Petrophysical Engineering

Confidential-Property and Copyright: SIPM, 1991

1

Cover illustration: Cross-well electromagnetic measurements

This book is the property of Shell Internationale Petroleum Maatschappij B.V., The Hague, The Netherlands. It must be promptly returned to them at any time they may so request. It is confidentially loaned to the holder for his personal information and use only, and neither its existence nor its contents shall be disclosed by the holder to any third party. The holder shall take every precaution to prevent third parties from perusing, reproducing or copying the same either wholly or in part. The copyright of this document is vested in Shell Internationale Petroleum Maatschappij B.V., The Hague, The Netherlands. All rights reserved. Neither the whole nor any part of this document may be reproduced, stored in any retrieval system or transmitted in any form or by any means (electronic, mechanical, reprographic, recording or otherwise) without the prior written consent of the copyright owner.

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3

PREFACE TO THE PRODUCTION HANDBOOK, REVISION 1991 Objective The objective of the Production Handbook is to contribute to efficient performance by all Engineering, Petroleum Engineering and Operations staff, by providing quick access to and practical guidance on their own and related disciplines’ technology. Being a comprehensive combination of condensed technical manuals, it provides a ready source of information for reference and self-training. It is not intended to replace detailed design manuals and state-of-the-art manuals; these should remain the first source of reference for more experienced technical specialists. Neither can the Production Handbook replace specialised training manuals. Distribution The Production Handbook should be available to all Engineering, Petroleum Engineering and Operations staff at or above JG5, in Group E&P Operating Companies and SIPM. These staff receive the Handbook as a personal loan; they may take it along when going on transfer within the Group but must return it when leaving for other reasons. Staff of other Functions’ parentages temporarily working in E&P companies may use library copies. The Handbook is confidential and holders should note the conditions stated opposite the title page. Issue and recovery should be registered by company secretariats/libraries. Reprinting and updating The Production Handbook was first published by SIPM in 1986. It is the successor to the Field Pocketbook versions of 1933, 1947, 1952 and 1955 and the Field Handbook of 1963. The 1986 version comprised 3000 pages in five A5 ringbinders; 6000 copies were distributed. An update of some 250 revised pages was issued in 1987 and a list of further corrections was published in the Production Newsletter of November 1988. A complete reprint is necessary at this time (1991). For flexibility and cost-effectiveness this updated reprint is in nine paperback volumes, each one dedicated to a major discipline with clear ‘ownership’ by the SIPM-EP department concerned. These ‘custodian’ departments will initiate further updates of their respective volumes as and when necessary. Additional volumes and state-of-the-art manuals in the same format may be added later as special supplements. Suggestions for revising and updating the Handbook should be directed to the SIPM-EP custodian department of the respective volume, using copies of the Specimen Amendment Sheet at the back of each volume. Overall editorial custodianship of the Handbook rests with SIPM-EPD/11.

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CONTENTS LIST PRODUCTION HANDBOOK SERIES (1991) SIPM Custodian Volume 1 Production General – Units and Conversion Factors – Health, Safety and Environment – Quality Management – Economic Analysis

EPO/71 EPO/6 EPO/72 EPE/1

Volume 2 Drilling and Transport – Drilling – Civil Engineering for drilling locations – Transport in Production Operations

EPO/51

Volume 3 Petrophysical Engineering

EPD/22

Volume 4 Reservoir Engineering

EPD/22

Volume 5 Production Technology – Production Engineering – Production Chemistry

EPD/41

Volume 6 Production Operations

EPO/53

Volume 7 Process Engineering – Oil Processing – Gas Processing Custodian for Part I, Ch. 7, Terminals:

EPD/42 EPD/13

Volume 8 Pipelines

EPD/61

Volume 9 Facilities and Maintenance – Running Equipment EPD/62 – Piping Systems EPD/62 – Electrical Engineering EPD/63 – Instrumentation EPD/64 – Telecommunications EPD/76 – Reliability and Availability Assessment EPD/13-EPO/54 – Corrosion Engineering EPD/65 – Inspection Techniques and Maintenance Terminology EPO/54 – Diving and Underwater Operations EPO/54 – Air Conditioning MFSH/11


5

PREFACE TO VOLUME 3, PETROPHYSICAL ENGINEERING, REVISION 1991 The subjects covered in this Volume were formerly included in the 1986 version of the Production Handbook as Chapter 3, Petrophysical Engineering.

6


VOLUME 3, PETROPHYSICAL ENGINEERING, REVISION 1991

SUMMARY CONTENTS LISTING

page

1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

10 70 130 144 167 187 205 239 258 269

Wireline Logging: General Open Hole Logging Wireline Coring, Testing and Sampling Coring Cased Hole and Production Logging Perforating Wellsite Geology Safety and Environmental Control Reservoir Compaction and Surface Subsidence References and Further Reading


7

Volume 3

PETROPHYSICAL ENGINEERING CONTENTS 1 1.1 1.1.1 1.1.2 1.2

WIRELINE LOGGING: GENERAL Logging Programmes Open Hole Cased Hole and Production Logging Preparation for Logging

10 10 10 11 12

1.3 Depth Checks and Calibration 1.3.1 Depth 1.3.2 Calibration 1.3.3 Depth Scales 1.3.4 Repeat Section 1.3.5 Statistical Checks 1.3.6 Tension Recording 1.3.7 Log Scales and Scale Changes 1.3.8 Computerised Service Unit (CSU) Filtering 1.3.9 Bottom Hole Temperatures

13 13 14 15 15 15 15 15 15 16

1.4

17

Field Prints, Headings and Service Reports

1.5 Dispatch and Transmission of Data 1.5.1 Dispatch 1.5.2 Transmission

19 19 20

1.6

Services and Codes

21

1.7

Tool Dimensions, Weights and Ratings

29

1.8

Logging Cables, Heads and Fishing Tools

45

1.9

Wireline Logging Operations in Deviated Holes

50

1.9.1 1.9.2 1.9.3 1.9.4

Friction Reducing Devices Other Devices Logging Through Casing Drill Pipe: Pumpdown Techniques Logging of Near-Horizontal Holes


50 51 51 53

1

Petrophysical Engineering

1.10

Sticking of Wireline Logging Equipment

55

1.10.1

General Guidelines on Stuck Tool, Weak Point and Fishing Kit 1.10.2 Fishing for Stuck Tool 1.10.2.1 Open Hole 1.10.2.2 Cased Hole 1.10.2.3 Fishing through Tubing

56 57 57 59 60

1.11

61

Detection of Stuck Point/Back-Off Equipment

1.11.1 1.11.2

Stuck Pipe Indicator Tool Back-Off Equipment

61 65

1.12

Wireline Logging Wave/Tide Compensation for Floating Rigs

65

2

OPEN HOLE LOGGING

70

2.1

Methods of Open Hole Logging

70

2.1.1 2.1.1.1 2.1.1.2 2.1.1.3 2.1.1.4 2.1.1.5 2.1.2 2.1.2.1 2.1.2.2 2.1.2.3 2.1.3 2.1.4 2.1.4.1 2.1.4.2 2.1.4.3 2.1.4.4 2.1.5 2.1.6 2.1.7 2.1.8 2.1.9 2.1.10 2.1.11

2

Rig-Up and Survey Checks Rig-Up Running in Hole On Bottom Surveying After Survey Induction - Spherically Focused Spontaneous Potential (SP) Spherically Focused Resistivity Induction Dual Laterolog Micro Tools Micro-SFL Proximity Log Microlaterolog Microlog Gamma Ray Density Neutron (Compensated) Acoustic (Bore Hole Compensated) Dipmeter/Diplog Caliper Gearhart Calibration Standards

70 70 70 71 71 71 71 71 72 72 73 73 73 74 74 74 75 75 76 77 78 80 82


Contents

2.2

Principles of Log Evaluation

83

2.2.1 2.2.2 2.2.3 2.2.3.1 2.2.3.2 2.2.4

84 85 94 94 99

2.2.5 2.2.6

Lithology and Reservoir Thickness Porosity Hydrocarbon Saturation Clean Rocks (Non-Argillaceous) Shaly Sands Determination of RW from SP curve – Shell Method Procedure Reporting of Petrophysical Data Quick-Look Evaluation Step by Step

116 124 124

3

WIRELINE CORING, TESTING AND SAMPLING

130

3.1

Sidewall Samples

130

3.1.1 3.1.2

Sidewall Sampling Using Explosive Bullets Sidewall Coring Tool

130 131

3.2 3.3

Repeat Formation Tester Sample Recovery

131 141

4

CORING

144

4.1 4.2 4.3 4.4 4.5 4.6

General Coring Equipment Coring Fluids, Hydraulics and Bits Coring Criteria for Exploration and Appraisal Wells Preparation for Coring Instruction for Handling Cores for Petrophysical and Related Analyses

144 144 147 148 149

4.6.1 4.6.2 4.6.3 4.6.3.1 4.6.3.2

Recovery of Consolidated Cores Cleaning, Boxing, Sampling and Labelling Recovery of Very Friable and Loosely Consolidated Cores Rubber Sleeve Coring Plastic Fibreglass Core Cartridges

151 151 158 158 161

4.7 4.8

Core Description Petrophysical Core Analysis: Suggested Standard Programme

163 166


151

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5

CASED HOLE AND PRODUCTION LOGGING

167

5.1 5.2

Preparation for Logging Operation Against Pressure

167 169

5.2.1 5.2.2 5.2.3 5.2.4 5.2.5 5.2.6

Testing Risers and Hydraulic Grease Tube (HGT) Testing BOPs Entering the Well Running in Hole PLT Logging Pulling Out of Hole

169 169 171 172 173 173

5.3 5.4 5.5 5.6

Cement Bond Survey Thermal Decay Time Logging Electromagnetic Thickness Tool (ETT) Production Logging Tool (PLT)

174 176 177 177

5.6.1 5.6.2 5.6.3 5.6.4 5.6.5 5.6.6

Flowmeter Gradiomanometer High Resolution Thermometer (HRT) Continuous Pressure Manometer Through-Tubing Caliper Tracer Ejector Tool

180 181 181 181 181 182

5.7 5.8 5.9

Continuous Flowmeter Gradiomanometer Thermometer

183 185 186

6 6.1 6.2 6.3 6.4 6.5 6.6 7

PERFORATING

187

General Preparations Arming Guns Entering the Well Depth Control Retrieving the Gun Gun Characteristics

187 189 190 192 194 196

WELLSITE GEOLOGY

205

7.1

Lithological Description of Sedimentary Rocks

205

7.1.1

Description and Coding of Rock Compositions

205

7.2

Hydrocarbon Detection

232

4


Contents

7.2.1 Natural Fluorescence 7.2.2 Solvent Cuts 7.2.3 Solvent Cut Fluorescence 7.2.4 Acetone Water Test (Acetone Reaction) 7.2.5 Visible Staining and Bleeding 7.2.6 Odour 7.2.7 Gas Detection Analysis 7.2.8 Irridescence 7.2.9 Acid Test 7.2.10 Reporting Results of Tests for Hydrocarbon Shows 7.2.10.1 Symbols for Hydrocarbon Shows 7.2.10.2 Reporting Procedure Example

232 233 234 234 234 235 235 235 235 236 236 237

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239

SAFETY AND ENVIRONMENTAL CONTROL

8.1

Handling and Storage of Radioactive Sources and Explosives

239

8.1.1 Radioactive Sources – Safe Working Conditions, Handling, Storage and Transport 8.1.1.1 Handling Radioactive Sources on the Wellsite 8.1.1.2 Storage of Radioactive Sources 8.1.1.3 Transporting Radioactive Materials 8.1.1.4 Safety Equipment 8.1.1.5 Emergencies Involving Radioactive Sources 8.1.2 Explosives – Handling, Transport and Storage

239 239 240 241 242 242 243

8.2

245

Operating Safety and Radio Silence

8.2.1 8.2.2 8.2.3 8.2.4

Radioactive Sources – Operating Safety Fishing for Radioactive Logging Tools Explosives – Operating Safety Radio Silence

245 246 247 248

8.3

The Presence of Hydrogen Sulphide

254

8.3.1 8.3.2

Toxicity of Hydrogen Sulphide Gas Determination of Sulphide Content in Mud and Fluid Samples Determination of H2S Content in Gas (Dräger Tube Method)

254

8.3.3


254 255

5


9

RESERVOIR COMPACTION AND SURFACE SUBSIDENCE

258

9.1 9.2

Introduction Compaction Prediction

258 259

9.2.1 9.2.1.1 9.2.1.2 9.2.1.3 9.2.2 9.2.3

Sandstone Reservoirs Linear Compaction Model Rate Type Compaction Model Recommended Procedure Compaction of Shales Prediction of Compaction due to Pore Collapse in High-Porosity Carbonate Reservoirs 9.2.3.1 The Trendline Model 9.2.3.2 Prediction of In-Situ Pore Collapse with the Trendline Model 9.3 9.3.1 9.3.2 9.3.3 10

6

Calculation of Surface Subsidence The Nucleus-of-Strain Approach Quick-Look Procedure to Calculate Subsidence in the Deepest Point of the Subsidence Bowl Using the Rigid-Basement Model Detailed Calculation of Subsidence Using the Rigid-Basement Model REFERENCES AND FURTHER READING

259 259 261 261 262 262 262 264 266 266 266 267 269


Tables and Figures

TABLES Table 1.7-1 Table 1.7-2 Table 1.7-3 Table 1.8-1 Table 1.8-2 Table 1.8-3 Table 2.2-1

Schlumberger tool data Western Atlas tool data Gearhart tool data Schlumberger logging cables and weak points Dresser Atlas logging cables and weak points Gearhart logging cables and weak points Photo-electric absorption index, bulk density, electron density and volumetric photo-electric absorption index of some common minerals and liquids Table 2.2-2 Porosity tools Table 2.2-3 Summary petrophysical evaluation (preliminary/final) Table 4-1 Core recovery and sampling record Table 6.6-1 Perforating gun performance summary – Schlumberger Table 6.6-2 Perforating gun performance summary – Western Atlas Table 6.6-3 Perforating gun performance summary – Gearhart Table 8.1-1 Radiation limits for working conditions Table 8.1-2 Approximate barrier distance from source container Table 8.2.4-1 Radio shut-down during operations with explosives applicable to installations and vessels within 500 metres Table 8.3.3-1 H2S determination by Dräger tube Table 9.2-1 Range of compressibilities and β for various rock Types


29 34 40 45 45 46 87 92 125 157 196 198 200 239 241 249 256 260

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FIGURES Figure 1-1a Figure 1-1b Figure 1-1c Figure 1-2a Figure 1-2b Figure 1-2c Figure 1-2d Figure 1-3a Figure 1-3b Figure 1-3c Figure 1-3d Figure 1-4 Figure 1-5 Figure 1.11-1 Figure 1.11-2 Figure 1.12-1 Figure 1.12-2 Figure 2.2-1 Figure 2.2-2a Figure 2.2-2b Figure 2.2-2c Figure 2.2-3 Figure 2.2-4 Figure 2.2-5 Figure 2.2-6 Figure 2.2-7 Figure 2.2-8 Figure 2.2-9 Figure 2.2-10 Figure 2.2-11 Figure 2.2-12 Figure 2.2-13 Figure 2.2-14 Figure 2.2-15 Figure 2.2-16

8

Schlumberger tool schematics 1 Schlumberger tool schematics 2 Schlumberger tool schematics 3 Western Atlas tool schematics 1 Western Atlas tool schematics 2 Western Atlas tool schematics 3 Western Atlas tool schematics 4 Gearhart tool schematics 1 Gearhart tool schematics 2 Gearhart tool schematics 3 Gearhart tool schematics 4 Cable head fishing dimensions (Schlumberger) Cable head fishing dimensions (Western Atlas Stuck pipe indicator tool (SIT) Stuck pipe pull and torque transmission Mechanical wave compensation device Hydraulic-pneumatic compensating device Importance of lithology determination Porosity and lithology determination from formation density log and compensated neutron log (CNL*) Porosity and lithology determination from formation density log and compensated neutron log (CNL*) Porosity and lithology determination from sonic log and compensated neutron log (CNL*) Density of water and NaCI solutions Archie equations Formation factor vs. porosity Average values for porosity and saturation exponents Resistivity Index vs. SW Calculation of SW Resistivity vs. temperature for NaCI solutions Resistivity vs. porosity crossplot The Waxman-Smits shaly sand model (1968) The Archie clean sand model (1942) B – RW temperature relationship BRW – salinity relationship Core conductivity 100% saturated with water Shaly sands formation factor – porosity relationships

31 32 33 36 37 38 39 41 42 43 44 48 49 62 63 66 68 86 89 90 91 93 95 96 97 102 103 104 105 106 106 107 108 109 110


Tables and Figures Figure 2.2-17 Figure 2.2-18 Figure 2.2-19 Figure 2.2-20 Figure 2.2-21 Figure 2.2-22 Figure 2.2-23 Figure 2.2-24a Figure 2.2-24b Figure 3-1 Figure 3-2 Figure 3-3 Figure 3-4 Figure 3-5 Figure 4-1 Figure 4-2 Figure 4-3 Figure 4-4 Figure 4-5 Figure 5-1 Figure 5-2 Figure 5-3 Figure 7.1-1 Figure 7.2-1 Figure 9.2.3-1 Figure 9.2.3-2 Figure 9.2.3-3 Figure 9.3-1

Determination of cation exchange capacity Qv from SP log Graphical solution of Waxman-Smits equation Solving Waxman-Smits by iteration Spontaneous potential, four components Streaming potential for various mud types Electrochemical potential (Ec) vs. NaCI concentration (CNaCl) for Qv shale = 1, 2 and 4 mmol/cm3 Example of petrophysical data log Resistivity vs. porosity crossplot, m = 1.8 Resistivity vs. porosity crossplot, m = 2.0 Western Atlas FMT assembly Repeat formation tester system Schlumberger RFT components RFT pre-test permeability indications (qualitative) Sample recovery at low pressure Core handling procedure Inner and outer labels for core boxes Core description Sawing device for cutting rubber sleeved cores ‘Sock’ for handling fibreglass sleeved cores Wireline lubricator set-up BOP test stand set-up Production logging tool Guide for lithological descriptions of sedimentary Rocks (TAPEWORM) Oil detection in rock specimens Stress dependence of porosity for mouldic limestone samples Laboratory trendlines for various different Carbonates Procedure to calculate compaction due to pore collapse from the porosity-stress trendline Normalised subsidence above the entra of a disc-shaped reservoir versus entraliza reservoir depth


111 114 115 118 119 123 127 128 129 132 133 135 137 142 154 155 156 160 162 168 170 179 206 last page 263 264 265 267

9

Wireline Logging: General

1. WIRELINE LOGGING: GENERAL 1.1 Logging Programmes The following notes provide guidelines on open hole and cased hole logging programmes. 1.1.1 Open Hole The policy for Wireline Logging is that exploration and appraisal wells are to be logged from the total depth to the surface and that development wells have to be logged over the intervals containing the reservoirs. The programme for Open Hole Surveys is integral with the Drilling Programme, and is the responsibility of the Petrophysics Section. No hard and fast rules can be laid down for logging programmes to cover all possible contingencies. The following guidelines are offered. (a) Exploration and Appraisal Wells (i) Surface Casing Depth. INDUCTION/SONIC/GR/SP from TD to Conductor Shoe. Transit Time Integration required. LITHO-DENSITY/NEUTRON/GR from TD to Conductor Shoe if required to confirm gas indications. GR through casing from Conductor Shoe to surface. Survey in 121/4” pilot hole. (ii) Intermediate Logging. INDUCTION/SONIC/GR/SP from TD to Casing Shoe or first reading previous survey, whichever is deeper. LITHO-DENSITY/NEUTRON/GR from TD to Casing Shoe or first reading previous survey, whichever is deeper. An overlap of 50 m is required with the previous run. DIPMETER if required by Geologist/Production Geologist. DUAL LATEROLOG/MICRO RESISTIVITY/GR/SP from TD to Casing Shoe if hydrocarbon-bearing intervals are encountered. SIDEWALL SAMPLES, REPEAT FORMATION TESTER (Pressures and Formation Fluid samples), and CEMENT BOND LOG as requested. (iii) Final Logging. As intermediate, with the addition of Velocity Survey if requested. CEMENT BOND/GR/CCL if casing is set for production testing.

10



(b) Development Wells (i) Surface Casing Depth INDUCTION/SONIC/GR/SP may be requested to check gas indications. Survey in 121/4” pilot hole. (ii) Intermediate Logging As for Surface Casing Depth. Only if unexpected lithology/shows are encountered as for Intermediate Logging in Exploration and Appraisal Wells. CEMENT BOND LOGGING may occasionally be required for confirmation of cementation. (iii) Final Logging. DUAL LATEROLOG/MSFL/GR/SP from TD to Casing Shoe. LITHO-DENSITY/NEUTRON/GR/SP and if required INDUCTION/SONIC/ GR/SP from TD to Casing Shoe. REPEAT FORMATION TESTER may be required for formation pressure monitoring. CEMENT BOND/GR/CCL after casing/liner cementation.

1.1.2 Cased Hole and Production Logging (a) The programme for perforation and completion logging is integral with the Completion Programme; perforation intervals are selected by the Petrophysics Section in conjunction with the Production Technology and Reservoir Engineering Sections. (b) Production Logging is normally required to solve a specific production or injection problem. Production Logging will normally be supervised by a Production Technologist or Petrophysicist to ensure valid and useful results. (c) Unscheduled Wireline Services may be requested to solve unexpected problems, e.g. Free Point Indication/Back-off, Temperature Survey for lost circulation. Responsibility for demand and supervision of these services rests with Operations Section.


11


1.2 Preparation for Logging (a) Ensure that all equipment and personnel required to carry out logging programme are on site and operational. (b) Ensure that surveys from adjacent/nearby wells are available for comparison /correlation. (c) Discuss logging programme with Logging Engineer, and confirm running order of tools. It is recommended to use a tool string with a maximum amount of logging tools combined, including radioactive tools, with the objective to minimise rig time used for evaluation. Take notice of Operating Safety and Radio Silence guidelines in Section 8.2. (d) Provide Logging Engineer with the following data: (i) Well description, location and DF elevation. Permanent datum is Mean Sea Level or ground level for offshore and land wells respectively. (ii) Bit and Casing Sizes, TD and Casing Shoe Depths. (iii) Mud type, weight, viscosity, water loss, pH and mud filtrate salinity. (iv) Changes to drilling/logging programme. (v) Downhole conditions relevant to operation (deviation, tight spots, doglegs, sloughing shales, over-pressurised or under-pressurised formations, lost circulation intervals, gas zones, etc.). (e) Provide samples of mud (5 dm3), mud filtrate and mud cake for resistivity measurements. The mud cake should be thick enough (5 mm) to be representative: the quantity of mud filtrate will then usually be adequate. Mud samples should be homogeneous and taken from the flowline during circulation just prior to logging. Ensure that measurements are made as soon as samples are ready.

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1.3 Depth Checks and Calibration

1.3.1 Depth Log depths are standard reference for Shell Group Companies. All subsurface maps and markers are established by reference to the gamma ray curve of the gamma-ray density log, which is the REFERENCE SURVEY. The reference survey must be correlated with the first tool run (Resistivity) and it is therefore essential to determine depths accurately during the first run into the hole. Depth below Derrick Floor (DF) will be determined as follows: (a)

First Survey

(i) Set tool zero at DF and set spooler at zero. (ii) Run in hole to first bell, check first bell at spooler pulling up. (iii) Proceed to casing shoe (CS), checking bell every 30 m. (iv) Just above CS catch mark at well, set at DF. Adjust spooler depth to read (distance from tool zero to first mark) + y Χ 30 m. (v) Pull up and check mark at spooler. This is the bell to be used for the survey. (vi) If the bell in (v) differs from the bell in (ii) by more than 1 m, the reason for the discrepancy must be determined (if necessary, by pulling out of the hole and re-checking surface mark) before logging. (b)

Subsequent Surveys

Subsequent surveys over the same section must be related to the first survey in the sequence. The mark at surface need be checked only roughly, and accurate correlation with the first survey made during recording of the overlap survey. It is perfectly normal, as a result of cable slack at surface, differences in tool weight, cable stretch, etc. for the bell at TD to be displaced several feet from the anticipated depth. If the discrepancy is excessive, the survey should be run by correlation with the first survey, and the tool zero checked at surface at the end of the survey. Provided the first survey was correctly recorded, both logs will then be at true depth. Major errors between surveys usually arise as a result of movement of the travelling blocks, either when the driller moves the blocks for rig maintenance during logging, or when the brake is not properly set. If a major discrepancy occurs between surveys, it is wise to check that the blocks have not moved. Surveys are normally taped, and can be played back on correct depth without wasting further rig-time, but this can only be done if the correct depth is known.


13


(c) Overlap Survey Overlap Surveys of about 50 m with previous surveys are normally required. If a survey overlaps a previous survey in a hole which has not been cased off, depth must still be determined as in (a) (First Survey) above; NOT by correlation with the previous survey. If the discrepancy between the surveys is 0.5 m or less, the new survey may be correlated with the original. If the discrepancy is greater than 0.5 m, the reason for the discrepancy must be established before the entire open hole section is to be rerun, including the depth determination. If logs are to be run in open hole, the cased part of which has previously been logged, the first survey must include a gamma-ray tool. Depths are initially to be determined as in (a) (First Survey) above, then a short through casing correlation film is to be made. If the discrepancy is less than 0.5 m, the new survey may be correlated with the original. If the discrepancy exceeds 0.5 m the reason for the discrepancy must be established before surveying continues. If it is considered that the new log is more accurate, the survey may be continued, but a through-casing correlation log must be made over enough of the cased section to correct the original survey. If it is considered that the previous survey is more accurate, the new log will be correlated with the original, but the correlation film at incorrect depth must be attached to the calibration tail with a note indicating the reason for the discrepancy. (d) Stretch Correction No stretch correction is to be applied to any open hole survey run at a depth of less than 3000 m. Normal stretch correction is to be applied below 3000 m and phased out to zero correction at 3000 m. When stretch correction is applied, this must be noted on the log heading of the first survey. Spooler depth correction is not to exceed 1 m in 300 m. 1.3.2 Calibration (i) Calibration records (see Individual Tool Calibrations) must be made before and after each survey. (ii) If problems are encountered with tools, and any part of the equipment which could cause an alteration in recorded parameters is exchanged, the equipment must be re-calibrated. Under no circumstances is a calibration record made with one set of equipment to be presented with a survey with another set.

14



1.3.3 Depth Scales

Surveys are to be recorded on 1 : 200 and 1 : 1000 scale, unless instructed otherwise.

1.3.4 Repeat Section A repeat section should be run over the reservoir interval. If corrections or memorisations are applied, part of the repeat section is to be run without correction or memorisation, the other part with them. This is particularly important in the case of a log run for perforating depth control, when this is the only way of establishing how much depth correction has been applied. Take care that radioactivity is not induced into the formations during this operation. 1.3.5 Statistical Checks All radiation tools are subject to statistical variations. Make a check on statistics if they appear to be excessive. The check should be made within the reservoir zone where deflections are representative of the reservoir. Pad tools must be opened, and statistics recorded for at least one minute. The check must be made in such a way that induced radioactivity from the source to the formation will not affect the main survey. No statistical check is to be made with the TDT. 1.3.6

Tension Recording

A recording of incremental cable tension is to be made on 1 : 200 scale only over the reservoir interval. The trace is to be located on the log where it will not interfere with more important data traces. 1.3.7

Log Scales and Scale Changes

With the exception of dipmeters, SP and temperature surveys, no scale changes are to be made during the course of a logging run. When a scale change is necessary, a 50 m overlap is to be made on both scales. 1.3.8

Computerised Service Unit (CSU) Filtering

All optical (film/print) surveys made using computerised units must be recorded with zero filtering (0.00). This will result in curves with minor deviations


15


from the smoothed surveys recorded using Standard Logging Units, or filtered surveys from computerised units, but this presentation must be adhered to for unitisation purposes. 1.3.9

Bottom Hole Temperatures

Three maximum thermometers should be run on each trip in the hole during open hole logging, the corresponding maximum bottom hole temperature to be reported on the log heading, together with time elapsed since circulation.

