids, temperatures and pressures generated in the pay zones. A plot of the triaxial safety factors is provided below for each casing and liner string, generated using Landmark WELLCAT analysis. Rev.4.5, 26 Feb 2016 Page 35

37 20 [508 mm] Surface Casing 13 ⅜ [340 mm] Intermediate Casing Rev.4.5, 26 Feb 2016 Page 36

38 9-7/8 [251 mm] Production Casing 7 [178 mm] Production Liner Rev.4.5, 26 Feb 2016 Page 37

39 4 ½ [114 mm] Production Liner Rev.4.5, 26 Feb 2016 Page 38

40 8.3 METALLURGY SELECTION Due to the exploratory nature of the project, the real magnitude of the corrosive environment is unknown; however, based on information from offset wells, it s possible to run a first pass corrosion resistant alloy (CRA) material selection. Different manufacturers and regulatory bodies have made public methodologies of selection based on decision trees. The following charts show the partial pressure estimation and the resulting material recommendation based on the decision trees and the limited fluid composition available from offset wells within Yamama and Najmah formations. Reservoir No Depth [m] Pressure [psi] Av. Water CO Temperature 2 H 2 S Salinity [ F] [ C] Content Content CO [ppm] 2 [mol %] [mol %] [psi] Partial Pressures CO 2 [bar] Yamama 2,275 4, ? Najmah 2,535 6, ? Table 10: Partial Pressure Estimates for CO 2 and H 2 S Based on Offset Wells H 2 S [psi] H 2 S [bar] Figure 6: Sumitomo Material Selection Chart Rev.4.5, 26 Feb 2016 Page 39

41 8.4 CASING DESIGN SUMMARY OD MD (m) Hole Size TOC Name Type (in) (mm) Top Base (in) (mm) MD (m) Annulus Fluid Conductor Driven Surface Casing Intermediate Casing 13 3/ , / ppg (1.16 S.G.) Mud ppg (1.25 S.G.) Mud Production Casing 9 7/ , / ppg (1.81 S.G.) Mud 1,400 2,400 Production Liner ,300 3,400 3,400 3, / , ppg (2.04 S.G.) Mud Production Liner 4 1/ ,550 3,900 3,900 4,245 Table 11: Casing Design Summary for SALMAN , ppg (2.25 S.G.) Mud Note: The Top of Cement (TOC) numbers shown above indicates how the WellCat modeling was conducted. This is intended to simulate low quality cement on the first 50 meters. As indicated clearly on the cementing program, the objective is to bring cement all the way to the surface. Rev.4.5, 26 Feb 2016 Page 40

42 9 Wellhead Design The objective is to retain the exploration well as a producer so it can be tested if formation evaluation results are positive and a drill-stem test is required for each potential productive formation. The wellhead should accommodate performing stimulation of production zone(s) if required flow rate will not be achieved. All operations must be performed in accordance with specified procedure and taking into consideration applicable hazards. Equipment Specification The wellhead design presented below is based on the anticipated well parameters, in accordance with API Spec 6A. Due to the exploratory nature of Block 12, the wellhead design should be reviewed and appropriate changes made should new information become available before mobilization or during the drilling operation. The XMAS tree specifications will be dependent on DST results, production tubing requirements and completion option (if not P&A). 9.1 SCHEMATIC Figure 7: Wellhead Schematic Rev.4.5, 26 Feb 2016 Page 41

43 10 Pre-Spud Preparations Prior to spudding the well, the rig must be 100% ready with all commissioning accepted and all integrated services must be in place and commissioned with reports of acceptance signed off by authorized drilling personnel RIG REQUIREMENTS The following table provides a summary of rig specifications based on load requirements of the proposed well design. This is not a comprehensive list and subject to change based on well design modifications. Rig Specification Minimum Requirement Comments Mast/Derrick Requirement Minimum 800,000 lbs. (200,000 lbs. of overpull over air weight of 9-7/8 casing and block weight) Recommended 1,100,000 lbs. (500,000 lbs. of overpull over air weight of 9-7/8 casing and block weight) Air weight of 2,400 m of 9-7/8, 66.4# casing weight = 522,860 lbs + estimated block weight of 60,000 lbs. The tensile rating of the 9-7/8, 66.4#, Q-125 is 2.39 MM lbs so 2.5 MM lbs derrick may be required to enable use of 100% casing tensile capacity. Set Back Capacity 350,000 lbs. (rounded up from 302,005 lbs) Air weight of 3,880 m of 5, G- 105, 19.50# DP m of 5, 49.7# HWDP) = 302,005 lbs. Rotary Beam Capacity 550,000 lbs. (rounded up from 529,396 lbs) Air weight of 2,430 m of 9-7/8, 66.4# casing = 529,396 lbs. Rotary Table Opening 36 Assumes 36 bit to drill conductor hole in case pipe not driven. Rotary Table Load Capacity 550,000 lbs (rounded up from 529,396 lbs) Air weight of 2,430 m of 9-7/8, 66.4# casing = 529,396 lbs. Traveling Equipment Crown Block Hook Elevator Links Casing Elevators 750,000 lbs. (200,000 lbs of overpull over air weight of 9-7/8, 66.4# casing) Air weight of 2,430 m of 9-7/8, 66.4# casing = 529,396 lbs. Top Drive and Drill Pipe Elevators Drill Pipe Description 500,000 lbs. (rounded up from 436,100 lbs) 5, 19.5#, G-105, NC50 Tensile rating of 5, 19.5#, G-105, NC50, Premium DP = 436,100 lbs. Rev.4.5, 26 Feb 2016 Page 42

44 Drill Collars Premium 3-1/2, 15.5#, S-135, Class 2 5, 49.7#, HWDP 3-1/2, 25.29# HWDP 4-3/4 6-3/ /2 Standpipe Pressure Rating Min. = 5000 psi Recommended = 7500 psi In the intermediate section (12-1/4 hole) the requirement is for 4850 psi based on initial hydraulics and well design. Some modifications to the nozzles for 12-1/4 Drilling BHA may be required for minimum 5000 psi SPP for the rig Table 12: Minimum Rig Loading Specification Requirements Please note that rig upgrade requirements for drilling and well testing will need to be evaluated after selection of rig contractor and completion of proper rig inspection. BOP stack requirements are provided with specific hole sections from this program and further details in Appendix PILE DRIVE 30 CONDUCTOR AND INSTALL DIVERTER SYSTEM Nipple Up 30 Diverter System Note: 30 Conductor installed at +/-30m MD/TVD 1. Cut the 30 Conductor to the required height (if possible do it offline before spudding the well). 2. Install the 30 Slip-Lock connector. Install RX-95 ring gasket into groove of Slip-Lock Connector 3. N/U the 30 Diverter Spool together with 12 Ball Valve & Side Outlet just above the Ground Level. Tighten and energize the slip segment as per wellhead installation guidelines. 4. Install the 30 1K Hydrill Annular, Bell Nipple and flow line. Check that flow line is open. Secure the riser to the rig substructure. 5. Install Shakers with the correct size mesh screens as specified in the drilling fluids program, and ensure all solids control equipment is functioning properly. 6. Confirm the alignment of the Derrick and Rotary Table over the conductor pipe using alignment shims if needed. Rev.4.5, 26 Feb 2016 Page 43

45 11 26 Hole Section [ mmd] 11.1 OPERATIONAL OUTLINE Drilling in Dammam, Rus, and upper UER formations. Depth 30 m to 190 mmd 11.2 DRILLING FLUIDS This section is recommended to be drilled with Bentonite, or equivalent mud system. Run all solids control equipment available to maintain control MW and maintain minimal LGS. High viscous pill will be pumped periodically to ensure a good hole cleaning. Control drilling and circulation required to unload the annulus while fast drilling. Expected losses at Dammam formation, keep enough LCM material on location. Mud Properties Type Density PV YP 6 rpm Unit ppg (SG) cps lbs/100 ft 2 Dial Units API Fluid Loss cc/30 min MBT lb/bbl PHB 9.7 (1.16) >10 NC Table 13: Mud Properties Summary for 26 Hole Section 11.3 BIT, DRILL STRING DESIGN AND HYDRAULICS 1 Description 26 Bit Bit Size (in) 2 9-5/8 Drilling Motor 3 9-1/2 Drill Collar Make Type IADC # OD/ID (in) Connection (Bottom/Top) (in) Gender (Bot/Top) Length (m) Cum. Length (m) Cum Weight (lbs) /8 Reg Pin Reg Box Reg Pin Reg Box Reg Pin mrkb (MD) 26 TBD T11 (MT) m /4 String Reg Pin Stabilizer Reg Pin 5 9-1/2 Drill Reg Box Collar Reg Pin 6 9-1/2 Cross Reg Box Over Sub Reg Pin 7 8-1/4 MWD Reg Box Tool REg Pin 8 8-1/4 Drill Reg Box Collar Reg Pin 9 Cross over Reg Box /8 x 6-5/ Reg Pin Reg 10 5 x 8 Drill Reg Box Collars Reg Pin 11 8 Jar Reg Box Rev.4.5, 26 Feb 2016 Page 44

46 12 3 x 8 Drill Collars 13 Cross Over 6-5/8 Reg x 5 NC jts. 5.5 HWDP Reg Pin Reg Box Reg Pin Reg Box IF Pin IF Box IF Pin 4.28 Table 14: Drill String Summary for 26 Hole Section Hole OD (in) Interval (m) TFA (in 2 ) Nozzles (32nds) Flow Rate (gpm) SPP (psi) WOB (klbs) RPM HSI [30 190] x 18s, 1 x Figure 8: Hydraulics Summary for 26 Hole Section Rev.4.5, 26 Feb 2016 Page 45

47 11.4 DRILLING PROCEDURES 1. M/U and RIH with 26 BHA as per BHA sheet included in drilling program. 2. RIH 26 BHA to the 30 conductor bottom. Tag the bottom and make sure that the depth is correct with pipe tally. 3. Break circulation and condition mud according to drilling fluids program. 4. Drill 26 hole to +/-190 m MD (top of UER). Losses are expected in the RUS and Dammam; refer to Lost Circulation Contingency Plan. Expect to drill shaly limestone, limestone, dolomite anhydrite and possibly streaks of marl. Drilling in Dammam, Rus, and upper UER formations Depth 30 m to 190 mmd 1. After drilling 30 conductor shoe, control drilling parameters (600 to 800 GPM, RPM, 10 to 20 klbs WOB) until 100 m MD to avoid washout around 30 conductor shoe. 2. Increase to optimum drilling parameters: GPM: 1500 GPM, RPM: 120 RPM, WOB: 10 to 22 klbs WOB. 3. Ream any tight spots until the section is clean prior to making connections. Please note that the cuttings velocity is lower than industry standard minimum (even at 1500 GPM flow rate). For this reason, high viscosity sweeps as described in the drilling fluids program should be used periodically to clean the hole. Also, a controlled rate of penetration would minimize increases in ECD and would help keep the hole clean and reduce the risk of lost circulation. 4. Note pick up and slack off weight of drilling string. Hole Cleaning & Tripping 1. At section TD circulate the wellbore clean, monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottoms up, especially if the flow rate is reduced. The flow rate should be kept at 1500 GPM ( gpm), and a minimum of the 2x to 3x bottoms up time should be circulated, due to the low cuttings velocity. 2. Perform wiper trip with 26 bit if necessary (if hole condition dictate). Surge and swab calculations indicate that there is little to no surge or swab when tripping the drilling BHA in the 26 hole. 3. Ream any tight spots to bottom and circulate out cuttings. 4. Circulate and condition the mud for running casing. Monitor for returns. 5. POOH & L/D 26 BHA. Rev.4.5, 26 Feb 2016 Page 46

48 11.5 OPEN HOLE LOGGING Descent 1: Gamma Ray/Neutron/Borehole Sonic 1. Rig up main tool set and perform rig floor operational and diagnostic checks. 2. Descend to base of Intermediate casing plus 40m into the open hole below. 3. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 4. Check casing depth, check caliper readings for nominal casing ID; check tension measurement. 5. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 6. Descend to TD logging down. 7. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 8. Drop back into open hole for a 60m repeat under the casing shoe. 9. Check with well site geologist for approval to POOH and rig down. 10. Make up field log as per program, deliver to Wellsite Logging Supervisor CASING AND CEMENTING Casing: 20, 133 ppf, K-55, BTC Running Procedures 1. Drift all casing joint prior running in hole. 2. Hold a Pre-Job Safety Meeting with all personnel involved. 3. R/U 20 Casing Handling Equipment as per Standard Operating Procedures 4. Pick Up 20 Stab in Float Shoe with 1 joint of 20 casing and Baker Lock (M/U Offline). M/U at the workshop is recommended as its the safest option and will also increase efficiency 5. Set the 20 shoe track in the Rotary slips and install the Safety Clamp if required - Test shoe track as per clients request 6. RIH with the 20 casing to 1 casing joint above TD with rotary slips and side door elevators. Note: Make up the first 2 joints to the triangle base, and note the torque reading via the measurement system in use Final make up of casing connections must be performed in accordance with pipe manufacturers recommendations Thread-lock the first 4 connections above float shoe (Tube-Lock). Client specific Dope all threads with API Modified thread compound prior to MU casing joint. Rev.4.5, 26 Feb 2016 Page 47

49 Pick up the casing joints out of V door Inflatable thread protectors are recommended on the pin end of each joint. Limit the running speed of the casing to avoid surge on the open hole formations. Monitor the returns at all times while running casing. Start and stop the casing string slowly. Fill each joint of the casing Monitor the hook load to establish a normal drag trend. Circulate / work the casing down through any significant resistance. 7. Circulate down the last joint of casing to tag bottom lightly. Casing circulating swage required 8. Verify the casing tally against the tag depth and notify any discrepancies. Count the number of joints left at rig site against the casing tally. 9. Pick up off bottom to last casing connection - record the pick-up and the slack off hook load and drag. 10. Space out if required any casing pups run at this time should be buried 1 full joint below wellhead. 11. Break circulation at low flow rates and wash down the 20 casing string to setting depth. 12. Circulate the casing with casing off bottom and in tension. Mud Engineer to confirm when mud is in acceptable condition for cementing. Record static hook load of 20 casing string prior to cementing. Rev.4.5, 26 Feb 2016 Page 48

50 The following figures shows the simulations of cement job for 20 casing. The details for cementation procedures are given in Appendix 5. Figure 9: Cement Job Simulation Summary for 20 Casing 11.7 INSTALL 21-1/4 CASING HEAD HOUSING While WOC as per cement lab test certificate, carry out a top job to fill the 20 casing annulus if required. Rough cut the 20 casing. N/D Bell Nipple. Install Wellhead landing base. Cut and bevel 20 casing as per stack up drawing and recommendations from Wellhead procedures. Install 21-¼ casing head housing as per the Wellhead representative BOP STACK INSTALLATION Nipple up 21-¼ annular preventer and choke line. Function test from remote panel prior to pressure testing. Install riser, bell nipple, flow line. Run and set the 21-1/4 Test Plug on 5 slick joint until Test Plug lands onto 21-1/4 CHH landing shoulder. Test the Pipe Ram and manifold valves as per procedure. Close Annular against slick joint. Test Annular as per procedure. POOH with Test Plug. RIH & install 21-1/4 Wear Bushing. Rev.4.5, 26 Feb 2016 Page 49

51 11.9 EQUIPMENT LIST No Description Provided by Unit 1 Logging Tools Wireline Logging TBD 2 26 Bit Bit Vendor TBD 3 9-5/8 Drilling Motor Directional Drilling TBD 4 9-1/2 Drill Collar Rig TBD /4 String Stabilizer Rig TBD 6 9-1/2 Cross over Sub Rig TBD 7 8-1/4 MWD Tool Directional Drilling TBD 8 8-1/4 Drill Collar Rig TBD 9 Cross over 7-5/8 x 6-5/8 Reg Rig TBD 10 Cross Over 6-5/8 Reg x 5 NC50 Rig TBD 11 Hydraulically Drive Power Casing Tong Casing Running Vendor 1 12 Diesel Powered Hydraulic Unit Casing Running Vendor 1 13 Torque Monitoring System Casing Running Vendor 1 14 Side door elevator Casing Running Vendor 1 15 Single door elevator Casing Running Vendor 1 16 Side 20 Bowl and Slip Casing Running Vendor Ton Slip Type Spider Elevator Casing Running Vendor 1 Table 15: Equipment List for 26 Hole Section Rev.4.5, 26 Feb 2016 Page 50

52 /2 Hole Section [ mmd] 12.1 OPERATIONAL OUTLINE Drilling in Umm Er Radhuma, Tayarat, Shiranish, Hartha, Sadi, Tanuma, and Khasib Formations. It is composed of argillaceous limestone, limestone, shale, salt, chalky clay and ending in argillaceous limestone. Depth: 190m RKB 1300m RKB DRILLING FLUIDS This section is recommended to be drilled with Bentonite/Polymer mud, or equivalent mud system. Use the same mud from previous section and treated as per the formula. 3% KCL will be used for inhibition in case of any shale formation. Run all solids control equipment available to maintain minimal LGS and control MW. Keep enough stock of LCM materials in case of down hole losses encountered at Hartha formation 100 bbl LCM pill of 40 ppb LCM concentration should be mixed and stand by Mud Properties Unit Type Density PV YP 6 rpm ppg (SG) cps lbs/100 ft 2 Dial Units API Fluid Loss cc/30 min MBT LGS KCL lb/bbl % % Water Based 10.4 (1.25) >10 < <6 <10 Table 16: Mud Properties Summary for 17-1/2 Hole Section 12.3 BIT, DRILL STRING DESIGN AND HYDRAULICS Bit Size (in) Make 17-1/2 TBD Type TFH619S (PDC) mrkb (MD) Back up bit Roller Cone Bit(s) (IADC CODES) 1300 TH43A (435), T13 (135) 1 Description 17-1/2 Bit 2 9-5/8 Drilling Motor /2 Roller Reamer 4 9-1/2 Cross Over Sub 5 8-1/4 NM Drill Collar 6 8-1/4 NM Drill Collar 7 8-1/4 MWD Tool OD/ID (in) Connection (Bottom/Top) (in) Gender (Bot/Top) Length (m) Cum. Length (m) Cum Weight (lbs) /8 Reg Pin Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Box Reg Box Reg Pin Rev.4.5, 26 Feb 2016 Page 51

53 8 17-1/2 Roller Reamer 9 9-1/2 x 8 Bottle type Crossover Sub 10 5 x 8 Spiral Drill Collars 11 8 Jar 12 3 x 8 Spiral Drill Collars 13 8 x 6-3/4 Bottle Type Crossover Sub jts. 5.5 HWDP 15 5 G-105, 19.5 lbs/ft Drill Pipe to Surface Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Pin If Box Reg Pin IF Box IF Pin IF Box IF Pin Table 17: Drill String Summary for 17-1/2 Hole Section Hole OD (in) Interval (m) TFA (in 2 ) Nozzles (32nds) Flow Rate (gpm) SPP (psi) WOB (klbs) RPM HSI 17-1/ [ ] x Figure 10: Hydraulics Summary for 17-1/2 Hole Section Rev.4.5, 26 Feb 2016 Page 52

54 12.4 DRILLING PROCEDURES 1. M/U and RIH with 17-1/2 BHA as per BHA sheet included in drilling program 2. RIH 17-1/2 BHA to bottom. Drill out shoe track and 3m of new formation. Circulate and condition mud as per program. 3. Perform the LOT. 4. POOH 17-1/2 BHA into 20 casing shoe track. 5. Rig up cementing lines. 6. Pressure test cementing surface lines according to LOT procedures for 10 mins. 7. Perform LOT until observed pressure start to level out (do not let pressure drop). 8. Drill ahead 17-1/2 hole in the following formations: Umm Er Radhuma, Tayarat, Shiranish, Hartha, Sadi, Tanuma, and Khasib Formations. It is composed of argillaceous limestone, limestone, shale, salt, chalky clay and ending in argillaceous limestone. Depth: 190m RKB 1300m RKB. 1. Tayarat, Shiranish and Tanuma formations are prone to stuck pipe events. 2. Ream any tight spots until the section is clean prior to making connections. 3. Note pick up and slack off weight of drilling string. Drilling in Umm Er Radhuma Formation [Limestone, Anhydrite and Arg.Limestone] Depth: 190m RKB 500m RKB. 1. UER formation contains mostly limestone with some anhydrite, and finishes in argillaceous limestone. 2. Ream any tight spots until the section is clean prior to making connections. 3. The cuttings transport ration (CTR) is 90%, well within industry standards for good hole cleaning. However, the cuttings velocity in this section is well below standards. High viscosity sweeps and a controlled rate of penetration to minimize cuttings accumulation are suggested. 4. Note pick up and slack off weight of drilling string. Drilling in Tayarat Formation [Mudstone and Argillaceous Limestone] Depth: 500m RKB 620m RKB. 1. Tayarat formation contains mudstone and argillaceous limestone. 2. Ream any tight spots until the section is clean prior to making connections. 3. The cuttings transport ration (CTR) is 90%, well within industry standards for good hole cleaning. However, the cuttings velocity in this section is well below standards. High viscosity sweeps and a controlled rate of penetration to minimize cuttings accumulation are suggested. 4. Drilling problems known in the Tayarat include stuck pipe, water inflow and lost circulation. Stuck pipe may occur from 550m to 590m, immediately followed by water inflow from 590m to 600m, immediately followed by lost circulation at 600m to 610m. Refer to the mud program to maintain the best possible slick sealing filter cake to minimize these problems. Best use of solids control equipment will also help maintain a slick filter cake. 5. Note pick up and slack off weight of drilling string. Rev.4.5, 26 Feb 2016 Page 53

55 Drilling in Shiranish Formation [Limestone, Chalky Clay and Shale] Depth: 620m RKB 779m RKB. 1. Shiranish formation contains limestone, chalky clay and shale. 2. Ream any tight spots until the section is clean prior to making connections. 3. The cuttings transport ration (CTR) is 90%, well within industry standards for good hole cleaning. However, the cuttings velocity in this section is well below standards. High viscosity sweeps and a controlled rate of penetration to minimize cuttings accumulation are suggested. 4. Drilling problems known in the Shiranish include stuck pipe, expected from 700m to 720m. Refer to the mud program to maintain the best possible slick sealing filter cake to minimize this problem. Best use of solids control equipment will also help. 5. Note pick up and slack off weight of drilling string. Drilling in Hartha Formation [Chalky Clay, Limestone and Shale] Depth: 779m RKB 1095m RKB. 1. Hartha formation contains chalky clay at the top, followed by alternating layers of limestone and shale. 2. Ream any tight spots until the section is clean prior to making connections. 3. The cuttings transport ration (CTR) is 90%, well within industry standards for good hole cleaning. However, the cuttings velocity in this section is well below standards. High viscosity sweeps and a controlled rate of penetration to minimize cuttings accumulation are suggested. 4. Drilling problems known in the Hartha include an interval between 820m and 840m that can either have inflow or lost circulation. Refer to the mud program to maintain the best possible slick sealing filter cake to minimize this problem. Best use of solids control equipment will also help. 5. Note pick up and slack off weight of drilling string. Drilling in Sadi Formation [Chalk, Chalky Clay and Limestone] Depth: 1095m RKB 1265m RKB. 1. Sadi formation contains chalk at the top with streaks of chalky clay followed by limestone. 2. Ream any tight spots until the section is clean prior to making connections. 3. The cuttings transport ration (CTR) is 90%, well within industry standards for good hole cleaning. However, the cuttings velocity in this section is well below standards. High viscosity sweeps and a controlled rate of penetration to minimize cuttings accumulation are suggested when drilling with the 17-1/2 Drilling BHA. 4. Well before reaching the bottom of the Sadi formation, the decision should be made and communicated to all relevant personnel regarding the contingency Drilling with Casing (DwC) program. 5. Current program calls for drilling the 17-1/2 section completely through the Sadi and continuing deeper to 1300m. 6. Note pick up and slack off weight of drilling string. Rev.4.5, 26 Feb 2016 Page 54

56 Drilling in Tanuma Formation [Shale] Depth: 1265m RKB 1280m RKB. 1. The Tanuma formation is composed of shale. The Tanuma shale is known to be unstable, resulting in many stuck pipe incidents. 2. Ream any tight spots until the section is clean prior to making connections. 3. The cuttings transport ration (CTR) is 90%, well within industry standards for good hole cleaning. However, the cuttings velocity in this section is well below standards. High viscosity sweeps and a controlled rate of penetration to minimize cuttings accumulation are suggested when drilling with the 17-1/2 Drilling BHA. 4. Note pick up and slack off weight of drilling string. Drilling in Khasib Formation [Chalk, Shale, and Limestone] Depth: 1280m RKB 1300m RKB. 1. Khasib formation contains thin layers of chalk, shale and limestone. 2. The 13-3/8 casing point depth is 1300m, which is in the Khasib formation. Identification of the relatively thin Khasib formation needs to be prompt, to avoid drilling too deep and penetrating the Msa ad/rumaila section and its coring points. 3. Ream any tight spots until the section is clean prior to making connections. 4. Note pick up and slack off weight of drilling string. Rev.4.5, 26 Feb 2016 Page 55

57 Hole Cleaning & Tripping 1. At section TD circulate the wellbore clean, monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottoms up, especially if the flow rate is reduced. The flow rate should be kept at 1200 GPM, and a minimum of the 2x to 3x bottoms up time should be circulated, due to the low cuttings velocity. 2. Perform wiper trip with 17-1/2 bit if necessary (if hole condition dictate). Surge and swab calculations indicate that there is little to no surge or swab when tripping the drilling BHA in the 17-1/2 hole. 3. Ream any tight spots to bottom and circulate out cuttings. 4. Circulate and condition the mud for running casing. Monitor for returns. 5. POOH & L/D 17-1/2 drilling BHA OPEN HOLE LOGGING Descent 1: Gamma Ray/Neutron/Borehole Sonic 1. Rig up main tool set and perform rig floor operational and diagnostic checks. 2. Descend to base of Intermediate casing plus 40m into the open hole below. 3. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 4. Check casing depth, check caliper readings for nominal casing ID, check tension measurement. 5. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 6. Descend to TD logging down. 7. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 8. Drop back into open hole for a 60m repeat under the casing shoe. 9. Check with well site geologist for approval to POOH and rig down. 10. Make up field log as per program, deliver to Wellsite Logging Supervisor. Rev.4.5, 26 Feb 2016 Page 56

58 12.6 CASING AND CEMENTING Running Procedures Casing: 13-3/8, 68 ppf, L-80, BTC 1. Drift all casing joint prior running in hole. 2. Hold a Pre-Job Safety Meeting with all personnel involved. 3. R/U 13-3/8 Casing Handling Equipment as per Standard operating procedures 4. Pick Up 13-3/8 Stab in Float Shoe with 1 joint of 13-3/8 casing and Baker Lock (M/U Offline). M/U at the workshop is recommended as its the safest option and will also increase efficiency 5. Set the 13-3/8 shoe track in slips. Function test the shoe track as per clients requirements 6. RIH with the 13-3/8 casing to 1 casing joint above TD with rotary slips. Note: Make up the first 2 joints to the triangle base, and note the torque reading via the measurement system in use Final make up of casing connections must be performed in accordance with pipe manufacturers recommendations Thread-lock the first 4 connections above float shoe (Tube Lock). Dope all threads with API Modified thread compound prior to MU casing joint. Pick up the casing joints out of V door Inflatable thread protectors are recommended to be utilized on the pin end of each joint. Limit the running speed of the casing to avoid surge on the open hole formations. Monitor the returns at all times while running casing. Start and stop the casing string slowly. Fill each joint of the casing Monitor the hook load to establish a normal drag trend. Circulate / work the casing down through any significant resistance. 7. Circulate down the last joint of casing to tag bottom lightly. Verify the casing tally against the tag depth and notify to the office of any discrepancies. Count the number of joints left at rig site against the casing tally. 8. Pick up off bottom to last casing connection - record the pick-up and the slack off hook load and drag. 9. Space out if required any casing pups run at this time should be buried 1 full joint below wellhead. 10. Break circulation at low flow rates and wash down the 13-3/8 casing string to setting depth. 11. Circulate the casing with casing off bottom and in tension. Mud Engineer to confirm when mud is in acceptable condition for cementing. Record static hook load of 13-3/8 casing string prior to cementing. Rev.4.5, 26 Feb 2016 Page 57

59 The following figures shows the simulations of cement job for 13 3/8 casing. The details for cementation procedures are given in Appendix 5. Figure 11: Cement Job Simulation Summary for 13-3/8 Casing Rev.4.5, 26 Feb 2016 Page 58

60 12.7 BOP STACK INSTALLATION Nipple down 21 ¼ BOP system and Install 13 5/8 Drilling Adapter The annulus valve must be open to monitor the well after the cement job has been completed. Wait for instruction from Drill Site Manager to lift BOP after ensuring that there is flow from the annulus valve. Disconnect bell nipple, flow line, lift 21 ¼ BOPs and prepare to land casing. Drain BOP and casing head through its side outlet. Leave the valve open until casing hanger is set. Install casing hanger as per the Wellhead procedures. Cut the casing from suitable distance to fit with casing head spool bottom flange and make sure the surface is levelled. Check with the Wellhead representative for the height of cut required. N/D 21-¼ BOP system and riser. Cut the casing top and remove the cutting of casing. N/U 13-5/8 casing head spool and pressure test the seals to the required pressure or 80% of 13-3/8 casing collapse pressure as per procedure. Nipple up 13 5/8 15K psi BOP N/U 13-5/8 15K psi BOP stack, riser and bell nipple. Hook up control lines, choke and kill lines. Function test all BOP components from remote panel prior to pressure testing as per procedure. Run and set 13-5/8 BOP test plug on slick joint into casing head spool. Pressure test cement unit and surface lines for 10 min as per procedure. Open the annulus valve of casing head spool prior to BOP test to monitor for any leak. Close Lower Pipe Ram, test choke and kill line as per procedure. Open Lower Pipe ram. Close Annular against Slick joint and test the annular as per procedure. Retrieve 13-5/8 BOP test plug. Install 13-3/8 lower wear bushing. Close the annular valve of casing head spool. Rev.4.5, 26 Feb 2016 Page 59

61 12.8 EQUIPMENT LIST No Description Provided by Unit 1 Logging Tools Wireline Logging TBD /2 Bit Bit Vendor TBD 3 9-5/8 Drilling Motor Directional Drilling TBD 4 9-1/2 Cross over Sub Rig TBD 5 8-1/4 MWD Tool Directional Drilling TBD 6 8-1/4 Drill Collar Rig TBD 7 9-1/2 x 8 Bottle type Crossover Sub Rig TBD 8 Cross Over 6-5/8 Reg x 5 NC50 Rig TBD /2 Roller Reamer Rig TBD 10 8 x6-3/4 Bottle Type Crossover Sub Rig TBD /4 NM Drill Collar Directional Drilling TBD 12 Hydraulically Drive Power Casing Tong Casing Running Vendor 1 13 Diesel Powered Hydraulic Unit Casing Running Vendor 1 14 Overdrive Casing Running Vendor 1 15 Torque Monitoring System Casing Running Vendor Ton Spider dressed with 13-3/8" Slips Ton Elevator dressed with 13-3/8" Slips Casing Running Vendor 1 Casing Running Vendor 1 18 FMS Casing Running Vendor 1 19 Side Door Elevator Casing Running Vendor 1 20 Fill - Up and Circulating Tool Casing Running Vendor 1 21 Hand Slip Casing Running Vendor 1 22 Safety Clamp Casing Running Vendor 2 23 Thread Protector Casing Running Vendor 4 24 Casing Drift Casing Running Vendor 2 25 Single Joint Elevator Casing Running Vendor 2 26 Stabbing Guide Casing Running Vendor 2 Table 18: Equipment List for 17-1/2 Hole Section Rev.4.5, 26 Feb 2016 Page 60

