Wireline and Perforating Service_Hallibuton

Knowl edgea ndDa t aT r a ns f er Res er v oi rE v a l ua t i onS er v i c es OpenHol eWi r el i neS er v i c es Ca s edHol eWi r el i neS er v i c es Per f or a t i ngS ol ut i ons Downhol eVi deo S l i c k l i neS er v i c eE qui pmenta ndS er v i c es Mobi l i z a t i on Mnemoni c s

Table of Contents Knowledge and Data Transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 Real-Time Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 Real-Time Data/Solution Delivery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 HalLink® Satellite Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-2 InSite Anywhere® Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-3

Reservoir Evaluation Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 Petrophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 MRI Petrophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 MRIL® Simultaneous T1 and T2 Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 MRIAN™ Magnetic Resonance Imaging Analysis. . . . . . . . . . . . . . . . . . . . . . . . . .2-2 Time Domain Analysis (TDA). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-4 Diffusion Analysis (DIFAN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-5 Enhanced Diffusion Method™ (EDM™) Technique . . . . . . . . . . . . . . . . . . . . . . . .2-6 Heavy Oil MRIANSM Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-7 StiMRIL™ Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-8 Volumetric Petrophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-10 Chi Modeling® Computation Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-10 ULTRA™ Module Suite . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-12 SASHA™ Shaly Sand Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-14 CORAL™ Complex Lithology Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-15 LARA™ Laminated Reservoir Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-16 Reservoir Characterization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-17 Borehole Image Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-17 AutoDip™ and TrendSetter™ Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-17 AutoDip Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-18 TrendSetter Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-18 ReadyView™ Open-Hole Imaging System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-20 Facies Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-22 Net2Gross Sand Count . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-24 ImagePerm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-25 Borehole Geophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-26 Wellbore Seismic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-26 High Resolution Seismic Imaging—(Near Offset VSP, Fixed Offset VSP, Walkaways, 3D VSP, Salt Proximity Surveys, Microseismic Surveys) . . . . . . . . .2-26 Reservoir Geophysics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 Long Array Multi-Component Acquisition Tools . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 GeoChain VSP Downhole Receiver Array . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 Synthetic Seismic and Sonic Log Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis . . . . . . . . . . . . . .2-28 ExactFrac® Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-29 Acoustics and Rock Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-30

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Anisotropy Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-30 RockXpert2™ Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-32 FracXpert™ Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-34 AcidXpert™ Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-36 Reservoir and Production Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 Reservoir Testing Studio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 RTS™ Reservoir Testing Studio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 Pressure Time Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 Exact™ Buildup Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-39 Exact Anisotropy Analysis Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-39 FasTest® Buildup Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-40 Horner Time Plots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-40 Log-Log Derivative Analysis Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-41 PVT Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-42 Formation Test Summary Program (FTS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-42 Well Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-44 Well Test Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-44 Well Test Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-46 Multi-Layered Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-47 Reservoir Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-48 SigmaSat™ Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-48 CarbOxSat™ Model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-49 TripleSat™ Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-50 Production Logging Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-51 Production Logging Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-51 FloImager® Analysis Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-54 FloImager® 3D Software Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-54

Open-Hole Wireline Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-1 Resistivity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-1 ACRt™ Array Compensated Resistivity Tool System . . . . . . . . . . . . . . . . . . . . . . . . . .3-1 HRAI™ High Resolution Array Induction Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-3 HRI™ High Resolution Induction Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-4 DLL™ Dual Laterolog Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-6 MSFL™ Micro-Spherically Focused Log and Microlog (ML) . . . . . . . . . . . . . . . . . . . .3-7 HFDT™ High Frequency Dielectric Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-8 Imaging. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-9 EMI™ Electrical Micro Imaging Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-9 XRMI™ X-Tended Range Micro Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-11 OMRI™ Oil-Based Micro-Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-13 CAST-V™ Circumferential Acoustic Scanning Tool-Visualization. . . . . . . . . . . . . . .3-15 SED™ Six Arm Dipmeter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-16 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-17 SDL™ Spectral Density Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-17

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DSN™ Dual-Spaced Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-19 DSEN™ Dual-Spaced Epithermal Neutron Log Tool . . . . . . . . . . . . . . . . . . . . . . . . . .3-21 CSNG™ Compensated Spectral Natural Gamma Ray . . . . . . . . . . . . . . . . . . . . . . . . .3-22 Acoustics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-24 BSAT Borehole Compensated Sonic Array Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-24 WaveSonic® Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-25 FWS™ Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-27 NMR. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-29 MRIL-XL™ and MRIL®-Prime Magnetic Resonance Image Logging Tools . . . . . . .3-29 MRILab® Magnetic Resonance Image Fluid Analyzer . . . . . . . . . . . . . . . . . . . . . . . . .3-31 Borehole Geophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-33 Wellbore Seismic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-33 High Resolution Seismic Imaging—(Near Offset VSP, Fixed Offset VSP, Walkaways, 3D VSP, Salt Proximity Surveys, Microseismic Surveys) . . . . . . . . .3-33 Reservoir Geophysics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 Long Array Multi-Component Acquisition Tools . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 GeoChain VSP Downhole Receiver Array . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 Synthetic Seismic and Sonic Log Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis . . . . . . . . . . . . . .3-35 ExactFrac® Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-36 Sampling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-37 RDT™ Reservoir Description Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-37 DPS Dual Probe Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 Oval Pad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 Straddle Packer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 FPS Flow-Control Pump-Out Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 QGS Quartz Gauge Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 MRILab Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-40 MCS Multi Chamber Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-40 CVS Chamber Valve Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-40 SFT-IV™ Sequential Formation Tester IV Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-41 SFTT™ Sequential Formation Test Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-42 RSCT™ Rotary Sidewall Coring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-43 SWC™ Side Wall Coring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-45 HRSCT™ Hostile Rotary Side Wall Coring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 Hydraulic Valve Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 Motor Drive Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 Mandrel Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 Hostile—Slimhole Formation Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-47 HEAT™ Hostile Environment Applications Tool Suite . . . . . . . . . . . . . . . . . . . . . . . .3-47 HEDL™ Hostile Environment Dual Laterolog Tool . . . . . . . . . . . . . . . . . . . . . . . .3-48 HFWS™ Hostile Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-49 HSDL™ Hostile Spectral Density Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-51 HDSN™ Hostile Dual-Spaced Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-53

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HNGR™ Hostile Natural Gamma Ray Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-55 HSFT™ Hostile Sequential Formation Tester Tool. . . . . . . . . . . . . . . . . . . . . . . . .3-56 Auxiliary Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-57 Multi-Conductor LockJar®* System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-57 Borehole Conditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-58 RWCH™ Releaseable Wireline Cable Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-59 Toolpusher™ Logging (TPL) Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-60 CTL™ Coiled Tubing Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-62 BHPT™ Borehole Properties Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-63 FIAC™ Four Independent Arm Caliper Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-65 SDDT™ Stand-Alone DITS™ Directional Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-67

Cased-Hole Wireline Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-1 Formation Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-1 TMD-L™ Thermal Multigate Decay-Lithology Logging Tool. . . . . . . . . . . . . . . . . . . .4-1 RMT Elite™ Reservoir Monitor Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-3 Spectra Flow™ Logging Service (SpFl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-5 DSN™ Dual-Spaced Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-7 FCMT™ Formation Compaction Monitoring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-9 CASE™ Casing Evaluation and Inspection Software . . . . . . . . . . . . . . . . . . . . . . . . . .4-10 Through Casing Acoustic Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-12 WaveSonic® Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-12 FWS™ Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-14 HFWS™ Hostile Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-16 Production Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 Production Logging Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 Memory Production Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 Electric Line Production Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 FloImager® Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-21 GHT™ Gas Holdup Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-23 MPL™ Memory Production Logging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-24 Quartz Pressure Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-27 Casing and Tubing Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-28 MAC™ Multi-Arm Caliper Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-28 CAST-V™ Circumferential Acoustic Scanning Tool-Visualization. . . . . . . . . . . . . . .4-29 The FASTCAST™ Fast Circumferential Acoustic Scanning Tool . . . . . . . . . . . . . . . .4-31 Cement Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-33 Cement Bond Log (CBL) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-33 Radial Cement Bond Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-35 ACE™ Advanced Cement Evaluation Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-37 Mechanical Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-39 Pipe Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-39 Chemical Cutter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-39 Tubing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-42 *LockJar is a registered trademark of Evans Engineering, Inc.