16



1.4 Field Prints, Headings and Service Reports Final print headings, and those surveys still being run by non-computerised logging units, are in the API format. Field prints of computerised logging units have a different format. The following notes will help in checking correctness of print headings. API Headings Most of the information supplied on a CSU heading is identical to the API data, but could be in a different location. Item

Description

1. 2. 3.

Location Other Services Permanent Datum

4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20.

Remarks

Latitude and longitude or co-ordinates of conductor. Codes of other services run during this trip to well. This normally is Mean Sea Level (MSL) for offshore operations and ground level for land operations. Elev. Height of datum point above sea bed (ASB). Log Measured from – Derrick Floor (DF). ft. above Perm. Datum Elevation of Derrick Floor above MSL/ground level. Date Day-month-year. Run No. Sequence number of that exact survey in that particular well, e.g.lSF/SONIC is Run No. 1. FDC/CNL run afterwards can ALSO be Run No. 1. Depth-Driller Total well depth as reported by Driller/Tool Pusher before logging. Depth-Logger Maximum depth reached during this logging run according to wireline measurements (not necessarily the same as Depth-Driller). Btm. Log Interval Deepest formation measured during this run (always shallower than Depth-Logger). Top Log Interval Shallowest recording during this run. Casing-Driller Casing OD at Drillers Casing Shoe Depth. Casing-Logger Casing Shoe depth as registered by logging tool. This must be the same on all surveys recorded through this casing. Bit Size Nominal size of drill bit used. Type Fluid in Hole Brief description of nature of mud/completion fluid. Fluid Level Position of Well Fluid in borehole. Dens. Density of hole fluid in psi/thousand feet. Visc. Viscosity of hole fluid (centipoise – NOT seconds in Marsh funnel). pH Acidity (pH) of hole fluid. Fluid Loss 30 minute fluid loss (cm3).


17

Wireline Logging: General 21.

Source of Sample

22.

Rm, Rmf, Rmc

23.

Source: Rmf, Rmc.

24.

Rm at BHT

25.

Time Since Circ.

26.

Max. Rec. Temp.

27. 28. 29. 30. 31.

Equip. Location Recorded by Witnessed by Remarks

32. 33. 34. 35.

Run No. C.D. S.O. Panel No.

36.

Cart. No.

37.

Sonde No.

18

Source (in mud system) of mud sample used for measurement of mud resistivity. This should always be the flowline. Resistivity of mud, mud filtrate, mud cake at measured temperature. Origin of sample used for resistivity determination, usually filter PRESS. The use of a downhole sample taken during a microtool run has now been discontinued. Mud resistivity at measured bottom hole temperature, estimated from charts. Approximate time (in hours) since mud circulation stopped. Maximum temperature as recorded by three maximum thermometers in this logging run. Contractor's Logging Unit number. Contractor’s base. Logging Engineer’s name. WSPE’s name. Use this space for any comments relating to surveying problems which could conceivably affect interpretation of the survey (overpulls, mud additives, lost circulation intervals, tool faults/failures, depth errors). Should be the same as item 7. Centralising Device (Centraliser, Caliper). Stand-off (Ex-centraliser, Induction stand-off). Contractor’s serial number of equipment used for this survey. Contractor's cartridge number. The designation YELLOW TOOL etc. WILL NOT DO. Contractor’s sonde number. The purpose of this item is to track down the exact equipment used for a survey, Sometimes years after a log was run.



1.5 Dispatch and Transmission of Data 1.5.1 Dispatch Surveyed data must be dispatched to the Opco Head Office (HO) as quickly as possible, to enable rapid decisions to be taken on other logging requirements and future rig activity. The following procedure has therefore been adopted:

A. LOGGING ENGINEER – is responsible for all survey data. He should supply: 1. Rough Print 2. Data Transmission 3. Field Prints 4. Sepias 5. Films 6. Tapes (CSU) 7. Service Order

To WSPE for transmission as soon as possible. If a data transmission link is available, transmit openhole logs to HO. To WSPE for safehand forwarding by first means of transport after logging. One set to be retained on rig. To WSPE to be dispatched with field prints. Sepias are NOT required when data is transmitted. To be taken by Logging Engineer or his representative to Service Company District Office by first transport for finalisation. To be sent safehand with field prints to HO, except except when surveys are data transmitted. In this case, field tape is not required. To be completed, signed and handed to WSPE as soon as possible.

B. WSPE– is to assist the Service Company Engineer, as required, to expedite data transmission, and also carry out the following: 1. Mufax*) recorded Survey as soon as possible, 1:1000 first, 1:200 relevant section ONLY. DO NOT MUFAX HEADING, BUT MARK SCALES CLEARLY AT HEAD OF LOG. 2. Forward Field Prints safehand by first transport after logging to HO. One complete set to be retained on rig.


19


3. Forward Sepias with field prints to HO. 4. Sign Service Order, attach to computerised log data and time allocation input sheets and forward to HO. 5. Arrange data transmission link for edit tape transmission to Wireline Company Computer Centre if required (CSU/CLS Operations).

1.5.2 Transmission 1. Data transmission is only required for open hole surveys, by formal request from HO. 2. The ‘Write’ ring must be removed from the Master tape before copying is attempted, to ensure preservation of the recorded data. 3. The Master tape must be copied, and from the copy a Field Edit Tape prepared for data transmission. 4. The Logging Company Engineer is responsible for transmission of data to the Computer Centre. On termination of transmission, the Computer Centre prepares an optical recording and confirms that the received data appear normal. 5. The WSPE notifies the Duty Petrophysicist that data transmission has been completed. 6. On receipt of log prints from the logging company's computer centre, the responsible Petrophysicist will check the transmitted log against the Mufax dispatched from the well-site, and subsequently against the 1:200 Field Prints hand-carried from the Wellsite. *) Type of facsimile data transmission

20



1.6 Services and Codes Code

Company

Service

AC ACBL ACL ACT AIS ASL(SDT)

WA WA WA SL BPB SL

Borehole Compensated Acoustilog Acoustic Cement Bond Log Long Space BHC Acoustilog Aluminium Clay Tool Array Induction Sonde Array Sonic Log

BCS BGL(BGT) BGN BGS BHC BHT BHTV BHTV BO BP BP

HLS SL BPB BPB SL BPB SL WA SL BPB SL

Borehole Compensated Sonic Tool Borehole Geometry Log Hole Tilt and Azimuth Borehole Geometry Borehole Compensated Sonic Log Temperature Borehole Televiewer Borehole Televiewer Explosive Service (Back off) Plug Setting Bridge Plug Setting

C/O

WA

CAC CAL CAL CAST CAV CBL(CBT) CBL-VDL

WA BPB SL HLS HLS SL SL

CBL/PET CBL/VDL/CCL CCAT CCL CCL CCL CDL

HLS BPB HLS BPB HLS SL WA

Multiparameter Spectroscopy Instrument Continuous Carbon/ Oxygen Log Circumferential Acoustilog Caliper Caliper Circumferential Acoustic Scanning Tool Compensated Acoustic Velocity Tool Cement Bond Log Cement Bond Log – Variable Density Log Cement Bond Tool Cement Bond Log Compensated Cement Attenuation Tool Casing Collar Locator Casing Collar Locator Tool Casing Collar Locator Compensated Densilog

(continued on next page)


21


Code

Company

Service (continued)

CDR CDS CDT CEL(CET) CFM CFS CHAR

SL BPB HLS SL SL SL HLS

CIC CIS CIT CLAM CNL(CNT) CNL CNS CNT CORA CPL(PCT) CSNG

HLS SL HLS HLS SL WA BPB HLS HLS HLS HLS

CSS CST

BPB SL

Directional Services-Continuous Compensated Density Compensated Density Tool (CDT-A) Cement Evaluation Log Flowmeter-Continuous Continuous Flowmeter Sonde Cased Hole Analysis and reservoir Monitoring Casing Inspection Caliper Tool Customer Instrument Service Casing Inspection Tool Clay and Matrix Analysis Compensated Neutron Log Compensated Neutron Log Compensated Neutron Compensated Neutron Tool (CNT-K) Complex Reservoir Analysis Combination Production Log Compensated Spectral Natural Gamma Tool Compensated Sonic Sonde Continuous Sample Taker

DCL DCL DD DEN DGL DIFL DIL DIL DIL DILB DILT DIS DLL DLL DLL DLLT

HLS WA SL HLS HLS WA HLS SL SL HLS HLS BPB HLS SL WA HLS

Dielectric Constant Tool Dielectric Log Depth Determination Density Tool Dual Guard Tool Dual Induction Focused Log Dual Induction Tool Induction Sperically Focused Log Dual Induction SFL Log Dual Induction Tool (DILTB) Dual Induction Tool (DILTA) Digital Induction Sonde Dual Laterolog Tool (DDL) Dual Laterolog Dual Laterolog Dual Laterolog Tool (PLS)


22



Code

Company

Service (continued)

DLS DNLL DNLL DPL DSEN DSN DSN2

BPB WA WA SL HLS HLS HLS

DSNC DTEMP

HLS BPB

Dual Laterolog Dual Detector Neutron Lifetime Log Neutron Lifetime Log (Dual Detector) Deep Propagation Log Dual Spaced Epithermal Neutron Tool Dual Spaced Neutron Tool Dual Spaced Neutron/Model DSNT-A Tool Comprobe Dual Neutron Tool Differential Temperature

EL ENVR EPT/PCD EPT/PCD ETT

HLS HLS SL SL SL

Electric Log Tool Environmental Corrections Electromagnetic Propagation Log Powered Caliper Device Casing Corrosion Detector

FAC FACT FBS FDC FDL FDS FED FFS

BPB HLS SL SL HLS BPB HLS BPB

FIT FLOLOG FMS FMT FMT FPI FPT/BO FS FTL FWS

SL WA SL WA WA WA BPB SL HLS HLS

Four Arm Caliper Four Arm Caliper Tool Fullbore Spinner Flowmeter Formation Density Log Fluid Density Tool Fluid Density (Production Logging) Four Electode Dipmeter Tool (Four Arm) Fullbore Flowmeter (Production Logging) Formation Interval Tester Flowmeter Formation MicroScanner Log Formation Multi-Tester Formation Tester Free Pipe Indicator Pipe Recovery Fluid Sampling Fluid Travel Tool Full Wave Sonic Tool

GCT GEN

SL HLS

Continuous Guidance Tool General Purpose



23


Code

Company

Service (continued)

GEOP GMS GR GR GR GR-N GRD GRN GRVL GST GTEM

HLS SL BPB HLS SL WA HLS HLS HLS SL HLS

Geophone Gradiomanometer Gamma Ray Gamma Ray Tool Gamma Ray Log Gamma Ray Neutron Log Guard Tool Gamma Ray Neutron Tool Gravel Pack Tool Gamma Ray Spectroscopy Log Gradiomanometer Temperature Tool

HDD HDT HMS HMST HRDIP HRI HTT

HLS SL SL HLS WA HLS SL

High Density Dipmeter Tool High Resolution Dipmeter Log Manometer Temperature Sonde (HP) Multiset Tester Tool Diplog (Four Arm High Resolution) High Resolution Induction Tool High Resolution Temperature Tool

IEL IEL IELT IFS IL

HLS WA HLS BPB SL

Induction Tool (DDL) Induction Electrolog Induction Tool (PLS) Inline Flowmeter (Production Logging) Induction Logging

JC

WA

Junk Catcher

LCS LDL(LDT) LFD LIDA LL LL LSAV LSS LSS

BPB SL HLS HLS HLS WA HLS HLS SL

Long Spaced Compensated Sonic Litho Density Log Low Frequency Dielectric Tool Lithology Indentification Analysis Laterolog Tool Laterolog Long Spaced Acoustic Velocity Tool Long Spaced Sonic Tool Long Spaced Sonic Log

MEL

HLS

Microelectric Tool


24



Code

Company

Service (continued)

METT

SL

MFC MFD MGL MGL ML ML ML MLL MLL MLL MSCT MSFL

SL SL HLS WA BPB HLS WA BPB HLS WA SL SL

MSFL MSG MSI C/O MTS MWP

HLS HLS WA SL SL

Multifrequency Electromagnetic Thickness Log Multi Finger Caliper Log Modular Formation Tester Microguard Tool Casing Thickness Log Micro Log MicroLog Tool Mini-log Micro Laterolog Microlaterolog Tool Micro Laterolog Mechanical Sidewall Coring Tool Microspherically Focused Resistivity Log Microspherically Focused Tool Micro-Seismogram Frac-Finder Tool Carbon/Oxygen Log Manometer Temperature Sonde Measurements While Perforating

NCS

BPB

NEU NFD NGS(NGT) NL NLL NML

HLS SL SL WA WA SL

Nuclear Combination Sonde (GR-CN-CD) Neutron Tool Nuclear Fluid Densimeter Natural Gamma Ray Spectrometry Log Neutron Log Neutron Lifetime Log Nuclear Magnetism Log

OBD OBDT

BPB WA

Oil Based Dip Meter Oil Based Mud Dipmeter Log

PAL PDC PDK-100 PDS PET PFC

SL SL WA BPB HLS WA

Pipe Analysis Log Perforating Depth Control Log Pulse and Decay Photo Density Sonde Pulsed Echo Tool Perforating formation Collar



25


Code

Company

Service (continued)

PFM PI PL PL PL PLA PLS PML PSD PSGT PTS PTS PTT

SL SL HLS SL SL HLS BPB WA BPB HLS BPB SL BPB

Flowmeter-Packer Phasor Induction Production Log Production Logs/Flow Profiles PL/Transient Pressure and Flow Tests Production Log Analysis Production Logging Proximity-Minilog Precision Strata Dip Meter Pulsed Spectral Gamma Tool Pressure Temperature Sonde Pressure Temperature Sonde Temperature (Production Logging)

QPG

BPB

Fluid Pressure (HP Gauge) (Production Logging)

RFS RFT RFT RSCT RSFE

BPB HLS SL HLS BPB

Repeat Formation Sampler Repeat Formation Tester Tool Repeat Formation Tester Rotary Sidewall Coring Tool Shallow Focussed Guard Log

SASH SCG SDL SED SFE SFT SFT SGP

HLS BPB HLS HLS BPB HLS WA BPB

SGR SGS SHDT

HLS BPB SL

SHDT SIT SIT/FPIT

SL SL SL

Shaly Sand Analysis Sidewall Core Gun Spectral Density Tool Six Electrode Dipmeter Tool (Six Arm) Short Focussed Guard Sequential Formation Tester Tool Selective Formation Tester Tool Fluid Pressure (Strain Gauge) (Production Logging) Spectral Gamma Ray Spectral Gamma Ray Stratigraphic High-Resolution Dipmeter Log Dual Dipmeter Log Free Point Indicator Stuck Point Indicator/Free Point Indicator


26



Code

Company

Service (continued)

SLD

HLS

SNL SP SP SP SP SPEC SPIN SPL SW SWC SWC SWN SWN

WA BPB HLS SL WA WA HLS WA BPB HLS WA HLS WA

Spectral Litho Density Tool Sound (Sonan) Log Sontanous Potential Sontanous Potential Sontanous Potential Sontanous Potential Gamma Ray Spectrum Spinner Survey Tool Spectralog Sonic Waveform Sidewall Coring Tool Sidewall Samples Sidewall Neutron Tool Sidewall Epithermal Neutron Log

TAC TBP TCS TDS TDT TEMP TL TMD TRL TVD

BPB WA SL BPB SL HLS WA HLS WA HLS

Two Arm Caliper Thru-Tubing Bridge Plug Thru-Tubing Caliper Sonde Thermal Neutron Decay Thermal (Neutron) Decay Time Log Temperature Tool Temperature Log Thermal Multigate Decay Tool Injection Profile by Radioactive Tracers True Vertical Depth

UCC UGD UHF

SL BPB HLS

Ultrasonic Caliper Log Acoustic Noise Ultra High Frequency Tool

VCST VDL

HLS SL

Vertical Cable Streamer Tool Variable Density Log

WSS/SAS/DSAS (WST/SAT/DSAT) WSS/SAS/DSAT (WST/SAT/DSAT) WSS/SAS/DSAS (WST/SAT/DSAT)

SL

Downhole Seismic Array

SL

Seismic Acquisition Tool

SL

Well Seismic Surveys


27


Code

Company

Service (continued)

WTPS

SL

Well Tests Instruments Pressure Sonde

XYC

HLS

X-Y Caliper Tool

Z-Density

WA

Compensated Z-Densilog

Logging Company Abbreviations SL – Schlumberger WA – Western Atlas HLS – Halliburton Logging Services BPB – British Plaster Board

28




29


30




31


32




33


34




35


36




37


38




39


40




41


42




43


44



1.8 Logging Cables, Heads and Fishing Tools



45


Table 1.8-2 (continued)

*) These characters are for Rochester cables Note: The maximum permissible pulling on a cable without customer’s order is 50% of the breaking strength of the new cable.


46



Table 1.8-3 (continued)


47


48




49


1.9 Wireline Logging Operations in Deviated Holes The main problems in logging deviated holes concern the lowering of the tools in open hole and the possible collapse of pad type tools due to gravitational force. Another problem is that in a very oval hole the four pads of the dipmeter may not all be in contact with the borehole wall. Normal wireline logging tools have been lowered successfully in properly drilled holes with deviation angles greater than 60 degrees, where all necessary care had been taken to avoid washouts, ledges, doglegs and sticking hole conditions. Under normal drilling conditions, holes with angles of greater than 45 degrees may cause difficulties in lowering wireline logging tools. In cased holes these tools can be lowered without difficulty at angles exceeding 70 degrees. Where more rugose borehole conditions and/or increased borehole angles prevent lowering of the tools, the first step is to log these holes with standard tools adapted to reduce friction, increase tool weight and tool flexibility. These tools can be used in open holes with angles up to 70 degrees. Under more severe open hole conditions or greater borehole angles the logging operation may have to be carried out by lowering the tools through casing, tubing or drill pipe. A pumpdown technique may have to be used to propel the tool down the pipe and into the open hole. These operations are time-consuming and evaluation results become less certain if smaller diameter logging tools have to be used because of the restricted diameter of the pipe. For near-horizontal drilling, special techniques have been developed to lower standard logging tools to the bottom of the drill pipe and make an electrical connection between the wireline cable and the tool at logging depth.

1.9.1 Friction Reducing Devices Two basic types of friction reducing device for open hole are available; these are an in-line wheel device, and a stand-off device made from rubber or low-friction plastic designed for operation in 57/8" diameter or larger bore-holes. For casing and tubing operations various sizes of wheel centralisers, wheel subs and weights, designed for installation at various places in the tool string, are available. The wheel centralisers are useful for wells with very high deviation and long intervals of smooth borehole wall consisting of consolidated rock.

50



1.9.2 Other Devices Weight Increasers For open hole operations a 2.5 m long, 33/8" diameter device, weighing 120 kg and containing straight-through electrical conductors, can be installed between the cable head and the top of the tool string. More than one can be run in tandem; other designs are available for cased hole and through-tubing operations. Tool Flexibility A flexible adapter consisting of a 33/8" flex joint and two 33/8 in. in-line wheels allowing a 4º flexure, can be installed between combination logging tools to negotiate doglegs in the hole. Tool Guidance A semi-flexible guide with rubber fingers connected to the bottom end of the tool string can assist in guiding the tool end past ledges or out of washouts. The stand-off devices help the tool to overcome washouts by keeping it in the middle of the hole and help in locating the hole in a ledge at the bottom of a washout. Schlumberger reports good results in with these friction reducing devices (Ref. 1) open hole and up to 65º hole angle.

1.9.3 Logging Through Casing Drill Pipe: Pumpdown Techniques Another method of lowering tools past difficult hole sections is to install open ended casing, tubing or drill pipe over these sections and to log the open hole section below it. Pumping down of the tools is required where friction is too high. When the complete open hole section cannot be logged in one run, it is necessary to lower the pipe over parts of the objective section as well and to log the remaining open hole. This procedure may have to be repeated several times to obtain logs over the complete sequence. It is advisable to install a tool re-entry guide on the bottom of the pipe to facilitate re-entry of pad type tools and to avoid cable damage. The internal diameter of the casing, tubing or drill pipe used may be too small for standard tools and slim hole tools have to be used. Allow 13 mm diameter clearance in the drill string.


51


The following tools are available:

The procedure for logging through drill pipe is as follows: (a) Run in hole with open ended drill pipe. Collars and Heviwate should only be used when essential (check clearance required for tools with the minimum ID string). Fit a guide shoe or skirt to the bottom of the string to permit easy re-entry of the logging tool. The pipe should be moved up and down slowly with the blocks to prevent sticking. (b) Attach mud pumps via Chicksan line to a circulating head installed at the top of the drill string. (c) Rig up logging company's top sheave wheel near the crown block using a 25 t sling. (d) Thread logging cable over sheave wheels and through the pressure control equipment and connect tool. (e) Set pipe in slips. Pick up pressure control equipment with tugger line; pick up tool with cable winch and run tool to 30 m below the drill floor. Slack off on tugger and connect pressure control equipment to circulating head. (f) Reciprocate pipe and begin circulation with the mud pumps. The mud pumps should be started with caution and only 10 – 15 bar pressure is normally required to circulate the mud.

52



(g) Run logging tool down inside the drill pipe as fast as possible without causing any drop in cable tension. The pipe should not be reciprocated as the tool approaches the guide shoe. (h) As soon as the tool is descending in open hole, move the pipe again if there is any risk of sticking. (i) Log from the lowest depth reached. Continue circulating mud until tool is inside drill pipe. (j) Stop moving pipe when tool approaches the guide shoe. (k) Depending on the maximum depth reached, it may be necessary to add some more stands to the drill string and set the guide shoe about one hundred metres deeper before the next attempt is made to get the tool down to total depth. If difficulty is encountered when re-entering the drill pipe after logging, very slow rotation of the pipe should allow re-entry. A disadvantage of slim hole tools is the reduced accuracy of the porosity measurement (by 2–3%) and resistivity measurement due to the larger borehole effects. 1.9.4

Logging of Near-Horizontal Holes

To overcome the problems with slim hole tools and to be able to log nearhorizontal holes, two systems have been developed as described below: (a) Logging Horizontal Wells by the SIMPHOR System The Institut Français du Pétrole and Elf Aquitaine have developed and used this method to log horizontal boreholes. Standard open and cased hole Schlumberger logging and perforating (4" carrier) tools have been lowered into the hole inside a protective housing on the bottom of the drill-pipe string. When this string reaches the shoe of the last casing, a 7 conductor electric transmission cable connected to a sinkerbar and female electrical connector system is lowered inside the drill pipe, until it locks mechanically into the logging sonde and makes the electrical connection. The logging cable is brought outside the drill string via a side entry sub. Further adding of drill pipe brings the logging tool in the open hole and logging can commence after power is applied to the cable. Some 500 m of near-horizontal 81/2" hole have been logged in this manner with standard 3 to 4” OD tools using the 5" OD SIMPHOR system. A 3" SIMPHOR is available for running tools without a protective housing.


53


Logs recorded to-date using this method are: induction, spherically focussed, dual laterolog, gamma ray, neutron, BHC sonic, 4 arm-caliper, CBL, CCL and 4" perforating gun for perforating 7" liner (9 m length). (b) Logging Deviated Holes over 65º A prototype has been built by Schlumberger of a tool system to lower standard size logging tools in a steel envelope with a stinger on the bottom of the drill pipe. A locomotive brings an 8-conductor cable down through the drill pipe and first connects the stinger and then makes the electrical connection with the tool. Further pumping brings the tool out of the steel envelope into the open hole, and logging can commence.

54



1.10

Sticking of Wireline Logging Equipment

Most Frequent Causes of Stuck Tools (a) Differential sticking. Cable or logging tools can be stuck to the wall of the hole by differential pressure if the tools are not moved or moved at a very low speed. (b) Key seating. Cable or logging tools can be pulled into a slot (key seat) which is sometimes cut in the (high) side of the hole by the cable during a series of logging operations, particularly so in deviated wells. (c) Unstable hole. Hole collapsing, loose formation and hole bridging.

Prevention of Differential Sticking (a) Move the logging cable continuously when running tools in open hole. (b) Calibration of certain tools which may be carried out in a 150 m open-hole section immediately below the casing shoe should take the shortest possible time. (c) During WLFT, after setting the tool, the cable should be slackened off and moved ('yo-yoing') throughout the test period. (d) Limit the number of logging runs in between bit trips in the hole particularly when heavy mud is used or frequent drag is experienced. This limit may be relaxed if the hole is in excellent condition and no drag is experienced. It is at the discretion of the Toolpusher advised by the WSPE and the Logging Engineer to decide if and when a checktrip will be made. (e) During sidewall sampling, the samples should be taken while moving the tool very slowly upwards (‘sampling on the run’). (f) Should the Logging Unit break down whilst running tools in the open hole, the following emergency procedures should be followed: Move the traveling block over a 3–5 m interval to move the cable, taking care that the cable does not jump out of the groove of the top sheave. Check the weight on the Martin Decker gauge. Before starting this operation, ensure that the Logging Contractor’s weight indicator cable is not fastened to the derrick floor and can move freely. The operation should always be supervised by the Logging Engineer. If possible there should be inter-communication between the Logging Unit and the Driller so that the operation can be controlled by the more sensitive wireline logging tension meter.


55


1.10.1

General Guidelines on Stuck Tool, Weak Point and Fishing Kit

(a) If tool is stuck on bottom, pull to maximum safe tension and hold it. (b) If tool is stuck during logging, try to go down. If tool is free to descend, attempt to pass bridge. If tool is not free to descend, tool or cable is stuck. Pull to maximum safe tension and hold it. (c) If the tool fails to come free after working the cable for 30-40 min, the ‘cut-and-thread’ technique should normally be attempted. The cable will hold the tool in a centralised position and serve as a guide for the overshot. (d) On no account should an attempt be made to break the weak point unless clear instructions have been given from base to do so. (e) Sharp edges and abrasive formations will cause wear during working the stuck cable. The weak point above the tool is therefore no longer the weakest point necessarily. Even if successful, breaking the weak point considerably reduces the chance of recovering the tool. (f)

In a vertical hole of good condition with no sign of cable key-seating, or when inside casing, a tool can be fished with good probability, using the technique of breaking the weak point and fishing with an overshot with OD slightly smaller than bit size.

(g) NEVER break the weak point when a radioactive tool is stuck. Cutting and threading is obligatory. (h) Never SUDDENLY release tension on a cable. This causes 'bird cages' and broken cables. Tension should be released slowly and should not drop below half the 'normal’ logging tension. (i)

Know the cable weight, the allowed overpull and hence the maximum safe pull which can be applied at all times.

(j)

Never pull more than 8,000 lb on a normal cable (break point 16,000 lb). Check the type and age of the cable.

(k)

Never pull more than 2,500 lb on a small cable (break point 5,100 lb).

(I)

Never pull more than 7,500 lb on a spliced cable.

(m) Never pull more than 4,500 lb on the standard weak point unless breaking is intended (and only on clear instructions from Base).

56



(n) Never pull more than 1,500 lb on the weak point of a small cable unless breaking it is intended. Safe pull is 1,125 + (0.08 x depth in feet) lb.

Schlumberger Fishing Kit The fishing kit is designed to fit 41/2" IF tool joint. It includes: 1. A complete overshot assembly. Four guides are available: 31/2", 4'/2", 53/4" and 7" OD. The grapples fit the different cable heads. 2. A spear rope socket with matching overshot rope socket assembly. 3. A circulating sub. 4. A cable hanger. Note: The WSPE should check with the Logging Engineer the correct size of grapple to use for the logging head in use before to RIH. The size of the grapple should be measured as a double check.