62 /4 Hole Section [ mmd] 13.1 OPERATIONAL OUTLINE Drilling in Khasib, Msa ad/rumaila, Ahmadi, Mauddud, Nahr Umr, Shuaiba, Zubair, Ratawi, Yamama, Sulaiy and possibly into the Gotnia Formations (if no pressure ramp exists). They are composed of limestone, dolomite, sandstone, shale, dolomitic limestone and ending in argillaceous. Depth: 1300m RKB 2400m RKB 13.2 DRILLING FLUIDS Recommended: Polymer/KCL/PHPA/CPG Mud (or equivalent mud system) Drill out cement and shoe with old mud from previous hole. Treat the mud as per mud formula while drilling. Provide maximum chemical inhibition (5% KCL, PHPA, CPG) for Shale formation, which is characterized by its sensitivity to water base drilling fluids, and its tendency to create bit balling problems & mechanical sticking problems due to its hydration while drilling Nahr Umr, Shuaiba and Zubair formations. Keep hourly treatment with wellbore strengthening material. Run centrifuge to remove solids and keep properties as per program. Initial mud weight of 10.4 ppg; observe cuttings integrity. Any indications of wellbore breakout should result in an immediate weight increase. Run all solids control equipment available to maintain minimal LGS. Recommended: Salt Saturated Polymer Mud (or equivalent mud system) At the bottom of Yamama formation, the hole needs to be displaced to a heavier fluid to overcome the pressure increase in Sulaiy and Gotnia; delay the displacement as much as possible. Salt saturated system should be mixed and made ready for the displacement prior entering the zone concerned. Mud Properties Type Density PV YP 6 rpm API Fluid Loss MBT LGS KCL Unit ppg (SG) cps lbs/100 ft 2 Dial Units cc/ 30 min lb/ bbl % % Water Based 10.4 (1.25) >8 <5 <5 <5 <10 Salt Saturated Polymer 15.1 (1.81) >6 <5 <5 <5 Table 19: Mud Properties Summary for 12-1/4 Hole Section Rev.4.5, 26 Feb 2016 Page 61

63 13.3 BIT, DRILL STRING DESIGN AND HYDRAULICS Bit Size (in) Make TBD Type SKH616M SKHI716M mrkb (MD) 2400m Back up bit RH30AP (537) S21-GP (217) 1 2 Description 12-1/4 Bit 8 Drilling Motor /4 Roller Reamer 4 8 Short NM Drill Collar 5 8-1/4 NM Drill Collar 6 8 MWD Tool 7 8 NM Crossover Sub 8 8 x 8 Spiral Drill Collars 9 8 Jar 10 3 x 8 Spiral Drill Collars 11 8 x 6-3/4 Bottle Type XO Sub jts. 5.5 HWDP 13 5 G-105, 19.5 lbs/ft Drill Pipe to Surface OD/ID (in) Connection (Bottom/Top) (in) Gender (Bot/Top) Length (m) Cum. Length (m) Cum Weight (lbs) Reg Pin Reg Box Reg Box Reg Box Reg Pin Reg Box Reg Pin Reg Box Reg Pin Reg Box REg Box Reg Box REg Pin Reg Box REg Pin Reg Box REg Pin Reg Box Reg Pin IF Box Reg Pin IF Box IF Pin IF Box IF Pin Table 20: Drill String Summary for 12-1/4 Hole Section Rev.4.5, 26 Feb 2016 Page 62

64 Hole OD (in) Interval (m) TFA (in 2 ) Nozzles (32nds) Flow Rate (gpm) SPP (psi) WOB (klbs) RPM HSI m [ ] x Figure 12: Hydraulics Summary for 12-1/4 Hole Section 13.4 DRILLING PROCEDURES 1. Install Wear bushing. 2. M/U and RIH with 12-1/4 BHA as per BHA sheet included in drilling program 3. RIH 12-1/4 BHA to bottom. Drill out shoe track and 3m of new formation. 4. Circulate and condition the mud as per program. The mud weight will be increased from 10.4 ppg (1.25 SG) as required until the bottom of Yamama where the hole needs to be displaced to a heavier fluid to overcome the pressure increase in Sulaiy and Gotnia as described above in the fluid properties table. Rev.4.5, 26 Feb 2016 Page 63

65 5. Perform the LOT. POOH 12-1/4 BHA into 13-3/8 casing shoe track. Rig up cementing lines. Pressure test cementing surface lines according to LOT procedures for 10 min. Perform LOT until observed pressure starts to level out (do not let pressure drop). 6. Drill and core as necessary in the 12-1/4 hole through the following formations: Khasib, Msa ad/rumaila, Ahmadi, Mauddud, Nahr Umr, Shuaiba, Zubair, Ratawi, Yamama, Sulaiy and into the Gotnia Formations. They are composed of limestone, dolomite, sandstone, shale, dolomitic limestone and ending in argillaceous. Depth: 1300m RKB 2400m RKB Ahmadi, Mauddud, Nahr Umr, and Zubair formations are prone to stuck pipe events. The Nahr Umr from 1620m to 1640m may be prone to both inflow and lost circulation. The Shuaiba from 1695m to 1715m may be prone to inflow. Keep in mind the six coring points in order to avoid drilling into zones to be cored. Drill ahead in 12-1/4 hole until reaching the core points depths as shown below table and subject to change as advised by Geologist. Section Drilling Parameters Recommended: GPM: 850, RPM: , WOB: For the PDC first and second choice bits, SKH616M and SKHI716M, WOB can be up klbs. For the third choice roller cone bits the WOB is klbs for the RH30AP or the S21-GP bit. Please note that these parameters may change for the coring BHA. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. Ream any tight spots until the section is clean prior to making connections. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. In the event of encountering overpressure within the Gotnia, a contingency plan for running a solid expandable is required for isolation. Details provided in Appendix 8. Coring Interval (m) Thickness of Cored Interval (m) Age of Depositions Lithology 1,320-1, Msa ad/mishrif Carbonate 1,580-1, NahrUmr Sandstone / siliciclastic 1,735-1,765 1,870-1, Zubair Sandstone / siliciclastic 2,045-2, Ratawi Carbonate 2,257-2, Yamama Carbonate Table 21: Interval Coring Plan 12-1/4 Section Rev.4.5, 26 Feb 2016 Page 64

66 Drilling in Khasib Formation [Chalk, Shale, and Limestone] Depth: 1300m RKB 1310m RKB. 1. Khasib formation contains thin layers of chalk, shale and limestone. 2. No coring is anticipated in the Khasib formation. 3. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 4. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 5. Note pick up and slack off weight of drilling string. This data is necessary to understand downhole conditions. Drilling in Msa ad/rumaila Formation [Shale, Limestone, Chalk and Limestone] Depth: 1310m RKB 1430m RKB. 1. Msa ad/rumaila formation begins in layers of shale, limestone, chalk, and ends in limestone. 2. Coring is anticipated in the Msa ad/rhumaila formation at 1320m-1350m. 3. Prior to pulling out of the hole to change the drilling BHA for the coring BHA, circulate the wellbore clean. Monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottoms up, especially if the flow rate is reduced. Continue to circulate the hole until the shakers are clean. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. 6. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 7. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Ahmadi Formation [Shale, Limestone, Chalky Clay] Depth: 1430m RKB 1505m RKB. 1. Ahmadi formation begins in layers of shale, alternating layers of limestone and chalky clay, and ends in shale. 2. No coring is anticipated in the Ahmadi formation. 3. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 4. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 5. Note pick up and slack off weight of drilling string. This data is necessary to understand downhole conditions Rev.4.5, 26 Feb 2016 Page 65

67 Drilling in Mauddud Formation [Limestone] Depth: 1505m RKB 1530m RKB. 1. Mauddud formation consists of predominantly limestone. 2. No coring is anticipated in the Mauddud formation. 3. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 4. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 5. Note pick up and slack off weight of drilling string. This data is necessary to understand downhole conditions. Drilling in Nahr Umr Formation [Shale, Sandy Shale and Sandstone] Depth: 1530m RKB 1695m RKB. 1. Nahr Umr formation begins in shale, then sandy shale and ends in sandstone. 2. Coring is anticipated in the Nahr Umr formation at 1580m-1620m. 3. Prior to pulling out of the hole to change the drilling BHA for the coring BHA, circulate the wellbore clean. Monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottom up, especially if the flow rate is reduced. Continue to circulate the hole until the shakers are clean. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. 6. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 7. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Shuaiba Formation [Dolomite] Depth: 1695m RKB 1730 RKB. 1. Shuaiba formation is a dolomite. 2. No coring is anticipated in the Shuaiba formation. 3. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 4. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 5. Note pick up and slack off weight of drilling string. This data is necessary to understand downhole conditions. Rev.4.5, 26 Feb 2016 Page 66

68 Drilling in Zubair Formation [Shale, sandstone, dolomite] Depth: 1730m RKB 2032m RKB. 1. Zubair formation begins in shale, then alternating layers of sandstone and shale, ending in dolomite. 2. Coring is anticipated in the Zubair formation at 1735m-1765m and again at 1870m- 1890m. 3. Prior to pulling out of the hole to change the drilling BHA for the coring BHA, circulate the wellbore clean. Monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottoms up, especially if the flow rate is reduced. Continue to circulate the hole until the shakers are clean. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. 6. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 7. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Ratawi Formation [Shale, Limestone] Depth: 2032m RKB 2257m RKB. 1. Ratawi formation begins in shale, and has alternating layers of shale and limestone. 2. Coring is anticipated in the Ratawi formation at 2045m-2105m. 3. Prior to pulling out of the hole to change the drilling BHA for the coring BHA, circulate the wellbore clean. Monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottoms up, especially if the flow rate is reduced. Continue to circulate the hole until the shakers are clean. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. 6. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 7. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Yamama Formation [Limestone] Depth: 2257m RKB 2361m RKB. 1. Yamama is consists of limestone. 2. Coring is anticipated in the Yamama formation at 2257m-2287m. Rev.4.5, 26 Feb 2016 Page 67

69 3. Prior to pulling out of the hole to change the drilling BHA for the coring BHA, circulate the wellbore clean. Monitor the shale shakers for returns and condition the mud to the required parameters as per program. The shale shakers should not be expected to clean up after circulating one bottoms up, especially if the flow rate is reduced. Continue to circulate the hole until the shakers are clean. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. 6. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 7. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Sulaiy Formation [Limestone] Depth: 2361m RKB 2400m RKB. 1. Sulaiy is made of limestone. 2. No coring is anticipated in the Sulaiy formation. 3. Assuming a mud weight increase to 15.1 ppg at the bottom of Yamama, the expected flow rate of 850 GPM results in an ECD of ppg equivalent, which is well within the specified pressure window. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 156 feet/minute, which slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. This data is necessary to understand downhole conditions. 7. Due to the uncertainty in PP&FG predictions and limited offset wells data, it is possible to encounter overpressure in the lower section of Sulaiy formation. Implementation of downhole tools (PWD & MWD) or technology (Closed-Loop Drilling, Dynamic Leak-Off Test, Real-Time Pore Pressure Prediction, Mud-Logging etc.) that validates the PP&FG values in real-time mitigates the drilling risks. 8. Drill ahead with caution with recommended flow check every 10m and monitor for overpressure trends in the transitional zone of potential pressure ramp. 9. Continue to drill ahead into Gotnia formation if there are no signs of pressure ramp or overpressure. If pressure ramp or overpressure is present, increase mud weight prior to drilling ahead to ensure overbalanced condition. However, maximum equivalent mud weight (EMW) / equivalent circulating density (ECD) for the 12-1/4 hole section is limited by 15.3ppge estimated fracture gradient at the 13-3/8 casing shoe at 1,300m. 10. Once the EMW/ECD for 12-1/4 hole section reaches 15.3 ppge, stop drilling and POOH to set 9-7/8 casing. Verify casing seat in the formation, as per the Salman-1 Geological Technical Order. A drilling liner or solid expandable liner may be required to isolate the pressure ramp / overpressure section prior to continue to drill the 8-1/2 hole section. Rev.4.5, 26 Feb 2016 Page 68

70 ** In the case of no overpressure suspected or identified, the contingency option is to further deepen the 12-1/4 hole to have the casing point within the Gotnia formation and details provided below; otherwise, the Gotnia formation will be drilled within the 8-1/2 hole section once 9-7/8 casing has been run and cemented. ** Drilling in Gotnia Formation [Arg. Limestone, Anhydrite] 1. Gotnia formation begins in argillaceous limestone, followed by anhydrite, limestone and ending in anhydrite. 2. No coring is anticipated in the Gotnia formation. 3. Assuming a mud weight of 15.1 ppg, the expected flow rate of 850 GPM results in an ECD of 15.4 ppg equivalent, which is well within the specified pressure window. 4. The 850 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 156 feet/minute, which is slightly low. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. This data is necessary to understand downhole conditions. 7. Drilling 12-1/4 hole section into Gotnia is contingent on no overpressure / pressure ramp above 15.3ppg EMW through the Sulaiy formation. Due to the uncertainty in PP&FG predictions and limited offset wells data, drill ahead with caution with recommended flow check every 10m and monitor for overpressure trends in the transitional zone of pressure ramp. 8. If pressure ramp or overpressure is present, increase mud weight prior to drilling ahead to ensure overbalanced condition. However, maximum equivalent mud weight (EMW) / equivalent circulating density (ECD) for the 12-1/4 hole section is limited by 15.3ppge estimated fracture gradient at the 13-3/8 casing shoe at 1,300m. 9. Once the EMW/ECD for 12-1/4 hole section reaches 15.3ppge, stop drilling and POOH to set 9-7/8 casing. Verify casing seat in the formation, as per the Salman-1 Geological Technical Order. A drilling liner or solid expandable liner may be required to isolate the pressure ramp / overpressure section prior to continue drilling the 8-1/2 hole section. Refer to Appendix 8 for expandable contingency procedures. Otherwise, continue to drill to the top of Najmah formation and set 9-7/8 casing. Note: A decision tree for the casing setting point is provided in Appendix 8 along with details on the solid expandable system. Hole Cleaning & Tripping 1. At section TD, circulate hole clean, monitor shale shakers for returns and condition mud by circulation to get the required mud properties as per program. 2. Perform wiper trip to 13-3/8 casing shoe noting any depth of resistance. If required, reduce pump rate in proximity of 13-3/8 casing shoe. Repeat wiper trip if required as hole condition dictates. 3. Run back to bottom. 4. Perform flow check prior to POOH. 5. POOH and L/D 12-1/4 BHA. Rev.4.5, 26 Feb 2016 Page 69

71 13.5 OPEN HOLE LOGGING Descent 1: Micro Imager / Dipole / Dual Lateral 1. Rig up main tool set and perform rig floor operational and diagnostic checks. 2. Descend to base of Intermediate casing plus 40m into the open hole below. 3. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 4. Check casing depth, check caliper readings for nominal casing ID, check tension measurement. 5. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 6. Descend to TD logging down. 7. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 8. Drop back into open hole for a 60m repeat under the casing shoe. 9. Check with well site geologist for approval to POOH and rig down. 10. Make up field log as per program, deliver to Wellsite Logging Supervisor. Descent 2: Photo Density / Dual Neutron / Micro Resistivity / Spectral Gamma Ray 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Load Logging R/A Sources (Rig Personnel Clear from Rig Floor) 3. Descend to base of Intermediate casing plus 40m into the open hole below. 4. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 5. Check casing depth, check caliper readings for nominal casing ID, check tension measurement. 6. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 7. Descend to TD logging down. 8. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 9. Drop back into open hole for a 60m repeat under the casing shoe. Rev.4.5, 26 Feb 2016 Page 70

72 10. Check with well site geologist for approval to POOH and rig down. 11. Unload Logging R/A Sources (Rig Personnel Clear from Rig Floor) 12. Make up field log as per program, deliver to Wellsite Logging Supervisor. Descent 3: Formation Tester / Gamma Ray 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Descend to base of Intermediate casing and perform and casing check to verify good seal (a dry pretest should be observed) 3. A correlation log will be acquired and log put on depth before the MFT program. 4. Prior to RIH, all seal valves should be physically checked for proper operation. 5. For each station, the following procedure applies: a. Wait for hydrostatic readings to be stabilized b. Set the probe and perform pretest c. Ensure formation pressure stabilized before retracting probe. d. Get three points after retracting probe to have an idea of the hydrostatic after e. Pretest could be resumed also on geologist request. f. Maximum time to spend stationary will be specified by geologist for pretest. g. With the exception of tight zones, all the points will be acquired with limited drawdown pressure, but could be adjusted depending on formation pressure results). After pre-tests, engineer must wait until pressure stabilizes to at least three points, or until the client representative provides the permission to retract piston. Rev.4.5, 26 Feb 2016 Page 71

73 Descent 4: Reservoir Sampler / Gamma Ray Correlation passes depending on the operation. This Log will be referenced to the first run in hole. R.E.S tool will be equipped with a standard probe for pre-tests. A correlation log will be acquired and log put on depth before the R.E.S program. Prior to RIH, all seal valves should be physically checked for proper operation. For sampling, at each station the following applies: o Perform a pretest to confirm formation pressure and mobility. o Start pumping fluid with the slowest speed, then increase pump-rate if formation drawdown allows it. The sample quality will be checked based on the RFA indications. The required contamination level must be confirmed and fixed by the client. Nevertheless if the level of contamination could not be reached in a moderate time, a sample reasonably clean could be taken. With client agreement, sample the fluid then stop the pump, retract probe and move to the next station. Prior to RIH, all seal valves should be physically checked for proper operation. After POOH, special care should be taken while handling the PVT bottles or the sample chambers it is pressurized. All transport valves should be in place before bottles are shipped to town. Rig safety officer will be noticed to be on the floor with portable H 2 S meter to check for H 2 S in samples. Descent 5: VSP 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Perform space check-shots while running in hole to TD to verify data quality and Vibro Truck settings 3. A correlation log will be acquired and log put on depth before the VSP program. 4. Start taking VSP surveys according to resolution agreed with well site geologist up to surface 5. Check with well site geologist for approval to POOH and rig down. 6. Make up field log as per program, deliver to Wellsite Logging Supervisor. Rev.4.5, 26 Feb 2016 Page 72

74 /8 CASING AND CEMENTING Casing: 9-7/8", 66.4 ppf, Q-125/VM-140/VM-150 VAM TOP 1. Drift all casing joints prior running in hole. 2. Retrieve Lower wear bushing. 3. Hold pre-job safety and procedural meeting. 4. RU casing handling equipment and JAM Unit as per standard operating procedures. 5. Make up 9-7/8 thread locked shoe track consisting of 9-7/8 Float Shoe, 2 joints of 9-7/8 casing and Float Collar. M/U offline at the workshop is recommended as the safest option and will also increase efficiency. 6. Record the value of the make-up torque applied in accordance to pipe manufacturers recommendations 7. Set shoe track in slips. Function test shoe track by circulate down to ensure it is clear from any debris. Note: Ensure that casing tally is given to TRS lead hand, driller and tool-pusher for verification of running order. Dope all threads with API Modified thread compound prior to MU. Pick up casing joints out of V door Inflatable thread protectors must be used on the pin end of each joint. Limit the running speed to seconds per joint to avoid surge on the open hole formations. Monitor returns at all times while running casing. Start and stop the casing string slowly. Fill each joint of casing Monitor hook load to establish a normal drag trend. Circulate / work the casing down through any significant resistance. 8. Continue RIH casing to 2 joints above TD. 9. R/U circulating head. 10. Circulate down the last 2 joints of casing to tag bottom lightly. Verify casing tally against tag depth and notify office of any discrepancies. Count the number of joints left at rig site against the casing tally. 11. Pick up off bottom to last casing connection - record pick up and slack off hook load and drag. Rev.4.5, 26 Feb 2016 Page 73

75 The following figure show the simulations of cement job for 9-7/8 casing. The details for cementation procedures are given in Appendix 5. Figure 13: Cement Job Simulation Summary for 9-7/8 Casing Rev.4.5, 26 Feb 2016 Page 74

76 13.7 BOP STACK INSTALLATION N/D 13-5/8 BOP and Install 11 Tubing spool The annulus valve must be open to monitor the well after the cement job has been completed. Wait for instruction from Drill Site Manager to lift BOP after ensuring that there is flow from the annulus valve. Disconnect bell nipple, flow line, lift 13-5/8 BOP and prepare to land casing. Drain BOP and casing head through its side outlet. Leave the valve open until casing hanger is set. Install casing hanger as per the Wellhead procedures. Cut the casing from suitable distance to fit with casing head spool bottom flange and make sure the surface is levelled. Check with the Wellhead representative for the height of cut required. Skid 13-5/8 BOP away using BOP trolley. Final cut the casing top and remove the cutting of casing. N/U 11 tubing head spool and pressure test the seals to the required pressure or 80% of 9-7/8 casing collapse pressure as per procedure. N/U 13 5/8 15K BOP Install drilling spool adapter 11 x 13 5/8. N/U 13 5/8 15K BOP. Run and set 13 5/8 BOP test plug on slick joint into casing head spool as per procedure. Test Blind rams, Pipe rams and Annular as per procedure. Test choke manifold, choke line and kill line as per procedure. Install 13 5/8 Wear bushing as per procedure. Rev.4.5, 26 Feb 2016 Page 75

77 13.8 EQUIPMENT LIST No Description Provided by Unit 1 Logging Tools Wireline Logging TBD /4 Bit Bit Vendor TBD 3 8 Drilling Motor Directional Drilling TBD /4 Roller Reamer Rig TBD 5 8 Short NM Drill Collar Directional Drilling TBD 6 8-1/4 NM Drill Collar Directional Drilling TBD 7 8 MWD Tool Directional Drilling TBD 8 8 NM Crossover Sub Directional Drilling TBD 9 8 Spiral Drill Collars Rig TBD 10 8 Jar Rig TBD 11 8 x 6-3/4 Bottle Type XO Sub Rig TBD 12 Hydraulically Drive Power Casing Tong Casing Running Vendor 1 13 Diesel Powered Hydraulic Unit Casing Running Vendor 1 14 Overdrive Casing Running Vendor 1 15 Torque Monitoring System Casing Running Vendor Ton Spider dressed with 13-3/8" Slips Ton Elevator dressed with 13-3/8" Slips Casing Running Vendor 1 Casing Running Vendor 1 18 FMS Casing Running Vendor 1 19 Side Door Elevator Casing Running Vendor 1 20 Fill - Up and Circulating Tool Casing Running Vendor 1 21 Hand Slip Casing Running Vendor 1 22 Safety Clamp Casing Running Vendor 2 23 Thread Protector Casing Running Vendor 4 24 Casing Drift Casing Running Vendor 2 25 Single Joint Elevator Casing Running Vendor 2 26 Stabbing Guide Casing Running Vendor 2 Table 22: Equipment List for 12-1/4 Hole Section Rev.4.5, 26 Feb 2016 Page 76

78 14 8-1/2 Hole Section [ mmd] 14.1 OPERATIONAL OUTLINE Drilling Gotnia, Najmah, Sargelu, Alan Mus Adaiyah, and into the Butmah Formation. They are composed of anhydrite, argillaceous limestone, limestone, shale, sandstone, dolomite and ending in limestone. Depth: 2400m RKB 3700m RKB 14.2 DRILLING FLUIDS Recommended: Salt Saturated Polymer Mud (or equivalent mud system) Drill out cement & shoe track with old mud using short system between suction tank & hole. Displace hole to fresh saturated salt polymer mud with initial mud weight of 17 ppg (if Gotnia Pressure ramp is not encountered) Observe cuttings integrity and adjust weight as hole dictates. Run all solids control equipment available to maintain minimal LGS. Store maximum volume of mud after cement job in reserve tanks and should be used for next interval. Add CaCO 3 fine and medium to the system as bridging material and to prevent differential sticking. Keep enough non-damaging LCM materials on board. Mud Properties Unit Type Density PV YP 6 rpm Salt Saturated Polymer ppg (SG) 17.0 (2.04) cps lbs/100 ft 2 Dial Units API Fluid Loss cc/30 min MBT LGS Cl lb/bbl % mg/l >6 <5 <5 <5 >120,000 Table 23: Mud Properties Summary for 8-1/2 Hole Section 14.3 BIT, DRILL STRING DESIGN AND HYDRAULICS Bit Size (in) Make 8.50 TBD Type SKH713M SKH716D mrkb (MD) 3700 Back up bit (IADC Code) R30AP (537) S21-GP (217) Description 1 8-1/2 Bit /4 Drilling Motor 8 x 6-3/4 String Stabilizer 6-3/4 MWD NMDC 6-3/4 MWD NMDC 10 x 6-3/4 Spiral Drill Collars OD/ID (in) Connection (Bottom/Top) (in) Gender (Bot/Top) Length (m) Cum. Length (m) Cum Weight (lbs) Reg Pin Reg Box Reg Box IF Box IF Pin IF Box IF Pin IF Box IF Pin IF Box IF Pin IF Box /4 Jar IF Pin 8 4 x 6-3/4 Spiral 4.50 IF 4.50 IF Box Rev.4.5, 26 Feb 2016 Page 77

79 Drill Collars 4.50 IF 4.50 IF Pin 9 15 jts IF Box HWDP IF Pin 10 5 G-105, IF Box lbs/ft Drill Pipe to Surface IF Pin Table 24: Drill String Summary for 8-1/2 Hole Section Hole OD (in) Interval (m) TFA (in 2 ) Nozzle (32nds) Flow Rate (gpm) SPP (psi) WOB (klbs) RPM HSI m [ ] x18s Figure 14: Hydraulics Summary for 8-1/2 Hole Section 17.5 ppg MW Rev.4.5, 26 Feb 2016 Page 78

80 14.4 DRILLING PROCEDURES 1. Install Wear bushing. 2. Make up 8-1/2 PDC bit with Motor BHA & RIH as per program. 3. RIH 8-1/2 BHA until tag 9-7/8 float collar. 4. Drill out 9-7/8 float collar, float shoe and 3m of new formation with low flow rate and RPM. 5. Circulate and condition mud as per mud program. The initial mud weight will be 17.0 ppg (2.04 SG) and be saturated with salt. Pressures should be expected to change significantly. 6. Perform LOT. 7. POOH 8-1/2 BHA into 9-7/8 casing shoe track. 8. Rig up cementing lines. 9. Pressure test cementing surface lines according to LOT procedures for 10 minutes. 10. Perform LOT until observed pressure starts to level out (do not let pressure drop). 11. Drill and core as shown in the table below in the 8-1/2 hole section through the following formations: Gotnia, Najmah, Sargelu, Alan Mus Adaiyah, and into the Butmah Formations. They are composed of anhydrite, argillaceous limestone, limestone, shale, sandstone, dolomite and ending in limestone. Depth: 2400m RKB 3700m RKB Sargelu is prone to stuck pipe from 2970m to 2990m. The Butmah formation is prone to stuck pipe from 3380m to 3565m. Keep in mind the four coring points in order to avoid drilling into zones to be cored. Drill ahead in 8-1/2 hole until reaching the core points depths as shown in table below and subject to change as advised by Geologist. Section Drilling Parameters: GPM: 350, RPM: , WOB: For the PDC first and second choice bits, SKH713M and SKH716D, WOB can be up 38 klbs. For the third choice roller cone bits, R30AP and the S21-GP, the WOB is klbs. Please note that these parameters may change for the coring BHA. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. Ream any tight spots until the section is clean prior to making connections. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Rev.4.5, 26 Feb 2016 Page 79

81 Coring Interval (m) Thickness of Cored Interval (m) Age of Depositions Lithology 2,460-2, Najmah Carbonate 2,890-2, Sargelu* Carbonate 3,105-3, Alan/Mus* Carbonate 3,430-3, Butmah* Carbonate * In addition to the intervals mentioned above, coring is to be performed in all the intervals with HC shows based on positive evidence from mud logging and other formation evaluation data. Table 25: Interval Coring Plan 8-1/2 Section Drilling in Gotnia Formation [Arg. Limestone, Anhydrite] Depth: 2400m RKB 2460m RKB. 1. Gotnia formation begins in argillaceous limestone, followed by anhydrite, limestone and ending in anhydrite. 2. No coring is anticipated in the Gotnia formation. 3. Assuming a mud weight of 17.0 ppg, the expected flow rate of 350 GPM results in an ECD of 17.8 ppg equivalent, which is well within the specified pressure window; however, this is dependent on existence or absence of overpressure as stated in earlier hole section with relation to casing setting depth. 4. The 350 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 178 feet/minute, which is above the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Najmah Formation [Arg. Limestone, Shale, Anhydrite, Limestone] Depth: 2460m RKB 2880m RKB. 1. Najmah formation begins in limestone, followed by layers of shale, anhydrite, with some argillaceous limestone and ending in limestone. 2. The first 20m of the Najmah (2460m to 2480m) will be cored. 3. Assuming a mud weight of 17.0 ppg, the expected flow rate of 350 GPM results in an ECD of 17.8 ppg equivalent, which is well within the specified pressure window. 4. The 350 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 178 feet/minute, which is above the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Rev.4.5, 26 Feb 2016 Page 80

82 Drilling in Sargelu Formation [Arg. Limestone, Limestone, Sandstone] Depth: 2880m RKB 3005m RKB. 1. Sargelu formation begins in argillaceous limestone, followed by limestone, more argillaceous limestone, followed by thin layers of limestone and sandstone, then ending in argillaceous limestone. 2. Coring is anticipated in the Sargelu formation from 2890m-2910m, which should be a gas show. 3. Assuming a mud weight of 17.0 ppg, the expected flow rate of 350 GPM results in an ECD of 17.8 ppg equivalent, which is well within the specified pressure window. 4. The 350 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 178 feet/minute, which is above the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Alan Mus Adaiyah Formation [Arg. Limestone, Anhydrite] Depth: 3005m RKB 3365m RKB. 1. Alan/Mus/Adaiyah formation begins in anhydrite, then layers of limestone and anhydrite, then shale, argillaceous limestone, chalky clay, limestone and ending in dolomite. 2. Coring is anticipated in the Alan/Mus/Adaiyah formation from 3105m-3125m. 3. Assuming a mud weight of 17.0 ppg, the expected flow rate of 350 GPM results in an ECD of 17.8 ppg equivalent, which is well within the specified pressure window. 4. The 350 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 178 feet/minute, which is above the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Butmah Formation [Limestone, Shale, Anhydrite, Dolomite and Sandstone] Depth: 3365m RKB 3700m RKB. 1. Butmah formation begins in limestone, and then contains layers of shale, anhydrite, dolomite, sandstone and finishes in limestone. 2. Coring is anticipated in the Butmah formation from 3430m-3445m. This is well into a known zone of sticking problems and may have commercial oil content. 3. Assuming a mud weight of 17.0 ppg, the expected flow rate of 350 GPM results in an ECD of ppg equivalent, which is well within the specified pressure window. 4. The 350 GPM flow rate results in a cuttings transport ratio (CTR) of 96% which is good. 5. The cuttings velocity is 178 feet/minute, which is above the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. Rev.4.5, 26 Feb 2016 Page 81

83 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Hole Cleaning & Tripping 1. At section TD, circulate hole clean, monitor shale shakers for returns and condition mud by circulation to get the required mud properties as per program. 2. Perform wiper trip to 9-7/8 casing shoe noting any depth of resistance. If required, reduce pump rate in proximity of 9-7/8 casing shoe. Repeat wiper trip if required as hole condition dictates. 3. Run back to bottom. 4. Perform flow check prior to POOH. 5. POOH and L/D 8-1/2 BHA OPEN HOLE LOGGING Descent 1: Micro Imager / Dipole / Dual Lateral 1. Rig up main tool set and perform rig floor operational and diagnostic checks. 2. Descend to base of Intermediate casing plus 40m into the open hole below. 3. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 4. Check casing depth, check caliper readings for nominal casing ID, check tension measurement. 5. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 6. Descend to TD logging down. 7. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 8. Drop back into open hole for a 60m repeat under the casing shoe. 9. Check with well site geologist for approval to POOH and rig down. 10. Make up field log as per program, deliver to Wellsite Logging Supervisor. Descent 2: Photo Density / Dual Neutron / Micro Resistivity / Spectral Gamma Ray 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Load Logging R/A Sources (Rig Personnel Clear from Rig Floor) 3. Descend to base of Intermediate casing plus 40m into the open hole below. Rev.4.5, 26 Feb 2016 Page 82

84 4. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 5. Check casing depth, check caliper readings for nominal casing ID, and check tension measurement. 6. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 7. Descend to TD logging down. 8. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 9. Drop back into open hole for a 60m repeat under the casing shoe. 10. Check with WSG for approval to POH and rig down. 11. Unload Logging R/A Sources (Rig Personnel Clear from Rig Floor) 12. Make up field log as per program, deliver to Wellsite Logging Supervisor. Descent 3: Formation Tester / Gamma Ray 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Descend to base of Intermediate casing and perform and casing check to verify good seal (a dry pretest should be observed) 3. A correlation log will be acquired and log put on depth before the MFT program. 4. Prior to RIH, all seal valves should be physically checked for proper operation. 5. For each station, the following procedure applies: a. Wait for hydrostatic readings to be stabilized b. Set the probe and perform pretest c. Ensure formation pressure stabilized before retracting probe. d. Get three points after retracting probe to have an idea of the hydrostatic after e. Pretest could be resumed also on geologist request. f. Maximum time to spend stationary will be specified by geologist for pretest. g. With the exception of tight zones, all the points will be acquired with limited drawdown pressure, but could be adjusted depending on formation pressure results). After pre-tests, engineer must wait until pressure stabilizes to at least three points, or until the client representative provides the permission to retract piston. Rev.4.5, 26 Feb 2016 Page 83