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Super Tubing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-44 Coiled Tubing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-46 Casing and Drillpipe Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-48 C-4 Casing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-50 Drill Collar Severing Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-51 Junk Shot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-53 Plug Setting Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-54 EZ Drill® Bridge Plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-54 Fas Drill® Bridge Plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-55

Perforating Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-1 Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-1 MaxForce™ Shaped Charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-1 Dominator® Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-2 Mirage® Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-3 Maxim™ Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-5 KISS™ Low-Damage Perforating Charge. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-6 Gun Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-10 VannGun® Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-10 1 9/16 in. to 7 in. and 4 SPF to 21 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-10 VannGun Phasing and Shot Patterns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-11 0° Phasing 4 and 5 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-11 60° Phasing 4, 5, and 6 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-11 90° Phasing 4 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-12 180° Phasing 4 and 8 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-12 60° Phasing 6 SPF Two Planes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-13 45°/135° Phasing 5, 6, 8, 12, and 18 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-13 140°/160° Phasing 11 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-14 51.4°/154.3° Phasing 12 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-14 30°/150° Phasing 12 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-14 25.7°/128.5° Phasing 14 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-15 60°/120° Phasing 18 and 21 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-15 138° Phasing 14 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-15 Tensile Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-16 1 9/16-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-16 2-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-17 2 1/2-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-18 2 3/4-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-19 2 7/8-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-20 3 3/8-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-21 4-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-23 4 1/2-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-24 4 5/8-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-25 4 3/4-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-28 5-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-29

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5 1/8-in. Premium VannGun® Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-31 5 3/4-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-33 6-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-33 6 1/2-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-34 6 1/2-in. High-Pressure Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . .5-35 7-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-36 Capsule Gun Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-41 Dyna-Star® Capsule Gun . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-41 Deep Star™ Capsule Gun . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-42 1.6875-in. and 2.125-in. Deep Star Debris Fill Data . . . . . . . . . . . . . . . . . . . . . . . .5-43 Ported Gun Perforating System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-44 Firing Heads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-45 Detonation Interruption Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-45 Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-46 Model II-D Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-47 Model III-D Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-48 Pressure-Actuated Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-49 Model K and K-II Firing Heads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-50 Model KV-II Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-51 Time-Delay Firer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-52 Multiaction-Delay Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-53 Annulus Pressure Firer-Control Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-54 Annulus Pressure Transfer Reservoir. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-55 Slimhole Annulus Pressure Firer—Internal Control . . . . . . . . . . . . . . . . . . . . . . . . . . .5-56 5-in. Annulus Pressure Transfer Reservoir . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-56 3 1/8-in. Internal Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-56 3 1/8-in. Annulus Pressure Transfer Reservoir—Internal Control . . . . . . . . . . . . . . . .5-56 Differential Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-57 Hydraulic Actuator Firing Head and Swivel-Type Hydraulic Actuator Firing Head. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-58 Mechanical Metering Hydraulic-Delay Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . .5-59 Slickline-Retrievable Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-60 Slickline-Retrievable Time-Delay Firer Firing Head. . . . . . . . . . . . . . . . . . . . . . . . . . .5-62 Extended Delay Fuses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-63 Modular Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-64 Side-Pocket Mandrel Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-66 Annulus Pressure Crossover Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-67 EZ Cycle™ Multi-Pressure Cycle Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-68 Pump-Through Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-70 Ancillary Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-71 Fill Disk Assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-71 Balanced Isolation Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-72 Ratchet Gun Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-74 AutoLatch™ Release Gun Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-75

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Isolation Sub-Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-76 Quick Torque™ Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-77 Detach™ Separating Gun Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-79 Rathole Length Restriction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-79 Rigless Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-79 EZ Pass™ Gun Hanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-80 Automatic-Release Gun Hanger—Rotational Set . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-82 Automatic-Release Gun Hanger—Automatic-J Mandrel . . . . . . . . . . . . . . . . . . . . . . .5-84 Explosive Transfer Swivel Sub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-86 Shearable Safety Sub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-87 Roller Tandem Assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-88 Centralizer Tandem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-89 Emergency Release Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-90 Annular Pressure-Control Line Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-91 Annular Pressure-Control Line Swivel Sub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-92 Annular Pressure-Control Line Tubing Release . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-93 Bar Pressure Vent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-94 Below-Packer Vent Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-95 Maximum Differential Bar Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-96 Pressure-Operated Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-97 Vann™ Circulating Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-98 Automatic Release . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-99 Mechanical Tubing Release . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-101 Pressure-Actuated Tubing Release. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-103 DPU® Downhole Power Unit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-104 SmartETD® Advanced Electronic Triggering Device . . . . . . . . . . . . . . . . . . . . . . . . .5-105 Y-Block Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-106 Non-Ported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-106 Ported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-106 Gun Guides. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-107 Hydraulic Metering Release Tool for the Single Trip System (STPP™-GH) Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-108 Fast Gauge Recorder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-110 Gamma Perforator Logging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-112 Detonators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-113 Capsule RED® Detonators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-113 RED GO™-Style Thermal Igniter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-114 Block RED Detonators. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-115 Top Fire RED Detonators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-116 Dynamic Modeling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-117 PerfPro® Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-117 PerfPro Process–Predicting In-Situ Charge Performance . . . . . . . . . . . . . . . . . . .5-117 Near-Wellbore Stimulation and PulsFrac™ Software . . . . . . . . . . . . . . . . . . . . . . . . .5-120 EOB - Energized Fluid Stimulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-120

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Propellant Stimulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-121 ShockProSM Shockload Evaluation Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-125 Near-Wellbore Stimulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-127 StimGun™* Assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-127 Propellent Stimulation Tool Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-130 POWR*PERFSM Perforation/Stimulation Process . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-132 PerfStim™ Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-133 Oriented Perforating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-134 G-Force® Precision Oriented Perforating System . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-134 Oriented Perforating with Modular Guns. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-136 Finned Orienting Tandem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-137 Eccentric Orienting Tandem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-138 Special Applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-139 Modular Gun System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-139 The Modular Gun System Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-140 Rathole Length Restriction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-140 Rigless Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-140 Select Fire™ Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-141 Coiled Tubing Conveyed Perforating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-142 DrillGun™ Perforating Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-143 Setting Tools for the Auto-Release Gun Hanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-145 Running and Retrieving Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-145

Downhole Video . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-1 Downhole Video Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-1 Hawkeye™ Camera System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-2 Fiber-Optic Camera System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-3 EyeDeal™ Camera System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-4

Slickline Service Equipment and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-1 Subsurface Service Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-2 Slickline Service Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-2 Slickline Toolstring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-2 Otis® Accelerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-3 Slickline Detent Jars. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-4 Otis Quick Connect Toolstring Connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-5 Auxiliary Tools For Use with Slickline Toolstring . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 Otis Gauge Cutter and Swaging Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 Otis Impression Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 Otis Tubing Broach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 Otis M Magnetic Fishing Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 Otis G Fishing Socket . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 Otis P Wireline Grab . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 *StimGun is a trademark of Marathon Oil Company.