1.10.2 Fishing for Stuck Tool 1.10.2.1 Open Hole When a tool becomes stuck in open hole and all attempts to free it have failed, the decision must be made at Base whether to fish the tool or cement it in place. This is particularly important in the case of tools containing radioactive sources, to which special regulations apply (see 8.1). In the unlikely event that the decision is made to cement the tool in place, specific instructions for the procedure to be followed will be telexed from Base. In general, the Wireline Company Engineer will probably have more experience at fishing for wireline equipment than the Oil Company Engineer. Nevertheless the responsibility for the fishing operation rests with the WSPE and the Toolpusher who should familiarise themselves with the equipment and technique to be used before the operation commences. The wireline company engineer will supply the required fishing tools and advise if requested, but once the tool is stuck his assistance is advisory only. The following procedure is to be adopted when fishing with the ‘cut and thread technique' (stripping over cable): Preparing the Cable: (a) Set cable tension at 2,000 lb above normal hanging weight. (b) Clamp the T-bar on the cable just above the rotary table, and lower the cable until the T-bar is supported by the rotary table. Continue lowering cable until there are several feet of slack cable on the drill floor.


57


(c) Cut the cable a few metres (1.5-2 m) from the T-bar and make up the Bowen spear to the logging unit end and socket to the tool end. (d) Rig down Wave Compensator (floating rigs). Attach upper wireline sheave to main cross-member of derrick with special chain to leave blocks free to run pipe. Ensure that the wireline tension device cable is carefully trained around the outside of the derrick to avoid damage during drill floor operations. Threading Cable Through Drill Pipe: (e) Make up correct fishing guide and grapple assembly for fishing neck of stuck tool. Use correct skirt for hole size. Feed socket on cable end through fishing assembly. (f) Thread overshot spear through first stand of pipe and stab into socket. (g) Take tension on wireline, check overshot assembly. Remove T-bar. Make up first stand to fishing assembly. (h) Run first stand into hole, set slips. (i)

Place C-clamp over top of drill pipe, lower cable assembly to catch lower rope socket on C-clamp, disconnect spear.

(j)

Pick up next stand of drill pipe, thread overshot spear through pipe, stab into rope socket, take cable tension with winch, remove C-clamp.

(k) Lower stand, watching cable tension carefully, and stopping if cable tension increases. DO NOT ROTATE PIPE while lowering, to avoid possibility of cutting cable. Approaching and Engaging the Fish: (I) When the grapple is one joint above the tool, install circulating sub, circulate slowly to clean top of tool. Continue circulation while lowering pipe and engaging fish in overshot. Note increase in pumping pressure and cable tension as tool head enters overshot. Stop circulation. (While circulating, the cable is held onto the circulating sub by a special bushing.) Breaking the Weak Point: (m) Ensure that fishing head is engaged in grapple, set pipe in slips. Attach T-bar to cable (below socket), pick up T-bar with travelling blocks. (n)

58

Pull up slowly on cable and break weak point. DO NOT SNATCH.



(a) Remove Bowen spear overshot and rope socket, knot logging cable, take cable tension with logging unit winch, remove T-bar. (p) Spool cable on logging unit. (q) Pull pipe out of hole slowly. DO NOT ROTATE. Close BOPs as soon as tool is safely through. (r) Ensure that complete tool has been recovered. Grapples, guides, skirts and circulating sub are supplied by the Wireline Logging Contractor. In deviated wells ( > 25º) it is almost invariably safer to strip over the cable to recover both tool and cable. If the cable breaks at a dogleg, it will still be retained inside the drill pipe. The procedure to be followed in this case is given above. 1.10.2.2

Cased Hole

It should not normally be necessary to strip over the cable to recover a tool stuck inside a vertical casing. In this case it is far quicker, easier and cheaper to break the weak point and fish for the tool with the cable removed from the hole. Nevertheless, the decision to follow this course must be made by Base. Procedure in vertical casing when strip over is NOT required is as follows: (a) Clamp the T-bar to the cable above the rotary table. (b) Rig down Wave Compensator (floating rigs). Attach upper wire line sheave to main cross-member of derrick with special chain to leave blocks free. (c) Pick up T-bar in travelling blocks, pull up and break weak point. (d) Lower blocks, take cable tension with logging unit, remove T-bar, spool cable on logging unit, (e) Rig down wire line. (f) Make up fishing assembly with correct fishing guide, skirt and grapple for casing size and tool fishing neck. (g) Run in to top fish, carefully engage fish. (h) When fish is securely engaged, pull out slowly. DO NOT ROTATE.


59


(i) Close BOPs as soon as tool is safely through. (j) Ensure that complete tool has been recovered. Grapples, guides, skirts and circulating sub are supplied by the Wireline Logging Contractor. 1.10.2.3

Fishing through Tubing

1. When a tool gets stuck either in or below tubing, the only remedy in most cases is to pull tubing to recover the fish. It is not unknown for a fish to be retrieved by pumping it out, using reverse circulation (down the tubing/ casing annulus, up the tubing). 2. Fishing can be attempted on piano wire. The technique can only be successful if the tool is free, e.g. it has dropped off the end of the logging cable. Fishing for a stuck tool using piano wire will almost invariably aggravate the problem. 3. Equipment required for fishing on piano wire is supplied and maintained by the piano wireline contractor.

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1.11 Detection of Stuck Point/Back-Off Equipment Detection of the stuck point in order to find the lowest possible back-off can be established by stretching the string and using stretch charts for drill pipe. A more accurate method of free point detection is using the Stuck Pipe Indicator Tool (SIT) (see Figure 1.11-1). 1.11.1 Stuck Pipe Indicator Tool In order to back-off the string at the deepest possible point a Stuck Pipe Indicator Tool (SIT) can be run on electrical wireline to determine the deepest free point of the string. By applying stretch and torque on the pipe the SIT can determine elongation or rotation at any depth by use of a strain sensor placed between two springloaded or hydraulic centralisers. The operation is monitored at the surface and depth control is provided by a CCL. A plot of depth versus the percentage of surface torque and pull transmitted downhole will show the deepest point at which the string is free (see Figure 1.11-2). Procedure for Running the SIT (a) Before running the tool the spring centraliser pads should be checked by the WSPE both for wear and for the correct pressure for the particular size of drill pipe. All IDs of the string should be checked to ensure the tool can pass through. (b) Determine approximately where the pipe is stuck by measuring the stretch of the pipe. (c) Using the Logging Company tables, determine the stretch and torque that have to be applied to the pipe. (d) Pull up to the neutral weight of the pipe above the stuck point. Mark the pipe at this point. Label this Mark No. 1. (e) Pull up to the neutral weight of the pipe plus the stretch required. Label this Mark No. 2. (f) After this the Martin-Decker gauge is not used but still observed. All tensions are referred to by the marks on the DP.


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Write out for the Driller the four instructions for the measurements viz: (i) Pull pipe up to Mark No. 2. Take reading. (ii) Release tension in pipe, go down below Mark No. 1 and pull back up to Mark No. 1. (iii) Drop in the slips without moving the pipe if possible. (If not using a kelly). Apply the required torque. Work down the torque using tongs preferably on a convenient tool joint to prevent the pipe from rotating. Pull up to Mark No. 1 before taking the measurement. Keep all nonessential personnel off the drill floor during this operation. (iv) Release the torque. Report the number of turns that come out of the pipe. Work the pipe to remove all torque. Pull back up to Mark No. 1. Notes: 1. It is essential that the pipe is pulled up to the marks to avoid problems due to pipe friction in the hole. 2. It is essential when measuring stretch that there is no torque in the drill pipe, and vice versa. 3. When taking the readings the Logging Engineer should refer to each instruction by number. This avoids any confusion and ensures that the operations are properly repeated.

(g) Run the SIT down to + 60 m above the expected stuck point where it is certain that the pipe is free. Take the stretch measurement first, followed by the torque measurement. Check the readings to confirm that the SIT is not slipping or that the torque has worked itself down. (h) Measure stretch and torque below the stuck point, as close as possible. (i) Take further measurements between the lowest free point and the highest stuck point. Take as many measurements as possible around the stuck point. (j) The PE and TP should co-ordinate the operations of the Driller and the Logging Engineer. Example: Rasau-6X (see also Figure 1.11-2). Driller's Instructions: 1. Pull pipe up to Mark No. 2 (185,000 lb). 2. Release pipe to 145,000 lb and pull up to Mark No. 1 (165,000 lb). 3. Drop pipe in slips, work in 5 turns RH torque 4. Release torque. Situation: 31/2” 15.5 lb/ft drill pipe stuck at 10,586 ft.

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1.11.2 Back-Off Equipment The back-off operation (with explosives) consists in transmitting torque to the joint to be broken while applying pull for neutral weight at this depth. Choose a connection that was broken on the last round trip. An explosive device is positioned by a CCL in the joint to be broken and is detonated to help unscrew the pipe. String Shot Size The size of the string shot should be determined as near as possible. It must be big enough to back off the joint without splitting the pipe. In general 2 – 3 strands of primer cord can be taken over and above the Schlumberger recommended charge. If no back-off torque can be applied, an attempt can be made ‘to jump’ the box: – Run 80 grain primer cord of a length (in feet) equal to at least 10 times the pipe diameter (in inches), e.g. for 41/2" drill pipe use 45 ft (15 m) of 80 grain primer cord. – Make sure the primer cord bundle passes through the minimum ID of the string. – As a last resort the pipe can be cut by using explosive or chemical cutters (111/16” Schlumberger severing tool). Here also the minimum restriction of the pipe should be observed.

1.12 Wireline Logging Wave/Tide Compensation for Floating Rigs The most common system used for wave/tide compensation is shown in Figure 1.12-1. The system works as follows: Three sheave wheels A, B, C are required for compensation. C is attached to the floating drill ship, below the reference point (in this example, the wellhead W). A is held in the travelling blocks, and B is supported by a1/2" steel cable which passes from the wellhead W, under wheel C, over wheel A, under wheel B and is tied back to wheel A again. The upper logging cable sheave wheel U is fastened to wheel B through the tension device T, and the lower logging cable sheave wheel L is attached to the drill floor of the rig. Assume the entire floating system moves upwards a distance h relative to the wellhead W, which is fixed to the sea bed.


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Wheel C will move upwards a distance h, and a length of cable equal to h will pass around wheel C and also around wheel A, which is fixed relative to C. Since the other end of the cable is attached to A, the extra cable is taken up by movement of wheel B downwards through a distance h/2 relative to A. Wheel B has therefore moved upwards by h/2 with respect to the wellhead and mean sea level (MSL). Now consider the logging cable. The upper sheave wheel U is attached to B, and has moved upwards h/2. The lower sheave wheel L has moved upwards a distance h. A length of cable h/2 therefore passes over U, equal to the upward distance moved by U; the logging tool therefore remains at exactly the same place relative to the wellhead and MSL. Notes: 1.Distance W–C must exceed the maximum tide/wave movement expected throughout the logging operation. 2. The rucker system to the wellhead must be operational when the wave compensator is in use. 3. State of the tide (above mean sea level) must be taken into account during the first logging run when the magnetic mark is caught at the rotary table with the tool at casing shoe. Thereafter, the tool zero and mark are checked roughly at surface, and the surveys are tied in to the first run. 4. Do not attempt to free a stuck tool with the Wave Compensator in use. Clamp off the logging cable with a T-bar and rig up with the upper logging wheel U in the travelling blocks.

An alternative compensating device is shown in Figure 1.12-2. This system is much simpler than the older device, which it is rapidly displacing. The system works as follows: A heavy cable C is connected from the top of the marine riser, over a large sheave wheel W which is supported by a tensioner D from the travelling blocks, to a shear pin attached to the derrick floor. The upper logging sheave wheel U is attached via the cable tension device to the sheave wheel W, and the lower logging sheave L which is fastened to the derrick floor. Suppose that the drillship moves down a distance h. The shear pin moves down the same distance, but the other end of cable C remains stationary. The compensatory device D operates to maintain tension in cable C, wheel W therefore moves down, but only a distance h/2. Now consider what happens to the logging cable.


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The lower sheave L, which is attached to the derrick floor, moves DOWN a distance h. If the upper sheave sheel U were fixed (relative to the seabed), the logging tool would have to rise through the same distance, h. But the upper sheave wheel U has descended by a distance h/2, allowing the tool to descend h/2 + h/2 = h. The net result is that the logging tool remains at a fixed depth relative to the top of the marine riser. Notes: 1. The compensating device (tensioner) D must have sufficient travel to cope with maximum tide/wave movement expected during the logging operation. 2. State of the tide above mean sea level must be taken into account during the first logging run (as in Note 3 above). 3. Attempts may be made to free a stuck tool with the wave compensator operating.


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Open Hole Logging

2 OPEN HOLE LOGGING 2.1 Methods of Open Hole Logging 2.1.1 Rig-Up and Survey Checks Details of the calibration can be found in the latest contractor literature, e.g. Schlumberger Cyber Service Unit, Well site Products Calibration Guide and Mnemonics, CP 32 or (Dresser) Atlas, Calibration Guide, 486. 2.1.1.1 Rig-Up (a) Check that the sheaves have been inspected on a regular basis. (b) Lower sheave. The wheel tie-down chain must be fastened to an integral part of the rig structure. The loose end of the chain should be taped or tied with string to prevent accidental release. (c) Tension device cable should be tied back out of the way of logging cable, and its path from rig floor to survey unit must be carefully arranged to avoid damage from crane operations during logging. (d) Cranes must not traverse or lift above logging cable during wireline operations. (e) When making up combination tools in the hole, the blind rams must always be closed. If the tool is too long to be made up above the closed rams, it must be connected together over the mouse-hole (f) Check that the lower sheave is aligned with the cable, and that the upper sheave has rotated so that the cable does not foul itself, after the tool has been picked up. (g) Make surface calibration before survey 2.1.1.2 Running in Hole (a) Set Tool Zero at drill floor. (b) Check that Bell remains on depth. (c) Check that tool appears to be working. Run in hole with such speed that can be reached on changes in cable tension without damaging the tool or entangling the cable. Overall maximum speed should be less than 12,000 m/hr (40,000 ft/hr). (d) Note all bridges, tight spots, etc. by watching tension indicator. (e) If tool hangs up above TD, attempt to work it past the obstruction but do not endanger the tool and do not spud. It is cheaper to make a wiper trip with the bit than to fish a radioactive source out of the hole. (f) Make downhole calibration before survey.

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2.1.1.3 On Bottom (a) Check depth. (b) Make repeat section. (c) Check scales, look for obvious anomalies, check light intensity of film Check memorisation and applied corrections. (d) Run survey. 2.1.1.4 Surveying (a) Check lift-off point. Restart if footage is missed. (b) Check readings to ensure they make sense. (c) Make sure that film canisters are turning. (d) Make sure Bell remains on depth. (e) Cable Tension. When using standard weak point on normal cable, this must not exceed 3,0001b overpull without permission from HO. The weak point is designed to break at about 5,000 lb overpull. Monocable heads (and monocables used for perforating) use weak points with considerably reduced breaking strength. (f) Logging Speed. See individual tools for maximum speed. (g) Correlate with previous logs. (h) Record 30 m past casing shoe, or overlap with previous logs. 2.1.1.5 After Survey (a) Check that repeat section repeats. (b) Record downhole calibration after survey, and check that both calibrations are correct. (c) Check that logging speed is correct. Note that the speed is indicated on the film by breaks in the left hand margin of track one. The distance between two breaks is the distance recorded in one minute. (d) Be satisfied with the log before laying down tools. (e) Check head, bridle, torpedo of the tool for damage as soon as the tool is out of the hole. (f) Make surface calibration after survey. 2.1.2

Induction – Spherically Focused

2.1.2.1 Spontaneous Potential (SP) (a) Scale 10 or 15 mV per division.


71

Open Hole Logging

(b) Speed (As Induction) 1800 m/h (limited by GR requirements). (c) Calibration Recording not required. (d) Common Faults. (i) Noise. This is frequently caused by welding on the rig, storms and rig generator faults. (ii) Oscillation. Caused by magnetisation of drum, winch chain or spooler. (iii) Galvo drifts off track. 2.1.2.2 Spherically Focused Resistivity (a) Scale Logarithmic 0.2 to 2000 Ω - m. (b) Speed 1800 m/h (but limited by GR requirements) (c) Calibration

Note: Look out for noise 'spikes’ caused by poor contacts in tool or electrodes, or wear on commutator. SFL cannot be run in oil-base mud.

2.1.2.3 Induction (a) Scale Logarithmic 0.2 to 2000 Ω.m. (b) Speed 1800 m/h (but limited by GR requirements) (c) Calibration

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Notes; 1. Ensure that Induction has been correctly memorised. 2. Induction survey should repeat exactly. 1 3. Ensure that 1 /2" standoffs are used.

2.1.3

Dual Laterolog

(a) Scale 0.2 to 2000 Ω.m logarithmic. (b) Speed 1200 m/h (limited by speed of MSFL or GR when run in combination). (c) Calibration (i) SU Calibration recorded downhole before and after survey, should match exactly. Crucial reading is 31.6 Ω m (last step). (ii) CSU

2.1.4

Micro Tools

1. Pad tools will rarely repeat exactly, but any discrepancy between runs should be minor. If in doubt, ask for extra repeats. In any case, check condition of pads before and after survey. 2. Always make a short piece of film into the foot of the casing, and check the resistivity readings and caliper. 3. Always run caliper with Microtools as it is essential for interpretation.

2.1.4.1

Micro-SFL

(a) Scale Logarithmic 0.2 to 2000 Ω. m. (b) Speed 600 m/h. (c) Calibration (i) SU Calibration before and after survey should match exactly. Check low reading (2 Ω. m) and high reading (1000 Ω. m). (ii) CSU


73

Open Hole Logging

Before Survey: After Survey: Tolerance:

Zero 0

Plus 1000mS/m

+2

+ 20mS/m

Note:

This tool sometimes has a tendency to oscillate, particularly at high resistivities. Above 100 Ω. m, the microtool reading is of little value.

2.1.4.2 Proximity Log (a) Scale Logarithmic 0.2 to 2000 Ω.m. (b) Speed 1200 m/h. (c) Calibration Calibration before and after survey should match exactly, except 1000 Ω.m signal may not be very stable and may drift between 750 and 1050. This need not cause concern. Note: The survey can be run with cartridge in 'Microlaterolog’ position. This results in a survey with the resistivities too low ( Χ 1.65 to get true reading).

2.1.4.3 Microlaterolog As for Proximity, except the most common fault is running the log with the cartridge in ‘Proximity’ position. This results in a survey with the resistivities too high (Χ 0.6 to get true reading).

2.1.4.4 Microlog (a) Scale O to 10 Ω.m (b) Speed 600 m/h. (c) Calibration Calibrations before and after survey should match exactly. Notes: 1. Reject a survey with negative readings. 2. One or both resistivity curves may read incorrectly – often caused by faulty pad wiring.

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2.1.5 Gamma Ray (a) Scale 0 – 100 API (Open and Cased Hole) (If recorded value is around 100 API for long intervals the scale may be changed to 0 – 150 API). (b) Speed 550 m/h Time Constant 2. 1100 m/h Time Constant 1 (Cased hole, for correlation only). (c) Calibration Before survey calibration only required. This includes zeros, memoriser sensitivity check, background and calibration. Notes: 1. Check that GR is correctly memorised, to be on depth with main simultaneous survey. 2. Check for cross-talk with other pulsed tools. 3. Reject a survey with spurious, random peaks or zero readings. 4. Clean, porous sections have a GR background reading around 10 API. 5. Repeat will not be exact, as a result of statistical variations.

(6) Depth Control for Perforating When surveying with CCL for perforating depth control, 60 m repeat run should include 30 m with CCL depth corrections; 30 m without. The log heading must include tool type and CCL and radioactivity tool measure points. State clearly whether CCL or the correlation log is on depth. If memorisation or optical correction is applied so that both the CCL and the recorded log are on depth, this should be stated, along with the amount of correction applied. Ensure that panel settings relevant to tool response are noted on the heading. Spooler adjustment is permissible during depth control logging, but must be limited to 1 m per 200 m of survey. 2.1.6 Density (a) Scales Bulk Density: 1.95 to 2.95 g/cm3 Correction: – 0.25 to + 0.25 g/cm3 (Track III) (b) Speed 550 m/h (Time Constant = 2)


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Open Hole Logging

(c) Calibration Before and after survey calibration checks of response of long and short spacing detectors should be as closely identical as statistical variations on calibration time constant will allow. Shop (master) calibration should be less than one month old. Checks include panel computation. Calibration film readings should correspond with legend on calibration tail, and observed count rates during calibration should match shop-recorded counts within 5%. Notes: 1. Correction: Unless the mud weight is excessive, correction magnitude is close to zero. Treat any survey with significant (0.05 g/cm3) and fairly constant correction in porous intervals with suspicion. 2. Repeat: Repeat Section will not match main survey exactly, but differences should be within statistical variation. 3. Check survey against logs from nearby wells, if possible. 4. Recording of caliper is essential for interpretation. 5. Record tension on 1:200 throughout survey. 6. Observe all safety precautions relating to handling and use of radioactive sources.

2.1.7 Neutron (compensated) (a) Scale – 15: +15: + 45% porosity when run with density. (b) Speed 550 m/h, T.C. = 2. (c) Calibration (i) SU Before and after calibration response should be as closely identical as statistical variation on calibration time constant will allow. Shop (Master) calibration should be less than 1 month old. Count rate deflection should match master calibration with jig. Porosity should be 18%. Ratio should match within + 0.04. Checks also include panel computation. After survey calibration should be left attached to main survey. Ensure that the memoriser sensitivity adjustment is recorded during panel test. (iii) CSU ZERO PLUS Before Survey NRAT 0 2.16 ( + 0.1) After Survey 2.16 + 0.04 During calibration the calibrating box must be at least 0.6 m away from any solid object. See Table 2.1-1 for tolerances for nuclear tools.

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Notes: 1. Check that hole size correction switch is properly set. 2. Check that correct time constant (= 2) is being used. 3. Check that memorisation depth is accurate. 4. Check for cross-talk. 5. Erroneous readings. Ensure that repeat section and main survey are basically identical. Then check against logs in nearby wells. 6. Recording of caliper is essential to interpretation of CNT when surveyed in open hole. The CNL normally makes use of the FDC caliper. When CNL is recorded alone a specially modified FDC caliper is run in conjunction for this purpose. 7. Record tension on 1:200 scale. 8. Observe all safety precautions relating to handling and use of radioactive sources.

2.1.8 Acoustic (Bore Hole Compensated) (a) Scale 0-90 – 140 µs/ft (run alone) over track 2 and 3 40-140 µs/ft single track (in combination) (b) Speed 1200 m/h (limited by gamma ray when run in combination). (c) Calibration (i) SU Downhole calibration before and after survey should match exactly. Calibrate signals are 40, 60, 80, 100 and 140 µs/ft. If integrated time is recorded, a check must be made with 100 µs and 50 µs signals for at least 10 pulses/signal (ii) CSU No calibration recorded. Notes: 1. Sonic equipment is not calibrated (in the accepted sense of the term) by feeding a known signal into the downhole circuitry and adjusting the recording equipment to give a standard output. Sonic calibration involves normalisation against time signals from a quartz-controlled clock, and can be effected with the downhole equipment disconnected. The only check of correct operation of the sound velocity recording system is the travel time in steel casing, which is 57 µs/ft. 2. Do not accept a survey with excessive cycle skips, which are long, thin ‘pips’ caused by severe signal attenuation. The 'pips’ may be either side of the correct reading. Occasional cycle skips are no great disadvantage, but since they can normally be prevented by a slight surface adjustment they should be kept to a minimum, particularly in reservoir sections. If cycle skips cannot be cured by panel adjustment, two other courses are possible: – Re-polarise the sonde.


77

Open Hole Logging – Ensure that centralisers are in good condition. Although cycle skipping is usually recognised in the form of ‘pips', it must be remembered that under appropriate conditions several feet of survey can be recorded with the wrong ∆t. This situation does not frequently arise but the possibility should be borne in mind. 3. Repeat will be exact, except for cycle skips. 4. Caliper is not normally required with BHC. 5. Sonic requires good centralisation. 6. Integrated Travel Time should always be recorded. 7. A short section must be run in casing to check correct ∆t, which should be 57 µs/ ft. 8. Ensure that trigger level is set manually by the Engineer, not automatically by the equipment.

2.1.9

Dipmeter/Diplog

(a) Scale Resistivity scale selection is based on the principle that curves have ample variation, without saturation. Scales may be changed during the course of the operation. Caliper scales Normally 6" – 16" (may be changed to suit hole size)

(b) Speed 730 m/h maximum. (c) Calibration Before survey only. After panel calibration has been recorded, a check is made of: (i) Caliper calibration (ii) Deviation (iii) Azimuth and Relative Bearing correct and tracking. (iv) Pads connected correctly, and no cross-talk. (d) Notes (i) This is one of the easiest tools for ensuring a good survey.

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Caliper Inside casing, both calipers should be virtually identical and equal to ID of casing. Over limestone/sandstone intervals calipers should be similar and about bit size. In shales the calipers may be considerably different, depending on the ovality of the hole. Calipers with stair-steps are not acceptable. The angle of dip will vary considerably depending on hole size – an accurate caliper is essential for accurate interpretation. If one caliper indicates a very large hole, one or both resistivity curves associated with that caliper may appear 'dead’. This is simply because the pad is not against the hole wall, and there is not much that can be done about it. Resistivity Resistivity curves will all indicate about the same deflection from zero at the same depth. Ensure that the intensity of the current is continuously adjusted by the operator on the CSU unit so that all the curves are lively without too much saturation. Scales can be changed while logging without affecting the value of the survey. A mechanical zero shift is unimportant. If one or more curves go ‘dead', check the hole size from the corresponding caliper – if the hole is too big the pads may not be touching the wall. Angles First check the deviation (solid trace). This should indicate the deviation known from surveys made while drilling. The curve is quite smooth, since it has a long time constant, but it will be affected by changes in resistivity scale. This need not cause concern, as rapid variations are discounted in interpretation. Note where deviation is less than 1/2º, since this will affect the behaviour of the Relative Bearing.

Next, check the Azimuth (solid trace). Have available the exact co-ordinates of the reference point used for the survey. If not, note precisely which fixed point was used for future checks. As a result of the cable characteristics, the tool rotates clockwise as it is pulled from the hole. When a low-angle dipmeter cartridge is being used, the azimuth of # (No.) 1 electrode moves from 1 division of Track 1 to the right hand edge of Track 1, then jumps back to repeat the movement, as the tool rotates. In an oval hole the tool may even rotate a few degrees counter-clockwise.


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Open Hole Logging

Again, look out for stair-steps – sudden changes of azimuth followed by constant readings, a series of 'steps' as the tool rotates. Reject a survey with ‘steps’ in the Azimuth reading. However, in high-angle cartridges the tool registers the actual hole azimuth, which is relatively constant, and changes only when the orientation of hole deviation changes. In this case long sections of constant azimuth, followed by a fairly rapid change, may be quite normal. Finally, check the relative bearing (dotted trace). If the deviation is less than 1/2º, the relative bearing may wander indiscriminately over Track 1. With a deviation greater than 1/2º, in the low-angle cartridge, the relative bearing behaves like the azimuth, with a separation which depends on the direction of hole deviation. Consequently, the relative bearing and azimuth ‘track' together until the hole deviation changes direction – in most holes, infrequently. Again, look out for ‘stair-steps' which indicate mechanical problems in the relative bearing mechanism. The relative bearing when a high-angle cartridge is in use may rotate independently of the azimuth. Note that an oval hole may prevent rotation, making the relative bearing almost constant. (ii) Avoid sudden changes in cable tension with dipmeter: torque induced in the cable may not be releasable, and a birdcage in the cable will result. (iii) Dipmeter requires good centralisation. 2.1.10 Caliper (a) Scale One inch per division. (b) Speed As for logging tool (c) Calibration Record settings for 8" and 12" rings before survey. (d) Notes (i) Stair-steps. Caliper does not move smoothly, but jumps from one reading to the next. A log with this defect should be rejected. (ii) Erroneous readings. Checks: In production intervals the hole diameter should be bit size minus up to 1" mud-cake. In tight intervals the hole diameter should be bit size. Best check is ID of casing.