85 Descent 4: Reservoir Sampler / Gamma Ray Correlation passes depending on the operation. This Log will be referenced to the first run in hole. R.E.S tool will be equipped with a standard probe for pre-tests. A correlation log will be acquired and log put on depth before the reservoir sample program. Prior to RIH, all seal valves should be physically checked for proper operation. For sampling, at each station the following applies: o Perform a pretest to confirm formation pressure and mobility. o Start pumping fluid with the slowest speed, then increase pump-rate if formation drawdown allows it. The sample quality will be checked based on the RFA indications. The required contamination level must be agreed and fixed by the client. Nevertheless, if the level of contamination could not be reached in a moderate time, a sample reasonably clean could be taken. With client agreement, sample the fluid then stop the pump, retract probe and move to the next station. Prior to RIH, all seal valves should be physically checked for proper operation. After POOH, special care should be taken while handling the PVT bottles or the sample chambers it is pressurized. All transport valves should be in place before bottles are shipped to town. Rig safety officer will be noticed to be on the floor with portable H 2 S meter to check for H 2 S in samples. Descent 5: VSP 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Perform space check-shots while running in hole to TD to verify data quality and Vibro Truck settings 3. A correlation log will be acquired and log put on depth before the VSP program. 4. Start taking VSP surveys according to resolution agreed with WSG up to surface 5. Check with well site geologist for approval to POOH and rig down. 6. Make up field log as per program, deliver to Wellsite Logging Supervisor Rev.4.5, 26 Feb 2016 Page 84

86 LINER AND CEMENTING PRE-JOB PREPARATION/CHECKS 1. Check compatibility between liner wiper plugs and casing, and Drill Pipe Wiper Dart with running string tubulars. 2. Install Drill Pipe Wiper Dart and setting ball in the top drive head. Company Representative to be present and witness. Tape up the operating handles to ensure they are not operated until the operation requires it. 3. Drift all running string tubulars to 2 1/2" minimum. 4. Remove any drill pipe protectors on lower 10 stands to reduce risk of cementing in the string. Ensure that any dart sub in the string is removed. 5. If the cement head is to be racked in the derrick please ensure it cannot be damaged and is accessible in the event that the job is delayed. 6. Confirm final well path information to ensure correct TVD versus MD values are used. Note depths of maximum deviations / doglegs. Obtain any relevant information regarding previous tripping such as tight spots, fluid loss problems etc. 7. Discuss and agree with all relevant personnel the figures to be used for displacement calculations. It should be noted that a large amount of pipe today is manufactured close to the minimum API tolerances so the use of nominal ID figures for pipe is not advisable. It is recommended to caliper a sample of the liner joints to give an accurate displacement figure. RUNNING THE LINER 1. Note total number of liner joints and pup joints on the pipe deck. 2. Install float equipment and the required number of casing joints for the shoe tract. Check that float valves are operating correctly. Install Landing Collar as necessary above the float equipment. 3. RIH with liner, filling approximately every 5 joints and fill completely when last joint is in slips. 4. Pick up hanger assembly, install wiper plug system and make up on liner. Start with chain tong. 5. Pick up approximately 3 feet / 1 metre, letting rotary slips ride on liner joint, to check if setting tool and all connections are properly made up. If so pull slips. 6. Note pick up and slack off weight of liner. Pull rotary bushing if the hanger can be damaged going through rotary table. Lower hanger assembly through rotary and set drill pipe slips on the 5" handling pup joint. TO AVOID POSSIBLE DAMAGE, DO NOT SET SLIPS ON THE PBR. Be careful to keep the hanger centered while lowering through rotary table to avoid damage to the assembly. Rev.4.5, 26 Feb 2016 Page 85

87 7. Circulate at least one liner volume to ensure there are no obstructions within the liner system, not exceeding 500 psi. Note the total number of drill pipe stands in the derrick. 8. While circulating the liner contents fill up the PBR with drill water through the junk bonnet 9. When PBR is full, water will discharge from the air outlet hole in the junk bonnet. Stop filling, wait for 2 minutes then top up PBR. plug both inlet and outlet holes and also remove the cap screws/protectors from the side of the junk bonnet 10. Run in hole using back up tong on running string. Put pipe wiper on pipe while running in. Drift pipe if not previously drifted. Ensure that both rabbit and rope handle are recovered each time. Fill drill pipe regularly, to a maximum of 5 stands unfilled. To avoid any pressure surges, do not use a closed system for this operation. Do not exceed running speed more than 15m/min lowering time. 11. Circulate at casing shoe with max 800psi. Take the free moving up and down weight and torques before going into open hole. Have the Field Supervisor on the drill floor before doing any rotating, circulating or setting down weight once the liner is in open hole. Do not exceed running speed more than 15m/min lowering time in open hole. 12. When running in open hole fill up each stand. In some hole conditions, when running into open hole, it may be desirable to put right hand torque in the string every ft to ensure there is no residual left hand torque at the HNG running tool. 13. Note that if rotation is required to get the liner in the hole, care has to be taken such that when rotation is stopped, the residual torque in the string is released in a controlled manner. The HNG tool s emergency release feature is activated with lefthand torque. 14. Space out drill string to put the cement head +/- 10ft above rotary table when shoe is on setting depth. Drift all pipe picked up from pipe deck, paying particular attention to pup joints. 15. Pick up and install the cement head. Take the free moving up and down weight. Break circulation and wash down to TD, not exceeding 800psi. Tag bottom and mark pipe. Pick up to the free moving up weight and measure out to the setting depth. 16. Circulate at setting depth with max 1,000psi. Rotate and condition hole as required. (Limit torque to cased hole torque at 20rpm + 80% of optimum liner make up torque, or hanger assembly make-up torque, whichever is less). Circulate at least bottoms up before setting the hanger. SETTING THE LINER HANGER AND RELEASING THE RUNNING TOOL 1. When circulation is completed, stop rotating and drop the setting ball from the ball releaser in the cement head. Ensure the flag sub is in the up position prior to dropping the ball. 2. Pump the ball down at 2-3 bbl/min with a maximum pressure of 800 psi. The ball should take approximately 2-3 min per 1,000 ft to land on its seat. Watch the pressure gauge closely. While pumping the ball down, reconfirm the setting depth by Rev.4.5, 26 Feb 2016 Page 86

88 tagging bottom and picking up to full up weight plus 3 metres. Further rotation at this point is not recommended. 3. When the ball lands, slow pumps and increase pressure to 300psi above that required to set the liner hanger, shut off the pumps and hold the pressure for 5mins. Bleed pressure back to 500psi. Slack off running string. When the liner is hung off, set down 20,000 lbs DP weight on the hanger. 4. Pressure up the string to 2,100 psi to activate the hydraulic release mechanism of the HNG running tool and bleed off pressure. Pick up the string 3ft past neutral to confirm the running tool is released. 5. Note: If the running tool is not released increase the pressure in 200 psi intervals, bleed to zero and check for release. 6. Should it not be possible to release the running tool with hydraulic pressure, apply left hand torque to shear the emergency release shear screws. A 1/6 th turn to the left at the tool will allow the mandrel to move down under slight compression, allowing the collet to be retracted and locked out in the release position. Straight pick up will now release the HNG from the liner. 7. Shear out the ball seat and note the pressure. Check for returns after shearing. CEMENTING / DISPLACING 1. Before cementing, establish circulation and circulation with limitations. Line up to cementing unit and test lines as required. Pump spacer. 2. Pump cement as per program; flush lines (if required) and release the pump down plug. Ensure the flag sub is set prior to releasing the pump down plug. Flush the bypass channel of the Top Drive Cement Head and displace cement at optimum rate. 3. Slow down the pump to 2-3 bbl/min when 5 bbl before the dart reaches the wiper plug. Note pressure required to release the wiper plug. Increase pump rate back up to optimum rate after the wiper plug is released. 4. Slow down the pumps and stop circulation 2 bbl/min, when 5 bbls before total displacement. Bump the wiper plug with the required pressure to test the liner. Record the bump / test pressure used. 5. NOTE: Use one system only for displacing the cement to remove any doubts about the volume pumped. 6. After testing the liner, bleed off pressure and check for back flow. Note the volume of returns. Rev.4.5, 26 Feb 2016 Page 87

89 Figure 15: Cement Job Simulation Summary for 7 Liner Setting the Packer Pull the string back to position the rotating packer actuator above the top of the PBR. DO NOT EXCEED THE CALCULATED PICK UP DISTANCE BY MORE THAN 3ft. Rotate the string slowly with a stable torque reading. The string will effectively shorten during this operation bringing the actuator dogs further above the PBR. Zero the Vernier on the weight indicator and slack off to set the packer. Watch the weight indicator for positive indications. Do not slack off in excess of 50,000 lbs whilst rotating. If no shears are observed, release torque slowly and continue to slack off to set the packer. Maintain set down weight on liner top packer for a minimum of three minutes. If desirable the packer can be pressure tested by closing the Annular preventer and pressure as required. RETRIEVING THE RUNNING TOOLS AND REVERSE CIRCULATING 1. Continued pick up of the running tools will shear the lock sleeve of the RSM pack-off bushing. An overpull of approximately 4000 lbs is required. Providing the liner wiper plug has been bumped, pressure up the string to 500 psi which will then bleed off when the pack-off bushing is pulled. As soon as the pressure bleeds off begin circulating slowly. It is advisable to pump approximately 10 bbls of mud down the drill Rev.4.5, 26 Feb 2016 Page 88

90 pipe whilst pulling the running tools above the liner top. This will ensure that the liner top will be as clean as possible. 2. Pull back sufficient pipe to place the end of the stinger approximately ft above the top of the PBR. 3. Reverse circulate, rotating the pipe regularly to break up any cement between the pipe and the casing, monitoring the returns to ensure that there are no losses. Do not re-enter the liner top with the tail pipe assembly. 4. POOH EQUIPMENT LIST No Description Provided by Unit 1 Logging Tools Wireline Logging TBD 2 8 1/2 Bit Rig TBD 3 6-3/4 Drilling Motor Directional Drilling TBD 4 8 x 6-3/4 String Stabilizer Rig TBD 5 6-3/4 MWD NMDC Directional Drilling TBD 6 6-3/4 MWD tool Directional Drilling TBD 7 6-3/4 Spiral Drill Collars Rig TBD 8 6-3/4 Jar Rig TBD 9 Rigid Centralizer " OH Rig 10 One Side Beveled Stop Collar, Slip On Rig 11 Polish Bore Receptacle Rig 12 Liner Top Packer Rig 13 Hydraulic-set Rotating Liner Hanger Rig 14 Landing Collar Rig 15 Single Valve Float Collar Rig 16 Single Valve Float Shoe Rig 17 Liner Wiper Plug Rig 18 Drill Pipe Dart Rig 19 Dropping Ball Rig 20 Hydraulically Drive Power Casing Tong Casing running Vendor 2 21 Diesel Powered Hydraulic Unit Casing running Vendor 2 Rev.4.5, 26 Feb 2016 Page 89

91 22 Torque Monitoring System Casing running Vendor 2 23 Side Door Elevator Casing running Vendor 1 24 Hand Slip Casing running Vendor 2 25 Safety Clamp Casing running Vendor 2 26 Thread Protector Casing running Vendor 4 27 Casing Drift Casing running Vendor 2 28 Single Joint Elevator Casing running Vendor 2 29 Stabbing Guide Casing running Vendor 2 Table 26: Equipment List for 8-1/2 Hole Section Rev.4.5, 26 Feb 2016 Page 90

92 15 6 Hole Section [ mmd] 15.1 OPERATIONAL OUTLINE Drilling in the Butmah and Kurra Chine Formations. They are composed of limestone, dolomite, anhydrite, salt, shale and ending in dolomite. Depth: 3700m RKB 4245m RKB 15.2 DRILLING FLUIDS Recommended: Salt Saturated Polymer Mud (or equivalent mud system) Drill out cement & shoe track with small portion of mud from previous interval. Treat with citric acid and sodium bicarbonate for cement contamination. Use the same mud from previous section and weighted to 18.8 ppg SG for this section. Observe cuttings integrity; any indications of wellbore breakout should result in an immediate weight increase. Keep salt saturation in the mud while drilling salt section to prevent washout and caving. Run all solids control equipment available to maintain minimal LGS. Add CaCO 3 fine and medium to the system as bridging material and to prevent differential sticking. Mud Properties Unit Type Density PV YP Salt Saturated Polymer ppg (SG) 18.8 (2.25) cps 6 rpm lbs/10 0 ft 2 Dial Units API Fluid Loss cc/30 min MBT LGS Cl lb/bbl % mg/l >6 <5 <5 <5 >120,000 Table 27: Mud Properties Summary for 6 Hole Section 15.3 BIT, DRILL STRING DESIGN AND HYDRAULICS Bit Size (in) Make 6.0 TBD Type DSFX713M SKRE613S mrkb (MD) 4245m Back up bit R30AP (537) RT2GP (127) Description 1 6 PDC /4 Drilling Motor 5-7/8 x 4-3/4 String Stabilizer 4-3/4 MWD Short NMDC 4-3/4 MWD Short NMDC 17 x 4-3/4 Spiral Drill Collars Connection Gender OD/ID (Bottom/Top) (Bot/Top) (in) (in) Reg Pin Reg Box Reg Box IF Box IF Pin IF Box IF Pin IF Box IF Pin IF Box Length (m) Cum. Length (m) Cum Weight (lbs) IF Pin /4 Jar IF Box Rev.4.5, 26 Feb 2016 Page 91

93 8 3 x 4-3/4 DC 9 40 jts. 3-1/2 HWDP 10 X-O Sub 11 5 G-105, 19.5 lbs/ft Drill Pipe to Surface IF Pin IF Box IF Pin IF Box IF Pin IF Box IF Pin IF Box IF Pin Table 28: Drill String Summary for 6 Hole Section Hole OD (in) Interval (m) TFA (in 2 ) Nozzles (32nds) Flow Rate (gpm) SPP (psi) WOB (klbs) RPM HSI [ ] x 15s Figure 16: Hydraulics Summary for 6 Hole Section Rev.4.5, 26 Feb 2016 Page 92

94 15.4 DRILLING PROCEDURE 1. Install Wear bushing. 2. Make up 6 PDC bit with Motor BHA & RIH as per program. 3. RIH 6 BHA until tag 7 float collar. 4. Drill out 7 float collar, float shoe and 3m of new formation with low flow rate and RPM. 5. Circulate and condition mud as per mud program. The mud weight will be increased from 17.0 ppg to 18.8 ppg (2.04 SG to 2.25 SG) and continue to be salt saturated. Pressures should be expected to change significantly. 6. Perform LOT. 7. POOH 6 BHA into 7 liner shoe track. 8. Rig up cementing lines. 9. Pressure test cementing surface lines according to LOT procedures for 10 minutes. 10. Perform LOT until observed pressure starts to level out (do not let pressure drop). 11. Drill and core as shown in the table below in the 6 hole section to planned well TD, through the following formations: Butmah and Kurra Chine Formations. They are composed of limestone, dolomite, anhydrite, salt, shale and ending in dolomite. Depth: 3700m RKB 4245m RKB The lower Butmah formation is primarily limestone and dolomite. The top of the Kurra Chine formation is a layer of anhydrite, quickly followed by salt. The mud for both the 8-1/2 and the 6 sections is salt saturated to minimize hole enlargement through the salt sections. Below the salt at 4000m is a coring point which is also expected to be a gas show that will be cased hole tested. Keep in mind the two coring points in order to avoid drilling into zones to be cored. Drill ahead in 6 hole until reaching the core points depths as shown in the table below and subject to change as advised by Geologist. Section Drilling Parameters: GPM: 200, RPM: , WOB: For the PDC first and second choice bits, DSFX713M and SKRE613S, WOB can be up 27 klbs. For the third choice roller cone bits, R30AP and the RT2GP, the WOB is klbs. Please note that these parameters may change for the coring BHA. Section Coring Parameters: Refer to the coring program for flow rate, weight on bit and rotation guidelines. Also refer to the coring program for coring bottom hole assembly guidelines. Ream any tight spots until the section is clean prior to making connections. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Rev.4.5, 26 Feb 2016 Page 93

95 Coring Interval (m) Thickness of Cored Interval (m) Age of Depositions Lithology 4,000-4,015 4,240-4, Kurra Chine* Carbonate * In addition to the intervals mentioned above, coring is to be performed in all the intervals with HC shows based on positive evidence from mud logging and other formation evaluation data. Table 29: Interval Coring Plan 6 Section Drilling in Butmah Formation [Limestone, and Dolomite] Depth: 3700m RKB 3745m RKB. 1. The lower Butmah formation is layers of dolomite and limestone. 2. No coring is anticipated in the Butmah formation in the 6 hole section. 3. Assuming a mud weight of 18.8 ppg, the expected flow rate of 200 GPM results in an ECD of 19.7 ppg equivalent, which is within the specified pressure window. 4. The 200 GPM flow rate results in a cuttings transport ratio (CTR) of 95% which is good. 5. The cuttings velocity is 83 feet/minute, which is below the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Drilling in Kurra Chine Formation [Arg. Limestone, Anhydrite] Depth: 3745m RKB 4245m RKB. 1. Kurra Chine formation begins in anhydrite, then salt with thin streaks of shale, followed by layers of anhydrite and limestone, then shale, and ending in dolomite. 2. Coring is anticipated twice in the Kurra Chine formation. The first coring point is from 4000m-4015m and is expected to be a gas show. The second coring point is the last 5m of the drilling program from 4240m-4245m. 3. Assuming a mud weight of 18.8 ppg, the expected flow rate of 200 GPM results in an ECD of 19.7 ppg equivalent, which is within the specified pressure window. 4. The 200 GPM flow rate results in a cuttings transport ratio (CTR) of 95% which is good. 5. The cuttings velocity is 83 feet/minute, which is below the standard industry minimum. Refer to the mud program hole cleaning guidelines if there are any suspected hole problems, especially when approaching coring or casing points. 6. Note pick up and slack off weight of drilling string. Note that this data will be different for the drilling BHA compared to the coring BHA. This data is necessary to understand downhole conditions. Rev.4.5, 26 Feb 2016 Page 94

96 Hole Cleaning & Tripping 1. At section TD, circulate hole clean, monitor shale shakers for returns and condition mud by circulation to get the required mud properties as per program. 2. Perform wiper trip to 7 casing shoe noting any depth of resistance. If required, reduce pump rate in proximity of 7 casing shoe. Repeat wiper trip if required as hole condition dictates. 3. Circulate clean and condition mud as per recommended drilling fluid in the program. 4. Perform flow check prior to POOH. 5. POOH and L/D 6 BHA OPEN HOLE LOGGING Descent 1: Photo Density/Dual Neutron/Micro Resistivity/Dual Lateral/Sonic 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Load Logging R/A Sources (Rig Personnel Clear from Rig Floor) 3. Descend to base of Intermediate casing plus 40m into the open hole below. 4. Log this tool string over the open hole (30m pass) continue with calipers and GR into the casing. 5. Check casing depth, check caliper readings for nominal casing ID, check tension measurement. 6. Adjust caliper measurements as necessary to measure casing internal dimensions before descending. 7. Descend to TD logging down. 8. From TD pull main pass with all measurements up to 30m into casing and verify calipers and Gr tie. 9. Drop back into open hole for a 60m repeat under the casing shoe. 10. Check with well site geologist for approval to POOH and rig down. 11. Unload Logging R/A Sources (Rig Personnel Clear from Rig Floor) 12. Make up field log as per program, deliver to Wellsite Logging Supervisor. Descent 2: VSP 1. Rig up main tool set and perform rig floor operational and diagnostic checks 2. Perform space check-shots while running in hole to TD to verify data quality and Vibro Truck settings 3. A correlation log will be acquired and log put on depth before the VSP program. Rev.4.5, 26 Feb 2016 Page 95

97 4. Start taking VSP surveys according to resolution agreed with WSG up to surface 5. Check with well site geologist for approval to POOH and rig down. 6. Make up field log as per program, deliver to Wellsite Logging Supervisor LINER AND CEMENTING PRE-JOB PREPARATION/CHECKS 1. Check compatibility between liner wiper plugs and casing, and Drill Pipe Wiper Dart with running string tubulars. 2. Install Drill Pipe Wiper Dart and setting ball in the top drive head. Company Representative to be present and witness. Tape up the operating handles to ensure they are not operated until the operation requires it. 3. Drift all running string tubulars to 2 1/2" minimum. 4. Remove any drill pipe protectors on lower 10 stands to reduce risk of cementing in the string. Ensure that any dart sub in the string is removed. 5. If the cement head is to be racked in the derrick please ensure it cannot be damaged and is accessible in the event that the job is delayed. 6. Confirm final well path information to ensure correct TVD versus MD values are used. Note depths of maximum deviations / doglegs. Obtain any relevant information regarding previous tripping such as tight spots, fluid loss problems etc. 7. Discuss and agree with all relevant personnel the figures to be used for displacement calculations. It should be noted that a large amount of pipe today is manufactured close to the minimum API tolerances so the use of nominal ID figures for pipe is not advisable. It is recommended to caliper a sample of the liner joints to give an accurate displacement figure. RUNNING THE LINER 1. Note total number of liner joints and pup joints on the pipe deck. 2. Install float equipment and the required number of casing joints for the shoe tract. Check that float valves are operating correctly. Install Landing Collar as necessary above the float equipment. 3. RIH with liner, filling approximately every 5 joints and fill completely when last joint is in slips. 4. Pick up hanger assembly, install wiper plug system and make up on liner. Start with chain tong. 5. Pick up approximately 3 feet / 1 metre, letting rotary slips ride on liner joint, to check if setting tool and all connections are properly made up. If so pull slips. Rev.4.5, 26 Feb 2016 Page 96

98 6. Note pick up and slack off weight of liner. Pull rotary bushing if the hanger can be damaged going through rotary table. Lower hanger assembly through rotary and set drill pipe slips on the 5" handling pup joint. TO AVOID POSSIBLE DAMAGE, DO NOT SET SLIPS ON THE PBR. Be careful to keep the hanger centered while lowering through rotary table to avoid damage to the assembly. 7. Circulate at least one liner volume to ensure there are no obstructions within the liner system, not exceeding 500 psi. Note the total number of drill pipe stands in the derrick. 8. While circulating the liner contents fill up the PBR with drill water through the junk bonnet 9. When PBR is full, water will discharge from the air outlet hole in the junk bonnet. Stop filling, wait for 2 minutes then top up PBR. plug both inlet and outlet holes and also remove the cap screws/protectors from the side of the junk bonnet 10. Run in hole using back up tong on running string. Put pipe wiper on pipe while running in. Drift pipe if not previously drifted. Ensure that both rabbit and rope handle are recovered each time. Fill drill pipe regularly, to a maximum of 5 stands unfilled. To avoid any pressure surges, do not use a closed system for this operation. 11. Circulate at casing shoe with max 800psi. Take the free moving up and down weight and torques before going into open hole. Have the Field Supervisor on the drill floor before doing any rotating, circulating or setting down weight once the liner is in open hole. Do not exceed running speed more than 5m/min lowering time. 12. When running in open hole fill up each stand as much as possible without interrupting the smooth running of the liner in the hole. In some hole conditions, when running into open hole, it may be desirable to put right hand torque in the string every ft to ensure there is no residual left hand torque at the HNG running tool. 13. Note that if rotation is required to get the liner in the hole, care has to be taken such that when rotation is stopped, the residual torque in the string is released in a controlled manner. The HNG tool s emergency release feature is activated with lefthand torque. 14. Space out drill string to put the cement head +/- 10 ft above rotary table when shoe is on setting depth. Drift all pipe picked up from pipe deck, paying particular attention to pup joints. 15. Pick up and install the cement head. Take the free moving up and down weight. Break circulation and wash down to TD, not exceeding 800 psi. Tag bottom and mark pipe. Pick up to the free moving up weight and measure out to the setting depth. 16. Circulate at setting depth with max 1,000 psi. Rotate and condition hole as required. (Limit torque to cased hole torque at 20 rpm + 80% of optimum liner make up torque, or hanger assembly make-up torque, whichever is less). Circulate at least bottoms up before setting the hanger. Rev.4.5, 26 Feb 2016 Page 97

99 SETTING THE LINER HANGER AND RELEASING THE RUNNING TOOL 1. When circulation is completed, stop rotating and drop the setting ball from the ball releaser in the cement head. Ensure the flag sub is in the up position prior to dropping the ball. 2. Pump the ball down at 2-3 bbl/min with a maximum pressure of 800 psi. The ball should take approximately 2-3 min per 1,000ft to land on its seat. Watch the pressure gauge closely. While pumping the ball down, reconfirm the setting depth by tagging bottom and picking up to full up weight plus 3 metres. Further rotation at this point is not recommended. 3. When the ball lands, slow pumps and increase pressure to 300 psi above that required to set the liner hanger, shut off the pumps and hold the pressure for 5 min. Bleed pressure back to 500 psi. Slack off running string. When the liner is hung off, set down 20,000 lbs DP weight on the hanger. 4. Pressure up the string to 2,100 psi to activate the hydraulic release mechanism of the HNG running tool and bleed off pressure. Pick up the string 3 ft past neutral to confirm the running tool is released. Note: If the running tool is not released increase the pressure in 200 psi intervals, bleed to zero and check for release. 5. Should it not be possible to release the running tool with hydraulic pressure, apply left hand torque to shear the emergency release shear screws. A 1/6 th turn to the left at the tool will allow the mandrel to move down under slight compression, allowing the collet to be retracted and locked out in the release position. Straight pick up will now release the HNG from the liner. 6. Shear out the ball seat and note the pressure. Check for returns after shearing. CEMENTING / DISPLACING 1. Before cementing, establish circulation and circulation with limitations. Line up to cementing unit and test lines as required. Pump spacer. 2. Pump cement as per program, flush lines (if required) and release the pump down plug. Ensure the flag sub is set prior to releasing the pump down plug. Flush the bypass channel of the Top Drive Cement Head and displace cement at optimum rate. 3. Slow down the pump to 2-3 bbl/min when 5 bbls before the dart reaches the wiper plug. Note pressure required to release the wiper plug. Increase pump rate back up to optimum rate after the wiper plug is released. 4. Slow down the pumps and stop circulation 2 bbls/min when 5 bbls before total displacement. Bump the wiper plug with the required pressure to test the liner. Record the bump / test pressure used. NOTE: Use one system only for displacing the cement to remove any doubts about the volume pumped. 5. After testing the liner, bleed off pressure and check for back flow. Note the volume of returns. Rev.4.5, 26 Feb 2016 Page 98

100 Setting the Packer Figure 17: Cement Job Simulation Summary for 4-1/2 Liner 1. Pull the string back to position the rotating packer actuator above the top of the PBR. DO NOT EXCEED THE CALCULATED PICK UP DISTANCE BY MORE THAN 3ft. Rotate the string slowly with a stable torque reading. The string will effectively shorten during this operation bringing the actuator dogs further above the PBR. Zero the Vernier on the weight indicator and slack off to set the packer. Watch the weight indicator for positive indications. Do not slack off in excess of 50,000 lbs whilst rotating. If no shears are observed, release torque slowly and continue to slack off to set the packer. Maintain set down weight on liner top packer for a minimum of three minutes. 2. If desirable the packer can be pressure tested by closing the Annular preventer and pressure as required. RETRIEVING THE RUNNING TOOLS AND REVERSE CIRCULATING 1. Continued pick up of the running tools will shear the lock sleeve of the RSM pack-off bushing. An overpull of approximately 4000 lbs is required. Providing the liner wiper plug has been bumped, pressure up the string to 500 psi which will then bleed off when the pack-off bushing is pulled. As soon as the pressure bleeds off begin circulating slowly. It is advisable to pump approximately 10 bbls of mud down the drill pipe whilst pulling the running tools above the liner top. This will ensure that the liner top will be as clean as possible. 2. Pull back sufficient pipe to place the end of the stinger approximately ft above the top of the PBR. Rev.4.5, 26 Feb 2016 Page 99

101 3. Reverse circulate, rotating the pipe regularly to break up any cement between the pipe and the casing, monitoring the returns to ensure that there are no losses. Do not re-enter the liner top with the tail pipe assembly. 4. POOH EQUIPMENT LIST No Description Provided by Unit 1 Logging Tools Wireline Logging TBD 2 6 PDC Bit Vendor TBD 3 4-3/4 Drilling Motor Directional Drilling TBD 4 5-7/8 x 4-3/4 String Stabilizer Rig TBD 5 4-3/4 MWD Short NMDC Directional Drilling TBD 6 4-3/4 MWD Tool Directional Drilling TBD 8 4-3/4 Spiral Drill Collars Rig TBD 9 4-3/4 Jar Rig TBD 10 Rigid Centralizer " OH Rig 11 One Side Beveled Stop Collar, Slip On Rig 12 Polish Bore Receptacle Rig 13 Liner Top Packer Rig 14 Hydraulic-set Rotating Liner Hanger Rig 15 Landing Collar Rig 16 Single Valve Float Collar Rig 17 Single Valve Float Shoe Rig 18 Liner Wiper Plug Rig 19 Drill Pipe Dart Rig 20 Dropping Ball Rig Table 30: Equipment List for 6 Hole Section Rev.4.5, 26 Feb 2016 Page 100

102 16 Cement Plug and Abandon 16.1 SCHEMATIC Tree Cap SV KV PWV X-mas tree MV Wellhead CMT Plug #10 CMT Retainer CMT Plug #9 CMT Retainer A B Crossflow barrier EAC Verification / Monitoring Cement plug m MD if set on a mechanical Initial pressure test 1000 psi above LOT or FIT plug as foundation Tagging & evaluation of job execution & samples Primary barrier EAC Verification / Monitoring 51 Pressure Integrity Test In-situ formation Leak-Off Test Cemented casing shoe Bonding Log m verified by calculations or if 30 m verified by Casing cement bonding log inside the liner lap - centralized 2 Tested to a maximum diff. pressure 20" csg Casing No testind during cement setting up Cement plug m MD if set on a mechanical Initial pressure test 1000 psi above LOT or FIT plug as fundation Tagging & evaluation of job execution & samples 7 Leak test to the maximum differential pressure 13 ⅜" csg Bridge Plug (Max. formation pressure minus brine hydrostatic) Secondary barrier EAC Verification / Monitoring 51 Pressure Integrity Test In-situ formation Leak-Off Test Cemented casing shoe Bonding log Msa'ad Casing cement (13 ⅜") m verified by calculations or if 30 m verified by bonding log inside the liner lap - centralized Casing cement (9 ⅝") m verified by calculations or if 30 m verified by bonding log inside the liner lap - centralized Nah Umr Production casing (9 ⅝") 2 Tested to a maximum diff. pressure (Above liner hanger packer) No testind during cement setting up 5 CMT Plug #8 Production casing hanger with Periodic leak testing CMT Retainer seal assembly Periodic monitoring of B-annulus Zubair Wellhead 12 Periodic leak testing (annulus valve) Periodic monitoring of B-annulus CMT Plug #7 Tubing hanger 10 Periodic leak testing CMT Retainer (body seals & neck seals) Continuous pressure monitoring of A-annulus Ratawi CMT Plug #6 CMT Retainer Liner Top 9-7/8" csg Najmah NOTE: Refer to NORSOK D-010 r4 for complete breakdown on (well barrier) element acceptance criteria (EAC) CMT Plug #5 CMT Retainer Sargelu CMT Plug #4 CMT Retainer Mus CMT Plug #3 CMT Retainer Butmah CMT Plug #2 Bridge Plug CMT Plug #1 CMT Retainer Liner Top NOTES: 7" lnr NORSOK D-010 standards requires 2 barriers for: d) Hydrocarbon bearing formations. e) Abnormally pressured formation with potential to flow to surface. Kurra Chine 4 ½" lnr Figure 18: Well Barrier Schematic for P&A Rev.4.5, 26 Feb 2016 Page 101