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Otis® Go-Devil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 Expandable Wirefinder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 Otis X® and R® Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 Otis RXN Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 Otis UP Running Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 Otis MR Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 Pulling Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-9 Internal Fishing Necks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-9 External Fishing Necks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-9 Test Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-11 Otis Non-Selective Test Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-11 Positioning Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-12 Tubing Perforators and Bailers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-13 Slickline Skid Units and Trucks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-14 Surface Service Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-15 Advanced® Slickline Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-16 Advanced Slickline Service System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-18 DPU® Tubing Punch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-22 CollarTrak® Slickline Collar Locator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-23 Advanced Measurement System (AMS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-25 Electronic Advanced Measurement System (Portable) . . . . . . . . . . . . . . . . . . . . . . . . .7-26 SmartETD® System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-27 JobTrak® Data Job Logger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-28 Standard Mounted Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-28 Memory Production Logging (MPL) Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-29 LineTrak® Slickline Inspection Device and Wire Management Program . . . . . . . . . . .7-31 Wire Management Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-31 Deepwater Riserless Subsea Light Well Intervention System . . . . . . . . . . . . . . . . . . . .7-33

Mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-1 LOGIQ™ Logging Truck . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-1 LOGIQ Modular Skid Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-3 Cabin Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-4 Winch Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-5 Power Pack. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-6

Mnemonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9-1 Wireline and Perforating Services Mnemonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9-2 Log Header Mnemonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9-44

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Real-Time Operations Real-Time Data/Solution Delivery Various methods are used to deliver data in real time from wellsites to offsite locations. The three main methods are: • InSite Anywhere® service • Collaborative formation evaluation and reservoir monitoring • Real-time monitor and control (RTMC)

Features • Scalable, from simple operations to the most sophisticated • Halliburton expertise available • Provides instant access and support from non-wellsite locations • Personnel can participate in multiple operations • Expand personnel capabilities

InSite Anywhere® service moves data from the logging tools onto a secured website, where it can be viewed in real time as it is acquired. InSite Anywhere service is also a drop box for data files and viewing DHV images in real time. With collaborative formation evaluation and reservoir monitoring, it is possible to deliver data to environments where experts can discuss any issues dealing with geology, operations, or the reservoir, thereby influencing the ongoing services at the wellsite immediately. Real-time monitor and control (RTMC) is an internal tool that provides both operational and technical support along with ability to control remote wellsite locations.

Knowledge and Data Transfer

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HalLink® Satellite Systems Three systems are available: land (tripod), skid (compensating), and vessel (permanent). HalLink® systems allow transmission of data and video at high speeds through a secure network supporting all Halliburton real-time operations. With “last mile” connectivity to the location, real-time support and decisions can be made more easily. Features • Fully scalable to client needs, simple point-to-point network through full mesh (point-to-many) • Deployment can be expanded per client needs • System is flexible, which enables the system to be part of the Halliburton or client network • Two phone lines for operational support • Improved reliability for wellsite connectivity • Bandwidth scalable to local/client needs Services Enabled by HalLink Systems • Immediate data transfer for: – QuikLook® reservoir fluid management services – Applied formation evaluation processing • InSite Anywhere® service – Downhole video – MRILab® downhole measurement service – RDT™ reservoir description tool – Standard logging suite • Collaborative formation evaluation and reservoir monitoring • Real-time monitor and control • Video conferencing

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Connectivity Anywhere


InSite Anywhere® Service InSite Anywhere® service is a next-generation, web-based data delivery system that gives you the flexibility of the industry’s most robust database structure—without the need to install special software. Using our advanced satellite communications technology or any other network, InSite Anywhere service moves data from the logging tools onto a secured web site, where you can view it in real time as it is acquired.

Requirements for Service • Internet or intranet access • Uses standard web browsers • User name, password, and URL • Uses the security protections of the HalLink® commuciations network or any other secure network

When an unplanned event arises, the InSite Anywhere web delivery system provides needed facts to command the situation. Whatever solution directed will be based on complete up-to-the-minute information. The system allows you to participate in multiple wellsite operations from one location. With all the travel time saved, capabilities are stretched further—and make the most of company resources.

Features • View and print logging and tester data in real time from any PC • Access offset well data from nearby wells • Download logging data, answer products, and more • Configure display to individual preference by manipulating logging or test data • View and print numerous display types: – Log plots – Pressure tests and samples – Streaming downhole video (view only or save/ print to screen capture) – Cross-plots – MRILab® service results (view only or save/print as screen capture) – Efficient gauges, LEDs, and other indicators • Expand personnel capabilities • Speed decision-making • Participate in multiple operations • Optimize logging passes • Deploy expertise and resources more efficiently • Save travel expenses • Avoid travel risk • No special hardware or software required


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Reservoir Evaluation Services

Reservoir Evaluation Services Petrophysics MRI Petrophysics MRIL® Simultaneous T1 and T2 Measurements Both the MRIL-XL™ and MRIL®-Prime tools acquire NMR data in several modes of operation. Simultaneous T1 and T2 log acquisition is a robust technique to acquire NMR reservoir information faster and simpler. T1 has made its wireline debut to join MRIL-WD™ (MRI while drilling) and MRILab® service (MRI fluid analysis during wireline formation sampling). In both the MRIL-WD and MRILab applications, the preference of T1 over T2 has been its insensitivity to motion as T1 measurements eliminate the detrimental effects from tool motion or fluid flow. Simultaneous T1 and T2 wireline acquisition is now done in a single log pass. Micro-porosity, capillary bound water, free fluid index, effective porosity, and total NMR porosity acquired during T1 logging may be used in MRIAN™ analysis as described on page 2-2. T1 logging offers a simplified NMR measurement composed of only two of the three decay mechanisms associated with NMR. Only surface and bulk relaxation mechanisms contribute to the T1 response. There is no diffusion effect in T1 data, so many fluid identification applications are simplified as in tight gas identification in water-based mud systems. For simple and faster NMR reservoir information, T1 offers a reliable alternative to T2. Features • Robust reservoir quality measurements of NMR • Total and effective porosity and bound fluid volumes

This T1 MRIAN™ analysis example depicts the long T1 gas signal in the upper zone, green waveforms on far right in Track 4. The free water T1 values are much shorter as can be seen in Track 4 in the lower zone.