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(iii) Micro SFL or Microlaterolog caliper is a two-arm device with very low pad force and soft pads. This caliper will follow the largest diameter hole (in the case of oval hole), but reduced by twice the mudcake thickness. FDC Caliper is also two-arm with high pad force and steel pad and back-up shoe. This caliper will also follow the greatest diameter, reduced by mud-cake thickness since the back-up shoe is assumed to cut through the mud-cake and press against the formation. Sonic and CDM (three-arm dipmeter) caliper are both three-armed calipers with moderate arm force. This device reads the smallest diameter of all, since it averages the hole size reduced by twice the mud-cake thickness. These calipers are no longer used. The four-arm dipmeter has a four-arm caliper which gives two independent orthogonal readings of hole diameter. Pad force is extremely high, and the reading will be affected very little by mud cake. BGT (Borehole Geometry Tool) is a four-arm caliper similar to the DIP Tool, giving two independent orthogonal readings of hole diameter, reduced by mud cake. The BGT can also be used to determine the magnitude and direction of hole derivation. Note The BGT includes a Hole Volume Integrator, but remember that the integrated volume may be severely underestimated.

(iv) Do not run caliper on 1: 1000 scale. Note: Gearhart calibration procedures generally follow the same principles. Different standard values are used. For further reading, see Schlumberger Cyber Service Unit, CSU Well Site Products and Calibration Guide, CP 26, Nov. 1983, from which much of the information in 2.1 has been taken with permission.


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Open Hole Logging

2.1.11 Gearhart Calibration Standards

Tolerances must be consequently adapted to match with SIPM specifications.

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Open Hole Logging

2.2 Principles of Log Evaluation Log Evaluation consists of a number of consecutive steps which result in the determination of net pay, porosity, hydrocarbon saturation, fluid content and where possible a permeability prediction. These data are required for the determination of oil and/or gas reserves in place and for the selection of intervals to be tested and/or produced preferentially. The first step in log evaluation is the quality control of the logs followed by correlation of these logs with the mudlog and logs of surrounding wells to determine the significant events, such as markers, contacts gas/oil, oil/water and gas/water, etc. The lithology is determined from the logs and compared with the cutting and core descriptions, whereafter the porosity can be calculated from the porosity logs and the hydrocarbon saturation from the porosity and the resistivity logs. The determination of the lithology is a significant step as the rock type determines input parameters for the porosity calculation and the method used for calculating the hydrocarbon saturation. For clean porous rocks the Archie Equations can be used, while for shaly sand reservoirs the Waxman-Smits approach is required to evaluate the hydrocarbon saturation. An important parameter in the Waxman-Smits equation is the parameter Qv (cation exchange capacity per unit total pore volume). Qv is normally obtained from a Qv - total porosity (ØT) relationship defined on the basis of either core data or log-derived Qv and ØT values calculated via the WaxmanSmits equation in water-bearing sands. In the absence of core data and water bearing sands the normalised Qv concept can be used. SIPM does not recommend the use of the Simandoux and the Indonesia equations as the validity of these equations cannot be substantiated. The accuracy of the calculated values for net reservoir rock, total porosity, hydrocarbon saturation and where possible the permeability depends on the evaluation approach selected and the available knowledge of the values of the input parameters for the calculation.


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The selection of the approach to log evaluation depends on the time frame and the knowledge available. A short description is given below: TECHNIQUE

REMARKS

ACCURACY

Quick Look

Wellsite use

LOW

Preliminary Evaluation

Detailed evaluation requiring confirmation by SWS, RFT, cores and tests.

FAIR

Final Evaluation

Detailed evaluation with parameters obtained from analyses of SWS, RFT, cores and produced fluids.

HIGH

Field Review

Detailed evaluation and reservoir description based on many cored and uncored wells, which have been producing for a significant time.

HIGH

2.2.1 Lithology and Reservoir Thickness The identification of the lithology and the determination of the reservoir thickness is carried out with help of the cutting description, the natural gamma ray (GR), the natural gamma ray spectrometry tool (NGT) and the SP. In more complex lithologies the use of other logs such as the litho-density, neutron and sonic is essential to determine the lithology of the reservoir rock with more accuracy. The first step is the determination of the reservoir rocks by eliminating the rocks built up of clay minerals. This can be done with the GR and NGT, as clays, claystones and shales normally have high gamma ray radiation due to the presence of montmorillonite, chlorite and illite, whereas most reservoir rocks have low gamma ray activity. The clay mineral kaolinite, however, has also a low gamma ray radiation due to its composition. The Gamma Ray Tool (GR) records the total natural gamma ray radiation of the formation, while the NGT differentiates between the three families of naturally radio-active elements, U, K and Th, and assesses their respective proportions. The significance of the type of radiation is dependent on the rock in which it is found. In carbonates uranium indicates the presence of organic matter, phosphates

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Open Hole Logging

and stylolithes. In sandstones the thorium level is determined by the heavy minerals and clay content, and the potassium is usually contained in mica minerals and feldspars. In shales the potassium content reflects the type of clay minerals and the presence of mica and the thorium level indicates the amount of detrital material or the degree of shaliness. The presence of uranium would suggest that the shale is a source rock. In salt sections the potassium content reflects the type of salt minerals: sylvite, carnallite, polyhalite, and others. In igneous rocks the ratios of the relative proportions of the three radio-active families are a guide to the type of rock. The Spontaneous Potential Curve (SP) indicates the presence of permeable rock when sufficient salinity contrast between mud filtrate and formation water exists. The SP curve is the recording of the potential difference between an electrode moving in the hole and another constant potential electrode at the surface. There is no zero on the SP log as the absolute value of this constant potential is not known. The SP readings along permeable beds will be made by reference to the deflections opposite thick shales and clays; these deflections provide the shale base line. The bed boundaries are chosen at the inflection points of the GR and SP curves. The SP curve can also be used for calculating the formation water salinity. The net reservoir thickness has to be determined in combination with the calculated porosity and porosity cut off applicable for the particular rock. 2.2.2 Porosity The porosity is defined as a fraction of pore volume per unit bulk volume of rock. It is measured on core plugs cut from conventional cores at 1 foot intervals and calculated by dividing the difference in bulk volume and grain volume by the bulk volume. The laboratory measurements provide the total porosity which includes the clay-bound water of shaly samples. The effective porosity is the maximum space available for hydrocarbon storage assuming no connate water. SIPM reports the total porosity only and therefore it is not allowable to correct the porosity derived from porosity logs for shaliness. The presence of shale in the reservoir sands is accounted for in the calculation of hydrocarbon saturation following the Waxman-Smits method.


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The porosity can be derived from density, neutron and sonic logs. For single mineral rocks one porosity log suffices, for two mineral rocks a crossplot of two porosity logs is required, while for triple mineral rocks three different porosity logs are required as each porosity log will produce a different response at a given porosity for a different lithology. The importance of proper matrix identification before translating a single porosity log into porosity values is illustrated in Figure 2.2.-1.

On this RESISTIVITY versus DENSITY plot, the three points A, B, C are plotted according to, e.g. the Laterolog, and to the density log values at the corresponding levels. Figure 2.2-1

Importance of lithology determination

The litho-density log (LDT) is an improved and expanded version of the standard Formation Density Log (FDC) and measures in addition to the bulk

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density (ρb) the photo-electric absorption index (Pe) of the formation. This new parameter enables a lithological interpretation to be made without prior knowledge of porosity. For evaluation the volumetric photo-electric absorption index U = Pe.ρe is introduced of which the unit is barn/cm3, where ρe is the electronic density in g/cm3. Table 2.2-1 shows various minerals, rocks and liquids and their properties. Table 2.2-1 Photo-electric absorption index, bulk density, electron density and volumetric photo-electric absorption index of some common minerals and liquids

*) Approximate values


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For two-mineral rocks the FDC-CNL and/or the SONIC-CNL crossplots shown in Figure 2.2-2 a, b and c respectively, can be used to determine the lithology and porosity as the readings of the FDC, neutron and sonic log depend on lithology, porosity and fluid content. The porosity can be calculated from the formation density, sonic and neutron logs (see Table 2.2-2). The equation relating porosity with log readings from the density and sonic logs is as follows: Xma – Xlog Ø=

,

Xma - Xfl where: ma stands for matrix fI stands for fluid X = ρ, g/cm3 (for the density log) X = ∆t, µ sec/ft (for the sonic log) The neutron log is calibrated in apparent limestone porosity units (%) and corrections are required for non-limestone lithologies. Standard parameters for some lithologies are given below: Matrix Rock Type Sandstones Limestones Dolomites Fluid Type Salt water Fresh water Oil

Density (g/cm3)

Transit Time (µs/ft)

2.65 2.71 2.87

55.5--51.2 47.6--43.5 43.8--38.5

1.1 1.00 0.8

189 189 ≈ 189

The variation of density for water and NaCI solutions with temperature and pressure is given in Figure 2.2-3. The FDC tool correction for mud cake varies with logging companies, depending on the principle of the tool. A limit must be fixed above which this correction becomes meaningless.

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Borehole Corrections are necessary for the FDC and neutron logs (see Schlumberger Log Interpretation Charts 1979). In many areas the Formation Density Log is considered the best porosity log and is also used as the standard depth reference log. FRESH WATER, LIQUID-FILLED HOLES

Figure 2.2-2a Porosity and lithology determination from formation density log and compensated neutron log (CNL*) (By courtesy of Schlumberger)


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SALT WATER, LIQUID-FILLED HOLES

Figure 2.2-2b Porosity and lithology determination from formation density log and compensated neutron log (CNL*) (By courtesy of Schlumberger)

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Figure 2.2-2c Porosity and lithology determination from sonic log and compensated neutron log (CNL*) (By courtesy of Schlumberger)


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REMARKS: Subscripts `ma' and ‘fl’ stand for matrix and fluid. They refer to theoretical log readings in: -- zero porosity context (matrix) = 100% porosity context (fluid)

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Groups of curves plotted versus pressure are shown for Distilled Water, and for NaCI solutions of five different salinities. Use the 70 bar lines to estimate the density at the given salinity and temperature. Then estimate the pressure correction on the basis of the separation between the 70 bar and 480 bar lines. Curves for temperatures above 100 ºC are derived from data given by Ellis and Golding, American Journal of Science, Vol. 261, pp. 47-60 (Jan. 1963). Figure 2.2-3 Density of water and NaCI solutions (By courtesy of Schlumberger)


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2.2.3

Hydrocarbon Saturation

2.2.3.1 Clean Rocks (Non-Argillaceous) In rock, the current emanating from the resistivity logging tools is conducted by the formation water and not by the rock matrix and the hydrocarbons, which are insulators. In water bearing rock the ratio between the measured resistivity (Ro) and the resistivity of the formation water (Rw) is called the Formation factor (F) by Archie: F = Ro / Rw

(1)

Archie relates the formation factor (F) and the porosity (ø) as follows: F = ø-m (2) where: ø = porosity fraction m = porosity exponent. Figures 2.2-4 and 5 give the equations and their derivation, while Figures 2.2-6 (a. to d.) gives average values for the lithological exponent. In hydrocarbon bearing rock the volume of water, usually expressed as the water saturation (Sw) in fractions of the pore volume, is less than in 100% water bearing rock of the same porosity. The measured resistivity (Rt) is then higher than the 100% water-bearing rock resistivity (Ro). The ratio between Rt and Ro is called the resistivity index I = Rt / Ro. The results of many laboratory measurements on partially saturated sandstones can be expressed by a simple power relationship between saturation and the resistivity index according to Archie: Rt / Ro.= I = Sw -n where: Sw = fraction of pore space filled with water n = saturation exponent For sandstone samples the average n and m values measured on 579 samples are 1.95 and 1.82 respectively (see Figures 2.2-6 (a. and b.)). For Rotliegendes sandstones and other sandstones with very rough grain surfaces n-values significantly lower than their m-values are measured.

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Figure 2.2-4 Archie Equations


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Figure 2.2-5 Formation factor vs. porosity

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In Figure 2.2-6 (c. and d.) histograms are given of the n- and m-values of limestone and dolomite samples, respectively. The wide spread of the m- and nvalues and the limited number of data currently available prohibit general conclusions except perhaps for the saturation exponent of limestones, which on average appear to be significantly lower than 2.0 (≈ 1.8). It should be borne in mind that certain carbonates with poorly connected vuggy oomoldic porosity usually exhibit abnormally high m-values (which may range from 2 to 5) whereas their saturation exponent is normal, say 1.8. Calculation of Sw The calculation of the hydrocarbon saturation Sh = 1 – Sw is presented in Figures 2.2-7 and 8. A significant parameter is the formation water resistivity, which can be calculated from the spontaneous potential (see 2.2.4), derived from water bearing sands using the equation Ro= Ø -m . Rw or obtained from production tests. Figure 2.2-9 gives the plot resistivity vs. temperature for various NaCI concentrations. Quick look Hydrocarbon Evaluation For a quick evaluation, a crossplot of resistivity (Rt) vs. porosity is made (see Figure 2.2-10). The points representing water bearing layers should fall on a straight line representing the 100% waterline (Sw = 1.0), while hydrocarbon bearing layers are represented by points to the right of this line (see also Figure 2.2-1 for the importance of lithology determination). 2.2.3.2 Shaly Sands Laboratory observations on shaly water bearing sands indicate for the major part a straight-line relationship between core conductivity and water conductivity. This straight line does not cross the origin, due to the contribution of the conductance of the clay (Ce). See Figure 2.2-11 for the Waxman-Smits Shaly Sand Model. For comparison, the Archie Clean Sand Model is given in Figure 2.2-12. The equations are described in terms of conductivity (= 1/ resistivity). The clay does contribute to rock conductance due to the presence of positive ions near the clay surfaces in the water, compensating for negative charges in the clay crystal lattice. The concentration of these ions in the pore water is


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Qv (mmol/cm3). The mobility of these ions is B (1/Ω.m)/(mmol/cm3). The product of mobility and concentration BQv is the conductivity (1/Ω.m). B, the mobility of the clay counter ions, is a function of temperature and (in the low conductivity range) also of formation resistivity. It is shown in Figure 2.2-13 in graphical form and in Figure 2.2-14 is shown a more practical graph of BRw vs. salinity. In water bearing shaly rock the ratio between the equivalent bulk water conductivity (Cwe) and the measured conductivity (Co) is called the shale corrected formation factor (F*): F* =

Cw + Ce Co

=

Cwe Co

where: Cw is the conductivity of the formation water Cwe is the equivalent bulk water conductivity of a shaly formation Ce = BQv and Co is the measured bulk conductivity. The shaly sand formation factor and the total porosity are related as follows: F* = Ø –m* where: m* = shale corrected lithological exponent. Note: Porosity is determined (KSEPL) after drying the sample at 105ºC. This, supposedly expels all the water from the sample. The measurement, therefore, correspond to the TOTAL POROSITY, i.e. the sum of EFFECTIVE POROSITY + INTERSTITIAL/BOUND WATER.

Figures 2.2-15 and 16 give the core conductivity 100% saturated with water and shaly sands formation factor-resistivity relationships respectively. In hydrocarbon bearing rock the counter-ions concentration in the water will be increased proportionally to the space taken up by the oil. Therefore, relative to the water phase, the effective counter-ions concentration will be Qv/Sw The relation between the measured resistivity (Ct) and the conductivity of the formation water (Cw) at water saturation below 100% can be expressed as follows:

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Solving the Waxman-Smits Equation Solving this equation requires the knowledge of m*, n* and Qv. The components m* and n* can be ascertained from core measurements, statistical data pertaining to the area, and in the absence of these data from guesstimated values. KSEPL recommends the values m* = 1.82 and n* = 1.94 in the absence of relevant core data for sandstones. Carbonate samples show a considerable spread in m* and n* values and at present there are not enough data on carbonates available to obtain meaningful average m* and n* values. Available data for n* suggest that the average value could be significantly lower than 2.0 (approx. 1.8). The cation exchange capacity (CEC) is a measure of the extent to which a substance will supply cations and it is related to the concentration of positive ions (or counter-ions) near clay-layer surfaces in the water bearing pore space (Qv). The CEO is expressed in milliequivalent or m.mol of exchangeable ions per 100 grams dry clay (meq/100 g) while Qv is expressed in milliequivalent of exchangeable ions per cm3 of pore volume (meq/cm3).

Qv can be obtained as follows: 1 from measurements on cores and SWS 2 from logs over water bearing intervals 3 from logs using the Normalised Qv method (information available from SIPM, EPD/22). 4 from the SP curve if RW, Rmf, and E are known with sufficient accuracy (see Figure 2.2-17 for the nomogram). 5 from locally valid relationships between Qv and porosity, generally having the form Qv = d.Ø-e or Qv = (Øs – Ø) / cØ The product BRw can be obtained from the water salinity with the help of the nomogram presented in Figure 2.2-14. The Waxman-Smits equation can now be solved by a graphical solution using the nomogram shown in Figure 2.2-18. It should be noted that this method is only valid if calibrated over a water bearing interval, thus Ro is known. Otherwise: RO = F*RW / (1+RWBQv) must be calculated first. Alternatively an iterative procedure using Figure 2.2-19 may be used. This is described below:

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The above can easily be programmed on a HP 25, 65 and 41 CV. In practice one does not need to account for shaliness when the correction term RwBQv/Sw is smaller than say 0.1. In those cases the Archie equations are valid and applicable.


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2.2.4

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Determination of Rw from SP curve – Shell Method Procedure


Open Hole Logging

(Continued from previous page)


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Note: Pm is the alkalinity (OH- and CO- -) of the treated mud filtrate using 0.02 molar HCL and phenolphthalein indicator.

Figure 2.2-21

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Streaming potentials for various mud types (continued)



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2.2.5 Reporting of Petrophysical Data Dated Summary Sheets of Petrophysical Evaluation are important documents for presenting results of evaluation to management, geologists, reservoir engineers etc. (see example in Table 2.2-3). It is recommended this summary is prepared in addition to the routine evaluation report or petrophysical note describing in detail the evaluation techniques used and the detailed results of the evaluation. 2.2.6 Quick-Look Evaluation Step by Step (a) Inspect mud log for intervals with reservoir rock, its lithology, hydrocarbon shows, mud losses and mud gains. (b) Wireline logs: Check heading, depth and log scales, before and after survey calibrations and tool checks. (c) Inspect logs for obvious faulty readings by comparison and correlation with logs from surrounding wells. (d) Distinguish gross potential reservoir rock from non-permeable rock by inspection of GR, SP, mudcake build-up and shape of curves from porosity logs. Make a sand count on a log, preferentially 1: 200 FDC/ Lithodensity log. See Figure 2.2-23 for an example. (e) Square log readings over reservoir sections. (f) Calculate porosity from bulk density and/or neutron depending on Iithology as follows: - For sandstones use FDC only with ρma = 2.65 (if unknown) and ρfl dependent on salinity of mud filtrate (see Figure 2.2-3). - For carbonates use the FDC-CNL crossplot to determine the approximate matrix bulk density (ρma) of the limestone-dolomite mixture and calculate the porosity from the FDC using the relevant ρfl. Examples of FDC-CNL crossplots are given in Figure 2.2-2a, b and c. (g) Calculate Rt from the deep laterolog RLLD and shallow laterolog RLLS using the superdeep equation: Rt = 1.7 x RLLD - 0.7 RLLS. (h) Plot on the resistivity-porosity crossplot for m = 1.8 for sandstones and m = 2.0 for carbonates the data points. See Figure 2.2-10 for an exampIe. Blank sheets are given as Figures 2.2-24a and b. (i) Determine the 100% water bearing line at reservoir temperature for the above plot as follows. 1. If water-bearing reservoir rock is present then is Rt = Ro, i.e. the

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resistivity of 100% water bearing rock. 2. If no water-bearing reservoir rock is present obtain the formation water salinity from surrounding wells and/or calculate the formation water salinity from the spontaneous potential (SP) as described in 2.2.4 (I) Draw the lines for 70% and 50% water saturations for which the resistivity indices I = Rt/Ro are 2 and 4 respectively. Points with water saturation less than 50% are hydrocarbon bearing, while points with water saturations between 70 and 50% need further investigation with RFTs to determine the productivity and type of fluid producible. (k) Determine the presence of hydrocarbon water contacts or hydrocarbon down to from the logs and crossplots. It is advised to take the upper 100% water saturation level as the hydrocarbon water contact and describe the interval with hydrocarbon saturations between 0 and say 50% as the transition zone. (I) Determine the presence of gas or oil by SWS, RFT pressure data and/or RFT sampling. For long hydrocarbon columns it is advisable to check for changes in the oil properties in the column. (in) For new discoveries it is recommended to ‘drill stem'/production test the reservoirs for fluid type, productivity and reservoir extent. It is also recommended to test those layers where the petrophysical evaluations are not conclusive concerning the presence/absence of hydrocarbons and their producibility. (n) Calculate net reservoir thickness, porosity and hydrocarbon saturation from Rt using n = 2.0 (if not known) and the Archie equation. (o) Prepare a summary of the petrophysical data (see 2.2.5) for Management and others.

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Wireline Coring, Testing and Sampling

3 WIRELINE CORING, TESTING AND SAMPLING 3.1 Sidewall Samples Sidewall samples can be taken by firing hollow cylindrical bullets into the formation at selected depths, or by drilling horizontally with a core bit. 3.1.1 Sidewall Sampling Using Explosive Bullets 1. Observe all perforating safety rules. 2. Check distance from measure point of correlation tool (SP or Gamma Ray) to bottom shot. Make appropriate correlation before taking first sample and adjust as firing proceeds. 3. Ensure that powder for each shot has been correctly loaded. 4. Ensure that: (a) Correct size gun is used (large gun not to be run in hole less than 8" diameter). (b) Correct length fasteners are used (normally 13": run 24" for holes over 12" diameter). (c) High-temperature powder is used when necessary (above 138º C BHT). (d) Correct ring size for degree of rock consolidation is used. 5. Make depth correlation log (GR) at normal GR logging speed (548 m/hr) and determine correct depth. CHECK CAREFULLY FOR CREEP, i.e. movement of sample taker AFTER winch has stopped. If CREEP is a foot or less, STOP at correct firing depth to shoot sample. If CREEP exceeds 1 foot, it is permissible to shoot ‘on the run'. In this case, note on the report form that this technique has been used. In particular report any samples suspected of being shot off depth. 6. After succesfully firing each shot, try to ‘work' the core free. If all attempts at freeing a core fail, the retaining wires can be broken by lowering the sampler rapidly, thereby snapping them off. 7. Move gun carrier with samples up and down slowly at speeds not exceeding 3000 m/h. 8. Watch tension very carefully when entering and ascending through casing. 9. Properly cap gun before removing cores. 10. Remove one bullet from gun at a time, pressing core into sample bottle and noting recovery before proceeding to the next bullet. Removal of

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more than one bullet from the gun at a time leads to confusion and errors. 11. Ensure that all relevant data (company name, well number, sample depth, sample number) are noted on sample container. Scratch sample number on container lid. Indentify SWSs which have been misfired, lost and recovered. 12. Payment for cores is normally on the basis of full payment for any core over 1.25cm in length, half payment for any core over 0.6 cm but less than 1.25 cm in length. 13. Examination and handling of sidewall samples. (a) Palaeontological samples. Limit description to assessment of shale, silt or sandstone. Describe colour. (b) Petrophysical samples. Determine lithology (i.e. sand, shale, etc; grainsize/sorting; roundness, etc.; intergranular cement, etc.) and hydrocarbon indications. 3.1.2 Sidewall Coring Tool Description and operation of Gearhart's Hard Rock Coring Tool. At a chosen depth a small electro-motor driven coring bit is turned horizontal and ejected from a hole in the side of the tool. While coring, an arm on the opposite side of the tool gives support. After 2.5 to 11 minutes, depending on the formation, a 15/16” diameter plug of 13/4" length is cut. By a slight vertical movement the sample is separated from the formation. When withdrawing the bit into the tool, it is tilted vertical again and a rod pushes the sample into a receiver tube. The samples are not compacted and give reliable core analysis results. Up to 30 samples can be taken with one run in the hole. Tool specifications: capacity length including GR minimum borehole diameter tool diameter maximum temperature maximum pressure

:12 or 30 samples :17 ft : 63/4 inch : 47/8 inch : 148 C : 20,000 psi.

3.2 Repeat Formation Tester The Repeat Formation Tester has the following characteristics: 1. An almost unlimited number of pressure tests can be made during one run in the well.


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2. Two fluid samples (from separate depths) or a segregated sample can be taken each run. 3. Pressure measurement incorporates a strain gauge transducer or a quartz crystal with a direct digital read-out at the surface. Accuracy of this gauge practically eliminates the need to run Ameradas in combination for absolute pressure confirmation. An adaptor allows Conversion of the open hole RFT to a cased hole RFT. Tool Size Minimum tool size can be reduced to 5.2" OD. Except in very unusual circumstances, no attempt should be made to run it into a hole less than 61/2" nominal OD. The basic tool will cope with holes up to 93/4" OD, but spacers may be added to increase the maximum to 143/4" OD, although in this case the closed tool size is 10.2" (see Figure 3-1 for tool specification). Schlumberger has also a few slim hole tools (RFT-N) with an OD of 33/8". Tool Description and Operation (Open Hole) When the tool is set, a rubber pad moves forward against the borehole wall. A probe pushes forward into the formation, and the piston inside the probe retracts, allowing formation fluid to enter the filter (see Figure 3-2). Fluid flows initially into two pre-test chambers: from the appearance of the pressure build-up formation permeability can be assessed. This can be used to determine whether the interval is suitable for sampling, and whether a good seal has been obtained. Since only a small amount of fluid has been withdrawn from the formation the final build-up pressure gives an accurate value of formation pressure. Operation (Cased Hole) The cased-hole RFT pre-test capability permits the operator to ascertain that a good seal against borhole fluids has been achieved prior to taking a sample/pressure measurement. However, seal against borehole fluid before firing does not guarantee that seal will be maintained after firing. Moreover, it cannot be ascertained before sampling if the tool's ‘probe' is not plugged prior to sampling as is the case in openhole. Also, the depth of penetration of the charges (maximum 5.15"), presently limits the tool's application in washed out zones with thick cement sheath. Sampling Techniques Two sample chambers may be run with the RFT. In vertical holes, one may be 23 dm3, the other 3.8 dm3. In deviated holes the largest chamber is 10 dm3. A different sample of formation fluid can be collected in each chamber, or alternatively a segregated sample can be taken. The tool is operated at

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sampling depth and the pre-test completed. The larger sample chamber is filled first, then the smaller chamber is filled at the same depth. The contents of the smaller chamber form the segregated sample to be used for analysis. See Figure 3-3 for an indication of possible arrangements for sample chambers and Amerada adaptor. Multiple Pressure Testing 1. Discuss RFT pressure testing operation with reservoir engineer/petrophysicist beforehand so that reason for taking the measurements is fully understood. 2. Use gamma ray for depth control. Check CCL if job is in casing in order to ensure that depth chosen does not correspond to a collar. 3. Calibration and Tool Check (i) A shop calibration not more than two months old forms part of the survey. This should include pressures up to 345 bar (5,000 psi) taken at ambient and 3 different temperatures between 77ºC and 121ºC, plus a zero pressure ‘offset' reading taken at a low temperature. (ii) At the wellsite, the electronics is calibrated with ‘zero' and ‘calibrate' (9,995 psi) values, and the ‘Offset' calibrated rheostat is set at the zero pressure ‘offset' reading in Step (i). With the tool hanging in the derrick, the pressure indicated should now be equivalent to the ‘zero pressure' indication on the shop calibration chart at the prevailing temperature an the rig. The equipment will not necessarily read zero pressure. (iii) Once the surface equipment has been set up, no alterations to panel settings should be made during a sequence of pressure tests. (iv) It is advisable to carry out a dry test in the casing to check if the tool packers are all right. 4. Measurements should always be taken from bottom to top to minimise depth errors and the chances of the tool becoming stuck. This requires that the tool be shop calibrated with decreasing rather than increasing pressures. 5. Switching tool to calibrate position removes power and the sensor cools. Once calibrated, switch back to ‘measure', wait 10 minutes for temperature stabilisation, leave surface panel settings for the sequence of tests. 6. Plot stabilised mud and formation pressure measurements against depth (ahbdf and TVDSS). Check that mud pressures lie on a straight line, and check the gradient against reported mud weight. Ensure that formation pressures are less than mud pressure. Compare pressures from other wells in same reservoir (see Figure 3-4). 7. On completion of measurements, select three arbitrary depths and repeat

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pressure measurements. Repeat pressures should match original readings within 340 mbar (5 psi). 8. The results of the testing have to be forwarded to the Head Office by telex and by normal mail. Examples of reports as to be sent by normal mail are shown on the following pages.