103 16.2 PROCEDURES After each targeted formation is production tested, the perforations will be squeeze cemented through a Cement Retainer, a minimum of 50 meters of cement will be dumped on top of the retainer, and the next formation uphole will be perforated and production tested. These alternating Well Test / Plug and Abandonment steps will be continued until all formations have been Tested and Plugged and Abandoned. The Plug and Abandon procedures will adhere to the NORSOK D-10, Revision 4 Standard. NOTE: The following Plug and Abandonment Procedure is based on the assumption that all identified formations are potential sources of inflow as defined on NORSOK D-010, Rev. 4, (according to the Openhole Logging and Formation Testing performed during the drilling operations). Actual formations, depths, etc., will be presented based on actual well conditions. NOTE: The well will be filled up with drilling mud as defined on the drilling program for each corresponding section before setting the plugs ensuring the plug and abandonment procedures are conducted on overbalance conditions. 1. Test the Kurra Chine Formation (4,000 4,015 m MD perforated interval), as per the Well Test Procedure. 2. Pick up work string and RIH with 3-3/4 inch bit and 4-1/2 inch, 16.6 lb/ft inch casing scraper and scrape the liner through the perforations. Circulate hole clean. 3. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 4. Run Gauge Ring and Junk Basket to top of the perforations. 5. Run and set 4-1/2 inch, 16.6 lb/ft Cement Retainer. Set the Cement Retainer at 3,998 m MD (2 m above the top perforation). POOH with WL. Rig down Wireline. 6. Run Cement stinger on work string. Sting into Cement Retainer. Pressure test Retainer by pressuring the annulus to 1,000 psi + LOT (Next casing shoe). 7. Rig up Cementing Unit. Establish injection rate into existing perforations. Record injection rate and pressure. 8. Squeeze the perforations to 900 psi above initial injection pressure, leaving the 4-1/2 in. liner filled with cement. 9. Sting out of retainer and spot 4 bbl of cement (89.2 m) on top of Cement Retainer. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string (CMT Plug #1 on well barrier schematic). 10. POOH with work string and stinger. 11. RIH with 3-3/4 in. bit and scraper on work string to top of cement. Dress cement off to 3,943 m MD (+/-55 m above the Retainer). Circulate the hole clean. Negative test the cement plug to insure proper isolation [1,000 psi + LOT (next casing shoe) differential)]. Isolating the Top of the 4-1/2 inch, 16.6 lb/ft Liner (TOL at 3,550 m MD) 12. RIH with 6 in. bit and 7 inch casing scraper and scrape the well to top of the 4-1/2 in. liner at 3,550 m MD. Circulate hole clean. 13. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 14. Run Gauge Ring and Junk Basket to top of 4-1/2 in. liner Rev.4.5, 26 Feb 2016 Page 102

104 15. Run a 7 inch, 32 lb/ft Bridge Plug. Tag the top of the liner; pick up 2 m and set Bridge Plug at +/- 3,548 m MD - directly above the 4-1/2 in. liner top (top of liner at 3,550 m). POOH with WL. Rig down Wireline. 16. Run Cement stinger on work string. Pressure test Bridge Plug by pressuring up to 1,000 psi + LOT (next casing shoe). 17. Spot 7 bbl (59.1 m) of cement on top of Bridge Plug. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string (CMT Plug #2 on well barrier schematic). 18. RIH with 6 inch bit and 7 inch scraper on work string to top of cement. Dress cement off to 3,498 m MD (+/-50 m above the Bridge Plug). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). 19. Test the Butmah Formation (3,430 3,445 m MD perforated interval), as per the Well Test Procedure. 20. Pick up work string and RIH with 6 in. bit and 7 inch casing scraper and scrape the liner through the perforations. Circulate hole clean. 21. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 22. Run Gauge Ring and Junk Basket to the top perforation 23. Run 7 inch, 32 lb/ft Cement Retainer. Set the Retainer at 3,428 m MD (top perforation at 3,430 m). POOH with WL. Rig down Wireline. 24. Run Cement stinger on work string. Sting into Cement Retainer. Pressure test Retainer by pressuring the annulus to 1,000 psi + LOT (next casing shoe). 25. Rig up Cementing Unit. Establish injection rate into existing perforations. Record injection rate and pressure. 26. Squeeze the perforations to 900 psi above initial injection pressure, leaving the 7 in. liner filled with cement. 27. Sting out of retainer and spot 7 bbl (59.1 m) of cement on top of Cement Retainer. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string (CMT Plug #3 on well barrier schematic). 28. POOH with work string and stinger. 29. RIH with 6 in. bit and 7 inch scraper on work string to top of cement. Dress cement off to 3,373 m MD (+/-55 m above the Retainer). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). 30. Move up hole and test the Mus Formation (3,105 3,125 m MD perforated interval), as per the Well Test Procedure 31. RIH with 6 in. bit and 7 inch casing scraper on work string and scrape the well through the perforations. Circulate hole clean. 32. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 33. Run Gauge Ring and Junk Basket to top of the perforations 34. Run 7 inch, 32 lb/ft Cement Retainer. Set retainer at 3,103 m MD - 2 m above the perforations. POOH with WL. Rig down Wireline. 35. Run Cement stinger on work string. Sting into Cement Retainer. Pressure test retainer by pressuring the annulus to 1,000 psi + LOT (next casing shoe). 36. Rig up Cementing Unit. Establish injection rate into existing perforations. Record injection rate and pressure. 37. Squeeze the perforations to 900 psi above initial injection pressure. Rev.4.5, 26 Feb 2016 Page 103

105 38. Sting out of retainer and spot 8 bbl (67.6 m) of cement on top of Cement Retainer. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string (CMT Plug #4 on well barrier schematic). 39. POOH with work string and stinger. 40. RIH with 6 in. bit and 7 inch scraper on work string to top of cement. Dress cement off to 3,043 m MD (+/-60 m above the Retainer). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). 41. Move up hole and test the Sargelu Formation (2,890 2,910 m MD perforated interval), as per the Well Test Procedure. 42. Repeat steps 31 through 40 - With the following changes: Set Retainer at 2,888 m MD and dress off the cement plug to 2,828 m MD (CMT Plug #5 on well barrier schematic). Squeezing the Najmah Perforations and Isolating the Top of the 7 inch, 32 lb/ft Liner (TOL at 2,300 m MD) 43. Move uphole and test the Najmah Formation (2,460 2,480 m MD perforated interval) as per the Well Test Procedure. 44. Pick up work string and RIH with 8-1/2 inch bit and 9-7/8 inch casing scraper and scrape the well to top of the 7 in. liner at 2,300 m MD. Circulate hole clean. 45. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 46. Run Gauge Ring and Junk Basket to top of 7 in. liner 47. Run 9-7/8 inch 66.4 lb/ft Cement Retainer. Tag the top of the liner, set Retainer at 2,298 m MD 2 m above the 7 in. liner top (top of liner at 2,300 m). POOH with WL. Rig down Wireline. 48. Run Cement stinger on work string. Sting into Cement Retainer. Pressure test retainer by pressuring the annulus to 1,000 psi + LOT (next casing shoe). 49. Rig up Cementing Unit. Establish injection rate into existing perforations. Record injection rate and pressure. 50. Squeeze the perforations to 900 psi above initial injection pressure, leaving the 7 in. liner filled with cement. 51. Sting out of retainer and spot 14 bbl (60.0 m) of cement on top of Cement Retainer. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string (CMT Plug #6 on well barrier schematic). 52. POOH with work string and stinger. 53. RIH with 8-1/2 in. bit and 9-7/8 inch scraper on work string to top of cement. Dress cement off to 2,248 m MD (+/-50 m above the Retainer). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). 54. Move up hole and test the Ratawi Formation (2,045 2,105 m MD perforated interval), as per the Well Test Procedure. 55. Pick up work string and RIH with 8-1/2 inch bit and 9-7/8 inch casing scraper and scrape the well through the perforations. Circulate hole clean. 56. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 57. Run Gauge Ring and Junk Basket to the top perforation. 58. Run 9-7/8 inch 66.4 lb/ft Cement Retainer. Set retainer at 2,043 m MD - 2 m above the perforations. POOH with WL. Rig down Wireline. 59. Run Cement stinger on work string. Sting into Cement Retainer. Pressure test retainer by pressuring the annulus to 1,000 psi + LOT (next casing shoe). Rev.4.5, 26 Feb 2016 Page 104

106 60. Rig up Cementing Unit. Establish injection rate into existing perforations. Record injection rate and pressure. 61. Squeeze the perforations to 900 psi above initial injection pressure. 62. Sting out of retainer and spot 25 bbl (107.2 m) of cement on top of Cement Retainer. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string (CMT Plug #7 on well barrier schematic). 63. POOH with work string and stinger. 64. RIH with 8-1/2 in. bit and 9-7/8 in. scraper on work string to top of cement. Dress cement off to 1,943 m MD (+/-100 m above the Retainer). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). 65. Move up hole and test the Zubair Formation (1,735 1,765 m MD perforated interval), as per Well Test Procedure. 66. Repeat Steps 55 through 64 - With the following changes: Set Retainer at 1,733 m MD, pump 20 bbl (85.8m) cement on top of the cement retainer and dress off the cement plug to 1,663 m MD (CMT Plug #8 on well barrier schematic). 67. Move up hole and test the Nahr Umr Formation (1,580 1,620 m MD perforated interval). 68. Repeat Steps 55 through 64 - With the following changes: Set Retainer at 1,578 m MD, pump 20 bbl (85.8m) cement on top of the cement retainer and dress off the cement plug to 1,498 m MD (CMT Plug #9 on well barrier schematic). 69. Move up hole and test the Msa ad Formation (1,320 1,350 m MD perforated interval). 70. Repeat Steps 55 through 64 - With the following changes: Set Retainer at 1,318 m MD, pump 25 bbl (107.2m) cement on top of the cement retainer and dress off the cement plug to 1,218 m MD (CMT Plug #10 on well barrier schematic). NOTE: NORSOK allows for cement plug testing via tagging if the mechanical support (cement retainer) was pressure tested to LOT+1000 psi. Cement plug testing should not exceed casing differential pressure rating P&A PROCEDURE IF NO FORMATIONS ARE CASED-HOLE PRODUCTION TESTED If preliminary Formation Evaluation Analysis Results demonstrates no need to perform Cased Hole Production Testing on any of the penetrated formations, the Plug and Abandonment Procedure will be modified as follows: A. The 4-1/2 inch liner will not be run and set. The 6-1/2 inch open hole will be isolated by setting a 7 inch Bridge Plug near the 7 inch liner shoe, pressure testing the Bridge Plug, and spotting a 50-meter cement plug on top of the Bridge Plug (as per the NORSOK D-10, Revision 4 Standard). B. The 7 inch liner will be isolated by setting a 9-7/8 inch Bridge Plug 2 meters above the top of the 7 inch liner, pressure testing the Bridge Plug, and spotting a 50-meter cement on top of the Bridge Plug. Isolating the 6-1/2 inch Open Hole (3,700 4,245 m MD) 1. RIH with 6 inch bit and 7 inch casing scraper and scrape the well to 3,650 m MD. Circulate hole clean. 2. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 3. Run Gauge Ring and Junk Basket to top of 4-1/2 in. liner Rev.4.5, 26 Feb 2016 Page 105

107 4. Run a 7 inch, 32 lb/ft Bridge Plug. Set Bridge Plug at +/- 3,645 m MD. POOH with WL. Rig down Wireline. 5. Run Cement stinger on work string. Pressure test Bridge Plug by pressuring up to 1,000 psi + LOT (next casing shoe). 6. Spot 7 bbl (59.1 m) of cement on top of Bridge Plug. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string. 7. RIH with 6 inch bit and 7 inch scraper on work string to top of cement. Dress cement off to 3,595 m MD (+/-50 m above the Bridge Plug). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). Isolating the Top of the 7 inch, 32 lb/ft Liner (TOL at 2,300 m MD) 8. Pick up work string and RIH with 8-1/2 inch bit and 9-7/8 inch casing scraper and scrape the well to top of the 7 in. liner at 2,300 m MD. Circulate hole clean. 9. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 10. Run Gauge Ring and Junk Basket to top of 7 in. liner 11. Run 9-7/8 inch 66.4 lb/ft Bridge Plug. Tag the top of the liner, set Bridge Plug at 2,298 m MD 2 m above the 7 in. liner top (top of liner at 2,300 m). POOH with WL. Rig down Wireline. 12. Run Cement stinger on work string. Pressure test Bridge Plug by pressuring the annulus to 1,000 psi + LOT (next casing shoe). 13. Spot 14 bbl (60.3 m) of cement on top of Bridge Plug. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string. 14. POOH with work string and stinger. 15. RIH with 8-1/2 in. bit and 9-7/8 inch scraper on work string to top of cement. Dress cement off to 2,268 m MD (+/-50 m above the Bridge Plug). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). Setting an Isolation Plug above the Uppermost Formation in the 9-7/8 inch Casing 16. Pick up work string and RIH with 8-1/2 inch bit and 9-7/8 inch casing scraper and scrape the well to 1,350 m MD. Circulate hole clean. 17. Rig up WL lubricator and test same to 11,500 psi (which is the calculated maximum expected wellhead pressure, rounded up to the next 500 psi, and this value will be updated based on the well testing results). 18. Run Gauge Ring and Junk Basket to 1,325 m MD. 19. Run 9-7/8 inch 66.4 lb/ft Bridge Plug. Tag the top of the liner, set Bridge Plug at 1,320 m MD. POOH with WL. Rig down Wireline. 20. Run Cement stinger on work string. Pressure test Bridge Plug by pressuring the annulus to 1,000 psi + LOT (next casing shoe). 21. Spot 14 bbl (60.3 m) of cement on top of Bridge Plug. Pull 3 stands and reverse circulate 2 work string volumes to circulate excess cement out of work string. 22. POOH with work string and stinger. 23. RIH with 8-1/2 in. bit and 9-7/8 inch scraper on work string to top of cement. Dress cement off to 1,270 m MD (+/-50 m above the Bridge Plug). Circulate the hole clean. Negative test the cement plug to insure proper isolation (1,000 psi + LOT (next casing shoe) differential). Rev.4.5, 26 Feb 2016 Page 106

108 17 HSE It is Bashneft s expectation and requirement that each service provider selected has in place the people, processes, systems and culture to work safely. In cases where it is discovered there is a conflict between the respective safety management systems of any of the companies involved it should be brought to the attention of the appropriate supervisors immediately. During project execution, all involved parties and contractors must comply with HSE program in accordance of the policies from Bashneft and the general contractor. It is critical that hazards specific to the operation are identified, the associated risks assessed and risk reduction measures put in place to ensure that risks are kept to as low as reasonably practicable (ALARP). The overall process as to how this is achieved encompasses various techniques. This section provides important considerations when forming the basis of an interface document to be utilized for this project. The following points should always be clearly communicated throughout the operation: Everyone is a safety leader and empowered to stop an unsafe act. Intervention is critical to a safe work place. Clear and continuous communication is essential. Target ZERO recordable injuries and environmental incidents EMERGENCY RESPONSE The purpose of developing a standard is to provide minimum requirements to ensure all work site personnel are suitably prepared to manage emergencies and business crisis situations. A site specific risk assessment of known, assumed or potential risks to the premises or personnel, using a Hazard Identification and Risk Assessment process, historical information and other data should be completed to develop a site specific Emergency Response Plan (ERP). The ERP shall incorporate any scenarios identified in the Risk Assessment with residual potential risk ratings of High or Severe (as per Operator s risk matrix). The work site should nominate or assign a team of work site dedicated responders with specific and documented roles and responsibilities for all members. The team should, at minimum, consist of a Person in Charge and alternate, QHSSE representative, fire warden(s), spill responders, a first aid responder and two alternate members. All employees must be trained on the site specific ERP to include any responsibilities, accountabilities and authorities. All work sites shall plan, schedule and conduct drills to reinforce the requirements of the ERP with all personnel at the work site. An emergency response drill intended to test or reinforce knowledge of the plan; process and personnel shall be conducted and documented FIRE PREVENTION AND PROTECTION The purpose of developing a standard is to provide the minimum requirements for identification and implementation of controls to prevent potential fire events. The location (to include contractors) shall conduct a comprehensive fire risk assessment to identify high risk areas with the potential to cause a fire event in order to implement the controls required to eliminate or reduce the risk to ALARP. Controls shall be developed and applied to eliminate or mitigate the hazards associated with potential fire events. Some examples include: Electrical equipment used to generate or provide light, heat or power shall meet regulatory requirements and local codes, as required. Rev.4.5, 26 Feb 2016 Page 107

109 The exhaust of internal combustion powered equipment shall be located well away from combustible materials. Work site shall establish designated smoking areas, with suitable signage, and enforce their use. Fire suppression and extinguishing equipment shall be put in place for areas with potential sources of ignition and/or sources of fuel. All firefighting protection equipment and emergency lighting shall be maintained in safe operating condition. The location, quantity and type of portable fire extinguishers shall be based on the location specific risk assessment. Work site shall have sufficient emergency exits to enable all personnel to safely evacuate the workplace in case of emergency. The alarm system shall be capable of being recognized above ambient noise by all employees in the affected portions of the workplace. Visual devices may be used to alert those employees who would not otherwise be able to recognize the audible alarm ENVIRONMENTAL PROTECTION The purpose of developing a standard is to provide the minimum requirements for identification and implementation of controls to prevent potential environmental hazards. All personnel are expected to comply with any and all regulatory and Operator requirements with regards to environmental stewardship. Operations shall be governed by sound environmental planning, use of appropriate control mechanisms and proper employee training. Some important points to be considered for the Block 12 drilling operation include: Fresh water resources and artesian water formations should be drilled with environment friendly drilling mud, isolated with casing and cemented to surface. Surface hole section will be drilled to ±195m, which is below water resources, and cemented to surface. Drilling with mud losses across water resources intervals is not acceptable and special drilling techniques should be implemented. Ensure waste is disposed of safely and in accordance with all Operator and legal requirements make sure hazardous materials and waste are correctly marked and properly stored with appropriate secondary containment. Permits for storage areas may need to be obtained where regulatory requirements exist. Storage areas, including those for waste, shall be marked with signs showing the type of materials permitted to be stored along with any hazardous characteristics, and configured to allow easy access by personnel and service equipment. At a minimum, storage areas should be located at least 4.5m (15 ft) from property line (lease boundary). Storage locations shall have easy access to fire extinguisher (for the type of material being stored), spill kit (designed for the volume and type of material stored, and have correct PPE worn by personnel in the area. All involved parties and contractors shall have the spill response plan and must be in compliance with it. Any spill, no matter how minor it appears to be, should be cleaned up with the implemented spill response plan and reported. It is important to complete pretask hazard assessments, have contingency spill control equipment (booms, pads, sorbent, etc.) available at every work location for use in the event of an incident. Rev.4.5, 26 Feb 2016 Page 108

110 17.4 PERSONNEL SAFETY The purpose of developing a standard is to provide the minimum requirements for identification and implementation of controls to prevent potential illness or injury. The drilling location shall include trained medical personnel to deal with any health issues. In the event of any medical injury or illness, immediately contact the medic. All personnel must conduct themselves appropriately as unruly behaviour is not acceptable. Persons participating in 'horseplay', fighting or abusive behaviour may be suspended from work or have their employment terminated. The use of intoxicants, including alcohol and "unlawful drugs" or the wilful abuse of non-prescription or prescription medications at the well site and in camp is strictly prohibited. It is each individual s responsibility to ensure that they are wearing the appropriate personal protective equipment (PPE) and to follow safety guidelines supplied by the drilling contractor. To ensure that each individual is provided with and uses correct PPE, each supervisor (crane operator, driller, mud logger supervisor, etc.) should ensure that each individual working directly for the supervisor has all appropriate PPE in his/her possession. A safety orientation must be completed by all site personnel upon arrival. During this time, the site layout (as discussed in Section 12.7 of this document) shall be reviewed and all site regulations and policies shall be discussed, including the Medevac Plan. All contractors shall be provided the Medevac Plan before commencement of drilling operations, taking into account appropriate governmental, municipal, and contractor HSE requirements. Bashneft has provided Minimum Standard Requirements for Security and further details can be found in Appendix 9. Management of Change (MOC) Work arising from temporary and permanent changes to organization, personnel, systems, process, procedures, equipment, products, materials or substances, and laws and regulations cannot proceed unless a Management of Change process is completed, where applicable, to include: a risk assessment conducted by all impacted by the change development of a work plan that clearly specifies the timescale for the change and any control measures to be implemented regarding: o equipment, facilities and process; o operations, maintenance, inspection procedures; o training, personnel and communication; o documentation. authorization of the work plan by the responsible person(s) through completion Personal Protective Equipment (PPE) PPE designed to minimize the hazards encountered by well construction operations while performing certain specific tasks and /or operating certain specific equipment. Body protection: Full body coverage shall include long sleeves only. No short sleeves allowed Loose clothes that can be caught in moving machinery must not be worn Rain suits shall be provided in case of rain, use of oil-based mud or use of completion fluids Rev.4.5, 26 Feb 2016 Page 109

111 Flame resistant coveralls Head Protection: Hard hats shall be worn by all personnel at all times in the specified areas, and outside accommodations and offices Hard hats shall be fitted with a chin-strap, while working aloft, or in windy areas Hard hats should be designed to accommodate earmuffs or face shields Hard hats shall be made of non-conductive material Eye Protection: Safety goggles shall be worn when chipping, grinding, hammering, cutting wireline, changing tong dies, scraping paint, mixing chemicals, and for any other activity which may result in a foreign body in the eye In addition to the safety goggles, a face shield shall be worn when handling corrosive or harmful products (solids or liquids) Welding helmet or hand-held shield shall be used when performing arc-welding Welding goggles shall be worn when using a cutting torch Except when required above, safety glasses shall be worn by all personnel in specified areas and when outside accommodations and offices Eye wash stations should be available at least in the following areas: rig floor, mud pit room, mud mixing area and shale shaker area. Hand Protection: Dielectric gloves shall be used by the Electrician and shall be stored in a known location Barrier cream shall be used personnel working with oil-based muds and completion fluids Foot Protection: Safety boots or safety shoes shall be worn by all personnel at all times in specified areas and outside accommodations and offices Neoprene safety boots or over boots shall be worn for chemical protection when handling caustic or corrosive products. Respiratory Protection: All personnel on location, who may have to use breathing apparatus, shall be clean shaven Whenever there is a risk to encounter an atmosphere immediately dangerous to health, a SCBA positive pressure type, shall be worn. Anti-fall devices: The anti-fall device shall be certified as per manufacturer's instructions The system shall be able to stop the person's free fall within 0.6 meters (2 feet). Hearing Protection: As a rule of thumb, hearing protection should be used when excessive noise causes the individual discomfort or prevents the hearing of a conversational voice at one metre. Rev.4.5, 26 Feb 2016 Page 110

112 The chart below summarizes standard PPE requirements. Figure 19: PPE Matrix Permit to Work Before conducting work that involves confined space entry, work on energy systems, ground disturbance in locations where buried hazards may exist, or hot work in potentially explosive environments, a permit must be obtained that: defines scope of work; identifies hazards and assesses risks; establishes control measures to eliminate or mitigate hazards; links the work to other associated work permits or simultaneous operations; is authorized by the responsible person(s); communicates above information to all involved in the work; ensures adequate control over the return to normal operations. Energy Isolation Any isolation of energy systems; mechanical, electrical, process, hydraulic and others, cannot proceed unless: the method of isolation and discharge of stored energy are agreed and executed by a competent person(s); any stored energy is discharged; a system of locks and tags is utilized at isolation points; a test is conducted to ensure the isolation is effective; isolation effectiveness is periodically monitored. Ground Disturbance Work that involves a manmade cut, cavity, trench or depression in the earth s surface formed by earth removal cannot proceed unless: a hazard assessment of the work site is completed by the competent person(s); all underground hazards (i.e., pipelines, electric cables, etc., have been identified, located and if necessary, isolated). Rev.4.5, 26 Feb 2016 Page 111

113 Confined Space Entry Entry into any confined space cannot proceed unless: all other options have been ruled out; permit is issued with authorization by a responsible person(s); permit is communicated to all affected personnel and posted, as required; all persons involved are competent to do the work; all sources of energy affecting the space have been isolated; testing of atmospheres is conducted, verified and repeated as often as defined by the risk assessment; stand-by person is stationed; unauthorized entry is prevented. Lifting Operations Lifts utilizing cranes, hoists, or other mechanical lifting devices will not commence unless: an assessment of the lift has been completed and the lift method and equipment has been determined by a competent person(s); operators of powered, lifting devices are trained and certified for that equipment; rigging of the load is carried out by a competent person(s); lifting devices and equipment has been certified for use within the last 12 months (at a minimum); load does not exceed dynamic and/or static capacities of the lifting equipment; any safety devices installed on lifting equipment are operational; all lifting equipment visually examined before each lift by a competent person(s). Equipment Maintenance All contractors must have a comprehensive plan for maintenance of supplied equipment and shall follow this plan according to the requirements. Driving Safety All categories of vehicle, including self-propelled mobile plant, must not be operated unless: the vehicle is fit for purpose, inspected and confirmed to be in safe working order; number of passenger does not exceed manufacturer s design specification for the vehicle; loads are secure and do not exceed manufacture s design specifications or legal limits for the vehicle; seat belts are installed and worn by all occupants; Drivers must not be authorized to operate the vehicle unless: they are trained, certified and medically fit to operate the class of vehicle; they are not under the influence of alcohol or drugs, and are not suffering from fatigue; they do not use hand-held cell/mobile phones and radios while driving; Effective Journey Management Plan is implemented. Rev.4.5, 26 Feb 2016 Page 112

114 17.5 H 2 S AND CO 2 Formation fluid (particularly crude oil) can contain H2S or CO 2 gas throughout the entire borehole. During drilling, there is potential to reach higher concentration at surface; high-level attention is needed to all sensors. Higher concentration can occur during well test operation, especially around the storage tank(s). Elevated concentrations of H2S are possible in Hartha, Mishrif, Nahr Umr, Yamama, Gotnia, and Najmah formations, but presence may appear in all reservoirs. Mud logging unit has to monitor both of these gas contents continuously, from spud Operator regulations for work in a possibly H2S and CO2 contaminated environment shall be followed. Special care has to be taken when drilling the above detailed formations, circulating bottoms up after tripping, conducting DST, recovering cores, carrying out well killing, opening previously shut-in drill/test string and annuli, working in the cellar or tanks, etc. Appropriate safety systems must be installed before drilling the hole sections where H 2 S and CO 2 are suspected. Well site shall be equipped with monitoring system consisting of at least three sensors, one in the cellar, one on the drilling floor and one at the shakers as a recommendation. Each sensor shall be able to initiate the alarm separately. Site drills should be routinely undertaken to keep personnel on alert and maintain competent understanding of the response plan. H 2 S Detection in Mud and Treatment Methods Monitor drilling fluid daily with the Garrett Gas Train (GGT) to measure presence of the gas and its concentration and record on Daily Mud Report Maintain H 2 S scavenger in the mud at all times; a sudden change in ph is a strong indicator. Ensure that any mud being sent for storage that has been exposed to H 2 S has been well vented and treated to remove any residual gas this is more of a risk with OBM but as a precaution will apply to WBM which will be recycled as well. Zinc Chelate will effectively scavenge all forms of sulphide present in the water base system. Zinc Chelate provides a water soluble form of Zinc over a wide ph range: The Zinc ion is loosely bonded in the Chelate and is readily available to react with Sulfide in the mud It does not have an adverse effect on mud properties (as Zinc Carbonate does) It does not settle out in brines or low carrying capacity fluids Treatment rate at 1 10 kg/m 3. 3 kg/m 3 Zinc Chelate will remove 200 ppm Sulfide. Determine the concentration of Sulfides with the GGT and add the required concentration of Zinc Chelate to the mud. All respiratory protection shall be certified/approved in accordance with local legislative or regulatory standards. The breathing apparatus (BA) sets, escape equipment and portable measuring devices shall be kept in proper working condition at the designated areas and their inspection and calibration has to be organized on a daily basis. The windsock has to be visible from the whole rig site; bug blowers should be on site. Safety supervision, performed by qualified personnel at rig site, is recommended to install, commission and maintain the H 2 S safety equipment, train rig personnel and service companies on H 2 S emergency procedures and use of the H 2 S safety equipment and to assist contractor person in charge in carrying out the H 2 S safety plan. Rev.4.5, 26 Feb 2016 Page 113

115 Figure 20: H 2 S Toxicity Levels 17.6 INDUCTION All personnel must report to the site manager upon arrival at rig site. This applies to both visitors and personnel attending to perform work operations. If it is the individual s first visit to this specific rig, an induction is required and will be provided. The induction will be provided by the drilling contractor. All personnel should familiarize themselves with the muster and evacuation procedure, the location of the muster point(s) and first aid station(s). All personnel who stay at the camp should be given an additional camp induction by the camp supervisor TRAINING All personnel related to the drilling operation should have, as a minimum, training certification for the following: H2S Basic fire fighting Drilling Supervisors, Tool pushers, Drillers and Assistants needs to have up to date IWCF certifications. Pre-spud and site specific training plans should be created for non-routine tasks or technologies being implemented to the drilling plan so that associated personnel are aware of the implementation process and potential hazards COMMUNICATION Multinational drilling crew is likely to be on the location. Communication difficulties are possible. All managing efforts are necessary to avoid misunderstanding, serious failures, incidents, accidents. Staff meetings should be held more frequently if necessary as long as each member of the crew understands clearly and satisfying his actual function and task. In case of any uncertain situation (with complete well safety), the operation has to be suspended until complete clarification is achieved. In order to maintain sufficient understanding of the operation and inherent hazards, the following communication tools (not a comprehensive list) should be incorporated: Pre-spud meeting(s) HAZID/HAZOP session(s) Safety inductions Rev.4.5, 26 Feb 2016 Page 114

116 Daily operations meetings Pre-tour meetings Pre-Job Safety Meetings (PJSM) Toolbox Talks (TBT) Work Instructions (WI) Management of Change (MOC) process Rev.4.5, 26 Feb 2016 Page 115

117 18 Contact List Name Job Title Phone / PRIMARY SERVICE CONTRACTORS Activity Service Contractor Phone No. Drilling Rig Drilling Bits Drilling Fluids Cementing / Pumping Directional Drilling Wireline Logging Services Float Equip & Centralizer Mud Logging Services Tubular Running Services Liner Hangers Wellhead & Xmas Tree Solids Control Services Waste Management Downhole Tools Rental Well Testing / DST Sampling Sampling Analysis Coring Coring Analysis CONTINGENCY SERVICE CONTRACTORS Activity Service Phone No. Contractor MWD Fishing Tools Rental Slickline Services Braided Line Fishing Solid Expandable Drilling with Casing Contact Contact Rev.4.5, 26 Feb 2016 Page 116

118 Appendix 1 Offset Well Information Rev.4.5, 26 Feb 2016 Page 117

119 Offset Well Inventory Currently, there is limited offset well information due to the exploratory nature of Block 12 and surrounding fields in south-west Iraq. While exploration maturity of the Western Desert by seismic surveys is satisfactory, and will be enhanced through Block 12, exploration maturity by drilling is extremely low. There is one other well drilled within the block (Sw-001) to a depth of 1784m into the Zubair formation. Some basic offset information is summarized in the below table. Well Operator Year Drilling Days Total Depth Diwan-1 (Dn-001) South Oil Company m Shawiya-1 (Sw-001) Ghalaisan-1 (Gh-001) Safawi-1 (Si-001) Samawa-1 (Sa-001) Ubaid-1 (Ub-001) Basra Petroleum Company Limited Basra Petroleum Company Limited Basra Petroleum Company Limited Basra Petroleum Company Limited Basra Petroleum Company Limited m m m m m Rev.4.5, 26 Feb 2016 Page 118

120 Data Availability Due to the fact that a limited number of wells were drilled, and most being completed over 50 years ago, there was inconsistency with amount of data available for each well. The data files provided by the client used for the analysis were summarized as shown in below table. Well Name Dn-001 Gh-001 Si-001 Sa-001 Sw-001 Ub-001 Year E ,382, ,500, ,730 1,533,660 N ,000, , ,382, ,530 Lattitude (deg N) Longitude (deg E) Caliper Log x x x x CBL Log x CPI Log x Sonic Log x x x x MSF Log x ElectroMagnetic x Free Point Log x LDL_ CNL x NGR x x DIP Log x x x Resestivity x Induction Log x x x x Micro Log x x x x x Electrical Log x x x x x LAS Files x x Graphic Well Log x x Temperature Log x Final Geological Report x x x x x Final Well Report x x x x x Formation Tops x Check Shot Data x x x x x Seismic x x x x x Core Results x Rev.4.5, 26 Feb 2016 Page 119