• Light hydrocarbon identification • Faster logging speeds • Simplified NMR interpretation (no diffusion effects) • Simultaneous T1 and T2 acquisition (single log pass) • Real-time permeability calculations


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MRIAN™ Magnetic Resonance Imaging Analysis MRIAN™ analysis is a technique that combines MRIL® and conventional data to identify potential hydrocarbon zones. MRIAN analysis uses the dual-water model technique to estimate the volume of formation fluids in a virgin zone. Using the dual-water model within the MRIAN program allows identification of free water volume. When the computed effective volume of water equals the MRIL data irreducible volume of water, then production is water free. Both T1 and T2 distributions and permeability calculations are provided to indicate reservoir quality. MRIL stand-alone analyses, such as time domain analysis (TDA), diffusion analysis (DIFAN), and Enhanced Diffusion Method™ (EDM™) technique provide hydrocarbon typing interpretation within the depth of investigation of the MRIL measurements. When MRIL data is combined with other logs, analysis can furnish even more information about the reservoir. MRIAN analysis is one of the interpretation models that use this data combination. Features MRIAN analysis combines MRIL analysis and deepresistivity data from any induction tool. MRIL data is used to provide two important parameters needed in the dual-water model: the clay-bound water porosity (MCBW) and total porosity (MPHIT).

• Provides enhanced permeability calculations • Indicates zones of potential water production • Identifies hydrocarbon-water contacts • Calculates water saturation in the uninvaded zone • Provides a solution for low-resistivity pay reservoirs

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Additional features include the following:

This MRIAN™ analysis indicates an oil/water contact at X940. The MRI T2 distribution in Track 3 demonstrates a change in relaxation times verifying the MRIAN analysis.

• Confirms dual-water Rw by reconstructing spontaneous potential (SP) • Uses a robust implementation of the dual-water resistivity model to provide improved water saturation (Sw) calculations, especially in shaly reservoirs

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This MRIAN™ analysis example demonstrates the effectiveness of this model to identify oil/water contact as well as zones of potential water production (Track 4). Enhanced permeability calculations are presented in Track 2 (red curve).

Inputs Outputs

MRIL® porosity data. The main data requirements for MRIAN™ processing are true formation resistivity (Rt), total porosity (φt), and clay-bound-water saturation (Swb). Density, neutron, and/or sonic porosity are optional inputs. MRIL activation planning is critical for successful interpretation. Permeability, effective porosity, total porosity, water saturation, free water volume, irreducible water volume


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Time Domain Analysis (TDA) MRIL® data can be analyzed independently or in combination with conventional logs. When MRIL data is processed independently, it can provide formation porosity and permeability information as well as complete information on fluid types and fluid saturation within the depth of investigation of the MRIL tool. Time domain analysis (TDA) is an interpretation technique that utilizes only MRIL data.

• Estimates free fluid volume and type in thinly laminated reservoirs • Indicates the best possible producing zones in carbonate formation

Time domain analysis operates on the principle that different fluids have different rates of polarization or different T1 relaxation times. The T1 of both gas and light oil (viscosity less than 5 cp) is normally much higher than that of water. TDA is very effective in evaluating gas and light oil reservoirs. TDA is very different from other techniques available because it uses only MRIL data in the interpretation process; no conventional data is needed in the processing. Features TDA analysis provides an alternative to the differential spectrum method for processing dual-Tw echo trains data. Interpretation is performed in the time domain rather than in the T2 spectra domain. Key features of TDA analysis include: • Subtraction of the two echo trains from one another • Processing echo differences in the time domain using predicted or measured oil, gas, and water relaxation times and hydrogen-index values Additional TDA features include the following:

• Allows complete fluid volume analysis within the depth of investigation of the MRIL tool using only MRIL tool data • Provides hydrocarbon typing • Recognizes direct pay

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• Provides accurate formation porosity in gas and light oil reservoirs

This MRIAN™ analysis example demonstrates the effectiveness of this model to identify oil/water contact as well as zones of potential water production (Track 4). Enhanced permeability calculations are presented in Track 2 (red curve).

• Improves permeability calculations in light hydrocarbon environment • Clearly identifies pay zones vs. tight zones

Inputs Outputs

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MRIL® data only from dual-wait time acquisition which can be acquired using MRIL-XL™, MRIL® -Prime and/or MRIL-WD™ tools Volumetric calculation of gas, oil, and water; formation total and effective porosity; permeability estimation


Diffusion Analysis (DIFAN) Diffusion analysis (DIFAN) is a stand-alone NMR technique for quantitative diffusion analysis of intermediate oil viscosity range of 2 to 30 cp and has been applied successfully in many fields. DIFAN was developed specifically for situations where TDA cannot be applied because of insufficient T1 contrast. Variations in molecular diffusion will manifest themselves as variations in the observed T2 distributions. These can be used to quantify water-filled and oil-filled porosity, respectively. Features Diffusion analysis is an interpretation technique utilizing dual-TE measurements. DIFAN relies on the diffusion contrast between water and medium viscosity oil to quantify oil volume within the depth of investigation of the tool. The data for DIFAN is acquired through single-TW (wait time), dual-TE (echo spacing) logging. Other features of diffusion analysis include: • Calculates hydrocarbon and water saturation in freshwater environments • Stand-alone analysis does not need resistivity logs • Works in low to moderate viscosity oils (typically 2 to 30 cp at reservoir conditions)

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• Works in areas of unknown or variable Rw

This log contains results from the application DIFAN to MRIL® data from an Indonesian well. Track 1 includes conventional gamma ray, spontaneous potential, and caliper curves. Track 2 presents deep, medium, and shallow resistivity data and MRIL permeability. Track 3 contains the long-TE T2 distribution. Track 4 contains the short-TE T2 distribution. Track 5 displays answer products from DIFAN calculations.

Inputs Outputs

MRIL® data (dual-TE activation) from MRIL-XL™ or MRIL®-Prime tools Porosity, Sw, diffusion ratios, permeability, watercut (if relative permeabilities are known)


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Enhanced Diffusion Method™ (EDM™) Technique Enhanced Diffusion Method™ (EDM™) NMR technique utilizes the contrast in molecular diffusion between water and oil to identify and potentially quantify oil accumulations. The diffusion properties of water, combined with tool parameters (TE, magnetic field gradient) and the temperature of the logging environment, define the slowest relaxation time possible for water to be observed: T2DW. Consequently, any NMR signal observed beyond this value can only be associated with oil. This offers a simple way to interpret the presence of oil and to differentiate pay from non-pay zones. The EDM technique can also be used to quantify residual oil. The advantage it has over conventional techniques such as pressure-coring and/or sponge-coring is that oil is measured at in-situ conditions. Hence, gas expansion or fluid expulsion need not be taken into account. As with any residual oil determination technique, controlling fluid loss from the mud system to the formation is critical to the overall success of the EDM technique.

For typing medium-viscosity oils with this method, standard CPMG T2 data recorded with a long TE is sufficient. Quantitative application of the EDM technique requires either dual-TW data recorded with a long TE, or dual-TE data recorded with a long TW. Additional features include: • Independent confirmation of oil-bearing zones and identification of oil/water contacts • Stand-alone determination of (residual) oil saturation with no need to dope drilling fluids • Sensitive to oil in the viscosity range from 1 cp to 50 cp • Works in areas of unknown or variable Rw

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Features EDM interpretation methodology is based on the contrasts in molecular diffusion between different fluids. Enhancement of the diffusion effect, by increasing the interecho spacing TE during data acquisition, separates water and oil in the T2 domain.

Enhanced Diffusion Method™ technique can differentiate pay from non-pay zones. Track 5 indicates an oil/water contact near the bottom and the oil column continues to the top of the zone. This finding is supported by the resistivity curves in Track 2.