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Repeat Formation Test Report (1) Pre-test results WELL: DATE:

1) Runs and tests should be numbered sequentially, i.e. Run 1 Test 1- 1.1 Run 1 Test 2- 1.2 Run 2 Test 1 -2.1 etc. 2) Pressures should be corrected for temperature and pressure using the shop calibration for the particular tool used (strain gauge only). 3) High-good-moderate-poor-tight (see Figure 3-4).


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Repeat Formation Test Report (2)

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3.3 Sample Recovery Occasionally PVT transfers may be required from the formation tester after sampling a prospective hydrocarbon-bearing interval*). The chamber contents in all other cases should be carefully measured and sampled at the wellsite. The equipment layout required is shown in Figure 3-5. It is important to check that all connections are made up correctly. The procedure to recover the sample is: 1. Connect the Xmas tree to the sample chamber. Check that all valves on the tree are closed, then open the valve on the chamber. Note the pressure and temperature. (Tape a thermometer to the side of the chamber). 2. Connect up the plastic hose/separator/gas meter. Check that the meter is zeroed. 3. Connect up the transfer line to the evacuated gas bottle. 4. Purge the sandtrap by cracking valve A, and allow the pressure in the sandtrap to increase to 1.7 bar (± 25 psi) then close valve A and bleed off the gas in the sandtrap to the gas meter via valve B. Make a check for H2S and CO2 using a Multigas Detector. 5. Open the valve on the bottle, open valve A fully, and fill the bottle via valve C to the sample chamber pressure. Close valve A. 6. Note final bottle conditions. 7. Close the bottle valve and bleed off the pressure in the sandtrap and line to the gas meter. 8. Close all valves and disconnect the sample bottle. 9. Check that the bottle valves are not leaking by immersing in water or applying Teepol to the valves. 10. Repeat steps 5 to 9 to obtain subsequent gas samples at different chamber pressures. For a normal test, two gas samples should be taken. If recovery is mainly gas (gas/condensate reservoir), four samples are taken: at opening pressure P, at 1/2P, 1/4P and final stage of recovery. 11. Bleed off all remaining gas through the separator, but DO NOT EXCEED 20 psi IN THE PLASTIC HOSE. Note the temperature of the exhaust. 12. Disconnect the separator and recover all liquid, ensuring that any mud/ *) The PVT sample transfer is normally covered by strict reservoir engineering procedures, which should be carefully observed.


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emulsion/filtrate is kept separate from the oil/condensate. This is particularly important if the reverse firing technique has been used. If the sample is from a water zone, it should be recovered on the rig floor. In this case, ensure that the mud (last to come over since the tool is vertical) is not mixed up with the formation water/filtrate. Recover the mud in a different container at first sight through the transparent hose. 13. Note the reading on the gas meter - the pointer revolves completely for each unit stated under the dial. 14. Measure the volume of liquid in the separator bottle. 15. Measure volume of all other liquids/solids recovered. 16. Determine the density of the oil/condensate (note the temperature) and the salinity of the water. 17. Complete the formation test report forms and calculate fill of the chamber in order to check for discrepancies. Note: if mercury is used for transferring the sample, make sure that there is no spillage and that the operator is not exposed to vapours.


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Coring

4 CORING 4.1 General It is sometimes argued that with the ever increasing quality of wireline logs and log interpretation methods, coring should become less necessary. However, cores will remain invaluable for geological control, wireline log calibration, fluid flow properties, rock strength and other measurements of rock and fluid properties. The increased interest in secondary recovery has led to coring in partially depleted reservoirs. For residual oil saturation determination in depleted reservoirs, special coring techniques are being applied. The present policy is to core the hydrocarbon bearing reservoir section in the first exploration well. Spot cores of a length of 9-18 m can provide geological control where required. When a prospect is entered and found to be hydrocarbon bearing, it is highly recommended that the prospect and part of the water leg are fully cored. This will aid considerably in wireline log calibration, in detecting differential diagenesis between hydrocarbon and water bearing reservoirs and in measuring aquifer flow and compaction properties. For strike and dip control orientated coring can give acceptable results, although this technique is not yet fully proven due to an unacceptable failure rate of magnetic multishot equipment available from the various survey companies.

4.2 Coring Equipment For well consolidated and not too friable rock the conventional coring technique with a steel inner barrel is used. The core is unloaded from the steel inner barrel at the wellsite and described before it is packed for transport. The standard 63/4" Χ 4" core barrel giving 4" diameter cores is mostly used for jack-up and land operations. For coring from semi-submersible drilling units the stronger 61/4" Χ 3” marine series core barrel should be used. When it is necessary to obtain precise geological information on structural and sedimentary dip, and/or for judging the information obtainable from dipmeter logs in a particular geological setting, the oriented coring technique has to be used. In this technique, three lines are incised on the core as it enters the inner barrel. By means of a telescoping extension rod the central reference knife is aligned to a magnetic multishot survey instrument. Thus the orientation of the knife is recorded on film in the same way as the bent

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sub-alignment is recorded during a steering tool assisted kick-off. It is advisable to use an 18 m core barrel to avoid the need to make connections during the coring run. Surveys can be taken after each metre cored, with circulation and drill string rotation stopped for 5 minutes to ensure that still pictures are obtained. While coring, compass pictures can be taken at one minute intervals. Cores can be taken in deviated holes, if proper stabilisation of the inner and outer barrels has been provided. For very friable and loosely consolidated sands rubber sleeve and plastic sleeve coring equipment are available. Experience has shown that there are many problems associated with rubber sleeve coring, such as core breakage and fluidisation due to rotation of the barrel, and collapse and disturbance of the core due to lack of support. Rubber sleeve coring equipment is only available for a 3" core (Christensen) and cannot be used on floating rigs. The use of plastic core cartridges, which fit inside a conventional inner barrel or fibreglass inner barrels has alleviated these problems to a certain extent, and in general has resulted in higher recoveries compared to rubber sleeve coring. The cartridge system has the disadvantage of reducing core sizes for a given barrel size. Both methods restrict the amount of core description that can be performed at the wellsite. It is considered that this is more than offset by the greatly improved chances of the core arriving in an undisturbed state at the laboratory. If large core samples or long plugs are requested for analyses, 8" conventional coring equipment available from American Cold-set Corporation can be used. When considering enhanced oil recovery processes in flooded or partially depleted reservoirs, it is essential to obtain knowledge of the residual oil saturation. This can be done by recovering a core with the fluids kept under reservoir pressure, in order to determine the residual oil saturation (Sor). The determination of the Sor can be done using the pressure coring technique provided that the oil in the reservoir is immobile at the time of coring. This technique is expensive and time consuming and requires meticulous planning and implementation. Pressure coring equipment is available from Pressure Core Inc., formerly Dowdco Loomis, and from Christensen and is designed for consolidated rocks. Some good results have been obtained in less consolidated rock. An alternative method to pressure coring, called Sponge Coring, is being carried out by Dowdco. This Company claims that the sponge coring technique


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provides more accurate oil saturation data for enhanced oil recovery operations at a relatively low cost for reasonably consolidated sandstones and carbonates. The principle of the sponge coring technique is to collect the fluids expelled from the core, as the core is brought to the surface, in a polyurethane sponge. This sponge is fitted in an aluminium liner placed in the inner barrel of a conventional core barrel (77/8" x 3.25"). This 'oil wet’ lining of polyurethane has a porosity of 70% and a permeability of 2 darcy and is designed to absorb up to 300% of the oil bleeding capacity of most cores. In the laboratory the sponge and the core are analysed foot by foot. The oil from the sponge is reconstituted into the porosity of the rock, resulting in a higher and more accurate oil saturation figure. A 51/4" x 21/2" core barrel is also available for this technique. For each of these coring techniques the instructions for tool operations issued by the contractor should be followed. KSEPL has also issued instructions for coring

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4.3 Coring Fluids, Hydraulics and Bits Normally, there are no special requirements for the mud used for coring consolidated cores for standard analyses. When water sensitive clay minerals are present, which can swell or disintegrate, then inhibition with KCI or the use of an oil-base mud may be required. When cores are cut for special core analysis it depends on the purpose of the coring exercise which mud type should be selected. If the purpose is measurement of relative permeabilities, saturation exponents, oil/water capillary pressure curve, wettability or (residual) oil/water saturations, then surface active agents (particularly thinners, lubricants and corrosion inhibitors) should not be used. Fluid loss control is, however, important to avoid excessive flushing of the core. It is advisable that the mud filtrate salinity and composition do not differ too much from that of the formation water. For determining residual oil saturations the coring fluid should be water based, while for determining residual (connate) water a low fluid loss oil-base mud is to be applied. The following properties are recommended for the coring fluid: (a) The mud weight should exert an overbalance over the formation pressure of less then 14 bar. (b) The static fluid loss < 5 mL/30 min. (c) The mud should have low viscosity and yield point to reduce core erosion. Additional recommended properties if Remaining Oil Saturation analysis is to be carried out: (a) Oil base mud should not be used. (b) The mud should be properly deoxygenated. (c) No surfactants should be present in mud. Further steps should be taken to ensure good core recovery by minimising core erosion and flushing as follows: (a) Use a fluid flow velocity as low as possible, staying within the range given by the contractor. (b) Use special face discharge bits for which the nozzles end in fluid passages which are in direct communication with the annular space. (c) Use fast coring bits, to minimise both filtration ahead of the bit as well as exposure of the core to the mud before it enters the core catcher. Good coring rates have been obtained with polycrystalline diamond bits, such as Stratapax.


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When it is important to know the amount of mud filtrate in the core, it is necessary to add a tracer to the water-base mud. Good results have been obtained with tritiated water added to the mud with a concentration of approx 450 µcurie/m3. Foam coring has been successfully applied in a number of areas. It has been observed that foam invades the core and that measurements are affected. Subsequent logs have shown a 'gas-effect' caused by foam which had penetrated the surrounding rock.

4.4 Coring Criteria for Exploration and Appraisal Wells

There is no generally applicable set of criteria to decide at which depth coring should commence. A number of criteria are listed below to assist in decision making: 1. The predicted depth of the rock required to be cored is reached. 2. An increase in the penetration rate occurs on entering the more porous reservoir to be cored. 3. Hydrocarbon indications are observed in ditch cutting samples and/or in the mud. 4. The type of rock. The following procedure should be adhered to in all cases where a drilling break and/or strong hydrocarbon indications are found: (a) Stop drilling and observe well for flow. (b) Circulate ‘bottoms up’ and determine hydrocarbon indications (both in mud and cuttings and from gas readings). (c) If hydrocarbon indications are strong*), pull out for coring if required. If no coring is programmed inform Base immediately. (d) If hydrocarbon indications are poor, drill another 2 – 3 m and repeat items (a), (b) and (c). (e) If indications are still poor, continue drilling ahead unless advised to the contrary. *) Strong hydrocarbon indications are: – good fluorescence – significant gas shows – oil in the mud.

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4.5 Preparation for Coring If coring is envisaged, guidance on taking, handling and transportation of cores for petrophysical analysis should be sought from SIPM-EPD/22. (a) Preparations before Coring Make sure that the following items are available in sufficient quantity at the wellsite: 1. Core boxes and lids. Make sure that the lids are the same length as the boxes. 2. Rags 3. Hammer and nails 4. Plastic bags 5. Tins with lids 6. Aluminium foil 7. Marker pens (black and red) 8. Core, Porosity and Saturation labels 9. Hydrocarbon solvent for ‘cut colour’ and ‘cut fluorescence’ tests 10. Stapler and staples 11. Scotchwrap tape 12. Core description sheets. 13. 25 metal core trays (or core boxes clearly marked Top and Bottom and numbered) 14. Wooden crates for transporting saturation sample containers 15. Standard Core Box; the inventory is specified below under (b). Make sure the following items are in working condition: – Ultraviolet lamp – Can sealing machine (if required) – Plastic sealing machine. Make timely arrangements for cleaning and laying out the cores. Prepare the trays or boxes to collect the cores from the core barrel on the derrick floor. (b) Contents of 'Standard Core Box’ Item Core description pads Hammer (claw) Hammer (geologist’s) Labels core box top – bottom Sample labels Large marker pens – black (indelible)


Quantity 4 1 1 1000 500 12

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(c) Additional Items If unconventional coring is required, the following additional items will be required: Fibreglass Coring 1. Fibreglass inner core barrels. Should be handled by the Operations Engineer. 2. Caps for top and base of each fibreglass section (These fit better if soaked in hot water first). 3. Circular saw and spare blades to cut the fibreglass into lengths for the boxes (+ 0.9 m). Shrink Sleeve Coring (rarely used) 1. Shrink Sleeve (‘Ness Heat') type. Operations Engineer to order a sufficient number. 2. Steam gun/hose for shrinking sleeve onto core. 3. Caps as in 2. (above). Sponge Coring 1. Ensure that enough 5' length P.V.C. tubes, P.V.C. glue and expandable caps are available. One cap per tube can be glued in advance. 2. Enough heavy duty cling film should be available. 3. Special shipping boxes for 5' core sections should be available.

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Before actual recovery of the core, prepare boxes and labels as far as possible. With the latest type of core boxes (1m long), 20 boxes per 18 m core are sufficient. Make arrangements for cleaning and laying out the cores in a relatively quiet and spacious place. Prepare the trays or boxes to collect the core from the core barrel on the derrick floor.

4.6 Instruction for Handling Cores for Petrophysical and Related Analyses If necessary, guidance on sampling, handling and analysis of cores may be obtained from SIPM-EPD/22. 4.6.1 Recovery of Consolidated Cores The following procedure is applicable to 18 m cores taken with the conventional coring assembly: 1. Place the 25 transit boxes on the derrick floor in the right sequence with the tops facing towards the core barrel. Two hammers must be available on the floor. 2. One man should be ready to feed the boxes in the right sequence with the tops facing towards the man collecting the core form the core barrel. Box No. 1 is the first box to be fed in and filled with the bottom part of the core. 3. Another man should be ready to receive the core from the core barrel and to put the core in the right sequence in the core boxes or trays. This man should NEVER get his hands between the core and the floor. 4. Ensure that the driller never lifts the core barrel more than 1 m above the derrick floor. 5. Transport the boxes after the core barrel has been emptied, one by one, to the place where they will be finally processed. A basket is also permitted but NEVER use a pallet. 4.6.2 Cleaning, Boxing, Sampling and Labelling 1. Rebox the cores from the boxes in which they were carried from the derrick floor to the final boxes and while doing so, clean them with rags only. Draw a black line and a red line parallel to each other on the core


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such that seen from the bottom end of the core the red line is to the right. The standard procedures indicated in Figure 4-1 are to be followed. It is recommended (although in principle not necessary) that all cores be sealed in polyethylene sleeves1) immediately after removal from the core barrel. This relatively simple procedure will protect the cores for more detailed measurements as and when required. A possibly even better method is to put the cores in shrink sleeves, wrap them in aluminium foil and pour peel coat over this. Gaps caused by the removal of samples should be labelled and stuffed with rags. Make sure that the cores cannot move inside the core boxes to avoid mechanical damage during transport. Prevent freezing of cores, e.g. in high altitude transport, and generally avoid exposure to extreme temperatures. In case of sponge coring, the 5' aluminium liners with sponge and core are, after a quick description of the ends or removing a chip from the end for later description, wrapped in heavy duty cling film and aluminium foil before they are put in P.V.C. shipping tubes. The remaining space is filled with brine before the tubes are closed to reduce evaporations losses. If cores are to be stored long before they are analysed, freezing is necessary for accurate determination of remaining oil saturation. In case of high water saturations, freezing might damage the pore system. When taking sections of the core at the wellsite for special analysis, they must be cleaned as described in Figure 4-1 and then packed and sealed, immediately, either in tightly wrapped polyethylene sleeves or in shrink sleeves as above. This will avoid oxidation by air entrapped inside the sleeve and/or evaporation punctures of the sleeve. The sections should be packed separately in tins or plastic containers. Each core section should be properly marked (depth, top/bottom) and be given a code number. This code number should also be indicated at the proper location inside the core box. Examples of outer and inner core box labels are shown in Figure 4-2. The reboxing must be done so that the original derrick floor box No. 1 (core bottom) is the last box of the final boxes, e.g. DF Box No. 1 becomes final Box No. 20. If recovery is not 100%, decide which part is missing and state the reason in the report. If there is no way of telling, it is assumed that the bottom part is missing. All depths should be reported in feet and decimal parts of feet Labels, inserted in small plastic bags, giving the following information must be securely fixed to the top and bottom rim of the core boxes: box

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number, well number, core number, depth (of box, not core), total percentage recovery. For addresses, interior and exterior of the boxes, see Figure 4-2. Do not use damaged boxes. 2. Make a core description as in Figure 4-3 and take a few evenly spread small samples for hydrocarbon tests on the rig. The following information is required by the laboratory for analysis: – interval of each core and each core section2) – core recovery2) – salinity or resistivity of formation water and mud filtrate – type of mud – composition of formation water – logs: for correlation of Gramper results a LDT is essential Notes: 1 ) Polyethylene sleeving is available in rolls from Plastic Verkoop Kantoor, Bussum, the Netherlands in two sizes: – flat width 20 cm, diameter 12.5 cm, thickness 0.25 mm and – flat width 15 cm, diameter 9.5 cm, thickness 0.20 mm. 2 ) To avoid confusion when data on outside of box are illegible it is necessary that these data are present inside each core box (see also Figure 4-2). A more detailed core recovery and sampling record should be enclosed with the core (see Table 4-1).


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4.6.3 Recovery of Very Friable and Loosely Consolidated Cores 4.6.3.1 Rubber Sleeve Coring Special Precautions in Rubber Sleeve Coring (a) To prevent disturbance of the core due to expansion of fluids during surfacing, especially if much gas is expected, the rubber sleeve should be perforated before running the barrel. This can be done, after loading the sleeve on the inner tube, by punching holes in the sleeve with a sharp pointed tool at one to two foot intervals. Punching is preferable to drilling, since a punched hole can function as a check valve to bleeding off highpressure fluid, closing again to prevent evaporation losses. It should therefore be borne in mind that perforating weakens the overall strength of the sleeve. Therefore, use of a fresh rubber sleeve in this case is of utmost importance to ensure maximum strength. (b) When coring with an oil-base or oil emulsion mud, a butyl rubber sleeve should be used for better oil resistance. Butyl sleeves should also be used in thermal areas. (c) The total flow area (TFA), pump discharge and weight on bit should be optimised for the formation to be drilled, so that excessive mud velocities will not wash away the sand in unconsolidated formations. Before each core is taken, make sure that the core-catcher rotates freely from the bit. Excessive or fluctuating weight on the bit should be avoided. Rubber Sleeve Core Handling (a)The key precaution in core handling is to avoid jarring and bending of the rubber sleeve. After removing the stripper tube, pull the core from the inner tube using the cat line connected at the swivel. Place the rubbersleeve core, without bending, in a length of 41/2" pipe standing in the mouse hole (this length of pipe should be cut lengthwise into halves before-hand, bolted together and closed at the bottom). Place the pipe in a horizontal position on the pipe racks and remove one half of the pipe. Cut off the tapered end of the sleeve and cap the end with Christensen rubber caps. Remove the swivel from top of the core and cap the top. (b) To allow for later identification and orientation of core segments, draw a red and green line parallel and close to each other over the full length of the sleeve. Looking from bottom to top, the red line should be on the right-hand side. The depths can then be marked on the sleeve at one foot intervals. If recovery is not 100% and if there is no way of telling where the missing section is, assume the bottom part is missing.

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Note: The use of Staedtler Glass Chrome pencils is recommended for marking the rubber sleeve since the standard felt marker pens are almost invisible on the rubber sleeve.

(c) Remove the core from the half-shell pipe by rolling, without bending onto a flat table (d) Sections of sleeve not filled with formation material (as identified by feel) should be cut out. (e) Starting at the top, cut the core into sections of three feet length each, and a remaining section of not more than 2 feet long (if recovery is 100%), with the aid of a hacksaw (see Figure 4-4). (f) The core material showing at the sawn surfaces should be inspected as to its degree of consolidation and samples taken at this point. A small sample every three feet is sufficient for indications and lithology determination. If the inspection in Step (f) indicates that the material is unconsolidated, i.e. not able to be sampled without disintegration, freezing the core at the wellsite should be considered as a means of preventing gross disturbance of the sand during shipment. This needs be done only on samples where mechanical formation properties are to be measured. The cores can be frozen in thermally insulated shipping containers packed with dry ice. The cores must be firmly supported and must be kept frozen until arrival at the laboratory. If freezing is not practical, the cores must be firmly packed in a shockproof manner to prevent bending, and gentle handling must be ensured during packing and shipment. If the material appears to be sufficiently consolidated to allow sampling without disintegrating, freezing should be avoided during shipment, since it may disintegrate the sand. In this case, the same care in packing and handling as above should be exercised. (g) Cap the ends of each core section with rubber caps supplied by Christensen and seal off with oil-resistant tape. (h) Any punctures or perforations in the rubber sleeve should be closed with oil-resistant tape. (i) Indicate on each section the well number, and core number. (j) Place each section in a plastic pipe halve ensuring empty space is filled with waste paper, rags etc. Place the other plastic half on top and secure with three straps of tape. Place core, packed in plastic pipe halves, in


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cardboard core boxes so that it cannot move. Use rags, paper waste, etc as insulating material. (k) Mark core boxes as outlined for conventional cores. Indicate on lid any sections removed and whether they were gas filled (empty) or mud-filled.

4.6.3.2 Plastic Fibreglass Core Cartridges 1. Have available two handling ‘socks’ (see Figure 4-5). Unscrew the core into two 9 m sections in the rotary table. Transfer each section into a ‘sock’ in the mousehole and have it laid down in a convenient place (on deck or in the mud chemical room in bad weather). 2. Remove core from ‘sock' and unscrew metal shoe, catcher and connector from both ends. Mark fibreglass sleeve with red and black lines (right side with red line) using waterproof pens. Fibreglass will not mark unless it is dried and sanded thoroughly. 3. Measure core and mark out 90 cm sections starting from bottom of the sleeve. Mark each section T (top) and B (bottom) and number them starting from the top of the core, e.g. top section of core 7 is numbered 5.1.

4. Using rotary saw cut the core into sections. Note: Geologists or petroleum engineers are not advised to attempt this themselves. All personnel involved should wear eye protection.

5. Estimate core recovery and reconcile this figure and depth cored with drilling personnel. Note: Remember to include effect of tide.

6. Take samples for lithology/biostratigraphy as required from top of each section and also the bottom of the last section. Number the samples from the top, e.g. the first sample in core 7 is numbered 7.0. 7. Put caps and clips on both ends of core sections and put sections into core boxes. Stuff sleeves and boxes with rags as required to prevent the core moving around and getting damaged. Nail up boxes and mark on the outside with details of contents. 8. Dispatch cores by sea and samples by air as soon as possible. Send appropriate dispatch telexes and make sure a boxing list and sampling record is sent to the office. 9. Describe the samples and make up a core description telex and core


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description sheet to be sent by facsimile (e.g. Mufax) to Base as soon as possible. Warning: Problems have been experienced with the handling of fibreglass sleeved cores recovered to surface still being pressurised. If there is any indication that the core may be pressurised, e.g. strong smell of gas, bubbling out of top of core and hissing noises, the core should be unscrewed into two sections in the rotary table with extreme caution including use of eye protection for all personnel in the area. The core should then be laid down and left for several hours before any attempt is made to cut it into sections. Failure to follow this procedure may result in the core being blown out with considerable force risking injury to personnel and losing valuable information.

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4.7 Core Description The following are general guidelines for the description of cores: 1. Inspect the cores as soon as possible after they have been recovered. The rock will still have its original characteristics. 2. Only examine the freshly fractured planes, both parallel and perpendicular to the bedding. Fractures already present in the core are usually contaminated with mud and less suitable to appraise the rock. 3. Inspect the core as a whole. Do not put too much emphasis on one or two outstanding features, for instance: a sandstone streak in a monotonous claystone. 4. Keep the report concise and try to use terms of single meaning: 'thick’ and ‘thin’ are ambiguous, but ‘1 to 2 mm thick’ is more exact. 5. Care should be exercised in using the expression ‘as above' in the core report. The rock properties change within a core, the top part often not being the same as the bottom part. 6. It is standard practice to examine and describe the rock in a set sequence (examine the rock in a wet condition). This prevents omission of important facts and leads to more uniform description. Cores are usually described in the following order using ‘Tapeworm’ as a guide for lithological descriptions (see 7.1.1). A. Main Components Describe the rock as a whole under the first heading. Most cores contain more than one rock type. These are described separately, but should be seen in the context of the entire core. In this way the relative importance of some of the different rocks can be appreciated. B. Colour Colours are preferably described referring to everyday colours, e.g. chocolate brown, rust etc. C. Hardness This is a result of the consolidation of the rock, i.e. the way the individual grains are cemented together. The hardness is sometimes expressed in the name of the rock (sand or sandstone) but better and more useful expressions are for instance: For a sand-sandstone: loose, friable, crumbly, frangible, well consolidated, hard, very hard.


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For a clay-claystone:

plastic, compact, frangible, hard, very hard.

It is recommended that the term 'hard' should be used for rocks which can only be broken with a hammer; 'very hard' when this can only be achieved with difficulty. D. Fracture The fracture should be described from a freshly broken piece. Do not describe from a fracture plane caused by bedding or tectonic influences. For fracture description use expressions as: shell shape, irregular, angular and splintery. E. Grain Size and Shape Permeability and porosity are depending of those two properties and thus very important. Also the grain size is to some extend already expressed in the rock name, e.g. fine sand, coarse sand, fine and coarse crystalline limestones. A sticky clay is more finely grained than a lean non sticky clay. For sands also the sorting is mentioned, e.g. poorly sorted, well sorted. Grain shapes are described in terms of: rounded, subrounded, subangular and angular. For limestones: crystalline, granular. Also include colour appearance, e.g. transparent, translucent, opaque. F. Porosity Mostly an indication of porosity can be determined by eye. Sands can be described as: not porous, slightly porous, moderately porous, porous. With limestones distinguish between primary and secondary porosity. The former is intergranular, the latter owing to fissures and cavities etc. Primary porosity of clayey rocks is practically nil. Note: Porosity is referred to in relative and not in absolute terms, i.e. whether or not the rock could be a reservoir rock.

G. Bedding True bedding is caused by differences in composition of the various layers. Descriptions are: 1. Bedding: well bedded, slightly bedded, non-bedded; 2. Bedding plane: wavy irregular; 3. Average thickness of the individual layers and 4. To which phenomena the bedding must be attributed, e.g. more or less sandy. Bedding planes are not always parallel, but in groups from different angles

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with respect to other groups. This is called a cross bedding. Clayey rocks which appear cleavable parallel to the bedding are called shales; marls and sands can thus be shaly. H. Accessories All components which only make up a small fraction of the rock. Commonly occurring: fossils (shell fragments, foraminifera etc.), carbonised plant remains, minerals (mica, pyrites, siderites, clay ironstone, calcite, gypsum, anhydrite, glauconite). It is wrong to attempt to identify more fossils and details than can be justified. It is better to write ‘shell fragments', when the reported ammonites were in fact gastropodae. Furthermore the occurrence of accessories in the rocks is noted, e.g. scattered, on bedding planes in particular, concentrated in certain layers. For minerals: veins, nodules, lumps etc. Also details as sandiness, clayeyness etc. which are not important enough to be included in the actual rock name, can be mentioned here. I. Tectonic Influences Natural fault planes, veins and scratches*) are signs of tectonic influences. The dip of the fracture plane and their shape is noted, e.g. flat, wavy, irregular. *) Scratches on the outside of the core can easily be caused by the core barrel. Also breaks in the rocks are often of core mechanical origin. True tectonical breaks are seldom open; minerals have filled the crack in general.