121 Well Information Summary The following section provides a summary of the most important offset trends in relation to Block 12. All of the wells were analyzed to gain understanding of the drilling operation and important events encountered, whether planned or not. However, the main focus was limited to Diwan-1 and Shawiya-1 wells because of the increased amount of data available and close proximity to planned exploratory well, respectively. Well Diwan-1 Exploration well drilled in 1989 reaching TD at 5476m. Completed geological evaluation and well testing. DST results are given below. Formation Interval (m) Hartha Nahr Umr Ratawi Resevoir Pressure DST Results Dissolved Salts P.P.M Reservoir Temp API Results ppm/1000bbl 174 o F m 3 Formation Water; 15.6 o C Formation Water + traces of heavy oil F.W o C 1m 3 Oil + gas w/ traces of mud Najmah Unsuccessful packer not set Najmah Dry Test Najmah o F m 3 Heavy Oil Drilling summary per section as follows: 36" Hole Conductor The conductor was drilled by 17.5" bit ahead of 36" hole opener down to 27m. Conductor pipe set at 24.5m. Cemented to surface by 20 tons IPC cement 1.85 gm/cm 3 (15.44 ppg) unsuccessfully. Due to bad cement, pipe dropped 2.5m while cutting it. 26" Hole The 26" hole started below conductor pipe and was drilled to 231m with many problems of complete and partial mud losses at different depths. During drilling at 30m, mud channeling occurred behind conductor pipe. Cement from surface was done. At 58m, complete losses. Spotted cement plug and drilled out cement (DOC) 19-65m. Drilled to 78m with losses of 2 m 3 /hr. Complete losses at 104m. Spotted cement plug. Checked TOC: no cement. Drilled with water to 110m with loss rate of 1 m 3 /hr. Spotted cement plug at 110m. Drilled to 156m with 1 m 3 /hr losses and then without losses to 231m. Total loss 90 m 3. Hole was reamed. 20" casing set at 229m and cemented to surface using 23 tons IPC + gilsonite 1.65 gm/cm 3 (13.77 ppg) + 15 tons 1.85 gm/cm 3 (15.44 ppg) to surface. Well head casing housing flange 20" (3000 psi) blow out preventer pipe and blind rams 20" (3000 psi) and hydril 20" (3000 psi) was installed and tested with 1422 psi and 1138 psi successfully. Rev.4.5, 26 Feb 2016 Page 120

122 17 1/2" Hole This hole was drilled to depth 2439m with many problems of mud losses and flowing S. water at different depths. While drilling at m, water flow from Umm-Rad formation so mud weight was increased from gm/cm 3 ( ppg). Mud losses occurred at 715m at rate 1.5 m 3 /hr. Mud losses and water flow controlled by setting 7 cement plugs. Tested formation at 1406m to 400 psi but pressure dropped. Spot & squeeze cement to cover Umm-Rad formation. This was done several (7) times and final cement plug was spotted at 296m and tested to 356 psi. Drilled out cement and continued without losses. Hole logged and reamed with 3-pt and 6-pt reamer. While RIH 13 3/8 casing, well flowing S. water at 1040m with rate of 30 m 3 /hr. Killed well with ppg mud and conditioned mud with ppg at bottom. Casing set at 2437m and cemented to surface using 50 tons IPC cement gm/cm 3 ( ppg) with 0.2% MHR-8 for first stage and 1.77 gm/cm 3 (14.77 ppg) second stage. Casing spool " (5000 psi) and well head was installed and tested successfully. 12 1/4" Hole Drilled to 4209m with many gas cut mud problems which required gradual mud weight increase from gm/cm 3 ( ppg). Due to bad barites, many issues with nozzle plugging while drilling. Reamed the section with 3-pt reamer; logged the same interval and carried out evaluation of Nahr Umr formation (procedure given in Final Drilling Report file). Reamed hole with 6-pt reamer and set 9.625" casing V150 (53.5 lb/ft) at 4207m. Cemented by 2-stage with first stage pumped 74 tons type G cement with 0.4% HR % Haliad 9 with gm/cm 3 ( ppg). Set plug and open DV. Cemented second stage with 78 tons class D cement gm/cm 3 ( ppg) to surface. Nippled up 11" (15000 psi) single and double BOP's + 11" (10000 psi) hydril and tested OK. 8 3/8" Hole Drilled with OBM to depth of 5476m. To mitigate tight hole problems, mud weight increased at 5377m from ppg. Nozzle plugging from bad barite. Mud needed to be conditioned to decrease the high viscosity. Reamed with 3-pt reamer. Spotted cement plug at 4168m. Completion from Nov.19/89 to Feb.04/90. Mounted x-mas tree psi. Tested with 6000 psi OK. Rev.4.5, 26 Feb 2016 Page 121

123 Measured Depth (m) 20" CSG 145m SALMAN-1 Drilling Program Drilling Curve ,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400 2,600 2,800 3,000 3,200 3,400 3,600 3,800 4,000 4,200 4,400 4,600 4,800 5,000 5,200 5,400 5,600 5,800 6,000 6, /8" CSG 2400m 6 Cement Plugs to harden Alignment of 20" CSG 9 5/8" CSG 4275m Diwan DN-001 Drilling Curve 13 3/8 Alignment on Well Head Logging Slow drilling due to Hard Formation Planned Actual Changed Draw work and levelled engine base 7" Casing Waiting For Barite Stop Drilling ( Order) Reaming, Cement Plug Total Days: 593 Days Well Shawiya-1 Exploration well drilled in 1960 with objective to gather stratigraphic information from Dammam to Zubair formations. The well reached target formation, Zubair, and tapped the Eocene-Cretaceous succession with depth of 1784m. Oil shows were recorded while drilling in the sandstones of Nahr Umr formation. A total of 4 coring runs performed: Core # Formation Core Interval Recovered 1 Shiranish m 100% 2 Rumaila m 33% 3 Nahr Umr m 10% 4 Zubair m 15% Drilling summary per section as follows: 15 Hole 15 hole drilled to 193m. Loss circulation zones encountered at 96m and 193m while drilling and cemented off. Bentonite-water mud with density of 9.1 ppg and Marsh viscosity of 45 seconds casing was run to 193m and cemented to surface. Pressure tested to casing and well head to 1500 psi (30 min.). Formation tested to 500 psi (30 min.). 10-5/8 and 7-5/8 Holes Drilled hole with spot coring. Same bentonite-water mud as previous hole section. Pipe 1114m and freed by spotting crude oil. Drilling suspended for 14 days while replacing low clutch. Rev.4.5, 26 Feb 2016 Page 122

124 Drilling continued to 1316m where tight hole made it necessary to convert the mud system to a high ph lime based mud (9.6 ppg, visc = 45s, filtrate 2.0 cc). Hole was logged and intended to run casing to isolate troublesome LC m, m, and 1308m. However it was decided not to run casing. Drilled reduced hole size of with spot coring to TD of 1786m (5860 ft). The hole was logged and cement plugs spotted to abandon the well. Well Ghalaisan-1 Exploration well drilled in 1960 reaching depth of m. Losses were encountered from 47m to total depth. Minor losses were treated with plugging agents and more severe losses were cemented off. Drilling and testing summary per section as follows: 10 5/8 Hole Drilled to 372m. The hole was logged and dipmeters indicated steadily increasing hole deviation up to 12 degrees. The hole was opened up to 10 5/8 before running 8 5/8 casing. The 8 5/8 csg was then run to 1222 (372m) and cemented to surface with no problems. 7 5/8 Hole At m after oil show in cuttings, a core was cut from m to 1179m. Another core was cut from m to 1396m following an oil show. A JFT was run and the interval 1371m to 1396m was tested. The tool was opened and a medium strong blow was observed, becoming stronger after four mins. The tools were left open for 22 minutes but no fluid surfaced. Reverse circulated and recovered formation water contaminated with asphalt and some oil, and loaded with sand. Hydrogen Sulphide was detected while sampling. Pressures from the recorder chart were as follows: bottom hole closed in pressure-1785psi; initial bottom hole flowing pressure- 845psi; final bottom hole flowing pressure -1590psi. Bottom hole temperature was 155 F. Drilling then resumed till 1797m. While trying to recover two bit cones a junk basket and two subs were left in hole. Attempts to recover the fish were unsuccessful and eventually had to be milled. 19 days were required to clean up the hole. Drilling then resumed. At 1890m while POOH, drilling line failed (stranded but did not part). Failure mode was determined to be fatigue caused by fishing ops. Line was replaced and drilling ops continued to TD of m The hole was logged and cement plugs were spotted. Well was plugged and abandoned on 25 July Well Safawi-1 Exploration well drilled in 1960 reaching depth of m. The objective was to gather stratigraphic information in the south-west desert, located on a gravity positive anomaly. Drilling was terminated in the middle Jurassic. The formations showed thinning by comparison with the Basrah area thickness. The Mishrif formation was only 8.2m thick with no oil or gas indications. The Shuaiba formation had wedged out or passed laterally into the Nahr Umr/Zubair sandstones. Some bitumen occurred at the top of Nahr Umr/Zubair sand and a little heavy oil in the Yamama formation. A brief drilling summary per section as follows: Rev.4.5, 26 Feb 2016 Page 123

125 15 Hole Drilled using a bentonite water mud. Heavy losses were encountered at 18m and persisted to the 11-3/4 csg setting depth at 184.7m 10-5/8 Hole Drilled using the same mud as for the 15 hole. Starch was added to reduce filtrate and plugging agents were used to counteract mud losses which were encountered at 281.7m and persisted till the 8 5/8 casing depth. Mud characteristics were maintained as follows; MW-8.96ppg, Visc- 45 Marsh seconds, filtrate 5.9cc. 7-5/8 Hole Drilling resumed with the same bentonite water mud used in the 10 5/8 hole. Calgon, Caustic and Quebracho were used to control viscosity and gels. Starch was added to reduce filtrate. At approximately 975m, trouble with tight hole made it necessary to change the mud to a high ph lime based mud. And the 7 5/8 hole was drilled from 975m to the total depth of m with this type of mud. Partial mud losses were maintained with mud properties of ppg, marsh sec. and filtrate cc. Well Samawa-1 Exploration well drilled in 1959 reaching depth of 3842m. Sa-1 is located on the shelf region of Eocene/Cretaceous basin of deposition at a point where local closure is indicated on seismic map. It was drilled for stratigraphic purposes, particularly in the L.Cretaceous and Jurassic. Significant oil shows were recorded while drilling the Upper and Lower Cretaceous and Upper Jurassic sequences. A drilling summary per section as follows: 20 Hole Well was spudded with 20in bit and 366m was reached without incident following which 16" casing was set and cemented to surface. Well head and casing shoe were successfully pressure tested. 15 Hole Drilling continued with 15" bit and at 755m water flow 2 bbl/hr was observed. Drilling and spot coring continued to casing point at 1372m where 11 ¾ casing was set and cemented. The fresh water/bentonite mud was treated with phosphate to maintain low viscosity desired. Starch was added to control the water loss. It became increasingly difficult to maintain mud properties due to gypsum contamination and mud was converted to low ph lime base at 1023m. Wellhead, casing and shoe was successfully pressure tested. 10 5/8 Hole Drilling resumed with 10 5/8 bit. Spot coring was carried out at zones of interest and a formation test was performed at 2482m on core evidence. At this depth a failure in rotary drive clutch resulted in pipe being stuck at bottom. The pipe was worked and diesel oil spotted around the collars, after which it came free. Rev.4.5, 26 Feb 2016 Page 124

126 Surveys were performed in OH, and was reamed to bottom as well as opening the core hole to full gauge. MW was raised to ppg to control sloughing shale. 3 attempts were required to successfully perform drill stem test. Continued drilling to 2500m. Another pipe stuck event. Crude was spotted around the collars while working pipe, finally coming free. MW was raised to 12.7 ppg and drilling continued to 2530m. 8 5/8 casing was set at this depth and cemented. Successfully pressure tested well head, casing and shoe. 7 5/8 Hole Drilling resumed with 7-5/8 bit. Due to cutting evidence, drill stem test was performed at m Diamond coring with 7-9/16 in head continued to 2742m at which depth another drill stem test was required. Open hole was logged and reamed prior to testing. While POOH 4" drill pipe parted at the weld below the box of 5th joint from surface. It was recovered with an overshot without difficulty. 10 collars and 119 joints of recovered drill pipe were badly bent and were L/D. Cones and bearing of the bit were left in hole. Attempts to fish with magnet were unsuccessful and eventually had to be milled with rock bit. Entire drill string was replaced with new 4in REED drill pipe. Drill stem test was performed at 2743m producing water. Interval 2729m-2743m was plugged off with cement on 3rd attempt. Top of cement was 2727m. 10 collars and 119 joints of recovered drill pipe were badly bent and were L/D. Drilling continued to 2771m and then coring until 2882m showing good indication of oil, but in tight zones. Drilling resumed and at 3006m got losses 50 bbl/hr. Controlled with reduction in mud weight (MW) and pump pressure. Drilling and spot coring continued to 3195m where gas-cut mud was controlled by raising the MW to 14.4 ppg. Gas cutting became issue again so MW further increased to 15.0 ppg. 150 bbls had to be dumped after every trip as being too heavily oil and mu-gas cut to recover. At 3353m, anticipated casing point, the open hole was logged and a core cut. It was decided to drill ahead and depth of 3425m was reached. While POOH, pipe became stuck (likely key seat) at 2991m and acid spotted. Pump pressure rose sharply to 2200 psi and then the annulus collapsed and circulation completely lost. Light mud and crude oil were pumped away with losses 50 bbl/hr. Formation finally plugged itself below the bit and annular circulation regained at 5600 psi, falling to 1500 psi. The mud was displaced with water after spotting more oil and acid and fishing operation ensued. A new bit was run and after drilling 1 ft of hole, 6-5/8" casing was set and cemented at m. The 4.5" fishing string was L/D and 3.5" Hydril string picked up. Wellhead, casing and shoe pressure tested satisfactorily. Rev.4.5, 26 Feb 2016 Page 125

127 5 5/8 Hole Drilling continued with 5-5/8" bit and on basis of core and cutting data, a DST was attempted at 3572m. Four attempts for DST were unsuccessful due to mechanical failures so drilled ahead to m where a diamond drill bit was run until 3839m where ROP dropped. The bit was examined and in good condition, but orders received to abandon the well. One final core cut at 3810m and plugging operations commenced. The well was formally abandoned on 26 Nov Well Ubaid-1 Located at the foot of the At Traq escarpment, this test well on a surface structure was drilled in 1960 to depth of 1844m into the Zubair formation to explore the possibility of hydrocarbon trapping in the Nahr Umr and Zubair sands. While drilling at the top of Nahr Umr formation, sandstones gas and water at high reservoir pressure were recorded. Drilling summary per section provided below. 15 " Hole Spudded with 15" bit made up with 4" IF.XH drill pipe using bentonite suspension in fresh water. Mud losses encountered at 49m at varying rates until suitable casing depth found at 179m. Hole was then reamed to bottom and logged before 11.75" casing run and cemented. 10-5/8 " Hole Drilled with bentonite suspension in water to 322.5m where mud losses were encountered at varying rates until suitable casing depth found at 972m. During trips, tight spots encountered and reamed using new bit from 298m-372m and 882m-964m. Hole was then logged and 8.625" casing run and cemented at 972m. 7-5/8 " Hole Drilled with bentonite suspension in water. Mud losses were encountered between 1204m-1268m. After, drilling continued without issue to 1623m where coring was done in Nahr Umr formation followed by DST. Drilling continued with losses at varying rates until m where coring was necessary to locate Zubair formation. Further 12m drilled to TD of 1844m. Hole logged and seismic surveys completed before cemented to top. For the DST, a 6-5/8" open-hole packer set at m. Upon fracturing the disc valve, a very slight blow resulted which increased slowly to a strong steady blow. After tool had been opened for 23 min., gas smelling strongly of H 2 S came to surface and was burned off. Due to a faulty bean and a leak, it had to be shut twice at surface and therefore only open for 1 hour. The test results are provided in chart below. Bean Setting Max. WHP Formation Flowing Pressure 8/64 inch Initial flow pressure 1930 psi 8/64 inch 1200 psi 2320 psi 16/64 inch 850 psi 2110 psi Rev.4.5, 26 Feb 2016 Page 126

128 Offset Well Design Summary Dn-1 Sw-1 Gh-1 Si-1 Sa-1 Conductor 30" Casing 20" K-55, 133 lb/ft 229m MD Casing 13-3/8" N-80, 72 lb/ft 2437 m MD Casing 9-5/8" V150, 53.5 lb/ft 4207 m MD Casing 11 3/4" J-55, 54 lb/ft 192 m MD 10-5/8" Open Hole m MD 7-5/8" Open Hole 1786m MD Casing 8-5/8" J-55, 36 lb/ft m MD 7-5/8" Open Hole m MD Casing 11-3/4" J-55, 54 lb/ft 180.2m MD Casing 8-5/8" J-55, 36 lb/ft 472m MD 7-5/8" Open Hole 1829m MD Casing 16" H-40, 65 lb/ft 366m MD Casing 11-3/4" J-55, 54 lb/ft 1371m MD Casing 8-5/8" N-80, J-55, 36 lb/ft 2530m MD Casing 6-5/8" N-80, 28 lb/ft 3436m MD 5-5/8" Open Hole 3842m MD Ub-1 Casing 11-3/4" J-55, 54 lb/ft 179m MD Casing 8-5/8" J-55, 36 lb/ft 972m MD Rev.4.5, 26 Feb 2016 Page 127

129 Appendix 2 BOP & Wellhead Design Summary Rev.4.5, 26 Feb 2016 Page 128

130 The following figures provide BOP stack configurations based on the provided well design. 30" WP DIVERTER SYSTEM " 2k flange 52" 8" ID ) 30" 1K Weld Neck Flange To weld customer Bell Nipple 2) 30" 1k WP Annular BOP top Studded & Bottom Flanged 3) 30" 1k WP Top & Bottom flanged Drilling Spool with 2x 9" 2K Flanged Side out lets 4) Hydraulic Ball Valves 8" ID c/w 9" 2K Flanged 5) Weld Neck Flange 9''-2k ( TO WELD CUSTOMER FLOW LINE ) 6) 30''-1K SPACER SPOOL 7) 30" 1K Weld Neck Flange ( To Weld 30" Conductor Pipe ) SPARES QTY-28 no's 2'' x 10-1/2'' long Tap End Studs with 1 nut ( Fixed on Annular Top ) QTY- 48 No's 1-1/8''-X 8-1/2'' Long Bolts With 2 Nut Each ( For Drilling Spool Outlets ) QTY- 84 2'' x 15-3/4'' Long Bolts with 2 Nut Each ( For Stack UP ) QTY - 4 NO RX- 49, CS ( Fixed on Drilling Spool Out Let ) QTY- 4 No's R- 95 CS Ring Gasket ( For Stack Up ) ) QTY-4 Hyd. Hoses with 1 end 1/2" Quick connector otherside 1" 602 Male & Female Hammering Unions 30 Diverter System Schematic Rev.4.5, 26 Feb 2016 Page 129

131 21.250" 5k BLOW OUT PREVENTER STACK /4''-5K ANNULAR BOP STOUUED TOP & BOTTOM FLANGED /4''5K CIW TYPE U DBL RAM BOP FLANGED TOP & BOTTOM WITH 4 X 4-1/16''-5K FLANGED SIDE OUTLETS /4''-5K DRILLING SPOOL FLANGED TOP& BOTTOM WITH 2 X 4-1/16''-5K FLANGED SIDE OUTLETS 2 X 4-1/16''-5K MANUAL GATES VALVES ON KILL & CHOKE LINE 2 X 4-1/16''-5K HYDRAULIC GATES VALVES ON KILL & CHOKE LINE 1 X 4-1/16''-5K CHECK VALVE FOR KILL LINE /4''-5K SPACER SPOOL FLANGED REQUIRED SPARES 1) QTY- 4 BONNET SEALS 21-1/4''-5K 1) 1 SET BLIND RAMS 2) 1 SET PIPE RAMS 3) QTY- 11 RX- 39, S-316 RING GASKETS 4) QTY /4'' X 8-1/2'' LONG BOLTS WITH 2 NUT EA ( FOR BOP OUTLETS AND VALVES ) 5) QTY- 96 2'' X 19'' LONG BOLTS WITH 2 NUT EA ( FOR STACK UP ) 6) QTY- 5 BX- 165, S-316 RING GASKET ( FOR STACK UP ) 7) 1SET OF BLIND RAM PACKERS & TOP SEAL 8) 1 SET OF PIPE RAM PACKERS & TOP SEALS 21-1/4 5K BOP Stack Schematic Rev.4.5, 26 Feb 2016 Page 130

132 13-5/8" 15k BOP STACK HEIGHT 72 '' INCH ) 13-5/8''-10K HYDRIL GK ANNULAR BOP 13-5/8''-10 K STUDDED TOP & BOTTOMM 13-5/8''-10K FLANGED HEIGHT 9'' INCH HEIGHT 82'' INCH 2 3 2) 13-5/8''-10K X 13-5/8''-15K DOUBLE STUDDED ADAPTER 3 ) 13-5/8''-15K CIW TYPE U DBL RAM BOP TOP WITH STD BONNETS & BOTTOM WITH LARGE BORE SHEAR BONNETS C/W WITH 4 X 3-1/16''-15K FLANGED SIDE OUTLETS 4 4) 13-5/8''-15K CIW TYPE U SINGLE RAM BOP WITH STD BONNETS C/W 2 X 4-1/16''-15K FLANGED SIDE OUT LETS HEIGHT 54'' INCH 13-5/8 15K BOP Stack Schematic Rev.4.5, 26 Feb 2016 Page 131

133 Wellhead Schematic The wellhead design is based on anticipated well parameters, in accordance with API Spec 6A. Rev.4.5, 26 Feb 2016 Page 132

134 The maximum anticipated surface pressure (MASP) calculations have been performed and the results are displayed below. Calculated Static Well Head Pressure psia 777 bara Rev.4.5, 26 Feb 2016 Page 133

135 Appendix 3 Well Testing Program Rev.4.5, 26 Feb 2016 Page 134

136 SECTION 1: INTRODUCTION 1.1 Testing Philosophy The testing program has been compiled with the objective of determining the presence, volume, and flow rate of testing of the SALMAN-1 exploration well. Testing is designed to obtain information on fluid type, flow rates and pressures, determine formation connectivity and overall general potential reservoir performance. The DST in the open hole sections is to form the primary option for well testing and wireline formation testers are only to be used as a contingency. No comingling of reservoir flow is allowed and so all potential targets are to be tested exclusively Open hole testing will be performed on penetration of the target formation after the planned coring and logging operations have taken place. Hole deepening by 30-50m will be required after the coring to allow for logging tools and to expose the entire formation for the subsequent well test. Logs run will be to confirm the testing interval and identify seats for open hole packers. Wireline Mini DSTs will only be performed if conventional open hole DST cannot be run either for operational or technical reasons or if unsatisfactory results are achieved from attempts to measure the dynamic flow performance characteristics of the target formation. Open hole DSTs will determine qualification of potential reservoir zones, the criteria for which will be provided by the Well Testing Supervisor. Because the strategy for open hole testing requires testing on initial penetration of the target formation, Conventional Testing will use a compressional DST BHA Cased hole testing will be performed on potential reservoir intervals after evaluation of open hole tests. Such target zones will be identified for extended duration testing, the procedures for which can be found below. Note: Due to the slim hole size (6 Hole/4 ½ Liner) of the final drilled section, open hole testing, if required, will be performed with a cased hole packer above the open hole section on encountering a target formation. Only one test zone is anticipated. Should there be cased hole testing in the 4 ½ Liner, the zone may be tested with the casing packer set in the 7 Liner. Rev.4.5, 26 Feb 2016 Page 135

137 SECTION 2: PRIMARY TEST OBJECTIVES a. There are a number of potential testing zones within the anticipated geological column in SALMAN-1. The following table sets out the six target intervals in the 12 ¼ hole section. Well Test Interval (m) Age of Depositions Lithology 1,320-1,350 Msa ad/mishrif Carbonate 1,580-1,620 NahrUmr Sandstone / siliciclastic 1,735-1,765 1,870-1,890 Zubair Sandstone 2,045-2,105 Ratawi Carbonate 2,257-2,287 Yamama Carbonate The below table shows four testing zones in the 8 ½ Section Well Test Interval (m) Age of Depositions Lithology 2,460-2,480 Najmah Carbonate 2,890-2,910 Sargelu Carbonate 3,105-3,125 Mus Carbonate 3,430-3,445 Butmah Carbonate In addition to the above intervals, coring is to be performed in all intervals that have HC shows. Determining qualitative parameters for the shows will be provided. The below table shows one testing zone in the 6 Section Well Test Interval (m) Age of Depositions Lithology 4,000-4,015 Kurra Chine Carbonate In addition to the above intervals, coring is to be performed in all intervals that have HC shows. Determining qualitative parameters for the shows will be provided. b. Evaluation of the hydrocarbon bearing intervals and to determine reservoir parameters of the sandstone and carbonate beds are as follows: Permeability PI Pore pressure Fluid Mobility Darcy Skin, Non Darcy Skin Rev.4.5, 26 Feb 2016 Page 136

138 c. Draft Drill Stem Test Procedures can be found below and the Mini DST procedures can be found in the Wireline program (some of which will be vendor specific). SECTION 3: OPEN HOLE TESTING The following sequence defines the open hole testing strategy for a single test including idealized times to perform a limited duration flow and final build up test. This test is limited in duration and may be extended based on well results and a more detailed schedule will be issued closer to the time by the Well Test Supervisor. Open Hole Zone Test Description Time (Hrs) Make Up BHA 6 RIH Compression DST String 12 At testing Depth install flow head and surface equipmen 2 Pressure test Eqpt 1 Set Packer Assemby 4 Initial Flow 1 Intermediate Build-Up 2 Main Flow Period 2 Final Build-Up 4 Well Kill Procedure 2 Unseat Packer & POOH 12 Break Out BHA & Lay Down Tools 6 Total Test Duration (Days) 2.3 Open Hole Well Test Procedure The Well Testing Supervisor is the person responsible for all DST safety procedures. All requests or instructions must be routed through him/her. Under no circumstances will Instructions be given directly to the testing or drilling contractors without his/her knowledge and approval. The drill pipe and bottom hole assembly must be strapped while pulling out for a test unless the pipe was recently strapped prior to the test. Test results must not be given to any third party. All enquiries must be referred to the client s office. All samples must be correctly and fully labelled. DSTs may only be pulled without reversing if a water flow to surface or a negligible blow with no string weight deviation is observed. All unnecessary electrical equipment must be switched off during DSTs, including making up the TCP guns and RIH. Ensure BOPs tests are current prior to running a DST. The mud pumps should be lined up on the hole and test run prior to picking up test tools. The Well Testing Supervisor must hold a safety meeting before picking up the test string. The Well Testing Supervisor must witness the picking up and running of the test tools. The Well Testing Supervisor must give the Driller written instructions Rev.4.5, 26 Feb 2016 Page 137

139 detailing the running procedure string make up, etc. Ensure that there is sufficient clearance around the flare pit and that there is no rubbish in the flare pit that could be blown out and become a fire hazard. Ensure that there is sufficient water hose available to allow fires to be extinguished around the flare pit. Any pup joints used for space out should be positioned one stand down from surface to avoid BOP space out problems. Driller or Tool Pusher to be on the floor at all times. Annulus level to be observed continuously. Testing Procedure Circulate until hole is clean, & Pull out of hole. Make up testing assembly for proposed test interval. Final test string configuration will be confirmed by the Well Test Supervisor prior to test. Tools must include as a minimum, four (4) recorders (mechanical inside, outside and recovery, electronic inside) plus two independent reversing / pump-out subs, safety joint and jars. Review testing assembly with contractor and client prior to RIH. Check measurements with the testing operator to ensure that the desired interval is in fact tested. Write all measurements on the back of the Drill Stem Test Report Form. Confirm if water cushion is required. Based on packer size, estimated hole size, depth and existing mud weight. Check that the flare line is clear and all valves on this line downstream from the choke are open. Ensure that, the separator valves and dumps are in the operating position and that the entry and exit valves are closed. Pressure test all surface flow lines to 3000 psi. Ensure water sprays to all exhausts are in operation and that all sources of ignition have been suppressed. Ensure appropriate flare buckets are in position and lit. Set packer. Initiate perforation by TCP guns. Open valve - observe annulus to ascertain if the packers are holding. After a 5-minute initial flow, close tool. Report to client Office on result of initial flow. After 60 minutes shut-in, re-open the tool. Open for a further 2 hrs. Consider shortening the second flow/shut-in periods shown below if indications of flow are poor. Shut-in tool after 2hrs flow. COLLECT FLUID SAMPLES AS PER BELOW PROCESS After 4 hrs buildup on second shut-in, pull free and P.O.O.H. Shut-in tool for at least 4 hours or as advised by the Well Test Supervisor, then pull packer free. Observe the mud level in the hole for any returns. If the contents of the drill pipe have not been reversed out, take samples of the fluid in the drill pipe and it is most important to take a sample from above the test valve. When pulling out of hole it is most important that the hole is kept full. Keep a full and accurate record of all operations during the test on the Drill Stem Test Report Form. If oil/condensate has been produced, reverse circulate out to a test tank. Rev.4.5, 26 Feb 2016 Page 138

140 Do not circulate to the flare pit. PULLING DRILLPIPE CONTAINING HYDROCARBONS MUST NOT BE ATTEMPTED. Reverse Circulating Procedures: If it is considered that there could be liquid hydrocarbons in the string, it should be reverse circulated out to a test tank, not the flare pit, prior to pulling the string. The following procedure should be followed when reversing out: Closing the choke manifold when shearing the knock out sub or opening the DCIP valve will buffer the sudden drop of annular fluid. This reduces the commingling of produced fluids, and by manipulation of the choke, a controlled recovery can be made. Calculate the drill string capacity above the pump out sub or DCIP (whichever is used), and convert the volume to pump strokes at 95% or at the %efficiency recommended by the Tool Pusher. Zero the pump stroke counters or have two people on the pumps counting strokes. Line the pump to the kill line - DO NOT close the BOP's. Measure and record volume of all mud tanks. Close the choke manifold. Drop the knock out bar or rotate the DCIP valve to the circulating position. Fill the hole as the annulus drops. Watch the annulus at all times, adjusting the pump rate to keep the annulus full, but not overflowing. Open the choke and commence recovery. Control the recovery rate using the choke and collect samples from the bubble hose. As the flow slows down due to hydrostatic balancing, shut-in the annular preventer and pump out the remaining recovery. Ensure the pump pressure, kpa max ( psi), does not exceed formation breakdown pressure. When the calculated capacity has been pumped, drilling mud returns should act as a final check to full recovery. Continue circulating for approximately 15 minutes to ensure a balanced system. Return fluids will normally be diverted into a holding tank where volumetric recovery is confirmed, and after a settling period, various fluid recoveries can be accurately determined. Pull out with test string. Formation Fluid Samples: Crude Oil Samples In the event that crude oil is recovered, two 5-litre can samples will be taken for analysis. Preliminary analysis of the API gravity and pour point of the oil will be made at the wellsite. The samples will be labelled with: Well Name, Date, DST Number, DST Interval, Formation, Sample origin and Temperature. Gas Samples Gas samples of ml are required for analysis. A minimum of two samples per test will be collected under pressure in an evacuated steel cylinder (minimum 1500 psi). The cylinder will be labelled with:- Well Name, Date, DST Number, DST Interval, Formation, pressure, sample origin, time sample was taken and the reservoir and surface temperatures. Use the Drill Stem Test Report form to record all information about the samples collected. Rev.4.5, 26 Feb 2016 Page 139