Inputs Outputs

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MRIL® data (dual-TE activation) from MRIL-XL™, MRIL®-Prime, or MRIL-WD™ tools Residual oil saturation, porosity, permeability, viscosity, flushed zone Sw


Heavy Oil MRIANSM Service The heavy oil MRIANSM service improves reservoir evaluation in areas where oil viscosity exceeds 100 cp at formation conditions, and the oil gravity is less than 20° API. The heavy oil MRIAN service combines dual-echo spacing MRIL® logs with conventional porosity and resistivity logs to provide improved: • Determination of bulk volume irreducible (BVI)

• Aid improved water saturation evaluation • Indication of moved hydrocarbons in the near-wellbore region • Determination of in-situ oil viscosity from MRIL signalloss in heavy oil-bearing formations • Indication of formation wettability conditions

• Measurement of movable water • Quantification of viscous oil reserves • Estimation of permeability in water-wet reservoirs By themselves, NMR responses to viscous oils are not readily distinguishable from those of capillary-bound and claybound water. The heavy oil model is able to differentiate these fluids by using MRIL® data to quantify movable water in the formation. This volume, when subtracted from the effective water volume derived from conventional logs, gives the irreducible water volume. In addition, this comparison is useful for recognizing mixed or oil-wet reservoir conditions, which can often occur in viscous-oil reservoirs. Good candidates for application of the heavy oil MRIAN service are heavy oil producing areas in Venezuela, Canada, Alaska, Russia, and smaller heavy oil provinces throughout the world. This service has been successfully applied in both sandstone and carbonate reservoirs. Features • An integrated NMR and conventional log heavy oil interpretation model • Movable water determination in heavy oil-bearing formations using the Enhanced Diffusion Method™ (EDM)

• Improved BVI determination compared to traditional interpretation of NMR measurements in heavy-oil reservoirs • Can provide a complete analysis of pore fluids, including clay-bound and capillary-bound pore fluids, movable water volume, and hydrocarbon volumes • Direct measurement of movable water Inputs Outputs

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• Comparison of NMR and conventional porosity responses to estimate in-situ oil viscosity

The log above shows results from a heavy oil MRIAN™ analysis of data collected from an area of the United Kingdom continental shelf. These results show the reservoir is mostly water-wet through the transition zone. The absence of capillary bound water above the transition zone indicates an oil-wet condition.

MRIL® data acquired with dual-TE and conventional data Corrected BVI, clay porosity, total porosity, improved permeability estimates, effective porosity, water saturations, viscosity


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StiMRIL™ Process The StiMRIL™ process is an integrated stimulation process built upon a reservoir performance model created from a combination of MRIL® magnetic resonance imaging logging analyses and reservoir simulations. This model allows the stimulation design engineer to develop optimum completion/stimulation plans and accurately predict the outcome of production enhancement efforts. Identification of hydrocarbon type and accurate determinations of porosity, free fluid, and bound fluid volumes from MRIL logging measurements provide operators with answers to critical questions by providing: • The location of oil, gas, or water in the zone • The potential for water production • The net present value (NPV) of the zone The rate at which the well will produce oil, gas, or water can then be predicted by carrying this information forward in the reservoir simulation step of the StiMRIL process.

Features The reservoir modeling capabilities included in the StiMRIL process use the results of the MRIL analysis to provide a relatively complete representation of the reservoir's production characteristics. An integrated stimulation design process allows operators to accurately predict reservoir performance and to optimize their financial investment based on the economics of the fracturing treatment for the reservoir. For example, in a tight-gas sand (low permeability formation), the completion design usually centers around a hydraulic treatment. Other features include:

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The MRIL® tool is used to perform high-quality measurements and collect the data required to make a thorough reservoir evaluation in a single logging pass. In addition to saving rig time, the resulting calculations of permeability, water saturation, and effective porosity are better than those derived from other lithology-dependent methods.

Here is an example of a layered sandstone reservoir which indicates a high clay, low porosity interval in the lower section of the well, cleaner zones with higher movable hydrocarbons in the middle, and an extremely high perm zone in the top, which contains a large amount of oil.

• Increased focus on the reservoir through the integration of well logging, reservoir performance, and stimulation design • Logging data and reservoir simulations used in combination to increase reservoir understanding • Built-in stimulation design capabilities to help operators develop the best completion strategies

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MRIL® logging has revolutionized the logging industry through its ability to directly and accurately measure the fluids in the reservoir. This results in the accurate determination of: • Porosity and permeability • Fluid type and viscosity changes • Irreducible water volume and free fluid volume In other words, MRIL logs indicate not only whether there is oil or gas in a zone but also where it is located within the zone. These logs also show how much water is present in the zone, how it is distributed throughout the zone, and whether it is free to move to the wellbore and interfere with

Inputs Outputs

hydrocarbon production. Before the StiMRIL™ process was developed, fracturing designs relied on lithological volumes from quad-combo logging data to provide the information to qualitatively evaluate zones and calculate fracture geometry. With the StiMRIL process, engineers are able to incorporate MRIL logging data into the design to predict productivity results. Quad-combo logs still provide the lithology information, while MRIL logs provide the fluid dynamics information. The result is optimized treatment designs for maximum, predictable well productivity and improved profitability for the operator.

Pore-size distribution, permeability, effective porosity, total porosity, water saturation, gas indicator Initial production rate, time of recovery, porosity, permeability, Young's modulus, Poisson's ratio optimum NPV for the well


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Volumetric Petrophysics Chi Modeling® Computation Service Some open-hole wells have difficult logging conditions that may result in missed zones of open-hole information, or in extreme conditions, even the loss of the entire open-hole logging run. Halliburton now provides Chi Modeling® computation post-processing service will help the user to better evaluate their reservoir when they have missing data due to borehole conditions, missing LWD sections, old wells, etc. Chi Modeling computation service is able to predict triple-combo or even quad-combo open-hole data with a very high degree of accuracy by using the input data obtained from a capture pass of a pulsed neutron tool and a known triple-combo or quad-combo data set from a neighboring well. Under some conditions, missing or incorrect data caused by tool pulls or intermittent sensor failure can be correctly generated using only the triple-combo data. Chi Modeling computation is also able to:

and predict the offset triple-combo or quad-combo data. Normal accuracy results are as follows: • Density ± .034 gm/cc = ±2PU • Neutron ±2PU • Resistivity ± .1 decade

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Chi Modeling computation service uses associations made in one well between an existing open-hole triple-combo and a cased-hole pulsed neutron tool. It does this by looking at data from a reference well and assigning a processing weight to each input variable.

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Validate

If the predicted values do not match the actual value in the reference well adequately, the weights are changed, and the model is re-computed. These associations are then used, along with pulsed neutron data from an offset well, to model a triple-combo or quad-combo response in an offset well. These associations may be confidently used as long as:

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Test

• Fill in data gaps where the original data is missing from either wireline or LWD data • Replace poor quality data that occurred due to poor borehole conditions

• The formation geology remains similar • The formations geology is adequately sampled and represented in the reference well When the formation geology from the reference well changes, a new set of open-hole data is required to create a new set of associations. This method retains the variability of the original data and does not over predict mean statistical values.