J. Dip The dip of the rock is determined from the main primary bedding with respect to the axis of the core which is considered vertical. K. Oil and Gas Indications Oil smell, oil traces, gas bubbles, general hydrocarbon test results are mentioned in the appropriate column on the core description form.


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Cased Hole and Production Logging

5 CASED HOLE AND PRODUCTION LOGGING 5.1 Preparation for Logging The Wireline Company should be provided with the following data: 1. A complete sketch of the well, including location of casing/tubing shoe, packers, perforations, etc. 2. An outline of the purpose of the operation (choice of tools, etc.). 3. A list of casing collars (correlated to reference survey depths). Prior to rigging-up, a meeting should be held between Logging Engineer, Production Supervisor, Wireline Operations Supervisor, Well Site Engineer and Toolpusher to establish communication channels and to discuss the programme and any special circumstances, e.g. conditions of equipment (ID and OD), amount of prinkerban to be used, H2S concentration during the operation (cable embrittlement, safety measures), etc. (see 8.3). Figure 5-1 shows a drawing of the installed equipment.


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5.2 Operation Against Pressure 5.2.1 Testing Risers and Hydraulic Grease Tube (HGT) (a) The Riser and HGT are to be laboratory tested 690 bar (10,000 psi) every six months. A metal band indicating the date and test pressure is to be attached to each item, and a copy of the Test Certificate retained for inspection at the Wireline Contractor's base. (b) Ensure that the riser is long enough to contain the longest tool to be used. - Schlumberger use a tool catcher at the top of the riser. In this case the BOPs and Otis 7" riser above the Swab Valve may be considered as part of the lubricator. - Dresser Atlas use a tool trap between the BOPs and the bottom of the lubricator. This arrangement requires the lubricator alone to be long enough to hold the tool. (c) Assemble the riser and HGT with cable-head, CCL and weights, but do NOT install tool or gun, i.e. dummy CCL. (d) Pull up to within 0.5 m of the tool catcher. Close stuffing box. (e) Fill the riser with test fluid. On water wells fluid is to be water; on oil or gas wells fluid is to be a mixture of water/glycol in a 50:50 proportion. (f) Once the system is full of test fluid, activate grease injection and establish seal in HGT. Slowly increase pressure to required test pressure -345 bar (5,000 psi) in water/oil wells; 450 bar (6,500 psi) in gas wells. Test for 15 minutes. Note: Normally the weight of the dummy tool is not sufficient to withstand the full pressure test, therefore, the stuffing box must be closed to prevent entry into the tool catcher. If the tool is allowed to engage in the tool catcher, the pressure must be reduced to zero to disengage the catcher.

(g) When the riser and HGT have been pressure tested at the commencement of a series of operations, it is not necessary to retest before every run. 5.2.2 Testing BOPs (a) BOPs are to be laboratory tested to rated test pressure 690 bar (10,000 psi) every six months. A metal band indicating the date and test pressure is to be attached to the BOP, and a copy of the Test Certificate


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retained at the Logging Company's workshop. Only double BOPs adapted for grease seal injection between rams may be used. (b) When the BOPs have arrived on the rig, they should be tested as soon as possible to ensure no damage has occurred during transportation. Thereafter, they must be tested before each set of operations against pressure. If practical, testing of the BOPs should be carried out on the test rig (see Figure 5-2). If not practical, they may be tested during rig-up (as in (d)). (C) Mount the BOPs on the test stand so that hydraulic pressure can be applied from below. Insert a 7/32" or 5/16" (depending on cable size) ‘I' shaped polished test rod between the lower rams of the BOPs. Ensure that the test rod is chained down to prevent movement during pressure operation. Ensure that BOPs are filled with water, close rams, and apply 345 bar (450 bar for gas wells) with a hand or electrically-driven hydraulic pump. If the lower rams held pressure, insert the test rod between the upper rams, tie down test rod and again apply test pressure. See also Section ‘Wireline Blowout Preventer-Pressure testing' in Volume ‘Production Operations'. (d) Chain down the test rod. Open the manifold across the lower BOP rams and close the manifold on the upper BOPs. Ensure that the BOPs have been manually closed following hydraulic operation. Slowly apply pressure from the cement unit and bleed off air from the BOP manifold. When the system is full, close the manifold outlet and apply test pressure to the top BOP. Test for 15 minutes. Close manifold on the lower BOP. Bleed off pressure from the top BOP manifold - pressure should remain constant. Test for 15 minutes.

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Bleed off pressure from the system and remove the rod. Open the BOPs. The BOPs and their manifolds are now tested. No further tests are necessary during the operation. (e) When this test has been personally witnessed with the Well Services' Supervisor, a signed label should be attached to the BOPs giving the date and test pressure. These BOPs may then be used for an uninterrupted sequence of operations.

5.2.3 Entering the Well (a) Before entering the well -check the tool length- CCL to measure point on top shot (gun). (b) Pick up the tool, install the riser, HGT and stuffing box. Tighten the Bowen Union. Pull the tool up to within 0.5 m of the tool catcher. Set the Depth Indicator. Close the Stuffing Box. Note: All depths are referred to the derrick floor on drilling rigs and platform, and to a theoretical point equivalent in height above MSL to the original DFE on wells perforated using the workover hoist.

(c) Close the Upper Master Gate Valve (UMGV), open the Kill Wing Valve (KWV) and Swab Valve (SWABV). Start pumping test fluid from the cement unit very slowly until all air has been evacuated from the lubricator assembly. The test fluid is to be water for water wells and water/glycol mixture in 50:50 proportion for oil or gas wells. Note: Grease injection must not be activated at this stage.

The lubricator is full when test fluid is observed coming from the exhaust hose on the HGT. Note: Pumping must be done very slowly. Normally pressures should not exceed 69 bar (1,000 psi) before the old grease is removed from the flow tubes/hoses. The stuffing box must be closed to prevent the tool being lifted into the tool catcher. The tool catcher is a safety device which is activated when well pressure is applied. Minimum pressure required for activation is 20-28 bar (300-400 psi).

A tool allowed to enter the tool catcher whilst equalising the riser pressure will therefore not be released until the pressure is reduced to zero.


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(d) If CITHP is less than the anticipated CITHP during the operation (i.e. after perforating), test to 35 bar (500 psi) above the anticipated CITHP. Activate grease injection before testing. Note: Weight of Schlumberger tools should be enough to balance the expected CITHP, but may not be enough to balance test pressure.

(e) Equalise the lubricator pressure to existing CITHP at the cement unit or BOP manifold. Close KWV then open UMGV. Release the stuffing box. Lower the tool into the well. (f) Throughout all wireline runs against pressure, inject glycol at the wellhead at a rate of 25 dm3/h. WARNING: At high production/injection rates fluid movement along the logging cable creates very large forces, which can lift the tool up the tubing (production) or break the cable (injection). Since these forces are still not quantifiable, production/injection rates during wireline logging must be strictly controlled as specified in the logging programme. Production/ injection must be stopped immediately if uncontrolled movement of the tool is observed. Note: The CCL tension and spinner must be monitored during bean up in high 3 flow rate wells (i.e. above 3000 m /d fluid). Communication to the wireline unit must be established and personnel must be on standby to reduce the flow rate in case of any movement.

5.2.4 Running in Hole (a) Check the monocable magnetic marks near surface, and add extra marks for close control when pulling out. Check the number of wraps of cable on the drum before running in hole and note monitor depth of each layer of cable when it reaches the flange of the drum (‘zig-zag' diagram). Check and note depth (wireline of SSSV) while running in. Do not exceed 3000 m/h when running through tubing. (b) Stop the tool in the tubing every 500 m and check the hanging weight. Allow any slack from friction to be taken up. In very highly deviated wells (60º) it is most important to keep the tool moving down: do not stop, and check descent using the CCL. (c) Take extreme care when passing through tubing downhole accessories, i.e. landing nipples, packers, tailpipe, etc. (d) Check periodically to ensure that the grease seal is holding well pressure.

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5.2.5 PLT Logging (a) Run the PLT log as recommended in the programme. Refer to the Bulletins on the individual tools. (b) Always state on the log the distance between the CCL and recording/ operating point of the tool. State clearly on all logs whether the CCL or recorded survey is on depth. If memorisation of optical correction is applied so that the CCL and recorded log are on depth, this should be stated, together with the amount of correction applied. 5.2.6 Pulling Out of Hole (a) Slow down and watch tension when re-entering tubing after survey. Slow down to not more than 100 m/h and take extreme care when passing through the tubing downhole accessories, i.e. landing nipples, packers, tailpipe, etc. (b) Take extreme care near surface. Use the SSSV as correlation while pulling out of hole. (Previously checked while running in loggers depth). Check magnetic marks if available. Check cable position on drum, i.e. number of wraps. Monitor the CCL and/or gamma ray, as the tool enters the riser assembly. Pull up until the tool is completely in the riser. Check the depth system display and cable position on the drum. The tool should now be a few feet from the tool catcher. If there is any doubt whether the tool is clear of the swab valve, proceed to pull gently into the tool catcher. (c) Close the swab valve. (d) Bleed off pressure from lubricator Note: In the case of Schiumberger's BOPs, bleed off should be done from the wellhead connections as it is impossible to bleed the Otis riser from the BOPs.

Check that pressure is zero before proceeding. Before breaking the Bowen union, open the BOP manifold outlets and check for no gas coming out. (e) Break off the Bowen Union and lay down the tool.


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5.3 Cement Bond Survey (a) Scales 0-50 mV Cement Bond 200-400 µs ∆ t. (b) Speed 1200 m/h (c) Calibration Before and after survey, the calibration should repeat exactly. Notes: 1. Ensure that survey is run, triggering on correct signal (trigger on E1 for CBL). Always run 50 m of CBL in free pipe to check saturation value, ∆ t and correct triggering. 2. Ensure centralisation is good. 6 mm eccentralisation can reduce amplitude signal by 50%. 3. Check casing arrival time.

Collars appear as distortions on both amplitude and ∆t logs. Use this phenomenon to check the logging engineer's assessment of corrected collar depths. 4. Absolute saturation value will vary depending on several factors but would normally be between 40 and 80 mVs for a polarised sonde. 5. Repeat survey should be exact.

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5.4 Thermal Decay Time Logging (a) Scale Σ (Capture Cross-Section) 60-30-0 c.u. (10-3 cm-1) ‫( ح‬Decay Time) 100-300-500 µs (b) Speed 275 m/h Time Constant = 4 s (c) Before-Survey Calibration The TDT-M tool contains two detectors and sixteen time gates are selected for each detector. This allows more elaborate decay time computation. Counts are not calibrated. The ratio is normalised with a static measurement. A source is placed near the detectors and counts in all gates are added. The background level is measured first and subtracted from the jig counts. There is no shop calibration for the TDT tool. The static calibration with the source is made at the wellsite just before the job. The calibration summary is identical to that of the TDT tool. However the tool must be at least 0.6 m above the ground, well away from any metal object, and all neutron sources must be at least 50 m away from the detectors. Before survey calibration cannot be made if the detectors have been exposed to neutrons less than 2 hours before calibration. Calibration after survey is not possible. Notes: 1. Reject a survey which exhibits lack of character. 2. Ensure repeat section and main survey are basically identical. In principle, the shape of the Decay Time survey follows the shape of the open-hole deep resistivity log: as resistivity increases, Decay Time also increases (Capture Cross-Section decreases). Be aware of the two major anomalous effects: - Acid effect (Capture Cross-Section over acidised interval too high, indicating higher water saturation than actually exists). Magnitude of anomaly is thought to be related to effectiveness of acid job. - Filtrate effect (Capture Cross-Section over affected interval too low: water saturation apparently lower than expected from open hole logs). Applicable over water-bearing and transition zones only.

(d) Preparations (i) TDT should always be run with well on production, to prevent settling and dispersion of fluids from the well-bore into arbitrary intervals.

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(ii) Run after acidisation and clean-up. (iii) Ratio curve is closely related to porosity, and should correlate very well with open-hole porosity surveys. (iv) Repeat two or three times if background level is higher than normal. (v) Ensure that Quality Control curve (at 9 divs Track 1) remains constant. (vi) Check that Σ x ‫ = ح‬4500. (vii) Do NOT make statistical checks.

5.5

Electromagnetic Thickness Tool (ETT)

(a) Scale 0-360o phase shift. (b) Speed 1000 m/h. (c) Calibration Calibration before and after survey should be similar-a small change is not important. Notes: 1. The ETT cannot be considered a quantitative tool. With new casing in faultless condition, each joint indicates a fairly uniform - but different - phase shift. Generally speaking, it is useless to run an ETT in the hope of detecting corrosion unless a reference survey was made shortly after completing the well. Comparison against a reference survey will readily indicate corroded areas. 2. Ensure that the correct diameter tool is used for the size of casing being measured. 3. Run a junk catcher until it comes up clean before running the ETT. 4. The ETT is not a very robust tool. If the reading is constant, change the sensor and re-run.

5.6

Production Logging Tool (PLT)

The Production Logging Tool (PLT) allows logging of several downhole parameters simultaneously during production control services in production, monitoring and injection wells. It can simultaneously record flow rate, fluid density, temperature, pressure, caliper, casing collars and gamma ray. It can be combined with additional sensors for tracer surveys and highprecision pressure recordings.


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The basic sensors are the flowmeter, gradiomanometer, thermometer, manometer and caliper. In addition to the CCL, a gamma ray detector can be added to aid in correlation. Figure 5-3 shows the tool configuration with the main sensors, including the two types of manometers which are available for use in the PLT combination To measure low flow rates and to detect fluid flow behind the casing a Tracer Ejector Tool (TET) can be combined with the PLT string. A PLT survey can be recorded with the tool moving up or down, and measurements can be made versus time with the tool stationary. Usually in a production well the down logs are most relevant and generally one pass gives an idea of what is happening over the producing interval. Conversely, in injection wells the up logs generally show the features most clearly. For every flow rate and at shut-in conditions several passes are made. During each pass all parameters are measured simultaneously and the CSU system puts the readings on depth by compensating for the different positions of the sensors. If an in-situ flowmeter calibration has already been made with the well shut-in, then a single run gives the necessary information to calculate flow rates and water cut under flowing conditions. The following notes are intended as a general guide for any engineer supervising a programme of production logging. (a) Make sure the well is clean by running a dummy CCL or sinker bar (if necessary, run a junk-basket) before starting production surveys. Flowmeter spinners have been clogged by bits of wire, remnants of ceramic capsule, or congealed mud. (b) Determine the location of the non-flowing sump early in the sequence of surveys, and avoid running the flowmeter into the junk and debris at the bottom of the hole. (c) During logging operations the PLT must not be allowed to approach closer than 20 feet to the tubing foot (or bottom of the tailpipe). (d) Before opening the well or changing the flow rate for further production logging ensure that the films of the logging surveys just completed are developed and checked. If there is any doubt regarding reliability or repeatability, re-run the respective logs. (e)During any flow rate changes the PLT is to be left stationary in the well at a point which is not directly opposite any perforations. Provided there is enough space between perforated intervals, the tool should preferably be placed between two of the lowermost intervals, just below a collar, but

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above the top of the sump. Watch the CCL carefully during the rate change. If the tool starts to float the collar should be clearly observable. In this case close the well in at once. After opening the well or changing the flow rate, allow well production to stabilise at the selected rate before commencing production logging. This can take an hour, often longer. Any changes to flowrate are to be made very slowly and carefully to avoid excessive forces on tool and cable. (f) Ensure that the survey date of any production survey is included on the FRONT of the heading after the witness' name. Although the date also appears as part of the survey statistics, including it in the front of the heading is very useful for retrieving the correct log from our files. Special Note: Maximum Flow Rates When production logging is carried out inside a 5" casing or liner, special care must be taken in observing the tension of the logging cable. If there is any indication of upward movement of the PLT due to the force of the gas/oil flow the well is to be closed in immediately. Do not carry out any production logging at flow rates exceeding 1.1 Χ 106 m3/ d. When logging inside 5" casing, check with base on the maximum flow rate to be used. Work is currently in progress to determine the maximum oil flow rates permissible during production logging, and these will be reported to the field as soon as possible. The PLT incorporates several logging sensors in one sonde. Before entering the well, check the positions of each sensor in relation to the CCL, as the exact tool configuration is quite variable. The sensors are briefly described below. 5.6.1 Flowmeter Two spinner-type velocimeters are available to give a continuous flow profile versus depth and to determine relative contributions of each zone to total well production: (a) CFM This is a standard 1 11/16" diameter flowmeter, which is affected by turbulence, and has better sensitivity and discrimination than the FBS: in high production or injection rate wells this flowmeter should normally be chosen.

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(b) FBS The full-bore spinner is less sensitive than the CFM, and appears to damp down the effects of turbulence. It should only be selected when its response characteristics are essential for the operation planned, as in biphasic flow. 5.6.2 Gradiomanometer The gradiomanometer measures the pressure gradient between two membrane-type pressure sensors two feet apart, in relative density units. 5.6.3 High Resolution Thermometer (HRT) The high resolution thermometer is a highly sensitive recorder capable of detecting temperature anomalies as small as 0.5ºF. The device incorporates an electrical bridge system using an exposed temperature-sensitive resistor as one arm of the bridge. Although the tool is primarily used for locating fluid entries and determining the lowest depth of production, other applications include identification of tubing leaks and determination of geothermal gradients. 5.6.4 Continuous Pressure Manometer These are of two types: (a) A Hewlett-Packard quartz strain gauge. This is very sensitive to temperature, the corrections for which are cumbersome but significant. The HP pressure sensor is recommended for comparison of downhole pressure between wells. (b) A Schlumberger RFT type strain gauge. This offers the pressure accuracy of the RFT, without large temperature effects. This option should be selected when continuous and accurate downhole pressures are required. 5.6.5 Through-Tubing Caliper The Through-Tubing Caliper has three bow-spring arms, movement of which is converted into movement of a linear potentiometer. This tool is useful for measuring hole sizes up to 12" diameter in barefoot wells. It is rarely of value in cased/lined wells.


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5.6.6 Tracer Ejector Tool To measure low flow rates and to detect fluid flow behind casing a Tracer Ejector Tool (TET) can be combined with the PLT string. With the tool stationary a small amount of radioactive tracer fluid is injected into the well and transported with the well fluid. Three gamma ray detectors measure the radiation continuously. There is always one gamma ray detector above the injection point and one below, and the position of the third is determined according to whether a producing or injection well is being surveyed. The direction of fluid flow is readily determined, and the time it takes for the tracer to move the distance between the gamma ray detectors is a measure of the fluid velocity. If well fluid goes behind the casing, the tracer tool can determine where the flow goes, by making a continuous survey. Because of radioactive contamination of the well fluids the tracer tool is normally used in water injection wells. For further information on a production logging tool, see Anderson, R.A., J.J. Smolen, Luc Laverdiere and J.A. Davis, A Production-Logging Tool with Simultaneous Measurements. SPE 7447, 1978.

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5.7 Continuous Flowmeter (a) Scale Depends on maximum flow anticipated. (b) Speed This also depends on anticipated flow rate. The criterion is to generate sufficient spinner speed at maximum flow to cover most of Tracks II and III on the film within any interval where flow rates may be changing. Careful control of logging speed is ESSENTIAL for determination of flow rates. See paragraph (e). (c) Calibration Calibrate downhole before survey. Calibration to be in accordance with paragraph (f). (d) Running Procedures (i) Record flow at a variety of cable speeds, to check linearity of tool response. (ii) Take readings at fixed stations, where the flow profile indicates constant flow without turbulence. Notes: 1. Survey against direction of flow, for maximum sensitivity. 2. Avoid stationary readings within 10 m of tubing shoe or top perforations if possible – these are regions of high turbulence. 3. Avoid running below lowest point of inflow/injection, as there is danger of clogging the spinner with mud or debris. 4. Flowmeters run in open hole should always be accompamed by a caliper.

(e) Control of Survey Speed: The continuous flowmeter is the only tool in which careful control of absolute logging speed is essential, as knowledge of cable speed is an integral part of any attempt to establish flow rates quantitatively. Methods available for determination of cable speed are: (i) Meter on winchman's panel. This is NOT to be trusted. (ii) One minute breaks on film track: the indicated 60 second period is a function of generator frequency, and is sufficiently accurate for calibration purposes, BUT it cannot be observed until the film has been developed. (iii) Cable speed galvanometer: calibration of this speed indicator is also a function of generator frequency. (iv) Observation of footage travelled in a fixed time as indicated by a watch with second hand. This is the only reliable check on cable speed during the survey. In order to guarantee the accuracy of cable


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speed indication, ensure that the following procedure is adhered to: 1. Calibrate speed galvanometer. 2. At a nominal cable speed of 15 m/min, check the exact distance travelled (ft) during an elapsed time of two minutes. 3. Repeat at a nominal cable speed of 30 m/min. 4. Note the results of this check on the heading thus: Nominal Speed 5 m/min 30 m/min

Actual Speed 15.15 = 7.575 m/min 2 30.30 = 15.150 m/min 2

(f) Calibration Procedure (i) Record a flow profile as usual, against the direction of flow. (ii) From the flow profile, select an interval of constant flow to make the response calibration. (iii) Moving the tool AGAINST the direction of flow within the selected interval, record the spinner speed at each 5 m/min step in cable speed, from zero to 30 m/min. (iv) Moving the tool WITH the fluid flow within the selected interval, record the spinner speed until the spinner recommences rotation in the opposite direction. (v) Plot the flowmeter response line to ensure validity of calibration. (vi) Make a zero flow calibration, as a check, if possible.

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5.8 Gradiomanometer (a) Scale 0-1 g/cm2 per cm track (b) Speed 2000 ft/hr (≈ 600 m/h) (c) Calibration Calibration is made at surface using air (0) and water (1). Before and after survey calibrations should repeat. Notes: 1. Most common problem is punctured bellows, which gives decreased readings. 2. Repeat section will be similar, but probably not exact. 3. Survey should be made twice, once with well flow, once against. 4. In gas wells, gradiomanometer should be run first, to determine liquid level at bottom of well. This sump should be avoided in subsequent flowmeter runs.

(e) Interpretation Friction and kinetic effects alter the gradiomanometer reading in a f lowing well, but these effects are usually spurious and unquantifiable. The recorded pressure gradient is also reduced by well deviation. If θ is the deviation angle from vertical, ρg is the gradiomanometer reading and ρf is the correct fluid density, then: ρg = ρf cos θ Care must be taken to ensure that deviation changes are not misinterpreted as alterations in wellbore fluid density.


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5.9 Thermometer (a) Scale As required: Temperature scale may be changed while logging. (b) Speed 1800 m/h. (c) Calibration Downhole calibration, before and after survey should repeat. Notes: 1. Lack of character/sensitivity may be caused by broken sensor. 2. Always run three maximum reading thermometers with HRT to check absolute value of readings. 3. Temperature survey should always be made running into the hole to avoid disturbance of temperature readings by passage of the tool and cable. 4. Basically, temperature will increase from surface to TD on the basis of the geothermal gradient. However, this will be affected by - length of time since cementation of casing - production rate - length of time shut in - gas production. 5. Ensure that a FULL history of anything which could possibly affect the interpretation of a temperature survey is added to the heading, e.g. an account of the well production history.

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Perforating

6

PERFORATING

6.1 General Preparations 1. All tubulars should be laid down before perforating or testing on floating rigs. This precaution is not necessary on platforms. 2. Working areas around the Xmas tree and separators should be kept clear and there must be unobstructed access to these areas at all times. When work is to be carried out on the wellhead, a suitable platform should be erected. Cranes must not be operated over or in the vicinity of separators. 3. Adequate killing fluid of the correct gradient should be available. Killing lines from the rig/kill pump should be as direct as possible. All valves should be trimmed and the non-return valve checked to ensure that it is not leaking. 4. All testing and kill equipment must be satisfactorily pressure tested with a pressure above the maximum pressures that can be anticipated during the operation. 5. The standard Xmas tree pressure test should be carried out with a plug installed in the tubing or hanger nipple. Each valve of the Xmas tree is to be individually tested. 6. The steam lines to the heat exchanger of the test equipment should be pressure tested with steam to the same pressure as the steam boilers are rated. 7. Provision is to be made for two blow-off lines. For offshore operations this involves one on either side of the platform. 8. A ‘Blowout and Fire Drill' is to be held prior to perforating operations. 9. Electric arc welding may only take place when authorised by a ‘Welding Permit', which is to be signed by both Installation Manager and Production Supervisor. 10. Before commencement of perforating operations, the fire-fighting water system should be under pressure. The Installation Manager will ensure that the rig is visited by a Safety Inspector before the well is perforated or tested.


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11. Gas explosion meters, a hydrogen suiphide detector and portable breathing apparatus sets must be available. The gas must be checked as soon as possible for the presence of hydrogen sulphide by either the Production Engineer or Wellsite Petroleum Engineer (see 8.3). 12. A production operator (Company or Contractor) shall assist the wireline operator in opening or closing the Xmas tree valves during perforating and wireline operations. 13. A production operator (Company or Contractor) shall be on duty at all times from the time that the well is perforated until the production test has been concluded. 14. The Wellsite Petroleum Engineer is to witness the earth testing of equipment. 15. Radio Silence (see 8.2.4). 16. Dummy Run Before the first gun is run in the hole, a dummy run is made on piano wire to check that the tubing and casing are free from obstruction. The dummy should have the same OD as the perforating gun to be run, and be at least 1.2 m long.

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Perforating

6.2 Arming Guns 1. During production tests in exploration wells, or initial perforations in deeper/unknown reservoirs drilled from a platform, the first perforation must be carried out in daylight, although later runs may be made at night. This procedure ensures that the wellhead and testing lines are not being pressurised by unknown hydrocarbons in darkness. 2. Ensure that the lubricator and BOPs have been tested to the pressure specified in the well programme. 3. Check rig wiring which could contact the cable armour for loose cables, faulty insulation, etc. 4. Shut down electric arc welding operations. 5. Initiate radio silence. 6. Visually inspect the gun assembly before the detonator is connected. Count the number of shots and overall length of gun and check this with the perforation programme. Measure and check the programme ‘blank’ intervals (if any). Measure the total length of the gun. Check the distance between the CCL recording point and the top shot of each gun. 7. Examine unijet guns very closely before running in the hole. The most frequent causes of sticking unijet guns in tubing are: (a) Screws used for coupling the assembly fall out and jam between head assembly and tubing. This will not happen if screws are properly tightened. (b) Carrier wires work free of head adaptor or bottom weight: this usually happens if they are incorrectly bedded from the beginning. (c) In deviated wells, sharp shoulders on gun assembly (particularly the adaptor head in the vicinity of the magnet) can lodge on X nipples and prevent descent. Make sure all shoulders on the gun are chamfered. 8. Check that casing-rig voltage is less than 0.25 V. 9. Ensure wireline unit safety switch is ‘off’ and key is in engineer’s possession. 10. Move non-essential personnel to a safe distance 11. Arm gun. 12. Cable head must be checked for stray voltages before attachment to the gun.


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13. When attaching head to gun, all personnel must be out of the line of fire. Non-essential personnel must REMAIN out of the line of fire until the gun is safely in the well.

6.3 Entering the Well 1. Check gun length, CCL to top shot. 2. Pick up gun and install lubricator, grease injection tube and stuffing box. Tighten Bowen Union. Ensure gun assembly head is lodged against tool catcher (leave 0.6 m slack in the cable, then pull up by hand). Set depth indicator. Note: All depths are referred to the derrick floor on drilling rigs and platforms, and to a theoretical point equivalent in height above MSL to the original DFE on wells perforated using the workover hoist.

3. Close upper master gate valve (UMGV), open kill wing valve (KWV)/swab valve (SWABV). Slowly pressure up lubricator to anticipated CITHP using water/glycol from cement unit, and check for leaks. If CITHP is less than pressure expected during the operation (as a result of perforation), test to 35 bar above anticipated CITHP. 4. Equalise lubricator pressure to existing THP at cement unit. Close KWV. Ensure tool catcher/trap is closed, then open UMGV. When both SWABV and UMGV are fully open, release tool from tool catcher or open tool trap and lower gun into well. 5. Ensure magnetic marks are boosted near surface and add extra marks for close control when pulling out. Switch on cable safety device when gun is below the seabed. 6. Speed A. Carrier Guns After the first trip in the hole, carrier guns can be run and pulled out at any speed consistent with limitations of personnel and well safety and winch mechanics. However, remember that stuffing boxes and high cable speeds are not compatible. B. Unijets In casing, speed should not exceed 3000 m/h. In tubing, even 3000 m/h may be too fast. Always drive flexible guns down tubing, watching tension and CCL indication closely and stopping at the first sign of hang-up.