141 A sample of any gas to surface will be analyzed at the wellsite using the chromatography in the mud-logging unit. Avoid saturating the detector by diluting with air. Water Samples The following procedures for sampling drill stem test fluid for hydro geochemical evaluation are recommended. Collect the following types of samples for evaluation:- Drilling mud sample - 1 litre plastic bottle Make-up water - 1 litre plastic bottle DST samples - 1 sample from the top - 1 sample from the middle - 1 sample from the bottom Mud filtrate - 20 ml sample Collect each DST sample in a 1 litre plastic bottle. If an organic extraction of possible petroleum components from the water is required, then two, 1 litre GLASS bottles should be collected. Sample Collection Methods Rinse all containers thoroughly with the fluid to be sampled before collecting the actual sample. If possible, obtain the ph and resistivity of each sample immediately after collection. Measure and record the amount of chlorides by titration. Fill all plastic containers to the brim with sample. Screw cap down and at the same time squeeze some of the liquid out then tighten the cap. Wrap the cap tightly with tape. This procedure will provide a good seal and reduce bacterial putrefaction and oxidation. For gas saturated samples, fill bottles ¾ full, tap cork evenly into position, invert and store with bottom end upwards. This will trap gases against the bottom of the bottle. Check for leakage around the cork. Label all containers clearly. STORE SAMPLES IN A COOL PLACE AND SHIP AS SOON AS POSSIBLE FOR ANALYSIS. Water samples quickly change composition upon sitting, especially if they have been contaminated with mud. Thus for best results, samples should be sent for analysis immediately after collection. Rev.4.5, 26 Feb 2016 Page 140

142 COMPANY: Bashneft International B.V. Formation: Fluid: S.G. 2.1 Salt Mud BLOCK / WELL: Blk 12 / SALMAN-1 Interval: BHT: 90 C DST #: 10 Date: Deviation: Vertical STRING DESCRIPTION OD ID TOP BTM LENGTH DEPTH (m) inch inch CONN CONN Meter TOP BTM REMARKS 1 FLOW HEAD CROSSOVER # " 2.25" 3-1/2 PH-6 4-1/2 IF CROSSOVER # " 2.50" 3-1/2 IF 4-1/2 IF TIW (STABBING VALVE) /2 IF 4-1/2 IF STICK UP 1 JOINT 5" HEVI-WATE 5.00" /2 IF 4-1/2 IF " DP PUP JOINT 5.00" 4.26" 4-1/2 IF 4-1/2 IF " DRILL PIPE (74 STDS+ 1 JNT) 5.00" 4.26" 4-1/2 IF 4-1/2 IF STANDS HEVI-WATE 5.00" /2 IF 4-1/2 IF STANDS - 6.5" COLLARS 6.50" 2.00" 4-1/2 IF 4-1/2 IF /2 IF PUMP-OUT SUB 6.25" 2.25" 4-1/2 IF 4-1/2 IF STAND - 6.5" COLLARS 6.50" 2.95" 4-1/2 IF 4-1/2 IF CROSS-OVER # " 2.25" 4-1/2 IF 3-1/2 IF SPACING 5.00" 2.25" 3-1/2 IF 3-1/2 IF /2 IF PUMP-OUT SUB 5.00" 2.25" 3-1/2 IF 3-1/2 IF GAUGE CARRIER (5 sec rate) 5.00" 2.00" 3-1/2 IF 3-1/2 IF HYDRAULIC VALVE 5.00" 0.75" 3-1/2 IF 3-1/2 IF SAMPLER 5.00" 0.75" 3-1/2 IF 3-1/2 IF SPACING 4.75" 2.50" 3-1/2 IF 3-1/2 IF GAUGE CARRIER (5 sec rate) 5.00" 2.00" 3-1/2 IF 3-1/2 IF EXTENSION JOINT 5.00" 0.75" 3-1/2 IF 3-1/2 IF JAR 5.00" 2.375" 3-1/2 IF 3-1/2 IF SAFETY JOINT 5.00" 2.00" 3-1/2 IF 3-1/2 IF COMPRESSION PACKER 7.50" 2.00" 3-1/2 IF 3-1/2 IF COMPRESSION PACKER 7.50" 2.00" 3-1/2 IF 3-1/2 IF TOP OF INTERVAL PACKER STUB 5.00" 2.00" N/A 3-1/2 IF SPACING 5.00" 2.25" 3-1/2 IF 3-1/2 IF PERFORATIONS X " 2.25" 3-1/2 IF 3-1/2 IF GAUGE CARRIER (5 sec rate) 5.25" /2 IF 3-1/2 IF CROSS-OVER # " 2.25" 3-1/2 IF 4-1/2 IF JNT HWDP 5.00" /2 IF 4-1/2 IF CROSS-OVER # " 2.25" 4-1/2 IF 3-1/2 IF BULL NOSE 5.00" N/A 3-1/2 IF N/A BOTTOM OF INTERVAL Rev.4.5, 26 Feb 2016 Page 141

143 SECTION 4: CASED HOLE TESTING The following sequence defines the Cased hole testing strategy for a single test including idealized times to perform a limited duration flow and final build up test. This test is limited in duration and may be extended based on well results and a more detailed schedule will be issued closer to the time by the Well Test Engineer, or duly representative of Bashneft. Test Zone Sequence & Timing Description Time (Hrs) Flex Trip 12 Make Up BHA 6 RIH DST String 12 Correlate Guns & Set Packer 6 Perforate & Initial Flow 2 Initial Build-Up 1 Well Clean-Up 4 Initial Flow Periods 4 Intermediate Build-Up 10 Main Flow Period 6 Final Build-Up 10 Well Kill Procedure 6 Unseat Packer & POOH 18 Break Out BHA & Lay Down Tools 6 Days 4 Standby Between Zones (Days) 2 Total Test Duration (Days) 6 Rev.4.5, 26 Feb 2016 Page 142

144 The intervals for cased-hole test in the target formations in shown below and provided by Bashneft. These intervals are to be adjusted and re-confirmed by Bashneft (as duly represented) subject to the actual results of log interpretation and open-hole tests while drilling. Cased-hole Production Testing # Interval, m Lithology, Age Expecte d fluid, O, G, C Flow regime, gusher / nongusher Completion, perf / 1 line m Stimulation, mode and bean (number of tests)** Cement plug Carbonates, oil, gas (15) Kurra Chine gusher Perforation, Swabbing, 20* compression Carbonates, Perforation, Swabbing, oil gusher (15) Butmah 20* compression Carbonates, Perforation, Swabbing, oil gusher (20) Mus 20* compression Carbonates, Perforation, Swabbing, oil gusher (20) Sargelu 20* compression Carbonates, Perforation, Swabbing, oil gusher (20) Najmah 20* compression Carbonates, Perforation, Swabbing, oil gusher (60) Ratawi 20* compression Sandstones, Perforation, Swabbing, oil gusher (30) Zubair 12* compression Sandstones, Perforation, Swabbing, oil gusher (40) Nahr Umr 12* compression Carbonates, Perforation, Swabbing, oil gusher (30) Msa ad 20* compression Notes * Perforation of the production casing: 20 holes per meter in the carbonate intervals and 12 holes per meter in the sandstone intervals. ** The number of tests (bean size, pressure regime, etc) is to be adjusted based on the actual fluid recovered (TBA). Rev.4.5, 26 Feb 2016 Page 143

145 Cased Hole Well Test Procedure The Well Test procedure is based on the following assumptions: Testing will be conducted in hydraulically isolated intervals inside cemented casing. A Flex trip will be performed to remove scale/debris from inside the tubing used for DST and confirm the pressure integrity of the production string. All downhole tools and surface equipment will be function tested and pressure tested prior to perform the operation. The DST tool string will include tools which will allow the test string to fill up while running in the hole (RIH) and the tubing to be hydrostatically tested before setting the test packer. The flow head with swivel will allow the surface lines to be connected prior to setting the packer. A mechanical (drop bar) TCP firing head will be run. This allows the well to be perforated underbalanced with a fluid or a nitrogen cushion. A Hydraulic Firing Head, pressure activated will be run at the bottom of the TCP string as backup to the mechanical one. A temperature activated detonation interrupt device will be run to prevent shallow firing of the guns. Down hole samples will be obtained with timed sample chambers run on slick line. Pressure build up (PBU) and temperature data will be collected with memory gauges run in the test string. Each well test operation is expected to follow the general steps outlined below: 1. Test Blow Out Preventer (BOP) 2. Make Up bit & scraper and cleanout to Plug Back Total Depth (PBTD) 3. Pressure test casing 4. Rig Up (RU) Electric Line (EL). Run Cement Bond Log/Casing Collar Locator [CBL/CCL+GR+Neutron (Pulsed Neutron)] and make correlation log. Pull Out Of Hole (POOH) & Rig Down (RD) EL 5. Perform remedial cementing operations, if needed and clean out to PBTD 6. Circulate and Condition (C&C) test fluid. POOH 7. Pick up and rabbit 3-1/2 test tubing 8. MU & RIH with Tubing Conveyed Perforating (TCP) guns, firing head with no-go sub, test packer and test tools o The Tubing Tester Valve will be run above the Safety Joint to allow pressure testing the production string and the BHA o The Down Hole Safety Valve (DHSV) will be run as downhole secondary barrier in case of extreme emergency. The valve is run open. Once closed it cannot be reopened but its pump through feature will allow bullhead back to the formation tested o The MCTV Tester Valve will be run in Lock open position to allow pressure testing the string all the way down to the Tubing Tester Valve (TTV) o The Multi Cycle Circulating Valve will be run above the MCCV to spot, circulate and reverse fluids and reclose. o The Single Shot Kill Valve (SSKV) will be run as the secondary reversing/circulating valve as back up of the MCCV. Once opened it cannot be reclosed. o The Fail Safe Valve N2 loaded will be set across the BOP as the primary safety barrier. Using a Controlled Panel on the rig floor it can be open and Rev.4.5, 26 Feb 2016 Page 144

146 closed without limitation. The Pump Through ball valve is designed to cut 7/16 WL and /or 1 ½" CT. 9. Pressure test bottom hole assembly BHA 10. RIH, pressure testing string periodically 11. RU EL and correlate guns on depth with GR/CCL 12. RU Subsurface Fail Safe Valve and space out to ensure the slick joint will be across the lower pipe ram to isolate the annulus from surface 13. Confirm Opening and closing of fail Safe Valve 14. RU flow head and surface lines 15. With the Fail Safe Valve in open position pressure test flow head, surface lines and test string against tubing tester valve (TTV) 16. Set packer 17. Close lower pipe ram and test packer set with pressure applied in the annulus 18. Cycle tubing tester valve TTV into permanent open position 19. Close the Annulus Reference sub to initiate Multi Cycle Tester Valve function 20. Cycle Multi-Cycle Circulating Valve (MCCV) to Circulating position 21. Displace mud with water or diesel 22. Rig up and run Coil Tubing equipment: pump nitrogen down tubing to partially displace cushion leaving a calculated column above MCCV to prevent spotting nitrogen on back side 23. Cycle MCCV in closed position, bleed off nitrogen pressure, POH Coil Tubing and Rig down (RD) 24. Drop bar to activate firing head 25. Open choke and monitor tubing with hose and water bucket. Monitor DP with acoustic recorder 26. Wait for guns to fire 27. Flow well 30 minutes. Close the MCTV to obtain initial BHP 28. Re-open MCTV and allow to clean up if possible 29. If well will not flow, consider reversing out sample of inflow fluid or running SL memory BHP gauges to determine type of influx 30. If producible hydrocarbons are determined to be present and the well will not flow, flow at a stabilized rate at surface and perform the following: o RIH with CT and establish nitrogen lift o Attempt to stabilize flow rate and nitrogen injection rate. o Collect surface samples o Flow and shut in well as directed in detailed procedure 31. If formation damage is suspected. Perform an acid stimulation according to the separate detailed procedure (to be supplied by service provider). 32. If well will flow on its own: o Run SL BH samplers o Collect surface samples o Flow and shut in well as directed in service provider s procedures 33. When Flow rate is stabilized and BSW < 1%, Formation fluid will be directed through separator and flow rates will be selected at the choke manifold. 34. Shut in well for intermediate Build Up (BU) 35. Re-open MCTV for Main flow period 36. Shut in well for final Build Up (BU) 37. At end of final BU, lock open MCTV and bullhead tubing contents into formation 38. Close MCTV and cycle MCCV to reversing position. Reverse circulate working fluid 39. Cycle MCCV to circulating position and circulate bottom up to homogenize well fluid to its original weight 40. Close MCCV and open MCTV back to well test position. Open packer bypass Rev.4.5, 26 Feb 2016 Page 145

147 and check for losses. Spot pill if needed. 41. Unseat packer and bullhead contents below packer. 42. POOH, LD DST tools, transfer samples and recover downhole memory gauge. 43. Provide MEMORY GUAGE readings (ascii files), final job log and work documents 44. Confirm samples and BHP data are adequate. 45. MU composite Bridge Plug (BP), RIH on test string and set above perforations. 46. Test BP and casing. 47. Dump cement on top of composite BP. 48. Repeat procedure beginning at step 8 until all intervals are tested. * BNI to confirm if P&A shall be carried out after cased-hole tests are completed. Surface & Down Hole Test Equipment Major surface equipment list is as per below for testing the 12 ¼ & 8 ½ hole & 6 Hole. Surface equipment should be rated to 15K psi. In cases where anticipated flaring should exceed 1% H 2 S o flare booms will be located a minimum of 300m away from the camp o flare stack positioned minimum 12M high. o Velocity should not exceed 95.6 m/s. SURFACE TESTING EQUIPMENT Item Description 1 15K psi Surface Test Tree /w Stiff Joint K Flexible Flowline 3 15K ESD Valve 4 Emergency Shut-Down System (ESD) 5 Upstream Choke Data Header 15K 6 Chemical Injection Pump 7 15K Choke Manifold 8 3" 15K Upstream Piping 9 3" / 4" Downstream Piping Separator 11 Oil /Gas Manifold 12 Oil Transfer Pump 13 Surge Tank 14 Calibrated Gauge Tank 15 3 Head burner(s) with diesel pilots. 16 Air Compressors 17 Propane Skid / Rack 18 Data Acquisition System 19 Laboratory Cabin Rev.4.5, 26 Feb 2016 Page 146

148 DST EQUIPMENT Item Description 1 7 HDL Compression - Set Packer 2 9 5/8 HDL Compression - Set Packer 3 Safety Joint 4 Hydraulic Jar 5 Tubing Test Valve 6 Downhole Safety Valve 7 Gauge Carrier 8 Memory Quartz Gauge x 4 9 Multi Cycle Tester Valve 10 Multi Cycle Reversing Valve 11 Single-Shot Kill Valve 13 Expansion Joint (each) 14 15K psi Well Head Safety Valve 15 X-Over API 17 Service Container /w Spares & Related Equipment Rev.4.5, 26 Feb 2016 Page 147

149 Example TCP AND DST STRING DIAGRAM Rev.4.5, 26 Feb 2016 Page 148

150 Example Tester Valve Calculations Example Rupture Discs Selection Above Rupture disc calculation would require 4000 psi casing pressure test prior the job. Rev.4.5, 26 Feb 2016 Page 149

151 Downhole DST Tool Requirements A standard DST string is required to enable the following operations to be carried out safely and efficiently: Downhole shut-in Annulus reversing and circulating capability Pressure testing BHA to 10,000 psi The equipment should be rated for 15,000 psi WP and suitable for H 2 S and CO 2 service. All downhole tools that may be exposed to wellbore fluids will be full sour services material as per NACE MR-0175 to the anticipated H2S levels of 7.5%+. BNI to confirm with SOC on open-hole testing regulations and maximum permissible concentrations of H 2 S/CO 2 to ensure HSE compliance. Example description of tool specifications is listed below and must be confirmed by the Service Company with the Contractor prior to mobilizing for the job. Description Quantity Specifications Retrievable Compression Set Packer Retrievable Compression Set Packer Full Bore Safety joint Hydraulic Jar Tubing Tester Valve - TTV Down Hole safety Valve DHSV Full Bore Gauge Carrier Downhole Quartz Memory Gauge Multi-Cycle Tester Valve MCTV Two Two Two Two Two Two Two Eight Two 7 HDL 26-32# 1/4 RHT to set, straight pull to unset; integral bypass & Hold down slips, 3.5 IF or 3.5 PH6 connections avail., 2.37 ID, 10,280 psi above & 9,580 psi below, 275 F, NACE MR / #, same features, 4.5 IF or 3.5 PH6 connections avail., ID, 9435 psi above & 7355 psi below, 275 F, NACE MR OD * 2.25 ID, Right Hand Rotation w/shear pins, come w/overshot, 3.5 IF or 3.5 PH6 connections avail., 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 2.25 ID, 3.5 IF or 3.5 PH6 connections avail., 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 2.25 ID, ball valve w/fill thru feature, annulus pressure operated, once open does not reclose, 3.5 IF or 3.5 PH6 connections avail., 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 2.25 ID, ball valve w/pump thru feature, annulus pressure operated, once closed does not reopen, 3.5 IF or 3.5 PH6 connections avail., 15,000 psi, 350 F, 350klb tensile, NACE MR OD offset * 2.25 ID for 4 MEMORY GUAGE gauges to read tubing and/or annulus Pres. & Temp, 3.5 IF or 3.5 PH6 connections avail., 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 36 L, 16,000 psi, Acc %, Res %, 302 F,, Acc F, Res. < F, CC Lithium Battery (3.6 V), Selectable 1 sec. min. 2.8 Million Data Points, Inconel 718 / Hastelloy C OD * 2.25 ID, 3.5 IF or 3.5 PH6 connections avail., unlimited opening/closing cycles, lock open position feature, annulus pressure operated, 15,000 Rev.4.5, 26 Feb 2016 Page 150

152 Multi-Cycle Circulating Valve MCCV Single Shot Kill Valve SSKV Full Bore Expansion Joint Model A Fail Safe Valve Crossovers Spares and consumables DST workshop and spares storage Related equipment Two Two Two Two As required As required One + one As required psi, 350 F, opening w/ 5,000 psi max diff. pres., 350klb tensile, NACE MR OD * 2.25 ID, 3.5 IF or 3.5 PH6 connections avail., unlimited opening/closing cycles, differential pressure operated, change of fluid direction to close; Circulating, reversing & spotting tool, 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 2.25 ID, 3.5 IF or 3.5 PH6 connections avail., annulus pressure operated, once open does not reclose, Circulating & reversing tool, 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 2.25 ID, 3.5 IF or 3.5 PH6 connections avail., compensates for expansion & contraction of the string, 15,000 psi, 350 F, 350klb tensile, NACE MR OD * 3 ID, 3.5 PH6 connections, installed across BOP, Hydraulic lines controlled, Ball valve w/pump thru feature can cut 5/16 WL cable (mode 1)or 1-1/2 CT (mode 2), 10,000 psi, 350 F, 450klb tensile, NACE MR-0175 Available in 3 1/2" IF and 3 1/2" connections for all tools, 2 7/8 EUE and 4 1/2" IF for packers, NACE MR-0175 Available for 10 runs for onsite maintenance and repair Available for DST tools maintenance and repair on rig site Pressure test pump 25k psi WP, N2 pump 9k psi WP, FSV Control Panel 10k psi WP, complete hand tool set for maintenance Rev.4.5, 26 Feb 2016 Page 151

153 Appendix 4 Wireline Logging Program Rev.4.5, 26 Feb 2016 Page 152

154 Scope of Work Outline As provided by Bashneft, the firm wireline logging program to be run in the open hole in SALMAN-1 is planned to achieve the following tasks: 1. Detect HC in the drilled section based on the qualitative and quantitative reservoir characterization parameters recorded and interpreted in the process of WL logging. 2. Determine rock physics properties of potential sandstone and carbonate reservoirs based on a variety of methods (saturation, porosity, Vshale, mineralogy, density, gross and net pay). 3. Evaluate the wellbore stability and rock mechanics properties with the help of the acoustic data (array/full-wave or dipole/cross-dipole acoustics). 4. Identify and pick intervals characterized by secondary epigenetic porosity, especially in the complex heterogeneous carbonate reservoirs with well-developed fractures and/or vugs, from sonic and resistivity image logs. 5. Perform integrated reservoir characterization studies with nuclear magnetic resonance data. 6. Run velocity survey with VSP and acquire WL data for well-to-seismic tie-in (3D seismic volume) (density and sonic data). 7. Update the structural setting and the static reservoir model within the study area (dip, orientation, etc.). 8. Control the drilling process and downhole conditions. 9. Match core intervals to the WL data 10. Evaluate reservoir pressure and obtain fluid samples with WL formation tester in the intervals of potential reservoirs (CONTINGENCY, ONLY IF IT IS IMPOSSIBLE TO RUN DRILL-STEM TESTS). As provided by Bashneft, the firm wireline logging program to be run in the cased hole in SALMAN-1 is planned to achieve the following tasks: 1. Control cement bond quality and integrity. 2. Evaluate the technical conditions and integrity of the wellbore and casing. 3. Tie-in and match the potential targets for cased-hole testing. During cased-hole testing the selection of the target intervals and their correlation to be performed with the following logs: CCL, GR, Neutron (Pulsed Neutron) and for flow control additional logs will be run including barometry, flow metering, (thermoanemometry), watercut logs and resistivity measurements. If acidizing or other stimulation job is required (TBA) logging should be done prior and after the treatment. As an option offset vertical seismic profiling is planned to assess the development of the carbonate reservoirs in the section (subject to their high heterogeneity) and evaluate the near-wellbore zone of the penetrated formations. Rev.4.5, 26 Feb 2016 Page 153

155 Firm Wireline Logging Suite in the Open-Hole Hole Size Interval Description Scale Comments Caliper, Gamma-ray spectrometry, Intermediate logging prior 26 Neutron, Full-way acoustic* and to setting the surface m General (660.4 mm) Induction*, mud resistivity, directional casing survey, and (optional) temperature log 17.5 (444.5 mm) 12-1/4 (311.2 mm) 8-1/2 (215.9 mm) 6 (152.4 mm) m m m m m m Caliper, Gamma-ray spectrometry, Neutron, Full-way acoustic* and Induction*, mud resistivity, directional survey, temperature log Caliper, Array (multi-sonde) lateral log, Array (multi-sonde) induction log, Gamma-ray spectrometry, Spectral Neutron, Litho-Density Log, Full-wave acoustic/dipole acoustic, Microresistivity mud resistivity, directional survey, temperature log In the reservoir intervals add: Nuclear Magnetic Resonance, sonic and resistivity image logs Caliper, Array (multi-sonde) lateral log, Array (multi-sonde) induction log, Gamma-ray spectrometry, Spectral Neutron, Litho-Density Log, Full-wave acoustic/dipole acoustic, Microresistivity mud resistivity, directional survey, temperature log In the reservoir intervals add: Nuclear Magnetic Resonance, sonic and resistivity image logs Caliper, Array (multi-sonde) lateral log, Array (multi-sonde) induction log, Gamma-ray spectrometry, Spectral Neutron, Litho-Density Log, Full-wave acoustic/dipole acoustic, Microresistivity mud resistivity, directional survey, temperature log In the reservoir intervals add: Nuclear Magnetic Resonance, sonic and resistivity image logs In-situ rock temperature measurements ** Check-shots/VSP*** General Detailed Detailed Detailed Intermediate logging prior to setting the intermediate casing m: Investigation of Sa di, Tanuma, Khasib, Msa ad, Mishrif, Rumaila, Ahmadi, Mauddud, Nahr Umr m: Investigation of Nahr Umr, Shuaiba, Zubair m: Investigation of Zubair, Ratawi m: Investigation of Ratawi, Yamama, Sulaiy, m: Investigation of Gotnia & Najmah m: Investigation of Najmah, Sargelu, Alan, Mus, Adaiyah m: Investigation of Alan, Mus, Adaiyah, Butmah m: Investigation of Butmah m: Investigation of Butmah & Kurra Chine m: Investigation of Kurra Chine Final logging For geothermal gradient Velocity data, for well-toseismic tie-in Notes * subject to the availability and specifications of the tools (investigation depth, etc.) ** at least 10 days after the completion of the drilling operations (requires additional approval). *** possible both in the open hole and cased hole subject to the availability of the required equipment, downhole conditions and wellbore stability. Rev.4.5, 26 Feb 2016 Page 154

156 Casing Drift ID (471.0 mm) (311.4 mm) (215.9 mm) (152.4 mm) (92.1 mm) Firm Wireline Logging Suite in the Cased-Hole Interval Description Scale Comments m m m m m Gamma ray, Cement bond log (acoustic), Variable density log, Cement density log (Gamma-gamma log for cement bond), Casing collar locator Gamma ray, Cement bond log (acoustic), Variable density log, Cement density log (Gamma-gamma log for cement bond), Casing collar locator Gamma ray, Cement bond log (acoustic), Variable density log, Cement density log (Gamma-gamma log for cement bond), Casing collar locator Gamma ray, Cement bond log (acoustic), Variable density log, Cement density log (Gamma-gamma log for cement bond), Casing collar locator Gamma ray, Cement bond log (acoustic), Variable density log, Cement density log (Gamma-gamma log for cement bond), Casing collar locator General General General General General Control integrity of cement bond behind the surface casing Control integrity of cement bond behind the intermediate casing Control integrity of cement bond behind the production casing Control integrity of cement bond behind Liner I Control integrity of cement bond behind Liner II Rev.4.5, 26 Feb 2016 Page 155

157 Technical Work Scope for Modular Formation Testing This document details the proposed formation testing activity in 11 target formations: Target Interval, m Formation Hole Size Msa ad/mishrif, carbonates / 311.2mm Nahr Umr, sandstones / 311.2mm Zubair, sandstones / 311.2mm Zubair, sandstones / 311.2mm Ratawi, carbonates / 311.2mm Yamama, carbonates / 311.2mm Najmah, carbonates 8.5 / 215.9mm Sargelu, carbonates 8.5 / 215.9mm Mus, carbonates 8.5 / 215.9mm Butmah, carbonates 8.5 / 215.9mm Kurra Chine, carbonates 6 / 152.4mm Formation Testing can be performed using a variety of tools. Rev.4.5, 26 Feb 2016 Page 156

158 Guidelines for Formation Testing: 1. Slim formation testing tool is recommended to be used for obtaining pressure data in all hole sizes. This is to be done before any sampling attempt. This is to gauge the hole conditions for a bigger tool (and its longer stay) in the hole, and reduce operational hazards and stuck ups. 2. Where formation permeability is low (below 0.1 md), or where fractures are to be tested, compact logging tool with packer assembly is recommended to be run with Drill Pipe. Flow modeling to be done to predict cleanup time (which depends on porosity and time since drilling affecting the invasion) for each point to be tested. Expected response in the Fluid measurements and Identification sensors should be made as part of pre job planning to be able to detect fluid changes. In-flow should be monitored real time by site and town Petrophysicist/Reservoir engineer for faster decision making. Rev.4.5, 26 Feb 2016 Page 157

159 Work Scope for each Formation: Scope of work may change depending on formation visibility on the logged data and depths provided here are only for reference and should be checked with recorded open hole logs and formation tops observed. A. Mishrif Formation: Formation: Mishrif Lithology: Carbonates Expected Depth Range m Expected Porosity 10-15% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 2m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec B. Nahr Umr Formation: Formation: Nahr Umr Lithology: Sand Shale Sequence Expected Depth Range m Expected Porosity 20% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 2m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec Depths of the test points may be modified if there are thick shale layers in the interval. Rev.4.5, 26 Feb 2016 Page 158

160 C. Zubair Formation: Zubair Lithology: Sand Shale Sequence Expected Depth Range m Expected Porosity 18% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 2m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec Depths of the test points may be modified if there are thick shale layers in the interval. D. Zubair Formation: Zubair Lithology: Sand Shale Sequence Expected Depth Range m Expected Porosity 18% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 1m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec E. Ratawi Formation: Ratawi Lithology: Mixed Lithology Expected Depth Range m Expected Porosity 12-15% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 3m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec Rev.4.5, 26 Feb 2016 Page 159

161 F. Yamama: Formation: Yamama Lithology: Limestone Expected Depth Range m Expected Porosity 12-15% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 3m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec G. Najmah Formation: Najmah Lithology: Limestone Expected Depth Range m Expected Porosity 10-12% Conveyance: Wireline surface Readout Pressure Testing Points: 10 Pressure Testing Depths m spaced at 20m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.5 cc/sec Depths of the test points may be modified if they fall into the lower shale zone H. Sargelu Formation: Sargelu Lithology: Dolomite Expected Depth Range m Expected Porosity 5-10% Conveyance: Wireline surface Readout Pressure Testing Points: 5 Pressure Testing Depths m spaced at 2m Testing Objective: Formation Pressure, fluid Gradient to fluid identification and fluid contacts Pretest Rate: 0.1 cc/sec Rev.4.5, 26 Feb 2016 Page 160

162 I. Alan Mus Adaiyah: Formation: Alan, Mus, Adaiyah Lithology: Dominantly Dolomite Expected Depth Range m Expected Porosity 3-5% Conveyance: Pipe conveyed surface readout Pressure Testing Points: 5 Pressure Testing Depths m with packer spacing of 5m Testing Objective: Pretest Rate: Formation Pressure and Sample 0.1 cc/sec Alan, Mus and Adaiyah are tight dolomitic formations. If a prospect is seen on the log data, a packer based RES tool is recommended to test the formation. Packer spacing can be kept 2-3 m depending on hole conditions. Water sample is recommended in one test point. PVT sample is recommended at two points for detected hydrocarbons. J. Butmah Formation: Butmah Lithology: Dominantly Dolomite with Anhydrite beds Expected Depth Range m Expected Porosity 3-5% Conveyance: Pipe conveyed surface readout Pressure Testing Points: 5 Pressure Testing Depths m spaced at 5m Testing Objective: Pretest Rate: Formation Pressure and Sample 0.1 cc/sec Butmah is a tight dolomitic formation. If a prospect is seen on the log data, a packer based RES tool is recommended to test the formation. Packer spacing can be kept 2-3 m depending on hole conditions. Water sample is recommended in one test point. PVT sample is recommended at two points for detected hydrocarbons. Rev.4.5, 26 Feb 2016 Page 161

163 K. Kurra Chine Formation: Kurra Chine Lithology: Dominantly Dolomite with Anhydrite beds Expected Depth Range m Expected Porosity 3-8% Conveyance: Pipe conveyed surface readout Pressure Testing Points: 5 Pressure Testing Depths m with (if used) packer spacing of 5m Testing Objective: Formation Pressure, PVT sample. Pretest Rate: 0.1 cc/sec Pump out module tool is recommended to be run with low flow rates, as formations are tight. One water sample is recommended to be taken. PVT samples of the hydrocarbons are to be taken and sent to laboratory for further analysis. Rev.4.5, 26 Feb 2016 Page 162

164 Typical Formation Testing Responses 1. Normal Fluid blow and buildup with a repeat 2. Typical Pressure Profile with insufficient initial draw down: Rev.4.5, 26 Feb 2016 Page 163

165 3. Low Permeability Formation Flow Profile: 4. Tight Formation with no flow profile: Rev.4.5, 26 Feb 2016 Page 164

166 5. Formation Response in unconsolidated Formation with tool plugging: 6. Pressure Profile in low permeability formation with gas breakout of the fluid: Rev.4.5, 26 Feb 2016 Page 165

167 Appendix 5 Cementing Program Rev.4.5, 26 Feb 2016 Page 166

168 30in CASING CEMENT JOB PROCEDURES 30 Conductor will be pre-installed as part of the civil site works. Casing will be installed vertically to a depth of 30m and cemented 20in CASING CEMENT JOB PROCEDURES 1. Review the job procedures, well data, calculation and volume with Drilling supervisor. 2. Hold a pre job safety meeting with all personnel involved with the cementing operation. Ensure that all key personnel are able to communicate throughout the job. 3. RIH 5in 19ppf DP with 5in Stab in adapter until 1m above shoe. 4. Rig up circulating head with TIW valve on the last joint of drill pipe. 5. Pressure test 2in line to 2,000 psi for 10 min. 6. Fill conductor and DP with mud prior to sting-in stinger. 7. Sting-in to the shoe and establish circulation. Make sure that stinger is place and is not jumping out of the shoe by observing no returns from inside the casing due to circulating pressure. 8. Pump 30 bbl water 5 bpm. 9. Mix and pump 318.2bbl of 15.8ppg cement slurry at 5 bpm. 10. Displace with 11.1bbl of water with cement unit. 11. Sting out and reverse circulate to make sure there is no cement inside drill pipe. 12. Ensure all pressure is released prior to rig down. 13. Conduct pre rig down safety meeting. NOTE: Don t start mixing until confirm by company man. Keep on pumping cement until cement returns to the surface. Rev.4.5, 26 Feb 2016 Page 167