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• Generate reliable open-hole logs when none are available

Figure 1 indicates that Chi Modeling™ software uses training data from the reference well in conjunction with weights for each input variable to generate predictions. The weights are then applied to the entire reference well to generate predictions. The values obtained are validated and tested against the original open-hole data. If they do not match, new weights are used until a match is obtained.

A root mean square (RMS) statistical analysis is performed on each curve generated in the base well to confirm the reliability of the data associations that will be used to project

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Chi

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Figure 2 shows the normal input data going into the Chi Modeling™ software. The weights used for data prediction are refined until a reasonable match is obtained with the open-hole data from the reference well. These relationships are used to predict and construct triple-combo data on offset wells that have only pulsed neutron data available.

Figure 3 shows a comparison between the original neutron/density porosity data (Track 3) and the predicted neutron/ density porosity data for a reference well (Track 4) as well as the original (black) and predicted (red) 90-in. resistivity data (Track 2). Track 1 is the open-hole gamma ray.


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ULTRA™ Module Suite ULTRA™ products are a suite of interactive and noninteractive modules which process well log data to make comprehensive formation evaluation computations determining mineral volumes and fluid saturations. The ULTRA tool uses a weighted least-squares error optimization technique to determine fractional lithology constituents (clay, sandstone, limestone, and other minerals) and the percent of saturation of individual fluid components which occupy total pore space.

LOGQUAL calculates the uncertainty or quality of each log using all levels. These log uncertainties are used as weighting factors in the minimization process in CORINV, ULFE, and AUTOMOD. The log curve names in the CLS file must be properly mapped into generic curve names used in the ULTRA suite via the group NAMLOG under JOBVAR. LOGQUAL must be run prior to any quantitative evaluation done under the routines CORINV, ULFE, and AUTOMOD. DATRED is used to square or block the logs. It provides nine different levels of squaring, ranging from coarse to fine, any of which may be selected during interactive processing to reduce the processing time. This routine must be run before CORINV, ULFE, or AUTOMOD. CORINV is designed to compute Rt, Rxo, and Di using any combination of resistivity logs. It has distinct advantages over the chart book approach when more than three resistivity logs are available and one or more logs in the suite have different degrees of reliability. The technique is based on a constrained weighted least squares error optimization using the inverse approach, wherein maximum likelihood values of Rt, Rxo, and Di are computed. Graphical comparisons of theoretical and measured log curves are used to determine the reliability of measurements. An interactive part of CORINV allows the log analyst to test hypotheses and to try various options to use weight multipliers and constraints. When the analyst is satisfied with the results, noninteractive option is used during which all data points in the zone selected are processed and computed results are written into the CLS file.

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PREPARE is a query-based module that leads the user through the basic parameter entries necessary for later use in other modules of ULTRA data. It is obligatory to use either PREPARE or JOBVAR before proceeding with the processing of modules in the ULTRA suite.

This ULTRA™ log presents a light hydrocarbon indicator and water saturation in Track 1; volumes of residual hydrocarbons, movable hydrocarbons, and water in Track 2; and lithology analysis in Track 3.

ULFE is used to perform log analysis involving the evaluation of constituent volume fractions of the rock and estimation of fluid saturations in the pore. A weighted least squares error optimization technique, using the inverse approach is employed. The analyst inputs the lithology, selects the response equations, enters the clay and mineral parameters, and geological constraints, etc. via the alpha-numeric edit screen. The data is then processed to obtain the statistically most probable results. The output is presented as graphical display of computed results, including formation bulk volume analysis and pore volume analysis, and a display of measured logs overlain by the theoretical or reconstructed logs. Theoretical logs are obtained by back computing the log values from the computed results. The degree of fit between the two sets of logs is a measure of the validity of the assumptions implicit in the model used.


Output can also be presented as a statistical display on an alphanumeric screen. The arithmetic average and the variance of the difference between each of the measured and theoretical logs over the zone processed is individually displayed. Also the total error, which represents the summation of the errors for each of the constituent logs over the zone, is displayed. If the fit between the measured and the theoretical logs is poor, the analyst can modify the lithology, vary the clay and mineral parameters and try out the different response equations until a satisfactory fit is obtained, and results correspond to geological expectations. Results are computed and displayed on the screen but are not written to the disk in the interactive ULFE. Non-interactive processing is the next step where all data points are processed, and all computed results are written to the disk. The AUTOMOD primary objective is to provide optimized values for parameters or constants. In addition to the weighted least squares error optimization in ULFE for computing the variables like Sw, Vcl, Phi etc., the AUTOMOD routine also performs a zone wide optimization on a set of constants or parameters to provide optimized values for the constants. The constants that can be optimized include all parameters associated with sand, lime, dolomite, minerals 1 through 9, clay, formation water resistivity, hydrocarbon density, cementation factor, and saturation exponent. The parameters to be optimized are set to the variable status. The log analyst furnishes an initial value and minimum and maximum values within which parameters are to be optimized. Computations are then made over the entire interval selected for analysis using various values of the parameters to be optimized. The incoherence between the measured logs and the logs reconstructed from computed variables is then analyzed. The parameters' values that yield Inputs Outputs

the least incoherence between the measured and reconstructed logs over the interval selected for analysis are considered to be the optimized values of the parameters. AUTOMOD is the automatic modeling to optimize unknown parameters—an especially useful feature in exploration wells where data is scarce. Features • Provides the analyst with statistically optimum computations of: – Porosity – Water saturation – Multi-mineral volumes – Hydrocarbon density • Uses all available log data simultaneously – Provides powerful quality control features – Cross-checks final interpretation results – Validates tool calibration and performance – Validates interpretive model and zone constants • Interactive testing and refinement of interpretation parameters and models • Allows combination of core analysis information with log measurements to help ensure accurate results • Allows the analyst to use zoned constants and interpretive model selection in multiple wells to facilitate field study applications

Minimum: at least one porosity measurement, resistivity, and GR or SP for shale volume ideal: all minimum inputs, plus caliper, Rxo-resistivity device, additional porosity sensors, MRIL®, Spectral GR, and Sonic Sw, Sxo, Vsh, φeff, lithology, hydrocarbon weight, permeability, plus volumetric percent of selected minerals


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SASHA™ Shaly Sand Analysis SASHA™ analysis provides volumetric evaluation of gas, oil, and water in shaly sands and uses traditional density/neutron crossplot as the basis of its volumetric analysis. A variety of water saturation and permeability models are available to optimize the petrophysical analysis to the reservoir.

Features • Robust, traditional cross-plot approach • Multiple saturation and permeability models • Calculation of hydrocarbon density • Summary table of each pay interval

The oil and gas company can use conventional wireline or LWD log data to evaluate potential hydrocarbon production from predominately shaly/sand depositional environments by using the results of this analysis. SASHA analysis produces a summary of the lithology in terms of percent volume shale, sandstone silt, dispersed clay, coal, and salt. It includes logic for detection and correction for salt, rugosity, and gas. It also computes water saturation (Sw), lithology, effective porosity (φeff ), hydrocarbon density, and relative permeabilities in shaly/sand reservoirs.

SASHA analysis can also produce a summary table of net pay, porosity feet, and hydrocarbon feet for each potential zone of interest. Environmental corrections for the resistivity and porosity devices should be done prior to running SASHA analysis.

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A number of different water saturation models may be chosen. Input from the client as to previous analysis or model preferences could avoid unnecessary guessing.