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Perforating

C. General Speed through wireline entry guide, tubing landing nipples, other tubing accessories and SSSV, should not exceed 1000 m/h for both descending and ascending. 7. When descending to perforate trigger interval, run gun down to 150 m above top packer. Open KWV. Pressure up tubing so as to get a 20 bar drawdown of the formation, using water/glycol and cement pump. Close KWV. 8. Continue down, checking depths of all tubing accessories such as landing nipple, ball valve nipple, etc. the packer and tailpipe and any pup joints in the casing string below the packer. Any large depth discrepancy may necessitate the running of a completely new GR/CCL log to be recorrelated with the original FDC-GR. 9. Always pull up slowly when entering tubing shoe. 10. In highly deviated wells, gun weight may not be sufficient to overcome combined cable friction and wellhead pressure forces. In this case the possibility of pumping guns down may be considered. Do not attempt to pump down a gun which has stuck. The reason for this is very simple. Should the obstruction be overcome, the cable will be subject to high drag forces downwards, while at the stuffing box, pump pressure tends to push the cable upwards. The net result is that the cable will part just below the stuffing box. 11. Avoid running capsule guns on to obstruction in the well bore such as cement plugs, bridge plugs, etc.


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6.4 Depth Control Casing collars are tied to formation depths using the gamma ray, usually in combination with the CBL/VDL. Collar indications on the CBL can thus be used to confirm the CCL correction interval. Perforation depths will be quoted relative to the GR recorded with a Density survey over the reservoir interval. This survey is the REFERENCE LOG. 1. On GR/CCL log the CCL is recorded off depth from the GR. Establish the collar depths at their correct location with respect to this GR, and mark these collars on the GR/CCL. 2. If there is a depth discrepancy between the GR of the GR/CCL and the GR/LDT, adjust the collars as determined from the GR/CCL to reference log depths as in the following example: The depth of a correlatable peak on the LDT-GR (reference log) is 3010.0 m, whilst the depth of the same peak on the GR/CCL log is 3010.6 m, i.e. the GR/CCL is reading 0.6 m too deep relative to the reference log. If the casing collar nearest to this correlation peak is at 3011 m on the GR/CCL, the true reference log depth of this collar is 3010.4 m.

3. Note the location of the 'short joint’ in the casing string. 4. Run a collar log over the entire interval to be perforated before shooting. Check the location of the short joint with the CCL run with the perforating gun to ensure correct depths. Make a 1/20 scale recording of the lower end of the tubing string to confirm the downhole assembly. 5. Check two collars below perforating depth before stopping to perforate, to ensure that there is no slack or loop in the cable. 6. In setting the gun depth, consider the spacing from CCL measure point to top shot, as measured before arming gun.

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Perforating

All possible checks should be made to ensure that the gun is at the correct depth before shooting. Rectifying an incorrectly located set of perforations is costly and time-consuming and almost certainly involves rig-work. 7. During the detonation look for indications that gun has fired, e.g. changes in cable tension or galvanometer reading. After firing capsules, leave gun for around three minutes to allow gun debris to fall before pulling up. This precaution is not necessary with carrier guns. Record on film the casing collars (at least three) immediately above the perforated zone before pulling tool into tubing. 8. When shooting multiple intervals, it is good practice to start from the lowest zone and work upwards. This minimises the possibility of debris blocking intervals not yet perforated, particularly when perforating with capsules. This procedure is not necessary with carrier guns.


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6.5 Retrieving the Gun 1. After shooting, pull up slowly and re-check collars above perforating depth. (Wait a few minutes if perforating with unijets to allow for debris to settle). 2. After last gun of a sequence has been fired, run a collar log across the entire interval to check perforated zones. 3. Take care when entering tubing shoe, particularly with unijets and enerjets. Carrier wires/strips can break and prevent entry. Occasionally a sharp edge on the downhole assembly, combined with magnetic positioning device (MPD) angles, can cause re-entry problems. 4. Pull out of hole with caution. The gun may jam as a result of debris, broken wires or strips, misfired charges, improperly assembled carriers. As long as it can still be moved, there is a chance of retrieving the gun without killing the well and pulling tubing. 5. Watch tension closely, and watch out for cable armour balling up inside stuffing box. 6. Assume the gun has not fired until confirmed by observation. 7. 60 m below seabed: – shut down all welding – maintain radio silence – remove logging unit safety key which should be kept by the Operating Company engineer – move all non-essential personnel to a safe distance – close tool-trap. 8. Observe magnetic marks near surface. 9.

Pull gun into lubricator. Ensure that passage of CCL into lubricator is observed on hand-held magnetic mark detector at rig-floor.

10. Take care when head is approaching stuffing box. Weak points have been broken by accidentally engaging the wrong gear in the wireline unit when gun was inside lubricator. ENSURE that gun is in the top of the lubricator BEFORE closing main valve. 11. Close BOPs. 12. Bleed off pressure in riser. 13. Disconnect riser. If the quick-joint is difficult to unscrew, BEWARE of pressure in the riser.

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Perforating

14. Lay gun on cat walk. 15. If gun has fired: Check carrier for unfired charges. 16. If gun has not fired: (a) Keep all personnel out of line of fire in so far as this is practicable. (b) Unijet guns Cut cleanly through primacord just below blasting cap so that charges cannot fire. Disconnect gun from cable. Remove blasting cap, twist leg wires together, render safe. Investigate reason for misfire. (c) Carrier guns Disconnect head from gun, cap gun. Remove blasting cap, investigate reason for misfire. 17. Check insulation and continuity of wireline.


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Perforating


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Perforating


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Wellsite Geology

7 WELLSITE GEOLOGY 7.1 Lithological Description of Sedimentary Rocks The Wellsite Petroleum Engineer is responsible for keeping up-to-date a continuous cuttings log, which includes the description of cores and sidewall samples. This log, called the `mud' log, should contain the following information: (a) Penetration rate (b) Well depth (c) Lithology described as per ‘Tapeworm’ (d) Lithology interpretation (e) Total gas readings and gas chromatograph (f) Hydrocarbon detection (see 7.2) (g) Mud data (h) Bit data (i) Deviation data (j) Casing data (k) Remarks on losses, gains, oil in mud and H2S indications. 7.1.1 Description and Coding of Rock Compositions A complete lithological description taken from the EP Standard Legend (1976) showing the symbols and abbreviations describing rock samples and hydrocarbon indications is given as Figure 7.1-1 (next 26 pages). It is also available from SIPM as a fold-out for field use (Reference: Guide for Lithological Descriptions of Sedimentary Rocks ['TAPEWORM’] by E.H.K. Kempter; revised by E.D. Benjamins, Shell-Gabon, Port Gentil, September 1981).


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7.2 Hydrocarbon Detection Methods used for detection and identification of hydrocarbons at the wellsite include the following: 1. Natural Fluorescence 2. Solvent Cuts 3. Solvent Cut-Fluorescence 4. Aceton-Water Test (Acetone Reaction) 5. Visible Staining and Bleeding 6. Odour 7. Gas Detection Analysis 8. Irridescence 9. Acid Test. The application of these methods is the responsibility of the Wellsite Petroleum Engineer. 7.2.1 Natural Fluorescence Examination of mud, drill cuttings, SWS and cores for hydrocarbon fluorescence under ultraviolet light often indicates oil in small amounts or oil of light colour which might not be detected by other means. All samples should be examined using this method. It is important to note that in addition to hydrocarbons other minerals fluoresce under the ultraviolet wavelength used in the common fluoroscope. The method of distinguishing between the two types is to test for cut-fluorescence not shown by the minerals. A portion of the lightly washed cuttings or freshly broken core is placed in the view box and observed under the ultraviolet light. Those parts of the sample exhibiting fluorescence are picked out and placed in a porcelain test plate hole to be tested for cut-fluorescence. It is important that the fluorescence examination is made on fresh wet samples that have not been dried. In many cases, very light oils or condensates will not fluoresce after the sample has dried. False indications may arise from any or all of the following: (a) The presence of resinous material in the formation. (b) Gilsonite cement, which has been known to give a colour reaction with some solvent. (c) Contamination of cuttings by grease used for casing joints, tool joints or rotary table bearings. (d) Fluorescence and/or solvent coloration may arise from oil used for preparing emulsion muds. This can occur when the oil is not efficiently

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emulsified or when the formation samples have not been cleaned sufficiently. 7.2.2

Solvent Cuts

The cut is the coloration observed with the naked eye imparted to a colourless solvent by the hydrocarbons (crude oils, etc.) bearing sample.The colour of the cut is reported. The heavier oils usually give stronger cuts than light oils for a given concentration, but oils of equal gravity show appreciable differences according to their chemical composition. Naphthenic (asphaltic) oils generally show darker cuts than alkanid (paraffinic) oils. Condensate will give a light to very light cut. In addition to the cut, an oil ring can often be observed on the side of the test tube or watch-glass after evaporation of the solvent. Place ± 3cm of dried and crushed sample in a 10cm3 test tube and add solvent (Chlorothene or chloroform, etc.) up to 1 cm above the sample. Shake well for 3 to 4 min and leave the sample to stand for about 15 min. Hold the tube against a sheet of white paper and note the discoloration. See Figure 7.2-1, shown on the inside of the back cover, for oil detection in rock specimens. Chlorothene is the recommended solvent (especially for heavy hydrocarbons) as it is non-flammable and relatively non-toxic. It is the registered trade mark of a chlorohydrocarbon containing methylchloroform. Trichloroethane, ether, chloroform, petroleum ether and acetone are other solvents commonly used (carbon tetrachloride used to be the most popular solvent for both light and heavy hydrocarbons until it was discovered that it is a cumulative poison particularly dangerous in enclosed spaces). Ether is the strongest solvent, but is not selective between oil-like substances and the oxygen-containing compounds derived from vegetable matter. In addition it is a potential fire hazard. Chloroform is also a good solvent (for heavy hydrocarbons), but is also not very selective and it can be dangerous in enclosed spaces. Petroleum ether is a relatively selective solvent for all hydrocarbons.


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7.2.3 Solvent Cut-Fluorescence The cut-fluorescence is recorded by placing the test tube (used for determining cut) under UV light, taking care to fill a test tube with pure solvent as control/comparison. It is sometimes useful to withdraw some of the solvent with a pipette from the test plate and to drop it on a piece of filter paper. A brown ring may form and/or the spot may fluoresce. 7.2.4 Acetone Water Test (Acetone Reaction) Acetone is a poor solvent, especially for the heavier hydrocarbons, but a good one for bituminous material and light oils. If the presence of light oil or condensate is suspected and provided no carbonaceous or lignitic matter is present in the rock sample, the acetonewater test may be tried. The rock is powdered and placed in a test tube and acetone is added. After shaking vigorously it is filtered into another test tube and an equal amount of water is added. Since acetone and water are fully miscible and since hydrocarbons are insoluble in water, a milky white dispersion of hydrocarbons is formed when hydrocarbons are present in the sample. In case of abundant fluid hydrocarbons in the samples some oil may coalesce and float on top of the acetone-water mixture. 7.2.5 Visible Staining and Bleeding The amount by which cuttings and cores will be flushed on their way to the surface is primarily a function of the permeability. In very permeable rocks only very small amounts of oil are retained in the cuttings. Often bleeding oil and gas may be observed in cores, and sometimes in drill cuttings, from relatively tight formations. The amount of oil staining on ditch cuttings and cores is a function primarily of the distribution of the porosity and the oil distribution within the pores. The colour of the stain is a function primarily of oil gravity; heavy oils give a dark brown stain, while light oil tends towards colourless. It is important to observe is differentiation since the amount of staining is often described according to the colour, which can give very erroneous results in exploration wells.

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7.2.6 Odour The smell of a freshly broken core is distinguishable and should be noted, i.e. petroliferous, sulphurous, etc. Smells from cuttings are often apparent during the drying process. 7.2.7 Gas Detection Analysis When an air-combustible gas mixture is passed over the hot detector filament of the gas detector wire, combustion of the gas occurs, causing the detecting filament temperature to be higher than when air or non-combustible gases are passed over the filament. The higher temperature increases the electrical resistance of the filament wire, which is one branch of a Wheatstone bridge. The increased resistance of the filament branch and the amount of unbalance is shown on a galvanometer. At high voltages all the combustible gases burn; at a specified lower voltage all the gases except methane burn. By recording the readings at both voltage settings, qualitative indications of the amount of total gas and of gas heavier than methane can be obtained. For even more refined determinations in special cases the gas detector can be connected up to a chromatographic unit. 7.2.8 Irridescence Irridescence may occur with oil of any colour or gravity but is more likely to be observed with the lighter, more colourless oils, where oil staining may be absent. Irridescence maybe observed in the wet sample tray or in the mud stream. Irridescence without oil coloration or staining may indicate the presence of light oil or condensate. When oil emulsion or oil-base muds are used, irridescence from the mud occurs and should not be mistaken for formation hydrocarbons. 7.2.9 Acid Test The presence of oil in calcareous cuttings can often be detected by dropping them into weak acid (10% HCL). The reaction of the acid on an even faintly stained cutting may form relatively large bubbles, which adhere to the cutting and cause it to rise to the surface. Sometimes the bubbles burst and the cutting falls again with a characteristic bouncing motion.


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7.2.10 Reporting Results of Tests for Hydrocarbon Shows The reporting of these results in a timely and accurate manner is of the greatest importance. The results can be fully described or expressed in symbol form. Examples of the symbols used and of a typical report are given in 7.2.10.1 and 2. 7.2.10.1 Symbols for Hydrocarbon Shows (a) Natural Fluorescence: Should be analysed for the following properties and reported. The use of the symbols below is optional. (i) Distribution A = Even B = Streaked. C = Spotted (patchy) Z = None (ii) Intensity 3 = Bright (good) 2 = Dull (fair) 1 = Pale (weak) 0 = None (iii) Colour A = White B = Blue C = Yellow D = Gold E = Orange F = Brown G = Coffee Z = None (b) Solvent Cut: To be reported (numerically) for the colour gradation given below (see Figure 7.2-1). 5 = Dark Coffee 4 = Dark Tea 3 = Normal Tea 2 = Light Tea 1 = Very Light 0 = Nil (Pure Solvent)

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(c) Solvent Fluorescence: To be reported the same way as for Natural Fluorescence (intensity). 3 = Bright (good) 2 = Dull (fair) 1 = Pale (weak) 0 = None (d) Acetone Reaction: Report numerically as follows: 4 = Milky (good) 3 = Opaque white (fair) 2 = Translucent white (weak) 1 = Traces (faint) 0 = Nil (clear) (e) If applicable, results of visible staining and bleeding, odour, gas detector analysis, irridescence and acid test should be reported in this standard order, using the following symbols: P = Positive N = Negative Q = Questionable 7.2.10.2 Reporting Procedure Example When reporting indications, either the depth (corrected for time lag) from which the cuttings originate, or in the case of the same results for more than one sample in sequence, the interval should be mentioned first, followed by the alphabetical and numerical symbols in a standard sequence as shown in the following example. A cutting sample exhibiting ‘shows' should be reported as follows:

If required or considered significant the presence of staining, odour etc. can be added.


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Combined symbols to show average or in-between ratings may also be used, e.g.:

If there are no indications, the information should read: 400-420 Z0Z000

(Zulu Zero for verbal reporting).

When describing hydrocarbon indications according to the standard system, cuttings fractions should be described separately, i.e.: (i) Those thought to represent genuine cuttings from the bottom (ii) Those thought to represent cavings. When drilling potential reservoirs, particularly those situated below a shale cap, the relevant cuttings may only account for a small fraction of the sample. If only the genuine cutting fraction of such a sample gives fluorescence, it is meaningless to describe the whole sample as `spotty'. It is also meaningless to report solvent tests made on a mixture of shale cavings and fluorescent cuttings. The entire report should refer only to the cuttings which are reasonably believed to come from the bottom. In cases of severe cavings, specify; e.g. A 3 B 5 3 1 (10% sst, 90% shale cavings). In cases where only a fraction of the ‘genuine’ cuttings show natural fluorescence, particular care should be taken in reporting the intensity and colour of the fluorescence fraction, and only the fluorescent fraction should be tested with solvent.

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Safety and Environmental Control

8 SAFETY AND ENVIRONMENTAL CONTROL 8.1 Handling and Storage of Radioactive Sources and Explosives 8.1.1 Radioactive Sources – Safe Working Conditions, Handling, Storage and Transport The information given below is derived from the ‘Radiation Manual for Well Logging Operations'. Refer to this document and to 'Contractor Radiation Safety Manuals’ for more detailed information. General information on radiation can be obtained from the ‘lonising Radiation Safety Guide', Shell Safety and Health Committee, 1991. Table 8.1-1 gives the Radiation limits for working conditions.

The logging engineer is responsible for the supervision of all work involving radioactive sources. He must be at the work site when sources are handled and he is responsible for compliance with legislation, Company and Contractor guidelines and procedures and for safety in general. Only the logging engineer, or the operators under his direct instructions are authorised to handle carrying shields containing the radioactive sources used in logging operations. Only the logging engineer is authorised to remove the sources from their carrying shields.


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The following should be adhered to: 1. Procedures must exist which cover a rig or platform emergency. 2. A contingency plan for accidents/incidents with radioactive sources should exist. 3. Emergency safety equipment as listed below should be available on site. 4. A work permit is required. 5. Radiological workers handling radioactive materials should wear their appropriate monitoring badges. 6. A working area must be defined and fenced off with warning signs prior to taking the sources from storage. The drillers' doghouse is excluded from the 'controlled area' for reasons of maintaining full well surveillance. 7. Gamma and/or neutron radiation monitors must be available at the working area. 8. Prior to removing the sources from their carrying shield, a pre-exposure warning must be given using the public address system informing rig personnel that source(s) are about to be exposed. 9. Dedicated source handling tools should be used; radioactive sources must not be handled with bare hands. After the operation: 10. Logging contractor personnel must check that the source is placed back in its carrying shield. 11. Radioactive materials must be returned to the storage facility. 12. A radiological survey must be conducted to ensure that the wellsite is free of contamination. 13. A Tannoy announcement should be made informing personnel of the end of the operation involving radioactive sources. 8.1.1.2 Storage of Radioactive Sources All radioactive sources when not in use should be kept under lock in a radioactive source store. The sources are kept in the store inside their locked carrying shield (some calibration sources are kept in a calibration instrument). A radioactive source register must be kept by the logging engineer showing: type of source, identification number, source activity, location on installation, owner, date of arrival, date/destinatian of departure and manifest number.

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The maximum permitted radiation level outside (above, below, at the sides) of the storage container or outside a fence errected around the storage container are:

8.1.1.3 Transporting Radioactive Materials Radioactive sources are always transported in their carrying shields. On land, the carrying shields are placed in the source compartment of the logging truck or a special transport truck is used. Offshore, the carrying shields are placed in a dedicated transport container. Carrying shields and transport containers are marked with a Transport Index (Tl) number. No passengers are allowed when sources are shipped by helicopter. When sources are received at a location they should be transferred immediately from the transport container or logging truck to the permanent storage facility. Such should be done by the logging engineer or the operators under his instructions. In their absence, the Shell Competent Person may transfer the sources or alternatively, barriers may be erected around the transport container at the 2.5 or 7.5 µSv/hr level. Consideration must be given to radiation levels above and below the container (see Table 8.1-2)


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For transport of sources from a location, all preparations such as packaging, labelling and paper work should be made by logging contractor personnel. 8.1.1.4 Safety Equipment The safety equipment that may be required during emergency situations involving radioactive sources should be kept on site: 1. Radiation monitors for gamma and neutron radiation; contamination monitors are required when unsealed sources are being handled. 2. Three bags of lead shot for shielding of gamma radiation (2 kg per bag). 3. Parafin slabs or plastic bags with water or oil (three) for shielding of neutron radiation. Neutrons in reaction with hydrogen produce gamma radiation which may also require shielding. 4. Absorbent material (e.g. sand) and a spare pair of impermeable coveralls and plastic gloves when unsealed sources are handled. 5. Spare chain barriers and ionising radiation warning signs. 6. The fishing tools for the wireline logging tool string. 8.1.1.5 Emergencies Involving Radioactive Sources Procedures have been developed which outline action to be taken and aspects to be considered in case of accidents or incidents involving radioactive sources in logging operations. Refer to ‘Radiation Manual for Well Logging Operations’, Section 7.

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8.1.2 Explosives – Handling, Transport and Storage Three basic types of explosives are in use for wireline operations: Class 1. Slow-burning Charges, which burn without exploding. These include Baker packer setting charges and sidewall sample gun charges. Class 2. High Explosives These burn only with difficulty, and do not normally explode unless initiated by an explosion or confined at high temperatures. Included in this category are all charges for perforating guns, jet cutters, formation interval tester charges and primacord. Class 3. Detonators These will explode violently if exposed to excessive shock (hammering), high temperature, electrical current above a certain minimum (including induced current from radio transmissions). Detonators for perforating guns and cutters, sidewall sample and formation interval tester igniters, and Baker igniters are all of this type. Classes 1 and 2 Explosives in the first two categories are a little more dangerous to handle than matches, provided reasonable care is exercised. Certain specific regulations apply to their shipment by air or sea, and these must be adhered to. They may be shipped either in their original packing cases, or properly mounted in hollow carrier guns, provided the ends are carefully capped against mechanical damage or water ingress. Care must be taken to prevent droppage, spillage, water damage or exposure to excess heat during transportation. An explosives store is provided for the exclusive storage of wireline charges on the rig/platform in a location remote from personnel accommodation and working areas. This store is designed to be jettisoned into the sea in the event of fire. Contents of this store must be limited to those charges required for perforation within one month, plus a small supply of primacord, Baker charges, and jet cutters or sidewall sample charges if necessary. Keys to this store are held by the TP and Logging Engineer and access is also permitted to the WSPE by permission of the TP.


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Class 3 Detonators must be handled, transported and stored with extreme care. They must be kept at all times free from shocks, heat and sources of electrical power including radio transmitters and lightning discharges. Stringent regulations apply to their transport, and these must be scrupulously observed. A separate storage cabinet remote from all other explosives, accommodation and working areas is supplied on each rig/platform. Contents of this store must be limited to blasting caps required for immediately foreseeable jobs. Keys to this store are held by the TP and Wireline Engineer and access is also permitted to the WSPE by permission of the TP. Explosives-on-Board Log A log of explosives on board the rig/plafform is to be maintained by the WSPE. The explosive log should show the following: (a) Charge type, e.g. 2½" Unijets, 7" cutter, primacord (b) Date of stock change (IN/OUT) (c) Number of charges added to/withdrawn from store (d) Quantity currently in stock.

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8.2 Operating Safety and Radio Silence 8.2.1 Radioactive Sources – Operating Safety (a) Many Operating Companies incorporate supercombo/grandslam tool runs in their logging programmes, which include the use of radioactive sources on the first logging run. Based on the good experience with this practice and provided hole conditions do not indicate undue risk, it is no longer recommended to avoid running radioactive sources on the first logging run. (b) The Logging Crew involved in handling radioactive sources must be issued with – and wear – a monitor badge. (c) Movement of radioactive sources inside the protective shield is not hazardous, but in principle the source should be conveyed from its storage container to the vicinity of the logging tool as rapidly as possible by the experienced Wireline Crew, and all other personnel should keep at least 3 m away during the transfer. (d) The vicinity of the logging tool/radioactive source should be marked by 'Radioactive Material' warning signs and people not directly required must keep clear. (e) The source (in its logging shield) must be transferred from the protective shield using special source holders, and locked into the tool, by the Wireline Engineer (not by any other member of the Wireline Crew). (f) The rig floor must be cleared of all personnel not directly involved while the tool containing a radioactive source is lifted to be lowered into the well. All personnel must be cleared from working areas below the drill floor before the tool is lowered into the well. Divers must be advised to maintain a safe distance from the well as the tool is being lowered. (g) If a tool containing a radioactive source becomes stuck in the well, the overstripping fishing techniques must be used. Under no circumstances is the cable weak point to be broken in open hole until the fish is safely engaged in the overshot. (h) When the tool is brought back to surface, similar remarks apply as in (f) above. Wash the tool from a distance and MAKE SURE THE RADIOACTIVE SOURCE IS STILL IN PLACE. (i) Lay down the tool, and return the logging source to its shield, and the shield to its storage container, as in (c) and (d) above.


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(j) A gamma ray radiation monitor (Gammatrol PR 9) should be available at the wellsite and (where applicable) a neutron monitor. 8.2.2 Fishing for Radioactive Logging Tools (a) General If a radioactive logging tool sticks in the hole, the following procedure should be adhered to: (i) Ensure that the weak point will not be broken. Do not continue endlessly to ‘work' the tool since this may reduce the weak point strength. (ii) Inform Base (both Head Toolpusher and Operations Engineer) and provide them with all relevant information – position of fish, allowable tension of weak point and cable, etc. (iii) Base will then decide on further action together with relevant authorities (mining inspection). (iv) WSPE to ensure that Logging Engineer informs Wireline Company’s representative at the Base. (b) Fishing Operations Regardless of where the fish is stuck the cable will always be cut and threaded through the drill pipe. The following points should be adhered to: (i) Circulate once around before latching on to the fish. (ii) Monitor constantly the mud returns with a Gamma Ray tool placed in the return line or close thereafter. (iii) Do not locate or engage tool with more than 5 t (10,000 lb) weight. (iv) Discuss with 6ase the maximum allowable pull. (v) No personnel other than Wireline Contractor should be near mud pits or returns lines. (vi) Ensure that with the tool engaged in the overshot, circulation remains possible. Use a circulating sub in the fishing assembly one stand above the overshot. (c) Handling of Retrieved Source The following points should be adhered to: (i) Limit rig personnel to the minimum required on the rig floor. (ii) Pull the source as far as possible in the derrick (min. 20 m). (iii) Cover rotary table, close rams, etc. then rig personnel except driller leaves rig floor. (iv) Driller assists Wireline Contractor in laying down equipment. (d) Abandonment of a Source in the Hole

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When everything else has failed, a separate plugging back programme will be issued. 8.2.3 Explosives – Operating Safety The following general safety precautions should be taken at all times when operating with electrically-fired perforating guns and charges: (a) Work involving the use of explosives should be carried out only by specialist personnel but never when electrical storms are in the vicinity. (b) During any job involving the use of explosives, the number of authorised personnel employed should be kept to a minimum. All other persons should be excluded from the danger area (e.g. walkway and derrick floor) throughout the operation. (c) Warning signs should be placed on access routes to the danger area to prevent access of unauthorised persons. (d) Electric Arc Welding can cause unacceptable voltage differences be tween different parts of the rig, or even create dangerous EM radiation levels. All arc welding should be stopped before electrical blasting caps are connected to the gun, and remain shut down until the gun is more than 60 m below the sea bed. (e) Radio Transmissions have the potential to fire blasting caps and/or igniters. Warning signs should be placed in the radio room to advise personnel of radio shut-down (see 8.2.4 on radio silence). (f) Faulty Rig Wiring has been known to set off guns at the surface. Check the rig wiring for loose wires or hanging cables, particularly in the vicinity of the derrick V adjacent to the cat-walk. (g) Casing and rig must be electrically bonded together, and stray voltage between them reduced to less than 0.25 V. The Service Company supplies a voltage monitor which should be checked frequently. If the potential difference exceeds the limit at any time throughout the perforating operation, all sources of electrical energy must be switched off (Note: This may preclude perforating at night). The WSPE is to witness the earth testing of the equipment. (h) The Logging Unit includes a safety switch which isolates the logging cable from internal circuits and grounds the cable conductors through 5000 ohm resistors. Before attaching an explosive device to the cable head, and whenever the device (whether fired or not) is less than 60 m from the surface, the logging unit safety key must be removed and in the Logging Engineer’s possession.