169 13-3/8in CASING CEMENT JOB PROCEDURES 1. Condition the mud prior to the cement job. Bring mud YP as low as possible depending on well conditions. This has to be done & confirmed by Mud Engineer on rig. Keep well under circulating condition before the cement job, recommended minimum volume is twice the open hole volume (bottom up). If losses are recorded, follow client s instructions. 2. Review the job procedures, well data, calculations and volumes with the drilling supervisor and the mud engineer. 3. Hold pre-job safety meeting with all persons involved with the cementing operations. 4. Prepare mix fluid and spacer. Take samples. 5. Remove circulation head / swage from the casing. 6. Verify top and bottom plugs. 7. Install preloaded WFT quick stab cement plug container on the casing. 8. Pump 10 bbl of fresh water, close 2 valve on cement head & pressure test 2 line to 4,000 psi for 10 min. 9. Pump 30 bbl weighted 5 bpm. 10. Drop bottom plug and verify initiation on the plug Container. Reset the flag position. 11. Mix and pump 426 bbl of 13.5ppg cement 5 bpm. 12. Mix and pump 276 bbl of 15.8ppg cement 5 bpm. 13. Drop top plug and verify initiation on the plug Container. 14. Pump displaces 10bbl water with cement unit. 15. Switch to rig pump and pump displace with following sequence: i. Pump 576 bbl of 7 bpm ii. Pump 30 bbl of 5 bpm iii. Pump 20 bbl of 2 bpm 16. The pumping rates are as per CEMPRO software simulation. Ensure that rates should not go beyond the maximum calculated. 17. Bump plug on the float collar by applying 1000 psi above the differential and hold up for 10 minutes. 18. Bleed off the pressure, and check returns. 19. If float does not hold, pump back the return volume & close the valve on surface. 20. Ensure all pressure is released prior to rig down. 21. Conduct pre rig down safety meeting. NOTE: Don t start mixing until confirm by Company Man. Displacement volume should be re calculated on rig and agreed by Company Man. Don t over displace above the half shoe track in any case. Rev.4.5, 26 Feb 2016 Page 168

170 9-7/8in CASING CEMENT JOB PROCEDURES 1. Condition the mud prior to the cement job. Bring mud YP as low as possible depending on well conditions. This has to be done & confirmed by Mud Engineer on rig. Keep well under circulating condition before the cement job, recommended minimum volume is twice the open hole volume (bottom up). If losses are recorded, follow client s instructions. 2. Review the job procedures, well data, calculations and volumes with the drilling supervisor and the mud engineer. 3. Hold pre-job safety meeting with all persons involved with the cementing operations. 4. Prepare mix fluid and spacer. Take samples. 5. Remove circulation head / swage from the casing. 6. Verify top and bottom plugs. 7. Install preloaded WFT quick stab cement plug container on the casing. 8. Pump 10 bbl of fresh water, close 2 valve on cement head & pressure test 2 line to 4,000 psi for 10 min. 9. Pump 30 bbl weighted 5 bpm. 10. Drop bottom plug and verify initiation on the plug Container. Reset the flag position. 11. Mix and pump bbl of 16.5ppg cement 5 bpm. 12. Mix and pump bbl of 17ppg cement 5 bpm. 13. Drop top plug and verify initiation on the plug Container. 14. Pump displaces 10bbl water with cement unit. 15. Switch to rig pump and pump displace with following sequence: i. Pump 501 bbl of 7 bpm ii. Pump 30 bbl of 5 bpm iii. Pump 20 bbl of 2 bpm 16. The pumping rates are as per CEMPRO software simulation. Ensure that rates should not go beyond the maximum calculated. 17. Bump plug on the float collar by applying 1000 psi above the differential and hold up for 10 minutes. 18. Bleed off the pressure, and check returns. 19. If float does not hold, pump back the return volume & close the valve on surface. 20. Ensure all pressure is released prior to rig down. 21. Conduct pre rig down safety meeting. NOTE: Don t start mixing until confirm by Company Man. Displacement volume should be re calculated on rig and agreed by Company Man. Don t over displace above the half shoe track in any case. Rev.4.5, 26 Feb 2016 Page 169

171 7in LINER CEMENT JOB PROCEDURES 1. Condition the mud prior to the cement job. Bring mud YP as low as possible depending on well conditions. This has to be done & confirmed by Mud Engineer on rig. Keep well under circulating condition before the cement job, recommended minimum volume is twice the open hole volume (bottom up). If losses are recorded, follow client s instructions. 2. Review the job procedures, well data, calculations and volumes with the drilling supervisor and the mud engineer. All must be agree before commencing the operations. 3. Hold pre-job safety meeting with all persons involved with the cementing operations 4. Prepare mix fluid and start mixing Spacer. Take samples. 5. Pump 10 bbl of fresh water, close 2 valve on cement head & pressure test 2 line to 4,000 psi for 10 min. 6. Pump 30 bbl weighted 5 bpm. 7. Mix & pump 85 bbl of 18.5ppg cement 5 bpm. 8. Mix & pump 51 bbl of 19ppg cement 5 bpm. 9. Release DP wiper plug / Dart. 10. Pump displaces 10bbl water with cement unit. 11. Switch to rig pump and pump displace with following sequence: i. Pump 247 bbl of 7 bpm ii. Pump 30 bbl of 5 bpm iii. Pump 20 bbl of 2 bpm 12. During displacement Mud Engineer has to monitor the displacement volume physically in order to avoid under displacement. 13. The pumping rates are as per CEMPRO software simulation. Ensure that rates should not go beyond the maximum calculated. 14. Bump the plug as per liner hanger engineer instruction. 15. Once bump the plug, bleed off the pressure, and check returns. 16. If float does not hold, pump back the return volume & close the valve on surface. 17. Ensure all pressure is released prior to rig down. 18. Conduct pre rig down safety meeting. NOTE: Don t start mixing until confirm by Company Man. Displacement volume should be re calculated on rig and agreed by Company Man. Don t over displace above the half shoe track in any case. Rev.4.5, 26 Feb 2016 Page 170

172 4.5in LINER CEMENT JOB PROCEDURES 1. Condition the mud prior to the cement job. Bring mud YP as low as possible depending on well conditions. This has to be done & confirmed by Mud Engineer on rig. Keep well under circulating condition before the cement job, recommended minimum volume is twice the open hole volume (bottom up). If losses are recorded, follow client s instructions. 2. Review the job procedures, well data, calculations and volumes with the drilling supervisor and the mud engineer. All must be agree before commencing the operations. 3. Hold pre-job safety meeting with all persons involved with the cementing operations. 4. Prepare mix fluid and spacer. Take samples. 5. Pump 10 bbl of fresh water, close 2 valve on cement head & pressure test 2 line to 4,000 psi for 10 min. 6. Batch mix 44.8 bbl of 20ppg cements slurry. 7. Pump 20 bbl weighted 5 bpm. 8. Pump batch-mixed 44.8 bbl cement 5 bpm. 9. Release DP wiper plug / Dart. 10. Pump displaces 5 bbl water with cement unit. 11. Switch to rig pump and pump displace with following sequence: Pump 66.5 bbl of 7 bpm Pump 30 bbl of 5 bpm, Pump 20 bbl of 2 bpm. 12. During displacement Mud Engineer has to monitor the displacement volume physically in order to avoid under displacement. 13. The pumping rates are as per CEMPRO software simulation. Ensure that rates should not go beyond the maximum calculated. 14. Bump the plug as per liner hanger engineer instruction. 15. Once bump the plug, bleed off the pressure, and check returns. 16. If float does not hold, pump back the return volume & close the valve on surface. 17. Ensure all pressure is released prior to rig down. 18. Conduct pre rig down safety meeting. NOTE: Don t start mixing until confirm by Company Man. Displacement volume should be re calculated on rig and agreed by Company Man. Don t over displace above the half shoe track in any case. Rev.4.5, 26 Feb 2016 Page 171

173 PROVISION OF CEMENTING SERVICES SALMAN-1 Vertical Depths OH Casing Shoe Mud Lead Slurry Tail or Single Slurry Temperatures Spacer Rate Casing M.D. T.V.D. Size Size Weight I.D Length Weight TOC X.S. Weight TOC X.S. Weight BHST BHCT Weight Vol m m in. in. lbs./ft. in. m ppg m % ppg m % ppg F F ppg bbls. bpm 30" Conductor Csg " Surface Csg /8" Csg /8" Csg " Liner " Liner Spacer Lead Tail Disp Units 30.0 in. Casing 30 in. Csg. Vols bbls 30 m. M.D m3 30 m. T.V.D. Est. Pump Rate BPM 20.0 in. Casing Est. Time to Displace mins 190 m. M.D. Est. Pump Time Required N/A 1:35 hours 190 m. T.V.D. Spacer Lead Tail Disp Units 800 m, M.D. 20 in. Csg. Vols bbls 13 3/8" Csg Tail TOC m3 Est. Pump Rate BPM Est. Time to Displace mins 13 3/8" Csg Est. Pump Time Required N/A 2:25 hours 1,300 m. M.D. Spacer Lead Tail Disp Units 1,300 m. T.V.D in. Csg. Stg bbls m3 Est. Pump Rate BPM 1,930 m, M.D. Est. Time to Displace mins 9 7/8" Csg Tail TOC. Est. Pump Time Required 5:45 4:20 hours in. Csg. Vols. Spacer Lead Tail Disp Units 7" Liner Liner Top bbls 9 7/8" Csg 2,300 m, M.D m3 2,300 m. M.D. 7" Liner Lead TOC. Est. Pump Rate BPM Est. Time to Displace mins in. Casing Est. Pump Time Required 4:46 3:31 hours 2,400 m. M.D. Spacer Lead Tail Disp Units 2,400 m. T.V.D. 7 in. Csg. Vols bbls m3 3,200 m, M.D. Est. Pump Rate BPM 7" Liner Tail TOC. Est. Time to Displace mins 4.5" Liner Liner Top Est. Pump Time Required 2:46 2:29 hours 3,550 m. M.D. 3,550 m, M.D. Spacer Lead Tail Disp Units 4.5" Liner TOC in. Csg. Vols bbls 7" Liner m3 3,700 m. M.D. Est. Pump Rate BPM 3,700 m. T.V.D. Est. Time to Displace mins Est. Pump Time Required N/A 1:52 hours 4.5" Liner 4,245 m. M.D. 4,245 m. T.V.D. Rev.4.5, 26 Feb 2016 Page 172

174 Appendix 6 Drilling with Casing (Contingency Plan and subject to approval) Rev.4.5, 26 Feb 2016 Page 173

175 Drilling with Casing Program 17-1/2 OH section BASHNEFT Iraq ** Dra ft unti l all sig nat ure s pro vided Date: 7 April 2016 Prepared for: BASHNEFT Iraq Drilling with 13-3/8 Casing to Planned TD Job No: Version** 1.0 WPTS No: RwC Supervisor Date Signature Regional BU Manager Date Signature Drilling Engineer Date Signature Drilling Superintendent Date Signature Drilling Manager Date Signature Rev.4.5, 26 Feb 2016 Page 174

176 This procedure is completed in conjunction with the appropriate JSA in the event of instituting the Drilling with Casing (DwC) contingency plan which is further subject to approval. Objective of Drilling with Casing As an optimization measure, the drillable casing bit may be utilized across the 17-1/2 OH section to land the 13-3/8 Casing while managing anticipated drilling hazards (hole instability across Tanuma). The interval is to be drilled with conventional BHA till top of Sadi then POOH and run the 13-3/8 casing with Casing bit till current TD; once at TD, drill through Sadi and Tanuma formation and set the casing within Khasib. The technique allows for minimal exposure time across the unstable tanuma shale. Equipment 13-3/8 x 16 Drillable Casing bit. 13-3/8 402 Float collar (x1) 13-3/8 68lb/ft. Torque Rings (as required) Rigid type Centralizer (optional) Casing joints and Casing Running Equipment TD Compact 500 with 13-3/8 Internal Clamping Tool and packer cups for circulation. Single joint elevator with 2ea of 40ft 5T wire rope slings complete with shackles Hand slips or hydraulic slips Safety clamp / dog collar Power tongs and back up tongs Responsibility TBA Drilling with Casing Supervisor (x2) Overall Role and Responsibilities Main point of contact with the client Drilling Supervisor Accountable for all drilling with casing activities. Responsible for operational HSE risk assessment and management/mitigation associated with drilling with casing operations. Support preparation and required revisions to operational procedure. Supports pre-job preparations in the well-site. Lead toolbox talks and job safety analysis (JSA). Provide detailed instructions to the driller/rig crew during operations. Responsible for post job data acquisition processing and reporting. Rev.4.5, 26 Feb 2016 Page 175

177 Well-Site and Equipment Inspection Ensure all of the above equipment is on location. Rig crew to ensure that following tasks are performed prior to the casing running/drilling operation. Check casing tally against number of casing joints and spare onboard. Visually inspect casing. Drift casing on pipe deck. Clean threads and apply API casing thread lubricant on pipe deck. Install centralizers on the pipe deck where possible. Ensure the shoe joint has the Casing Bit made up to it onshore to the correct torque. Check Casing Bit cutting structure for any damage incurred during transport. Check and record Casing Bit serial number, tool size and type. Check that all Casing Bit ports/nozzles are clear. Ensure the nozzles size are as per proposed in the Hydraulic Analysis report. Confirm that the Casing Bit is clear of debris and any other material that may cause an obstruction. Check shoe joint, float collar joint and casing joints to ensure the casing connection dimension are compatible to the surface casing drive system as per plan. Hold pre-job safety meeting as per JSA to review well control and safety procedures. DwC field Personnel must be on the rig floor to supervise the rig up and make up of the surface casing drive system to the Top Drive System. NOTE: Alignment of the surface casing drive system is critical. If rig misalignment problem between the Top Drive System and the Rotary Table was found critical, RwC personnel should, and are required to stop the job and consult with the Company Representative and Rig Tool Pusher. Any changes to DP pup joints, x-over, etc. between surface casing drive system and the top drive must be reviewed and approved by TDS team Applications Engineers. Clean and prepare joints for thread locking compound. Consult with company representative to establish the number of connections to be thread locked. Ensure casing tally reflects the joint numbers requiring thread locking compound. Rev.4.5, 26 Feb 2016 Page 176

178 Operations 1. Hold pre-job safety meeting to communicate the Drilling with Casing with TD compact procedures. Ensure everyone involved with the DwC operation is aware of their roles and responsibilities. Remind all involved that they are empowered to STOP the job if they are unsure or deemed unsafe. 2. Brief Driller and Assistant Driller on planned Drilling parameters in below Table 1 or as per the DwC Driller Summary Checklist prepared by TDS team during the job. Recommended Operating Parameters While Drilling Through The 17-1/2 OH Section Minimum Rotary Speed 40 Maximum Rotary Speed 80 Minimum Weight on Bit Maximum Weight on Bit Minimum Flow Rate Maximum Flow Rate Minimum Torque 6,000 lbf 16,000 lbf 550 gpm 800 gpm 3000 ft.lbs Maximum Torque 90% of max conn. make-up torque Table 1: Recommended Drilling Parameters /2" OH section 3. Rig up casing handling equipment: slips, SJE, tongs, etc. a. Make up surface casing drive system to the top drive, as per agreed plan with correct & approved pup joints and x-overs. 4. Pick up shoe joint with bit attached and set in Slips. Break circulation slowly. Bring pump up to 200gpm to check flow. Zero the weight indicator, record pump pressure. Set torque limiter to maximum M/U torque of the 13-3/8 casing connection. 5. Make up float collar joint. (Tube-lok all shoe track joints as per instruction of BASHNEFT.) 6. Continue running casing in hole. Torque connection as per thread manufacturer s specifications. 7. Fill casing every joint. Fill casing to surface every five joints run. 8. Record pick-up and slack off weights every joint. Monitor for any abnormal trends. 9. Continue running casing in until enter open hole. When entering open hole, zero the weight indicator, record pump pressure, stand pipe pressure and torque. Rev.4.5, 26 Feb 2016 Page 177

179 RUNNING CASING ACROSS OPEN-HOLE SECTION 10. Wash and trip in the casing slowly and carefully monitoring WOB, torque and pressure. 11. When tight spot is encountered, pick up the casing string a few meters, establish planned Drilling parameters and record torque, pressure, pick-up and slack off weights. Planned reaming parameters across the OH section will be as below: RPM : WOB : 1 2 tons Flow : gpm Torque : Up to 90% of Connection Make-Up torque Always kick in the pumps and rotate before going to bottom 12. Once at bottom hole, drill ahead till planned TD. Planned Drilling parameters will be as below: RPM : WOB : 1 2 tons Flow : gpm Torque : Up to 90% of Connection Make-Up torque Remember that excessive RPM and WOB will create side track hole Do not rotate TD Compact 500 at more than 100rpm for prolonged duration. Monitor pump pressure carefully, an increase in pressure and torque may indicate bit balling. Should this occur, mark the pipe at current depth and pick up off bottom. Fanned the bit by establish rotation and flow at maximum recommended parameters (100rpm) to wash the bit clean of cuttings. Reduce RPM and lower casing to previous depth at full flow rate. If stringers (Conglomerates) are encountered; maximum flow-rate (800gpm) is recommended to generate sufficient Jet Impact Force as required; this will minimize potential wears on the cutter blades Drilling with very low RPM (<30rpm) will generate Stick-slip vibrations, the Rotary speed should be kept within the defined range (40-80rpm) while varying WOB accordingly to manage ROP. Drilling within recommended optimum flow-rate range of gpm to ensure that a good annular velocity 170ft/min is maintained while drilling the interval. (detailed hydraulics simulation will be carried for respective operations). 13. Drill with casing to plan and agreed Total Depth (TD). 14. Circulate hole clean and pump hi-vis. When using high viscosity sweeps avoid excessive ECD, which will increase the possibility of breaking down the formation. Rev.4.5, 26 Feb 2016 Page 178

180 15. Stop pumps and check well for flow. 16. Work the casing to ensure it is free. 17. Retrieve casing string and lay down excess casing joints with casing drive system to space out for installation of landing string and wellhead. 18. Rig down casing drive system. 19. Rig up the landing string. 20. RIH with wellhead running tool. 21. Cement as per cementing program 22. Bump plug with pressure specified by BASHNEFT Company Representative. 23. Check floats to ensure that they are holding. Green Cement Pressure tests may be performed at this stage. 24. Rig down cement head. 25. Break out and lay down landing string. 26. Rig down TRS equipment as per standard operating procedure. Rev.4.5, 26 Feb 2016 Page 179

181 Once Drilling hazard is identified and confirmed. The below contingency plans are recommended accordingly. Contingency Hazard Mitigation Plan 1.1 Fail to Reach TD Refer to Operator s procedures 1.2 Lost Circulation: While running casing continue to RIH at reduced rate. Fill hole with trip tank While circulating While drilling reduce circulating rate, pump LCM as required Casing landed - Begin cementing immediately While cementing - Land Hanger or position casing at setting depth 1.3 Float fails to hold Continue cementing minimum acceptable rate Partial returns: Monitor % returns with trip tank Total lost returns: Fill hole w/ trip tank Re-pressure plug. Bleed off pressure quickly to close floats WARNING: Attempt this no more than twice! Float still not holding: Pressure up to final circulating pressure & WOC 1.4 Shoe squeeze NOTE: Hold pressure for remainder of cement test pump time Braden head squeeze from surface 1.5 Stuck Pipe Refer to Operator s procedures. (Standard Casing Running procedure applies.) 1.6 Damaged joint If the joint torques up early or undue wobble is noticed, back out the joint and check connection. Lay down the joint if necessary and replace with similar length joint. 1.7 Well Flow - Casing in stack Refer to Operator s procedures Rev.4.5, 26 Feb 2016 Page 180

182 Appendix 7 Well Control & Contingency Plans Rev.4.5, 26 Feb 2016 Page 181

183 The main objective is to maintain well control during drilling, testing, and all well construction activities by a double barrier (after setting and cementing the surface casing). Well Control Policy 1. Refer to Well Control Manual. 2. Personnel safety is of primary importance. If the Toolpusher and/or Driller believe that there is danger of losing control of the well, the Drill Site Manager will take any actions necessary to ensure the safety of all personnel on the rig. a. Tool Pusher, Driller, Assistant Driller and Day and Night DSVs all require current IWCF certificates as per HSE requirements. 3. The well will be shut in as per rig well control shut-in procedure. 4. It will be desirable to keep the drill string moving if conditions permit in order to avoid differential sticking; however, high surface pressure may not permit this and the kill joint must be used. Procedures to be followed after an influx is detected are as follows. 5. While drilling: a. Pick up to position the drill pipe across the pipe ram and the safety valves above the rotary table. b. Shut in the well. c. Check SIDPP: i. If below 2000 psi: Close the annular Open the rams. ii. If above 2000 psi: Consider reciprocating the drill string as soon as possible. 6. While tripping: Shut the safety valve Break out the top drive Make up the kill joint Make up the top drive Make up 2 Lo-Torq valves and kill hose to the pump-in sub side outlet. Pressure test kill hose to 10,000 psi. Equalize pressure across the safety valve and open the safety valve. Rev.4.5, 26 Feb 2016 Page 182

184 a. Position the drill pipe across the pipe ram with tool joint at a working height above the rotary table. b. Make up a safety valve and close it. c. Shut in the well. d. Make up the top drive. e. Equalize pressure across the safety valve and open the safety valve. f. Check SIDPP: i. If below 2000 psi: Close the annular Open the rams. ii. If above 2000 psi: Consider reciprocating the drill string as soon as possible. Shut the safety valve Break out the top drive Make up the kill joint Make up the top drive Make up 2 Lo-Torq valves and kill hose to the pump-in sub side outlet. Pressure test kill hose max rating. Equalize pressure across the safety valve and open the safety valve. Note: It will be necessary to pump open the float to obtain accurate SIDPP. 7. Inform the Drill Site Manager immediately. The Drill Site Manager has the responsibility to alert all personnel at his discretion. 8. The person directly in control of the killing operation will be the Senior Toolpusher in full consultation with the Senior Drilling Supervisor and the Drill Site Manager. Should unexpected or abnormal conditions develop, shut in the well and reassess the situation. 9. Estimate the maximum surface pressure and maximum pit gain based on the SIDPP and initial pit gain for the first circulation of the Driller's Method to be able to check that surface pressure and pit gains are within the estimated values. 10. Use the Driller's Method to kill the well. In the event of a large influx and/or high surface pressure, particularly if the drill string must be stripped back to bottom, consider bullheading prior to implementing the Driller's Method. 11. The MGS mud seal will be circulated with mud at the mud weight in use at all times during a well kill. Rev.4.5, 26 Feb 2016 Page 183

185 12. Continuously monitor the MGS pressure to ensure that overloading does not occur. Set values for the controller box alarm and the dump controller box signal to automatically vent will be calculated based on the mud weight circulated in the mud seal with the hot loop system as per drilling contractor work instructions Contingency Plans 1. Lost Circulation a. Keep the hole full. b. Minor losses will be treated with LCM. c. Severe losses will be treated with cement plugs. d. In the event of a repetitive loss / gain situation, ECD drilling techniques, LCM treatment of the mud system, and, if necessary, cement plugs set through the drilling assembly will be used to drill ahead. It is possible that the formation could become supercharged in a loss / gain situation. In this case it will be necessary to bleed back mud. Contact office for detailed instructions in the event of suspected supercharging. e. If adequate wellbore integrity cannot be achieved by these means, i.e., severe lost circulation or severe loss/gain situation accompanied by high hydrocarbon levels, a liner may be set and drilling continued in smaller hole. Alternatively, the well may be plugged back and sidetracked to place casing points differently. 2. Insufficient Casing Shoe Strength a. The casing/liner shoe will be squeezed with cement if the FIT pressure is insufficient to provide a safe margin to drill to TD. b. If the casing/liner shoe FIT pressure remains inadequate even after remedial cementing, the well may be plugged back and sidetracked to place casing points differently. 3. Casing Pressure Tests a. Test the casing as per the drilling program prior to drilling out the casing / liner shoe. Rev.4.5, 26 Feb 2016 Page 184

186 The below flow charts represent an overview of procedures for well control incident while drilling, tripping, and out of hole, respectively. Well Control Guidelines - Drilling Rev.4.5, 26 Feb 2016 Page 185

187 Well Control Guidelines Tripping Rev.4.5, 26 Feb 2016 Page 186

188 Well Control Guidelines While Out Of Hole Rev.4.5, 26 Feb 2016 Page 187

189 Stuck Pipe Contingency Plan Analyze the well configuration & well condition at the time of sticking Gather & analyze information about current well conditions. Gamma ray, pipe recovery & noise/temperature logs might provide additional relevant information. Work the pipe & determine the estimated free point Run a free-point tool to determine the uppermost stuck point. A pipe recovery log can be used to identify the amount of stuck pipe below the uppermost stuck point. Select the best method & tools to separate the pipe Back off, cut or sever the pipe Remove the free portion of the pipe from the well Run fishing BHA with grapple to recover the pipe Rev.4.5, 26 Feb 2016 Page 188

190 Rev.4.5, 26 Feb 2016 Page 189

191 Rev.4.5, 26 Feb 2016 Page 190

192 Rev.4.5, 26 Feb 2016 Page 191

193 Fishing Contingency Plans String Parted Rev.4.5, 26 Feb 2016 Page 192

194 Junk in Hole Rev.4.5, 26 Feb 2016 Page 193

195 Wireline Tool Rev.4.5, 26 Feb 2016 Page 194

196 FISHING OPERATION GUIDELINES 1. Start with a Safety Meeting including all aspects of fishing operation. (Key points highlighted in green). 2. Keep a note of depth changes in Benchmark panel in order to have accurate depth/cable length measurements. 3. Pull cable to line weight lbs. (Base weight) 4. Install T-Bar on cable (Make sure the inserts are the right choice for your cable) as close to KB as possible. Mark cable at the top of T-Bar for checking slippage. 5. Rest cable on T-Bar. Look for slippage of cable. If it slips, pull back to Base weight and tighten T-Bar slips again. Repeat procedure to ensure no cable slippage. Clear Rig floor. 6. Use pneumatic wrench on T -Bar if available only for the final tightening when the bolts are properly threaded. (Pneumatic wrench damages the thread used on threads which are not properly threaded into nuts) 7. Slack off cable on the rig floor. 8. Rig down Top Sheave from the blocks. 9. Rig up top sheave high on the derrick. Make sure it is high enough to have room for the weight bar/overshot assembly to be threaded into the drill pipe by the derrick man. 10. Cut cable 8 feet from T-bar. This is to ensure that the cable once threaded into the pipe sticks out of the pipe when resting on pipe slips. Allow for the lengths of Circulation Sub and it s crossover to drill pipe. Basically length of cable > Drill pipe stickup + Circulation Sub + X over for circulation sub. 11. Build reliable rope sockets on both ends of the cable. (Well-end and Drum-end Rope sockets) 12. Makeup Spearhead on the well-end rope socket. 13. Makeup knuckle joint on drum-end rope socket. Makeup weight bar on knuckle joint. Makeup swivel on weight bar and makeup overshot on swivel. Engage overshot to spearhead. 14. Pull cable to test the spearhead/overshot connection. Clear Rig floor. 15. Pull upto Base weight in increments of 500 lbs. 16. Slack Off cable to rest on T-Bar and disengage spearhead/overshot. 17. Makeup Drill Pipe crossover + Top Sub + Bowl (with proper grapple) + Donut Guide (BHA). Rev.4.5, 26 Feb 2016 Page 195

197 Fishing BHA with Spiral Grapple Fishing BHA with Basket Grapple 18. In hole sizes that are significantly larger than the fish size, install an oversized guide to prevent the overshot from passing the fish. 19. Do not use Lip guide only Donut guide is recommended (Avoid sharp edges on fishing guide). Do Not Use Lip Guide Use Only Donut Guide 20. Pick up first drill pipe. Makeup BHA onto the drill pipe. 21. Pull cable with weight bar/overshot assembly to the top of drill pipe. Thread the assembly into the drill pipe. Derrick man needs to do this. Rev.4.5, 26 Feb 2016 Page 196

198 22. Pick up D/Pipe with BHA above the spearhead and run in overshot through the d/pipe to engage onto the spearhead. 23. Pick up to Base weight and remove T-Bar. 24. Run in Drill pipe and rest on slips. 25. Rest Spearhead on drill pipe box using C-Plate (for spear) 26. Disengage overshot using Overshot Tongs 27. Pull overshot and thread into the next drill pipe, pick up drill pipe over spearhead, run in overshot through drill pipe, engage onto spearhead, pick up cable to base weight, run in drill pipe and rest on slips, rest spearhead on the box using C-plate and disengage overshot using tongs. 28. Repeat step 24 until BHA is near casing shoe. 29. It is recommended to circulate through the BHA once it is in openhole, every 10 stands. 30. Pass overshot assembly through Circulation Sub/X over (if needed) on the floor. Pick up Circulation Sub assembly using sling and winch. 31. Engage overshot to spearhead and pick up base weight. Remove C-Plate. Makeup Circulation Sub assembly on the drill pipe box. 32. Place Circulation Sub Bushing into Circulation Sub. Remove bolts from the bushing once placed. 33. Lower Spearhead/Overshot into the circulation sub, resting the spear on the bushing. 34. Disengage overshot from spear using tongs. 35. Makeup the Kelly (on Rotary rigs) or drill pipe (on top drive rigs) onto the circulation sub. 36. Circulate enough. (say 20 minutes) 37. Break Kelly or Drill Pipe from Circ. Sub, engage overshot to spear, pickup on cable, remove Circ. Bushing using bolts, break Circ. Sub/X over, pick them up using winch, rest spear on drill pipe box using C-Plate, disengage overshot from spear, lay down Circ. Sub. 38. Follow step 24 for next 10 stands and then circulate again following steps 27 through While running in drill pipe make sure the line tension stays close to the base weight. Never allow any slack into the well. 40. Never rotate drill pipe before or after catching the fish. 41. Before approaching the fish with the BHA, circulation must be done to clean top of fish. 42. Stop as close to the fish top as possible, from the fish top depth estimate done prior to operation. 43. Circulate for 30 minutes. Note down the Pump strokes and attained circulating pressure 44. Approaching the fish 45. Make sure the cable tension is at least 1500 lbs above the cable weight in mud. 46. Make sure if the fish is not latched even after running in one single (drill pipe) of the stand, convince the client to do another circulation with this single in the hole. That is, break this single from the stand, pick the remaining singles up, rest the spear on C- Plate, disengage overshot from spear, remove overshot from the drill pipe and follow circulation procedure. 47. The whole exercise is to make sure that the fish top is cleaned before approaching. Basically knowing the fish top as accurately as possible is critical in approaching the fish without circulating. 48. Indication of latching onto fish is observed by an increase in line tension. Never allow it to go above maximum safe pull. 49. Driller also sees a slack in his weight indicator. Attempts are then made to release the fish by applying compression and tension on the tool within limits. Rev.4.5, 26 Feb 2016 Page 197

199 Final indication of release of fish is confirmed by pulling a single or stand and seeing equal amount of slack generated on the line Now you have two options, either break the weak point and pull cable out of hole or proceed to step 44 for reverse cut and thread technique (Reverse cut and thread recommended when radioactive tools are part of the fish) Now starts the long and tiresome job of reverse cut and thread After a stand of drill pipe has been pulled with line slacking off simultaneously, break the joint Install T-Bar on line close to the box. The spear/overshot is now at the top of the stand as line was coming out with the pipe Rest T-Bar on pipe, slack off line to get the spear/overshot come out of the stand from bottom. Disengage overshot and pull line to get the overshot out of the stand altogether. Rack the stand on derrick. Slack off to get overshot/weight bar assembly on rig floor Cut both spearhead rope socket and overshot rope socket off the cable. Cut wellend cable enough to make a knot with the drum-end cable. Pull tight on the line to base weight Remove T-Bar and pull out next stand. Keep line under tension. 50. Repeat steps 44 through 48 until the fish is out of hole or the client decides to break from the weak point Before breaking from weak point make reliable rope sockets again on both ends as the knot might not be enough to hold the tension Break weak point using T-Bar and block Cut spear and overshot off cable ends. Make knot and pull it over the sheave carefully and pull out line from the well (drill pipe in the well) Pull out of hole with the fish. Rev.4.5, 26 Feb 2016 Page 198