Example SASHA™ analysis showing (l-r) shale/sand volumetric analysis; hydrocarbon weight analysis with oil (red) and gas (pink) volumes and pay flag (black); saturation analysis; relative permeability analysis

Applications • Formation lithology analysis • Porosity, saturation, and hydrocarbon flags • Overview of potential pay zones over the well

Inputs Outputs

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Minimum: at least one porosity measurement, resistivity, and GR or SP for shale volume Ideal: All minimum inputs, plus caliper, additional porosity, Spectral GR, and Sonic Sw, Sxo, Vsh, φeff, lithology, hydrocarbon weight, permeability


CORAL™ Complex Lithology Analysis CORAL™ complex lithology analysis helps evaluate the potential production from complex or mixed lithology reservoirs using wireline or LWD log data. CORAL analysis computes water saturation (Sw), lithology, effective porosity (φeff ) and relative permeabilities in carbonates and complex lithology reservoirs. CORAL analysis produces an analysis of the lithology in terms of percent volume shale, limestone, dolomite, sandstone, coal, and salt. It includes logic for detection and correction for salt, rugosity, and gas. CORAL analysis uses a traditional crossplot-based formation evaluation approach to determine shale volume, effective porosity, and water saturation. CORAL analysis also estimates relative permeabilities from several different models. A number of different water saturation models may be chosen. Input from the client as to previous analysis or model preferences could avoid unnecessary guessing.

Environmental corrections for the resistivity and porosity devices should be done prior to running CORAL analysis.

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CORAL analysis also can produce a summary table of net pay, porosity feet, and hydrocarbon-feet for each potential zone of interest.

Example of CORAL™ log analysis in late Pennsylvanian carbonates and sands.

Applications • Formation lithology analysis • Porosity, saturation, and gas flags • Pay zone evaluation summary • Overview of potential pay zones over the well Features • Robust, traditional crossplot-based approach • Flexibility for almost all lithology mixtures • Multiple saturation and permeability models • Summary table of each pay interval

Inputs Outputs

Minimum: Neutron, Density, Resistivity, and GR or SP. Ideal: All minimum inputs, plus Caliper, Spectral GR, Sonic, and Pe. Sw, Sxo, Vsh, φeff, Lithology volume percent, permeability


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LARA™ Laminated Reservoir Analysis Many highly-laminated reservoirs have been missed in existing wells due to the coarse vertical resolution of older logging tools and the inadequate analysis techniques of traditional interpretation programs. To better detect and study thin-bed reservoirs, it has been necessary to develop new logging tools, post-processing techniques, and data analysis methods. High-resolution shale indicators allow separation of the sand and shale components but still require thin bed resolution of true formation resistivity and porosity. The measurements produced by high resolution shale indicators are used with those from conventional or resolution-enhanced porosity logging tools to improve the saturation analysis of the laminated reservoir. This is the basis of LARA™ laminated reservoir analysis.

Features • High-resolution shale indicator generally yields significantly more accurate analysis in laminated reservoirs than standard shaly sand models • Helps with the reliable quantitative interpretation of thinly laminated reservoirs • Helps identify potential hydrocarbon production often missed by conventional analysis

The high-resolution shale volumes are then used with the known shale resistivity to generate high resolution resistivity expressions that involve shale and non-shale volumes and resistivities. These expressions are integrated to the vertical resolution of the resistivity device. The integrated resistivity is equated to the measured resistivity, and the resulting equation solved to give the non-shale resistivity, which is essentially a shale-corrected true formation resistivity (Rt). Finally, the calculated effective porosity and true formation resistivity are used in a modified Waxman-Smits equation to calculate Sw.

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To determine shale volume, the high-resolution shale device data is first integrated to the vertical resolution of the porosity device. Then two medium-resolution shale volumes are calculated—one from the integrated high-resolution data and one from the porosity data. Device-specific shale parameters are automatically adjusted until the two volumes are equal. Then LARA analysis calculates the conventional total and effective porosities. It also determines the mode of clay distribution, i.e., dispersed or laminated.

Thinly laminated hydrocarbon bearing zones above the main clean sand pay zones would have been overlooked with conventional log analysis. In this case, high resolution data from the EMI™ image tool was integrated into the LARA™ analysis. Note the gas effect density-neutron crossover in the clean sands and lack of crossover in the thinly laminated zone above the clean sand zone.

Applications • Resolving gross shale volume percent to high resolution laminated and dispersed clay content • Detection of thin-bed reservoirs • Improve saturation analysis of the laminated reservoir Inputs

Outputs

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In addition to the minimum of a GR, resistivity and porosity measurement, one or more of the following thin-bed shale indicator inputs is required for LARA™ analysis: SED™, Pe (unfiltered), Microresistivity (ML, MSFL™), CAST™, EMI™, XRMI™, OMRI™, EVR-GR. The best high-resolution shale indicators are six-arm dipmeter or EMI, XRMI, OMRI, but alternatives include all of the above. LARA program requires only a single porosity device but yields better results when more than one is used. Sw, Sxo, VSH, φeff, lithology hydrocarbon weight (oil, gas), permeability


Reservoir Characterization Borehole Image Analysis AutoDip™ and TrendSetter™ Services AutoDip™ and TrendSetter™ services automate dip and dip trend analysis of EMI™, XRMI™, and OMRI™ borehole data. These services save time and provide high-quality data that can help spot “hidden features” in sedimentary beds and laminates. AutoDip service automates high-resolution dip detection—a vast improvement on tedious manual dip picking. Unlike traditional dip computation methods, AutoDip service does not simply correlate raw resistivity data. This method operates independently of often inappropriate correlation parameters, such as correlation length, step length, and search angle. TrendSetter service augments AutoDip functionality by taking dip data and automatically sorting it into categories: • Constant dip with depth • Increasing dip with depth

TrendSetter service helps characterize geologic features based on dip trends. AutoDip and Trendsetter services provide a continuous plot with a break out of dip trends and constant dips. These dips and trends can be easily recognized and incorporated into a geological model.

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• Decreasing dip with depth

Slumping and soft sediment deformation are evident in this section of log. The AutoDip™ program does a good job of capturing the changing dips.

AutoDip and TrendSetter services differentiate themselves by selecting bedding features more quickly and consistently than hand picking. This provides more time to view the results and interpret the data.