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(i) Pre-armed guns must be properly capped until attachment to the cable head. (j) The cable head should always be checked for stray voltages before attachment to the gun. (k) All non-essential personnel must be moved to a safe distance before the head is attached to the gun, until the gun is safely in the well. (I) A gun which has been lowered into the well should always be treated as live and dangerous until observation outside the lubricator confirms a successful firing. 8.2.4 Radio Silence In certain operations there must be radio silence for the following reasons: Radio Silence is a general term which covers all precautions taken to reduce or eliminate potential sources of stray currents and radio induced voltages, which could detonate explosives prematurely (see Table 8.2.4-1). During Radio Silence the rig platform status will remain ‘Normal'. Stray Currents are eliminated by stopping all electric welding, shutting down electrical equipment which may cause stray currents in the rig structure, isolating cathodic protection and fitting grounding straps between critical areas such as the casing, rig structure and wire line logging unit. Radio Induced Voltages are reduced to insignificant levels by ensuring radio and radar transmissions from the installation are controlled by a radio shutdown. The area in which transmissions are controlled will also include all vessels within 500 m of the installation. (Outside 500 m the standby boat will warn vessels of the radio shut-down area). Essential radio links for production and pipeline control operations may remain operational, when on-site electromagnetic field measurements have shown that the fields generated by these radio links will not detonate the explosives prematurely. Radio Silence is enforced whenever operations involving the use of electroexplosive detonators are being carried out. This comprises perforating, side wall sampling, formation interval testing (FIT), explosive backing-off (string shot) and explosive cutting, wireline set packers or bridge plugs. The WSPE must inform the TP when Radio Silence is required. On installations where an OIM (Offshore Installation Manager) is present notice of the need for Radio Silence should be given at least 24 hours in advance to the OIM. This should also apply to cancellation of the intended

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Radio Silence if required. The OIM will act as co-ordinator for the Radio Silence procedure. Table 8.2.4-1 Radio shut-down during operations with explosives applicable to installations and vessels within 500 metres

TEMPORARY RELAXATIONS: (Prior Agreement OIM, Petroleum Engineer, Logging Engineer required) 1. Operation of a single 1 watt hand portable radio (more than 10 m from the wireline) for communication with the standby boat. 2. Temporary operation of any fixed transmitter for urgent communications. Notes:

1. 'RECEIVE ONLY’ RADIOS CAN REMAIN IN OPERATION DURING ANY OF THE OPERATIONS LISTED ABOVE. 2. Although line-of-sight links may be permitted, the back-up UHF transmitter must be switched off while operations defined in A are being carried out. 3. When operations defined in A are being carried out, the troposcatter link to shore must be switched off.


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4. No operation defined in A or B will be carried out during weather conditions which are likely to produce electrical discharges. 5. Potential difference between casing and rig must not exceed 0.25 V. (Electrical equipment may have to be isolated to achieve this). Temporary Relaxation of Radio Silence The normal procedure is that an installation and all vessels within 500 m will remain in radio shut-down until the specific task is completed. However, if the task is delayed, or is of a protracted nature, and there is an urgent requirement to break radio silence, a limited temporary relaxation of some of the radio shutdown requirements is permitted. Most relaxations will be permitted only when the detonators are more than 75 m below the sea bed. Below this level, the direct hazard area is restricted to the wellbore, and although a potential hazard of detonation remains, it is greatly reduced. In the case of packers and bridge plugs, radio silence may be interrupted when the wireline is more than 60 m below sea bed. For all cases, radio silence must be instigated when running in and when pulling out in the last 60 m until the clear sign is given by the Logging Engineer, Petroleum Engineer or Toolpusher (TP). Any relaxation will be by prior agreement between the OIM, the TP, the Logging Engineer and the Petroleum Engineer, and will be restricted to the use of certain radios. Any such relaxation must be strictly controlled. Permanent Relaxation of Radio Shut-Down for the Operation of Pipeline Integrity and Production Operations Systems The operation of these systems is dependent on the continuous operation of the interplatform line of sight links and the Troposcatter link to shore. Troposcatter cannot be used from a platform in Radio Silence due to the large power radiated. In the field it is necessary to maintain the inter-platform line of sight links, even from the installation in Radio Silence. If the contractors (e.g. Schlumberger and Dresser Atlas) agree that the line of sight links does not pose a detonation hazard it may safely remain in service during operations with explosives. Note: Any back-up UHF transmitters must be switched off during Radio Silence.

Alert Conditions In the event of a platform ‘Yellow Alert’ status being raised while explosives are being made up prior into going in the well, the explosives must be made safe and the operation suspended until the platform is returned to ‘Normal'

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status. When live explosives are in the well they should be lowered to more than 75 m below the sea bed and the operations suspended until the platform is returned to ‘Normal’ status. In the case of a ‘Red Hazard' status the operation must be suspended as for the 'Yellow Alert’ but in addition the well must be secured by closing the BOPs around the logging cable. The nature of the emergency should be established BEFORE operating shear rams/cutting the cable (when using explosives in a drilling well) or before closing the Xmas tree/SSSV (when using explosives in a completed well).


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8.3 The Presence of Hydrogen Sulphide Hydrogen sulphide (H2S) may occur as a component of produced gas. It is an extremely toxic gas. Protection against hydrogen sulphide requires stringent precautionary measures. 8.3.1 Toxicity of Hydrogen Sulphide Gas Hydrogen sulphide (H2S) occurs widely at varying concentrations in EP gas production and processing operations. It is an extremely toxic gas (almost as lethal as hydrogen cyanide and more lethal than chlorine). It should also be noted that when H2S is burnt it is oxidised to sulphur dioxide (SO2). H2S at very low concentrations has the smell of rotten eggs. However, at slightly higher concentrations, the sense of smell is anaesthetised and it cannot be detected. Under these circumstances a victim can lose consciousness without warning. H2S therefore presents a potentially serious hazard to personnel and requires stringent safety precautions at every stage of design, operation and particularly maintenance (see also Health, Safety and Environment in Vol. 1) Whenever it is necessary to work in areas where the concentration of H2S in the atmosphere exceeds 10 cm3/m3 (ppm by vol.), PROTECTIVE EQUIPMENT MUST BE WORN. (10 ppm is termed the Threshold Limit Value or TLV and is the time weighted concentration for an 8-hour period to which a person can be exposed without harmful effect.) The choice of sampling/analysis method (see below) is critical to accident prevention. 8.3.2 Determination of Sulphide Content in Mud and Fluid Samples Method Summary When H2S contaminates mud and fluid samples, water soluble sulphides as well as insoluble sulphides are formed. For this reason a method has been chosen to measure the total sulphide content. Principle By adding an excess of concentrated HCI to a sample of drilling mud the total sulphides present in the mud are converted to H2S. The H2S is stripped from the liquid and forced through a lead acetate test paper. Lead acetate turns

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brown or black even with traces of H2S. The sulphide content is then estimated by comparison of the test paper colour with a standard colour chart. Apparatus – Sample bottle (35 mm diameter, 100 mm high) with perforated plastic cap – Hydrogen sulphide test papers – Drop bottle with antifoam (NF-1 Bayer Entsch.) – Graduated colour chart – 10% wt. hydrochloric acid – Stripping tablets, e.g. Alka Seltzer. Procedure 1. Place 25 mL mud in sample bottle. 2. Place piece of test paper inside plastic cap. 3. Add 5 – 7 drops of antifoam to sample and mix carefully. 4. Add 7 mL HCI 10% to sample and IMMEDIATELY snap the cap containing the test paper on the bottle. 5. Shake carefully, taking care that liquid does not touch the test paper. 6. After the acid is spent (appr. 5 min) remove test paper and compare with standard colour chart. Note: If the colour of the test paper is too dark for proper comparison, the sample may be diluted with water and the result corrected for dilution. When a high dilution is required, it may be necessary to add an Alka Seltzer tablet to strip the H2S from the liquid.

8.3.3 Determination of H2S Content in Gas (Dräger Tube Method) Method summary Dräger tubes containing colourless crystals, change colour when H2S gas is passed through them. The colour change depends on the H2S concentration; brownish for concentrations up to 2000 ppm vol., and black for high concentrations. Procedure Make a connection with a kerotest valve and lead the gas via a plastic hose to the bottom of a sampling bottle (max. 1 litre) with a sufficiently wide neck. Flush the bottle clean and continue with H2S determination procedure whilst the gas flows continuously via the bottle.


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The apparatus can also be used for H2S determination in the free air above mudpits, on the drill floor, etc. Determination The Dräger apparatus equipped with the correct tube (see Table 8.3.3-1) is placed inside the bottle so that the lower tip of the tube reaches half-way down the sampling bottle. For the actual H2S determination both tips of the tube should be broken off with an eye attached near the chain of the pump. Make the required number of strokes by pushing in the pump completely and wait till the chain is fully stretched again. The amount of H2S can then be determined directly from the colour change in the tube.

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9 RESERVOIR COMPACTION AND SURFACE SUBSIDENCE 9.1 Introduction Withdrawal of fluids from hydrocarbon reservoirs can result in a substantial reservoir pore pressure drop when aquifer support is limited. As a result of the pressure drop in the reservoir, the effective stress which acts on the rock matrix (the difference between overburden and pore pressure) increases and as a result reservoir compaction may occur. The degree of compaction depends on the rock mechanical properties of the depleting reservoir. The reservoir compaction can have far-reaching implications and proper prediction and monitoring can be significant attributes of a field development (planning) activity. The possible implications are: 1. The compaction may act as an additional drive mechanism, affecting ultimate recovery. This is discussed in more detail in Volume 4, chapter 9 FORMATION COMPRESSIBILITY. The same process may, however, result in a reduced permeability, canceling out the effect of partial pressure maintenance. 2. Compaction of a reservoir may result in subsidence of the overburden. This can present downhole and surface problems: (a) Downhole casing damage may occur. Research is ongoing to quantify the effects of compaction on casing damage. The results are planned to be incorporated in a future update of the Casing Design Manual (EP 50600). It should be noted that the combination of compaction and sand production will be even more detrimental to casing integrity, as the cavities resulting from sand production will locally reduce support to the casing. For more background information, see Refs. 13,14, 15 and 16. (b) At the surface, subsidence may or may not be a problem, depending on the field location. in sensitive areas a maximum allowable surface subsidence may impose a pressure maintenance scheme to prevent further compaction/subsidence. For the allowable remaining subsidence additional measures may have to be taken, such as upgrading the system of ground water level management. In offshore areas, expected subsidence will dictate platform height. The following Sections outline the various procedures to predict reservoir compaction and the related surface subsidence, the laboratory procedures to determine the relevant rock mechanical parameters and the procedures to monitor in situ compaction at the reservoir level.

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9.2 Compaction Prediction It is clear from the foregoing that an accurate prediction of compaction and related subsidence is an important issue and the development of prediction models has been the subject of various studies in the recent past. In this paragraph the relevant prediction models for sandstones, shales and carbonates will be treated separately. 9.2.1 Sandstone Reservoirs 9.2.1.1 Linear Compaction Model The linear compaction model assumes compaction to be proportional to the reservoir pressure drop at all stages of field production. The compaction is estimated according to:

In which: ∆h is the amount of compaction as a result the increase in effective stress. cm,o is the uniaxial compressibility in 10-5 bar

-1

or in 10-7 psi-1

hi is the initial thickness of the depleting reservoir ∆p is the pressure drop in the depleting reservoir in bar or in psi as a result of production. Where the reservoir consists of several layers with distinctly different properties, compaction ∆h of each layer has to be evaluated separately using eq. (1) and the appropriate parameters for each layer. Total compaction ∆htot of the reservoir is then obtained by summation of the contributions of the individual layers. The same approach can be taken for stacked reservoirs, where also the pressure differential will be different for each contributing reservoir. The uniaxial compressibility cm,o can be obtained from laboratory compaction tests on representative core material. These measurements are carried out in a triaxial (or alternatively an oedometer) compaction cell, where the sample is loaded along one axis, while adjusting the applied radial stress to maintain the condition of zero radial strain. As the lateral dimensions of a reservoir are usually large compared to its height, the reservoir will deform predominantly in the vertical direction. The uniaxial measurement is therefore considered the most representative of the reservoir compaction process.


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The ratio of matrix-to-bulk compressibility, β, should in theory be used in the correction of the lab-measured bulk compressibilities to the effective formation compressibilities. In practice, however, this correction may not be as straightforward as assumed in the theory. As evident from Table 9.2-1 the value of β is only significant at low values of cm,o at which the fluid compressibility is likely to dominate in any case. For elastic deformations, use of linear elasticity theory allows for correction of the compressibility data measured under hydrostatic conditions to uniaxial values by the use of Poisson's ration, ν. When only hydrostatic compressibility data are available the hydrostatic bulk compressibility cb should be converted to the uniaxial compressibility cm,o according to:

A conversion to calculate pore compressibility cf can be simply done by dividing the uniaxial compressibility cm,o by the sample's porosity:

If no core derived compressibility data are available, order-of-magnitude estimates can be obtained from the table below.

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9.2.1.2 Rate Type Compaction Model The Rate Type Compaction Model (RTCM) was developed at KSEPL during the early 1980s for the description of campaction of sandstone reservoirs as a result of pressure depletion (Ref. 1). The model was based on an observation during the laboratory experiments, when it was noted that the compaction behaviour of reservoir rock depended upon the rate of loading of the rock. When the loading rate was increased, a delay was observed: the rock did not respond immediately with an increased compaction rate. This observed experimental behaviour was placed in a theoretical framework, and several field cases were studied. This led to the formulation of the RTCM as a tool for the prediction of compaction in the field, using laboratory measurements on core samples as input data. In some reservoirs, however, this theoretical increase in compaction rate has not been observed and the actual field data still show a linear compaction behaviour, although at a rate of about one half to one third of what would have been expected on the basis of the laboratory compressibility measurements. Based on this discrepancy, KSEPL have carried out a review of the RTCM (for more details see Ref. 12) and have concluded that, although support was found in data from a number of fields, the extrapolation to field conditions and time frame is not as straightforward as suggested by the RTCM. In addition, the core derived compressibility values may be higher than those observed in the field. This is thought to be due to the non-native state of the core material and possibly also due to core damage. Care has to be taken therefore in the use of compressibility data derived form core analysis. 9.2.1.3 Recommended Procedure It follows from the above that, pending the results of further research, the RTCM should not be used for the prediction of sandstone reservoir compaction. Instead, it is recommended that the following procedure should be applied to make a prediction before production of the field has started and when field compaction and subsidence data have not yet become available. - Use a linear compaction model. - Use core-determined rock compressibility data as input. These core data may be pessimistic, as the core may be damaged and weakened without this being obvious from visual inspection. - Take other uncertainties into account: thickness of the depleting interval, aquifer support etc. - Use the ‘Nucleus of strain' approach (see paragraph 9.3) for the conversion of compaction to subsidence.


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Compaction

With this procedure a ‘maximum case' prediction of compaction and subsidence can be made. Based on this, and depending on the circumstances, data gathering can be planned to monitor field behaviour. When field data become available, uncertainties can be reduced and the original prediction can be updated and refined. Due to the potentially far reaching implications of subsidence, expert advise from KSEPL may be sought in an early stage. 9.2.2 Compaction of Shales When shales are present within the actual reservoir intervals as relatively thin intervals (thicknesses as a few of feet or less), the pressure depletion in the shales is virtually equal to that in the pay zones. Compaction of these shales can be calculated with the compaction models generally applied for sandstones (Section 9.2.1) as follows: - Compaction of thin interbedded shale laminations can be taken into account in the total compaction of the sand-shale sequence using laboratory compressibility data on representative shale-laminated (sandstone) samples. - Compaction of a 100%-shale interval (of small thickness) is evaluated from the relevant shale thickness and the laboratory uniaxial compressibility. When core compressibility data are not available, a first estimate of cm,o (shale) can be obtained from Table 9.2-1, using the appropriate total porosity range. In low-permeable (thick) shale layers, which are located adjacent to the reservoir, pressure lags may occur that can give rise to non-linear (time delayed) compaction of these shales. 9.2.3 Prediction of Compaction Due to Pore Collapse in High-Porosity Carbonate Reservoirs 9.2.3.1 The Trendline Model In general the bulk compressibilities of carbonates are much lower than those of sandstones of comparab!e porosity. Field cases of considerable reservoir compaction and surface subsidence due to hydrocarbon production from carbonate reservoirs are therefore rare. In high-porosity carbonates however, the phenomenon of pore collapse can occur in the pressure regime prevailing during production (Refs. 6, 7 and 8). These carbonates, which are usually well consolidated, exhibit a low compressibility up to a certain stress level (elastic deformation regime), but strong compaction at

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higher stress. This sudden increase in compressibility, coupled with a large irreversible deformation, is called pore collapse.

The compaction behaviour of carbonate rock is strongly dependent on the initial porosity: high porosity rock shows pore collapse at a much lower stress level than rock material of lower porosity. After the onset of pore collapse, the porosity reduction as a function of stress is independent of the initial porosity and can be described by an average porosity - stress trendline (Figure 9.2.3-1). This trendline is strongly dependent on carbonate rock type, as is shown in Figure 9.2.3-2 (The laboratory trendlines depicted in this Figure have been obtained on water-saturated samples). The procedure to predict compaction due to pore collapse in high-porosity carbonate reservoirs is outlined in Section 9.2.3.2. Compaction in low porosity


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Compaction

carbonate reservoirs, in which pore collapse does not occur during production, can be calculated using the linear compaction model (Section 9.2.1.1), which is often adequate at these low compressibilities and gives a worst-case estimate. 9.2.3.2 Prediction of In-Situ Pore Collapse with the Trendline Model The trendline model can be used to predict the pore collapse stress of the various layers and the total amount of compaction to be expected at a given stage of depletion ∆р by means of the following procedure: 1. Establish the laboratory trendline(s) for the various carbonate rock types present in the reservoir. To this end, uniaxial compaction tests should be done on a set of non-cleaned core samples with as large a range of initial porosities as possible (The samples should be partially saturated with water). 2. Divide the reservoir into a number of layers (gridblocks) of more or less constant (average) porosity and carbonate type. 3. Determine the collapse stress and the amount of compaction after collapse

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for each layer (gridblock) according to the procedure illustrated in Figure 9.2.3-3, using the appropriate trendline and the value of the effective stress at the stage of depletion considered (e.g. at abandonment). Note that the value of the effective stress corresponding to a given drop in pore pressure can depend on the reservoir geometry and on the compressibility of the rock surrounding the collapsing layers, If this is suspected, more detailed 3D computer modelling may be required.

4. Calculate the total amount of compaction due to pore collapse in a given layer (gridblock) using the equation:

The total amount of reservoir compaction is then obtained by aggregating the contributions of the various layers (gridblocks). If the collapse stress is not reached during depletion, the contribution of ‘normal' compaction can be taken into account, for example by using the correlation between porosity and compressibility prior to pore collapse for the relevant carbonate type.


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9.3 Calculation of Surface Subsidence It should be noted that the models described below exclude the prediction of surface subsidence caused by the settlement of shallow (young) sediments as a result of their own weight and as a result of surface activity such as building facilities and traffic. This effect will have to be taken into account separately. 9.3.1 The Nucleus-of-Strain Approach Surface subsidence can occur above strongly compacting reservoirs that are of relatively large lateral extent. For deeply buried reservoirs, compaction results in a rather continuous subsidence bowl, in which surface subsidence is a maximum above the field centre. A commonly applied procedure to calculate subsidence above compacting hydrocarbon reservoirs is the nucleus-of-strain approach (Ref. 10). In this model the reservoir and the overburden are assumed to have equal linear elastic properties. Moreover, this model assumes a rigid basement to be present at some depth below the reservoir to account for the usually large stiffness of the ‘underburden' (Ref. 11). This ‘rigid-basement' model enables a realistic calculation to be made of subsidence above hydrocarbon reservoirs which are buried at a sufficiently large depth. The model has the following advantages: (1) the model is 3D, (2) any reservoir of arbitrary shape can be handled, and (3) computation of subsidence is rapid and at low cost. For shallow compaction prone reservoirs, subsidence can be accompanied by fault reactivation from the reservoir up to surface due to large differential strains in the reservoir. In such cases, it is advisable to have a Finite Element calculation carried out to assess whether fault reactivation is likely to occur for the reservoir under consideration. 9.3.2 Quick-Look Procedure to Calculate Subsidence in the Deepest Point of the Subsidence Bowl Using the Rigid-Basement Model Subsidence can be rapidly calculated from compaction (calculated as described in Section 9.2) when the reservoir (being depleted by a pressure drop ∆p) can be approximated by a disc of average radius R and a constant thickness. Figure 9.3-1 depicts the ratio of subsidence above the field centre over compaction (normalised subsidence) as a function of the ratio of reservoir depth over reservoir radius (C/R), for different ratios of basement depth over reservoir depth (curve parameter K/C). (The rigid basement should always be taken below the reservoir: K > C.) Figure 9.3-1 shows that for C/R ratios of

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less than 0.2, subsidence is vitually equal to reservoir compaction, irrespective of the depth of the basement. This plot has been calculated for an average Poisson's ratio ν of overburden and reservoir equal to 0.25. (Given the minor influence of Poisson's ratio, Figure 9.3-1 can also be applied for other values of ν.)

9.3.3 Detailed Calculation of Subsidence Using the Rigid-Basement Model To obtain detailed subsidence contour plots as a function of time or pressure drop, a numerical calculation must be carried out by running the SUBCAL computer program. In this package, which is available under ICEPE, three different compaction models are implemented: the linear model and the RTCM for sandstones, and the pore collapse trend line model for carbonates. The RTCM has not yet been removed from SUBCAL, but should not be used pending results of further research (see 9.2.1.2).


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10 REFERENCES AND FURTHER READING WIRELINE LOGGING: GENERAL (1) Further Reading – Atlas Wireline Services – Log Interpretation Charts, 1985 – Services Catalog (Dresser Atlas), 1985 – Equipment and Specification Catalog, 1989 – Calibration Guide (Dresser Atlas), 1986 – Schlumberger – Log Interpretation Charts, 1989 – Openhole Services Catalog, 1983 – Production Services Catalog, 1984 – Cyber Service Unit, Wellsite Products, Calibration Guide, and Mnemonics, 1989 – Log Interpretation Principles/Applications, 1989 – Advanced Interpretation of Wireline Logs, 1986 – Cased Hole Log Interpretation Principles /Applications, 1989 Halliburton Logging Services – Gearhart Well Service Systems, 1983 – Welex Open Hole Services, 1986 – Welex Cased Hole Services, undated – Gearhart Formation Evaluation Chart Book, 1985 OPEN HOLE LOGGING (2) Further Reading – Lynch, E.J., Formation Evaluation. A Harper International Reprint, Harper and Row New York, Evanston and London, 1964 – Desbrandes, R., Théorie et Interprétation des Diagraphies, Publication de L’Institut Franglais du Pétrole, Editions Technip, Paris, 1985 – idem translated, Encyclopedia of Well Logging, Graham & Trotman Ltd, London and Edetions Technip, Paris, 1985 – Dewan, John T., Essentials of Modern Open-Hole Log Interpretation. Penn Well Books, Tulsa, Oklahoma, 1983


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References and Further Reading

– Serra, O. Fundamentals of Well-Log Interpretation, Elsevier, Amsterdam, 1984 – Bateman, R.M., Log Quality Control, Reidel, Dordrecht, 1985. CORING (4) Further Reading – Abrams, A., Mud Design to Minimise Rock Impairment due to Particle Invasion. Journal of Petroleum Technology, May 1977 – Determination of Residual Oil Saturation. Interstate Oil Compact Commission, June 1978 – Christensen Diamond Products, Operating Manual 67/8" X 3" Model ‘B’ Rubber Sleeve Core Barrel. Salt Lake City, Utah, USA, (undated) – Jenks, L.H., Huppler, J.D., Morrow, N.R. and Salathiel, R.A., Fluid Flow within a Porous Media near a Diamond Core Bit. Journal of Canadian Petroleum Technology, December 1968 CASED HOLE AND PRODUCTION LOGGING (5) Further Reading – Bateman, R.M., Cased-Hole Log Analysis and Reservoir Performance Monitoring, Reidel, Dordrecht, 1985 SAFETY AND ENVIRONMENTAL CONTROL (8) Operating Safety and Radio Silence (8.2) Further Reading – Institute of Petroleum, Offshore Operations United Kingdom Shelf. Recommended Practices for Radio Silence when Conducting Wireline Services Involving the Use of Explosives, Aberdeen, Nov. 1983 – BS 4992/a and /b for onshore operations (in preparation 1984) (UK) – Guidance Note GS 21 from Health and Safety Executive (UK)

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RESERVOIR COMPACTION AND SURFACE SUBSIDENCE (9) References 1. de Waal, J.A., On the Rate Type Compaction Behaviour of Sandstone Reservoir Rock. Thesis, Technical University of Delft, 1986. 2. de Waal, J.A. & Smits, R.M.M., Prediction of Reservoir Compaction and Surface Subsidence: Field Application of a New Model. SPE 14214, 1985. 3. Geertsma, J., 1957a, The Effect of Fluid Pressure Decline on Volumetric Changes of Porous Rocks. Trans. AIME, 210, pp. 331-338. 4. Jaeger, J.C., & Cook, N.G.W., Fundamentals of Rock Mechanics. Chapman & Hall, London, 1977. 5. Smits, R.M.M. & de Waal, J.A., A comparison between the Pressure-Lag Model and the Rate-Type Compaction Model for the Prediction of Reservoir Compaction and Surface Subsidence, paper submitted for publication in SPE Formation Evaluation. 6. Blanton III, T.L.: Deformation of Chalk Under Confining Pressure and Pore Pressure. SPE Journal, February 1981, pp. 43-50. 7. Newman, G.H.: The Effect of Water Chemistry on the Laboratory Compression and Permeability Characteristics of Some North Sea Chalks. SPE paper 10203. 8. van Ditzhuijzen, P.J.D & de Waal, J.A.: Reservoir Compaction and Surface Subsidence in the Central Luconia Gas-Bearing Carbonates Offshore Sarawak, East Malaysia. Offshore South East Asia Conf., Singapore, 21 – 24 February 1984, Paper 12400. 9. Smits, R.M.M., De Waal, J.A. & Van Kooten, J.F.C., Prediction of abrupt reservoir compaction and surface subsidence due to pore collapse in carbonates. SPE 15642. Geertsma, J., A Basic Theory of Subsidence Due to Reservoir Compaction: the 10. Homogeneous Case. Trans. Royal Dutch Society of Geologists and Mining Engineers, 1973, 28, pp. 43-62. 11. van Opstal, G., The Effect of Base Rock Rigidity on Subsidence Due To Compaction. Proceedings of the Third Congress of the International Society of Rock Mechanics, Denver, Colorado, September 1-7, 1974. Vol. 2. part B, National Academy of Sciences, Washington D.C. 12. van Hasselt, J.P., Description and Prediction of Sandstone Reservoir Compaction. Present Position and Recommended Procedures. EP 89-2383 (RKGR 89-152) 13. Cernocky, E.P. and Scholibo, F.C., Casing Compaction Design. Part 1: Development and Calibration af a Finity Element Model of Casing Cross


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References and Further Reading

Sections Subjected to Nonuniform, Transverse Loads. EP 88-0034 14. Cernocky, E.P. an Scholibo, F.C., Casing Compaction Design. Part 2: Development of Guidelines for the Ability of Casing to Resist Cross Section Deformation under Nonuniform Transverse Load and pressure acting on the Cross Section. EP 87-2172 15. Cernocky, E.P. and Scholibo, F.C., Casing Compaction Design. Part 3: Influence of Internal and External Fluid Pressures on the Cross Sectional Deformation of Casing Subjected to Nonuniform, Transverse Compaction Loads. EP 88-1070. 16. Cernocky, E.P. and Scholibo, F.C., Casing Compaction Design. Part 4: Crushing Resistance of Casing in the Presence of Axial Tensile and Compressive Loads. EP 90-3172.

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