200 Loss Circulation Contingency Plan NORMAL DRILLING Surface Losses While Drilling Stop Drilling, Observe Downhole Use diagnostic to asses type of loss Locate Source and Cure Determine Source of Losses NO Are Losses Tolerable? YES Determine Loss Rate Minor Losses < 10 bbl / hr Partial Losses < 30 bbl / hr Severe Losses > 30 bbls / hr Natural? Induced? If possible reduce ECD If possible reduce ECD If possible reduce ECD If possible reduce ECD Treatment #3x2 NO Losses Continue? NO Losses Continue? NO Losses Continue? Losses Continue? NO YES YES YES Treatment #1 Treatment #2 Treatment #3 Natural? Induced? Spot Hard plug Hi Fluid loss Pill NO Losses Continue? NO Losses Continue? NO Losses Continue? YES YES YES Losses Continue? NO Treatment #2 Treatment #3 Hi Fluid loss Pill Spot Hard plug NO Losses Continue? YES NO Losses Continue? YES NO Losses Continue? YES Losses Continue? NO Spot Hard plug Repeat Hard plug NO Losses Continue? Losses Continue? NO YES YES Pump Conventional Cement. Rev.4.5, 26 Feb 2016 Page 199

201 H 2 S Contingency Plan (Breathing Apparatus sufficient for rig crews working at rig site). Required equipment When operating in an H 2 S zone, you must use equipment that is constructed of materials able to resist or prevent: Sulfide stress cracking (or hydrogen embrittlement), Chloride-stress cracking, Hydrogen-induced cracking and Other failures. The following testing equipment must be approved for H 2 S service: Downhole test tools, Wellhead equipment, Tubular and other related equipment, including: casing, tubing, drill pipe, couplings and flanges, Surface test units and related equipment and Temporary downhole well-security devices such as retrievable packers and bridge plugs. In addition, the following test equipment must conform to NACE Standard MR : BOP system components, Wellhead, Pressure control equipment and Related equipment exposed to H2S bearing fluids. Preparing equipment Thoroughly inhibit waster cushions to prevent H2S attacks on metals. Flush the test string fluid treated for this purpose after completing the test. Notification requirements ERT (Emergency Response Team) MUST BE NOTIFIED IMMEDIATELY OF ANY RELEASE THAT RESULTS IN A 15-MINUTE TIME WEIGHTED AVERAGE ATMOSPHERIC CONCENTRATION OF H 2 S OF 20 PPM OR MORE ANYWHERE ON THE FACILITY. Rev.4.5, 26 Feb 2016 Page 200

202 Procedure: - IF there is a H 2 S leak, THEN implement the following emergency action plan immediately. Stage 1 Description Evacuate all personnel immediately to a safe work or briefing area. Give immediate medical attention to injured or exposed personnel. 2 3 Assess the situation. During the assessment, determine which equipment and valves will need to be closed to contain the well. Contact: The Company man/drilling Supervisor and The Rig Manager or Safety Coordinator. 4 Rig personnel will close the appropriate valves on BOP's and any other equipment as required containing the well. Caution: Rig personnel must use the buddy system and appropriate personal protective equipment when re-entering the H 2 S area. 5 Obtain the appropriate supplied air breathing equipment for the assigned rig personnel. 6 Once the respiratory equipment arrives, then issue it to all rig employees required to complete the job. Be sure that: A qualitative or quantitative fit test has been performed by a competent person; A written and signed copy of the fit test is on file and All employees have received a walk-through and explanation of the cascade system and understand how it works. 7 Rig personnel wearing the appropriate respiratory protection will air up to finish the job. Rev.4.5, 26 Feb 2016 Page 201

203 Blowout Contingency Plan Rev.4.5, 26 Feb 2016 Page 202

204 Rev.4.5, 26 Feb 2016 Page 203

205 Appendix 8 Solid Expandable Contingency Rev.4.5, 26 Feb 2016 Page 204

206 Contingency for Setting Casing into Gotnia Formation Note: Overpressure in Gotnia may necessitate the need for an expandable liner to isolate and allow for liner to be set. This is only a contingency recommendation from Weatherford considering the potential for overpressure; however, if no pressure increase is realized in this formation (as was the case in Dn-001 offset well), then casing will be set within the Gotnia without need for solid expandable liner. Rev.4.5, 26 Feb 2016 Page 205

207 Implementing Solid Expandable technology delivers: No modification of present well design. Maintains drifts of casing program. Available from various vendors. ID of the 9-7/8 66.4# VAM TOP casing is 8.553in (as shown in Appendix 10), which is compatible with the 7-5/8 x 9-5/8 53.5# Solid Expandable system. Specifications are shown below. Running procedures in the event of contingency expandable is required Rev.4.5, 26 Feb 2016 Page 206

208 Contingency Expandable Procedure 1. Once the EMW/ECD for 12-1/4 hole section reaches 15.3ppge, stop drilling and POOH to set 9-7/8 casing. Verify casing seat in the formation, as per the Salman-1 Geological Technical Order. 2. Make up and RIH 9-7/8, 66.4ppf, Q-125/VM-140/VM-150 VAM TOP as per procedure in Section Make up & RIH 8-1/2 x 9-1/2 drilling BHA with under-reamer (max blades opening OD is 9-1/2 ). 4. Drill 8-1/2 x 9-1/2 hole section from the 9-7/8 casing shoe through the Lower Sulaiy and Gotnia formation to approximately 2,500m MD (Top of Najmah). Ensure overpressure section has been fully penetrated. 5. Circulate and clean. POOH. 6. Make up, RIH and install the 7-5/8 x 9-5/8 expandable liner as per Expandable Liner Procedure (generic procedure provided below which will be detailed once the service vendor is confirmed) 7. Make up and RIH 7-1/2 x 8-1/2 drilling BHA with under-reamer (max blades opening OD is 8-1/2 ). 8. Continue to drill out of the 7-5/8 x 9-5/8 expandable shoe (~2,500m MD) to 7 Liner seat at 3,700m MD (bottom of Butmah formation). POOH. 9. Make up & RIH 7, 32 ppf, P-110/Q-125 TSH 513 as per procedure in Section Contingency Hydraulics for 7-5/8 x 9-5/8 Expandable Option Assuming overpressure presence in lower Sulaiy & Gotnia as per Geomechanics model, the 9-7/8 casing is set at ~2,400m due to evidence of pressure ramp in the lower Sulaiy and the maximum 12-1/4 EMW Limit of 15.3ppg has been met. Set 9-5/8 casing before penetrating 2,400m. Overpressure exists in Gotnia. Isolation across Gotnia is required prior to drilling ahead. Fracture gradient at 9-5/8 shoe is max = 17.7 ppge Rev.4.5, 26 Feb 2016 Page 207

209 8-1/2 x 9-1/2 hole from 2,400m 2,500m MD with 17.8ppg (2.14sg) MW 7-1/2 x 8-1/2 hole from 2,500m 3,700m MD (with 7-5/8 x 9-5/8 solid expandable installed). Rev.4.5, 26 Feb 2016 Page 208

210 8-1/2 x 9-1/2 Drilling BHA with Under-reamer # Component Type Length (m) ID (in) OD (in) Distance from Bottom (m) 1 BIT SUB Custom /4" Motor 1.15 / 8 1/8" Sleeve STB, Top sub w/float Custom " -6 3/4" String Stabilizer Custom /4" MWD NMDC Custom /4" MFR Tool Custom /4" MWD HEL/IDS Tool Custom x6 3/4" Spiral Drill Collars Drill Collar Under-Reamer Underreamer x6 3/4" Spiral Drill Collars Drill Collar x 6 3/4" Drilling Jar Jar x6 3/4" Spiral Drill Collars Drill Collar jts 5" HWDP Drillpipe DP 5" S lb/ft Drillpipe /2 x 8-1/2 Drilling BHA with Under-reamer # Component Type Length (m) ID (in) OD (in) Distance from Bottom (m) 1 BIT SUB Custom /4" Motor 1.15 / 8 1/8" Sleeve STB, Top sub w/float Custom /4" String Stabilizer Custom /4" MWD NMDC Custom /4" MFR Tool Custom /4" MWD HEL/IDS Tool Custom x4 3/4" Spiral Drill Collars 8 Under-Reamer 9 8x4 3/4" Spiral Drill Collars Drill Collar Underrea mer Drill Collar x 4 3/4" Drilling Jar Jar x4 3/4" Spiral Drill Collars Drill Collar jts 5" HWDP Drillpipe dp 5" S lb/ft Drillpipe Rev.4.5, 26 Feb 2016 Page 209

211 In order to evaluate load requirements of the solid expandable contingency liner, simulations were carried out using Landmark WELLCAT software and results given below. The maximum gas kick they can safely circulate to the surface is 220 bbl before achieving the burst pressure for the expandable liner, although the formation below the expandable liner is more likely achieve fracture pressure first. Maximum allowable mud drop on the annulus before collapsing the expandable liner is 350m. Rev.4.5, 26 Feb 2016 Page 210

212 Rev.4.5, 26 Feb 2016 Page 211

213 Section 1 Well Prep Procedure 1. The Expandable will be received on location and will be unloaded using the specified handling procedures to prevent damage. A Field Service Representative will supervise the unloading and loading. The Expandable will be drifted, the threads will be visually inspected, and the casing will be tallied. All liner threads are ready to run and no thread dope should be applied. 2. The base casing and any other equipment, such as inline centralizers, landing collars, and the wear bushing, that the cone housing will be run through or the Expandable expanded through, must be inspected for adequate clearance. All dimensions must be verified, and confirmed correct by personnel and Client well site representative prior to running the Expandable. Any under-gauge dimensions established must be opened to the equivalent drift of the base casing prior to running the Expandable. 3. All drill pipe and work string components will be drifted with a minimum 2.1 in. OD drill pipe drift. The hole should be well circulated to control losses; and the drilling mud should be properly conditioned for running the Expandable. Clean, newly built mud must be used to fill the expandable liner. Note: While a certain amount of loss circulation material (LCM) can be tolerated, LCM concentration should be minimized, and use of fibrous LCM should be avoided. 4. The base casing and the open hole must be clean, free of obstruction and drifted to ensure that the launcher (Launcher OD specific size) can be run to total depth. Include in the cleanout assembly a combination of bit, scraper, mill, stabilizers and junk basket. Work this assembly through any tight spots until smooth pass though. This is to ensure that the base casing diameter and the OH diameter is large enough for the Expandable to be run to bottom. Note: It is critical that the base liner be thoroughly free from any debris or jagged edges. The final drift run must be run by drifting a BHA as agreed by Client and that will ensure that the Expandable is not damaged, or the bend radius is not exceeded on the connections (max DLS x.xx /30m size specific). This drift run must be performed without rotation or pumping to ensure the Expandable is able to reach TD. Any issues related to this step must be discussed and agreed upon prior to running the Expandable. 5. The open hole will be drilled with a reamer to open the bore to 9-1/2 from the 9-7/8 casing shoe. 6. Review the log data for both open-hole and cased-hole sections. Log data or report should be provided to engineering for evaluation for tight spots, casing wear, etc. 7. Strap and number the work string going in hole, carefully document the running tally as this will be referenced later in the procedure. 8. RIH with wellbore clean-out assembly. 9. Circulate and condition with low viscous pill and weighted high viscous pill while reciprocating. Circulate at high rate as much as possible. Prior to POOH short trip cleanout assembly with no rotation or pumping back to TD. Rev.4.5, 26 Feb 2016 Page 212

214 10. If hole is clean (no sizeable junk recovered) and drift run smooth to TD, lay down clean out tools, ready to run Expandable. 11. Client representative together with Expandable representative will decide whether or not to perform another clean-out run with same BHA. 12. Hydro test the work string required to run the Expandable to 5,000 psi prior to running the liner. This will flex the string and mitigate any debris from the ID compromising the expansion process. Note: A 15 to 30 internal shoulder taper will be maintained on all Expandable running BHA components and work string components. This includes backup assemblies of all critical components. This is to ensure the dart does not hang up during displacement. Note: Maximum allowable pressures must be confirmed for all surface equipment. Maximum allowable pressure for the Expandable is x,xxx psi Maximum allowable Push \ Pull for the Expandable is xx,xxx lbs A separate volume of the clean mud is required to fill the Expandable while it is being made up and during expansion. The volume of the lubricated mud needed to fill the Expandable while making it up is calculated based on the volume of expandable liner being run. After UR to TD pull back into 9-7/8 in. casing shoe and perform short trip with no pumping or rotation. Carefully observe any drag when drift BHA re-enters 9-1/2 hole. If drag observed pull/rotate until string is free. RIH back to TD. Circulate bottoms up, flow check, pump slug. Repeat until little or no resistance to RIH or POOH with drift assembly. Note: Notify the mud logger to set up expansion template for rigs data acquisition system to monitor hook load, bit depth, and stand pipe pressure. Section 2 Solid Expandable Liner Handling & Liner and Inner String Make Up Procedure Pipe Handling Procedures: Care & Handling Extreme care should be taken in handling so as not to damage either the pipe or the connection. It is mandatory to handle pipe using slings Thread protectors should not be removed during any movement of the pipe Specific lifting subs have to be used Do not stack pipe on pipe without separating with something softer than metal Slips should be fitted with non-directional inserts if available Liner & Inner String Make-up Procedures: Note: Expandable will include xx joints total, approximately x,xxx m pre-expanded length: (this is to be verified and confirmed in advance) 1. Conduct safety meeting prior to picking up casing handling equipment. Confirm responsibilities. Rev.4.5, 26 Feb 2016 Page 213

215 2. Make up the circulating crossover sub with a TIW valve and crossover to DP connection. Set back, and ensure the expandable liner connection box threads are not damaged during handling. 3. Rig up 7-5/8 in. Expandable special casing handling equipment (low penetration dies and slips, false rotary table, and torque turn). The tong dump settings and gripping capacity should be tested with a pup joint prior to running liner to verify. 4. Pick up the launcher with Expandable expansion assembly (pre-assembled in shop) expandable liner connection threads are Pin Up and set in the rotary table. Carefully install safety clamp, do not over tighten. 5. Pick up first Seal Joint of and make up to Launcher assembly in rotary. 6. Torque connection to x,xxx ft-lbs optimum torque. Max torque - x,xxx ft-lbs 7. Lower casing to rotary table and fill with treated mud. Raise casing to confirm mud is flowing from float shoe. 8. Continue to pick up casing with the crane to the V door and attach to side-door singlejoint elevators. Webbing slings provided by SERVICE COMPANY will be used to lift expandable casing. 9. Lift casing using the SERVICE COMPANY supplied expandable liner connection lift sub and stab using SERVICE COMPANY supplied stabbing guide. Torque to 5,704 ft-lbs optimum torque. Record all make-ups using torque monitoring equipment. Do not apply pipe dope to expandable liner connection threads. Special pipe dope will be provided by SERVICE COMPANY to be applied to pin of connections. 10. Continue to run a total of xx standard expandable liner joints (plus exit joint and seal joint) as detailed above. Note: Fill every 2 joints with treated mud. Stop filling after 2/3 of total run joints in hole to prevent mud from overflowing when inner-string is run. Use mud screen on each fill up. Empty screen in to plastic bucket after each fill up to observe any debris suspended in the mud. 11. Make up 7-5/8 in., expandable liner connection Pin x Box Seal Joint with x.xx in HNBR elastomer anchor bands. Take care not to damage elastomer bands while RIH and setting in slips. 12. Make up the seal joint. Set as low as possible in slips and install safety clamp. If required use a landing joint to get casing stump low enough to accommodate false rotary table. 13. Once casing landed out R/U false rotary table over casing stump. Swap all tubular handling equipment to 3-1/2 in. IF for inner string. Note: Precaution to be taken at all times to cover hole to keep items from being dropped into the liner or down annulus. Rev.4.5, 26 Feb 2016 Page 214

216 14. Stop for Safety Meeting to discuss running inner-string. Confirm responsibilities. 15. Install False Rotary Table avoiding any contact with the top of the Expandable. 16. Rig up to run 3-1/2 in. IF in. inner-string. 17. Pick up and run the Bottom Hole Assembly. (Sample) BHA will consist of the following: Example: Safety Sub with 3-1/2 in. IF (B) Example: Pup joint with 3-1/2 in. IF connections Example: Debris Sub with 3-1/2 in. IF connections Example: Crossover Example: Drill pipe to surface Note: May incorporate jars & HWDP into this BHA. Final BHA setup TBD. 18. Review inner string tally to check depth to tag safety sub receiver above the expansion mandrel. Continue to run in hole and mark work string where safety sub is tagged. Note: Prior to picking up last joint of inner string, strip the top cap over and tie back. This to be made up after removing false table. 19. Lower drill pipe and tag Safety Sub lightly and make up the inner-string into the Safety Sub with approximately 12 right hand turns, slacking off weight as needed to facilitate ease of make-up. Actual torque will be less than or equal to the make up torque of the expandable liner connection (x,xxx ft-lbs). This connection makes up easily and torque will give the indication that the assembly is fully engaged into the Safety Sub and Launcher assembly. Make sure rotary table is locked while making up Safety Sub. Note: Prior to screwing in, record PU & SO of inner-string. 20. Rig down False Rotary table and make up top cap with chain tongs. Use loc-tite or thread lock on this make-up. 21. Pick up over previous string weight slowly to check that Safety Sub is made up. Take new PU/SO weights. Slack back down into casing slips and install safety clamp. 22. Conduct safety meeting about risk while RIH. Review any well control issues and actions. Confirm trip tank monitor is working. Note: RIH at a controlled rate to avoid surge and induced losses. Do not RIH if you encounter any obstruction. Stop and review the situation. Install the drill pipe wiper on the first joint of drill pipe. 23. Continue running in the hole with the drill pipe. Fill the string with mud every 3 stands. Use mud screen on each fill up. Empty screen in to plastic bucket after each fill up to observe any debris suspended in the mud. Note: RIH at a maximum rate of ~ 1 Stand / 3 Minutes. Do not rotate liner while RIH. If a restriction or bridge is encountered, wash through of the liner can be attempted. If at any time the well should start gaining or losing mud, stop and confirm the well control action before continuing to RIH. Rev.4.5, 26 Feb 2016 Page 215

217 24. Check up and down weights before exiting the casing shoe at approximately xxxx m. Fill expandable casing prior to running in open hole. 25. Run in the hole to setting depth of xxxx m. Confirm tally. Take up and down string weights. 26. Position drill pipe for circulating. 27. Conduct a safety toolbox talk to review procedures for cementing and expansion. 28. Cement will be pumped and displaced with the cement unit via cementing lines. 29. Pick up the cementing head / plug container and screen sub with drill pipe screen, and make-up onto the work string. 30. Rig up the cementing lines to the manifold on the rig floor. Flush all lines to remove any debris. Rig up the cementing lines from the manifold to the cementing head. 31. Ensure that the manifold is lined up for the cement job. 32. Position the shoe 3 to 4 feet below setting depth, and then pull up on string to the setting depth. 33. Pump cement per cement company/customer standard procedures. 34. Continue to circulate and condition the mud through the drill pipe screen at max 3 bbl/min until proper mud properties are achieved. Do not exceed 1,000 psi circulating pressure. 35. Pressure test pumps and lines to rig floor to 5,000 psi. Pressure test standpipe to 4,000psi. 36. Line up the cement head, and release the dart. Ensure fresh mud used for displacement. 37. Pump calculated volume of cement and launch dart. Displace the dart at minimum 4 bbl/min. Note: Do not stop pumping until dart seats (Pump till you bump). Over pressure shutdown on pump to be set at 4,000 psi. Rev.4.5, 26 Feb 2016 Page 216

218 Section 3 Expanding Expandable Liner 1. When dart seats ensure work string is in upstroke and continue pressuring up to 500 psi, expansion should begin at x,xxx psi. Pressure and hook load must both be visible from drillers console. Expanding correctly/ safely is a balancing act between these two parameters. Cement pump to be used for expansion. Have radios available for communication between cement pump & rig floor. 2. Once expansion is initiated driller will start pulling work string, maintaining string weight on the blocks. 3. Expand the first stand until the tool joint is at a workable height to break the connection above the rig floor. Stop pumping and bleed off pressure. Record flow back volume. Slack off enough to break the connection. Break out and lay down drill pipe joint or rack back stand. Track barrels in / barrels returned this will serve as tool to ensure we are expanding pipe and not just pulling it up hole. 4. Reconnect to drill pipe. Start pressuring up and continue expansion as above. Drill pipe will be racked back in stands. Pressure and weight will spike when pulling through connections and seals. 5. Continue until last joint before the hanger joint is to be expanded. After the hanger joint has started expanding, pull additional force above string weight and reduce pump rate. Have Derrickman come down from derrick prior to exiting liner top. Note: It is very important that the driller does not stop pulling when the cone exits to avoid damaging the top of Expandable when the stretch is relieved from the drill pipe. A minimum of 2m should be pulled before the driller stops lifting the drill pipe. 6. After the liner has been completely expanded, circulate as per customer requirements. 7. Locate liner by slacking off and recording bobble on weight indicator. May also establish circulation pressure above pop out and SO into expanded liner and record where circulation pressure raises. 8. Pressure test liner top per customer requirements. 500 psi recommended. 9. Pull out of hole and lay down work string assembly. Rev.4.5, 26 Feb 2016 Page 217

219 Section 4 Expandable Float Shoe Mill/Drill Out Procedure 1. Make up the mill/drill out BHA as per Client specifications. The post-expanded drift diameter of the Expandable is x.xxx in. and the nominal ID is x.xxx in. Note: Recommended equipment for the Expandable shoe drill out: Any PDC, Mill tooth Rock bit or junk mill Watermelon mill String mill Drill collars (as needed) follow the Client requirement. Take precaution while the drill out BHA is RIH to the top of the expanded Expandable. If the mill/bit takes weight inside the Expandable, attempt to rotate maximum 5 minutes through the restriction, if unable to pass POOH & run smaller bit. The smallest expected liner ID is at the elastomer seals. The bit should pass the elastomer sections but may have to rotate the mills through, dressing the restricted area. 2. Mill/drill out the Expandable shoe. Note the milling information (WOB, type of bit used, pump pressure, ROP, time required for drillout) for future reference. Circulate the hole clean to remove the milling debris from the hole. POOH with the milling tools. Rev.4.5, 26 Feb 2016 Page 218

220 Under-reamer Specifications Concentric under-reamer is typically used for enlarging hole while drilling that is compatible with rotary steerable system. A typical placement in the bottom hole assembly is shown below: Some of the key features in an under-reamer Hole Enlargement While Drilling (HEWD) PDC cutters for durability (impact wear & tear) and cutting efficiency Cutter block design to minimize vibration Lock-closed mechanism to prevent pre-mature activation of the cutter block Multiple activation/actuation mechanism available (ball drop, pump rates, RFID technology) The contingency cases drilling through Gotnia may require under-reaming hole as follows: 8-1/2 x 9-1/2 from 2,400m 2,500m MD 7-1/2 x 8-1/2 hole from 2,500m 3,700m MD General specifications: Rev.4.5, 26 Feb 2016 Page 219

221 Appendix 9 Minimum Standard Requirements for Security (As written by Bashneft International B.V.) Rev.4.5, 26 Feb 2016 Page 220

222 Security Approach Bashneft International B.V. approach to security is based on the key elements of risk mitigation through careful planning and defensive protection measures that are sufficiently dynamic to meet the constantly changing operational environment. The employment of a layered security approach with both local community and Iraqi security forces is seen as critical in providing a safe environment in which to conduct our business activities. Bashneft International B.V. requests its contractors to conduct operations in the Block 12 in strict accordance with its minimum security requirements. Minimum Standard Requirements for Security 1. General The Contractor shall comply with, and adhere to, all the Company security policies, guidelines, standards, procedures and processes, as may be updated from time to time. The Contractor is required to define risk profiles and security obligations for each tier and member of the Contractor Group. Thereafter, the Contractor shall ensure that each tier and member fully understands and complies with its security related obligations. 2. Physical Security Plans The Contractor shall develop and implement a Physical Security Policy (PSP) which shall be passed to the Company. The Contractor shall ensure that physical security is managed and implemented in a responsible and ethical manner within the context of peace, social responsibility and sustainable development. In addition to the protection of the Company/Contractor personnel and assets, physical security provisions must facilitate and promote Company/Contractor community relations and shall demonstrate respect for our neighbours and host communities. In developing its PSP, the Contractor shall consider specific requirements of all interested parties including, but not limited to: employees, neighbours, public interest groups, security forces and the Company. At regular intervals, and in a format to be agreed with the Company, the Contractor shall submit a Physical Security Report documenting all relevant achievements, deficiencies, concerns and remedial activities occurring within the mentioned period. 3. Security Providers The following requirements apply to security contractor personnel employed by the Contractor for the purposes of carrying out the work: - the Contractor shall carry out pre-employment vetting to ensure that any employee providing security services has no criminal record; no past responsibility for human rights violations; and has not been dishonorably discharged from the police or armed forces; - unless otherwise approved by the Company, the Contractor shall recruit employees from local communities where it operates, subject to individuals being able to demonstrate the appropriate skills; Rev.4.5, 26 Feb 2016 Page 221

223 - the Contractor shall assign a responsible senior manager to lead on human rights assurance and compliance with the VPSHRs; - the Contractor shall ensure that all employees receive technical and professional training before deployment and then on a continuous basis, and are provided with appropriate instruction in the areas outlined in the contract; - the Contractor shall maintain 'Minimum Use of Force' policies and 'Rules of Engagement' for employees, in accordance with applicable national and international guidelines regarding the use of force; - the Contractor shall maintain accurate employee records, ideally in the form of a database, to support effective information sharing with the Company and, where applicable, inspection by state supervision authorities. The database shall include the information on training, misconduct and dismissals; - the Contractor shall initiate and maintain a grievance procedure, and keep a written register of any grievances raised and report these promptly to the Company; - the Contractor shall initiate and maintain a disciplinary and investigation procedure for managing employees whose conduct is shown to be abusive and inappropriate in the course of their employment; - in cases where physical force is applied by the Contractor's employees, the Contractor shall properly and promptly investigate and report on the incident to the Company; - in cases where inappropriate physical force is used, the Contractor shall refer the matter to local authorities and/or take disciplinary action where appropriate. 4. Specific Legal Regulations The Contractor's physical security performance and activities are required to fully comply with Iraqi laws and regulations, including the Iraqi Ministry of Interior requirements relating to Private Security Companies (PSC's). 5. Contractor's Obligations The Contractor is fully responsible for the security of its facilities and personnel in Iraq, and for ensuring that its personnel have the appropriate levels of awareness, skills and training to operate efficiently and safely. The Contractor shall conduct comprehensive risk identification and assessment exercise with respect to the physical security requirements of each separate area of operations associated with the work on the Block 12 Project. Risk mitigation measures shall then be documented within a formal project specific "Risk Register" which shall be passed to the Company for consideration. The Contractor shall update the Risk Register on an on-going basis. The Contractor shall submit a report to the Company outlining its recruitment policy and processes for the operations. This report shall, as a minimum, address the following issues: - Criminal record checks - Personal data collection and checks - Personal safety studies, mandatory for all tiers of the contractor group Rev.4.5, 26 Feb 2016 Page 222

224 - Check of the Iraqi personnel - Medical assessment stating the named individual is fit to work The Contractor shall provide and install all necessary physical and technical security capabilities required to fully protect all the Company s property (sites, equipment, plants etc.) utilized by the Contractor when operating on the Block 12. The Contractor shall ensure mobile security services for safely movements of its personnel operating for the Block 12 project. The security providers chosen by the Contractor shall be preliminarily approved by the Company before signing the agreement with. The Contractor shall ensure on-site static security within the field in order to provide safety and security of its personnel. Static security shall be carried out in coordination with oil Protection Forces of Iraq. When designing a static security site the objective is to ensure it is an integrated static security system, utilizing both physical and technical solutions, that meets the baseline requirements for that site. An initial threat assessment will be carried out in order to identify potential threats, and the possible mitigating strategies in order to neutralize those perceived threats. Below is a list of considerations when designing and building a site: Eliminate potential hiding places and dead ground near the facility. Provide unobstructed 360 degree view of the facility. Ensure watchtowers achieve overlapping fields of view/fire. Site sensitive areas are not concealed or obstructed from view. Assets located or stored outside of the facility should be in view of watchtowers or CCTV. Provide adequate standoff from site boundary to nearest buildings. Eliminate lines of approach perpendicular to critical areas/buildings. Minimize access points. Locate parking as far from the facility as practical possible. Illuminate all buildings, perimeters and any exterior storage sites. Secure and manage access to critical areas. Locate construction staging areas away from asset locations. Locate the facility away from natural or manmade vantage points. The Contractor shall develop and present to the Company for consideration it s Security, Evacuation, Emergency, Medevac Plans and shall be able to respond adequately in case any threat is imposed. All individuals engaged by the Contractor for the provision of physical security shall be fit and properly trained for their respective assignments. The Contractor's training procedures shall be subject to the audit by the Company. The Contractor shall fully comply with all present Company s rules, regulations, guidelines and policies. Where appropriate, such rules, regulations and policies, shall be adopted by the Contractor and incorporated within the Contractor's own equivalent documentation. Rev.4.5, 26 Feb 2016 Page 223

225 The Contractor shall obtain a written reply from all the personnel and subcontractors confirming that they have received and gained a full understanding of the Company s rules, regulations, guidelines and policies and that they will fully comply with the requirements thereof. 6. Relationships with the Oil Protection Force (OPF) The OPF is an authority assigned by the Iraqi Ministry of Interior to protect the areas of oil operations. Block 12 Project management is keen to involve the OPF in the liaison role. To facilitate that, the Contractor shall assign a Liaison Manager who shall be responsible for all the coordination and liaison with the OPF and also with his Company s counterpart. 7. Planning All phases of the Contractor's security planning, and the implementation of the security standards set forth herein, shall be subject to the Company s audit and check. 8. Traveling within Iraq Whilst in Iraq, the Contractors shall provide their personnel with both Ballistic Protective Equipment (BPE) - Helmets and Body Armours - as well as Personal Protective Equipment (PPE) to ensure their safety and security during the movements on the Iraqi territory and the operations within Block 12. Utilization of BPE and PPE shall be required by the Contractor's Standard Operating Procedures (SOPs). Security Plan Requirements It is essential that the Contractor has a comprehensive understanding of the operations environment in which the Contract is performed. The Contractor shall provide its security plan. The aim is to provide a comprehensive security plan and to demonstrate an understanding of the main risks and methods of their mitigation associated with the performance of the Contract. The security plan shall cover the following main points: Understanding of the operating environment Understanding of the security risks associated with the performance of the Contract Risk mitigation measures to include: - Employment of a security provider - Understanding of the layered approach to security - Liaison with all security stakeholders in the area of operation including the OPF, the Ministry of Interior and other security authorities - Social and economic approach to positively respond to the operational environment. - Compliance with VPSHRs After awarding the Contract, the Contractor shall be liable to provide a detailed and comprehensive security plan covering all aspects of the operations to ensure the welfare, safety and security of all the personnel to be employed and assets to be deployed for the Contract within 14 days. The security plan shall be formed in accordance with the Chart below. Rev.4.5, 26 Feb 2016 Page 224

226 Subject Geo political overview Project area Risk/Threat Assessment Intelligence Support Covering: - Journey management in/out the country and internally to project locations. - Camp and Site security - Non-drilling activities Security Authorities Liaison Security requirements and concept of operations during the conduct of the Journey management process. Security requirements and concept to support seismic, drilling and other nondrilling operations as well as mobile and static site security operations Remarks Southern Iraq/Basra operating environment Provide detailed understanding of the site locations and environment To inform Risk mitigation measures OPF, ISF-I, LA and IP Covering both the Iraqi and expatriate personnel and including: - Program management - Operational establishment and support - Logistics support (to include fleet management) - Communications To deter, detect and deny terrorist or criminal activity As above Emergency procedures - Emergency Response - Evacuation Plans - Medevac Plans Human Resources Quality Assurance Process Host Nation compliance Contractor Contact List Recruiting and checking Initial and ongoing training MOI requirements Key management/operations staff/tls Those in the chart above are the minimum requirements. It is the contractor's responsibility to design the structure and layout of the security plan that is appropriate for the Contract needs. The Security plan will be reviewed by the Bashneft International B.V. security team to ensure it is essential and is in compliance with the minimum security standard requirements. Rev.4.5, 26 Feb 2016 Page 225

227 Initial Incident Report Detail (a) Type of Incident Information Required (b) Remarks (c) IED/Small Arms Fire/Other Description of Incident Time Location Injuries Casualties Initial Response Steps Taken Emergency Response, Evacuation Plan, Medevac Plan applied Rev.4.5, 26 Feb 2016 Page 226

228 Appendix 10 Casing Specification Sheets Rev.4.5, 26 Feb 2016 Page 227

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