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AutoDip™ Service AutoDip™ service uses data from all resistivity buttons—not just 4, 6, or 8—to more accurately determine dips. By using more data, more accurate dip readings are possible. AutoDip service translates the human visual experience of event correlation into an equation that quantifies visual recognition to obtain the optimal dip. The self optimizing algorithmic process¹ operates without the need to adjust correlation parameters, which can introduce bias into dips or even hide dips when using traditional methods. The AutoDip program works equally well in simple bedding or in more complex bedding environments. Applications • High-resolution dip detection of EMI™, XRMI™, and OMRI™ borehole data to help spot “hidden features” in sedimentary beds and laminates Features • Uses all buttons to compute dips

TrendSetter™ Service The AutoDip program can generate many dips. The number of dips is partially determined by dip quality filters. During the analysis process, it is prudent to look for patterns to help recognize trends that can impact mapping, offset wells, and describe depositional environments and structural changes. TrendSetter™ service automatically separates dips into constant, increasing, and decreasing categories, making it easier to visualize changes and trends. TrendSetter service separates the dips from stratigraphic events such as current bedding, slumps, and drapes from the more constant structural dips, which allows better estimates of local structural dip. Applications • Dip trend analysis of EMI, XRMI, and OMRI borehole data to help spot “hidden features” in sedimentary beds and laminates

• Uses quality curves to optimize dip selection

Features • Automates the selection of dip trends

• Removes user bias in selecting dips

• Provides quality curves used to control grade of trend

• Consistent picks independent of interpreter bias

• Removes scatter from structural dip trend

• Output curves that indicate degree of laminations

• Identification of other stratigraphic or structural events when used with other geologic data

• Output curves that indicate degree of bed contrast • Independence from search angle, correlation length, and step length

• A user interface that provides flexibility and quality control

¹Shin-Ju Ye, et al., Automatic High Resolution Sedimentary Dip Detection on Borehole Imagery (SPWLA 38th Annual Logging Symposium, 1997) Inputs Outputs

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EMI™, XRMI™, and OMRI™ data set Computed dips and dip trends


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Trendsetter™ service eliminates need for hand-selecting dip trends.


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ReadyView™ Open-Hole Imaging System The ReadyView™ system provides easy-to-use interactive software for the analysis of acoustic and electrical wellbore image data. The ReadyView™ system consists of three separate applications that provide image and dip interpretation and 3D visualization of the wellbore. The ReadyView™ system can be used to determine both true and apparent bedding dip and can also be used to determine the distribution, orientation, and apparent aperture of natural and drilling-induced fractures. This innovative system uses a customized USB flash drive to store and launch the applications. Performance on the flash drive is comparable to running on a local hard drive.

• Customers can pick and interpret their own dips, save and restore their own dip results, and export them in a variety of formats for transfer to other systems including OpenWorks™ and Microsoft Excel® applications • All image projections and data analysis views may be saved in a variety of raster and vector formats for report generation • Allows wellbore image data to be easily viewed in full color unwrapped views, polar cross-sections, 3D cylindrical displays, log profile views, and many others • The ReadyView system is also an excellent archival system for use of the digital image data at a future date

It provides unique accessibility to all types of wellbore image data, along with measurement and classification tools required for borehole breakout, structural, stratigraphic, and formation evaluation applications of image analysis. The software can be modified or augmented to meet the specific requirements of individual clients. Features • Runs on Microsoft® Windows® 2000 and Microsoft Windows XP platforms • Works with a wide range of wellbore image data including third party imaging tools, allowing full 32-bit RGB color resolution of acoustic and electrical image data • User interface provides a comprehensive set of sophisticated, interactive measurement tools and the ability to more easily classify and describe features observed in these logs. In particular, the ReadyView system offers a series of 2D data filters (i.e. Sobel, Gaussian, Sharpen, Horizontal edge detection) to enhance the image

ReadyView™ System USB Flash Drive

• Planar features can be displayed in stereographic projections or rose diagrams; tadpole profiles can be used to display planar data or wellbore trajectory • Standard log profiles, including gamma and resistivity logs, can be imported and displayed as reference logs for formation interpretation • Menus and dialog boxes allow quick scrolling, resizing, and selection of intervals of the data, making image analysis easy and straightforward

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This example shows a 2D view of image data when launching ReadyView™ software. From left to right, the first tract is a compressed image, second tract static image, third tract is depth, fourth tract is a dynamically enhanced image and the right side is a Schmidt plot, image histogram, and a dip-azimuth plot.


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Facies profile partitions the reservoir into discrete electrofacies or flow units. Producing electro-facies is a common and valuable operation performed by oil companies to discriminate discrete reservoir components. These components are used to populate reservoir models, flow simulators, determine porosity/permeability relationships, and describe the reservoir. The facies profile model can be run with conventional log data (such as GR, RHOB, or ΔT), NMR data, and possibly other data (not yet tested). A texture profile model based on the same clustering method has been developed to extract texture from electric (EMI™, XRMI™, and OMRI™ data) image data.

HAL9129

Facies Profile Facies profile is a multi-dimensional, dot-pattern recognition, clustering method based on nonparametric K— nearest neighbor and graph data representation. The underlying structure of the data is analyzed, and natural data groups are formed that may have very different densities, sizes, shapes, and relative separations. Facies profile automatically determines the optimal number of clusters, yet allows the analyst to control the level of detail actually needed to define the electro-facies.

Track 4 shows nine electro-facies computed from the GR (Track 1 black) RHOB (Track 3 red) NPHI (Track 3 green) and PE (Track 3 magenta). Using these four inputs, facies profile is able to discriminate differences in the lithology (but not actual lithology) and automatically order them according to increasing grain size or porosity. The EMI™ image in Track 1 is provided to show the correlation between the image and electro-facies.

The facies profile analysis shows similarities to a core description that might be done on a whole core or outcrop. Grain size, cleanliness, or porosity increase toward the right and changes in facies correspond to different colors and patterns. The Facies profile analysis contains automatic ordering that performs the grain size or porosity function automatically. The lowest numbered electro-facies has the smallest grain size or porosity and the highest number electro-facies has the largest grain size or porosity. The smaller numbered facies would plot farthest to the left, and the larger numbered facies would plot farthest to the right. Applications • Log interpretation that helps define 3D reservoir facies models describing the distribution of porosity, permeability, and capillary pressure in more detail than is possible with reflection seismology • Determination of the optimal number of clusters, while still allowing the analyst to control the level of detail actually needed to define the electro-facies

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Features • Helps define layering and select the best options for production test interpretation • Integrates geological insight into conventional log analysis • Automatically clusters and orders log data for generating electro-facies. It processes conventional log data, array data, such as NMR T2 distribution, image texture parameters, (texture profile), or any combination of a wide range of data

• Automatically proposes optimal number of clusters. Clusters are organized in a hierarchical way which can ease the interpretation • Automatically orders the clusters in log space which uses coarse-to-fine self-organizing map (CFSOM). This ordering usually corresponds to the geological facies evolution order which is particularly important for assessing geological meaning of each of the facies and their vertical sedimentary sequences

• Partitions the natural pattern of the data without requiring the user to give the number of clusters

Inputs

All the input curves must have the same step. Halliburton recommends placing the input curves to be used in a separate CLS file because numerous new curves may be generated. The output will have the step of the CLS file. ALPHA–The higher ALPHA the greater the smoothing. ALPHA can vary from 1 to 500. This parameter has been optimized and it is highly recommended that the user leave it at the default of 10. K–Another smoothing parameter that can vary from 4 to 20. The higher the number the greater the smoothing. K has also been optimized and it is recommended that the user leave it at the default of 5. The minimum number of electro-facies to compute. The maximum number of electro-facies to compute. The number of optimal electro-facies models generated by the program.

Outputs

EFAC_1, EFAC_2, and EFAC_3EFAC—stands for electro-facies. EFAC_1, EFAC_2, etc. are generated electro-facies model 1, 2, etc. Also see PARAMETER OM. Gives cluster kernels in log space order (after automatic ordering). The Kernel Representative Index of each data point. The Neighboring Index of each data point. It is unique for each data point for a given ALPHA. It measures the local data density around each point. Higher its value, higher its local density. The normalized Neighboring Index of each data point within the cluster. Because the cluster member configuration change with different electrofacies models, NNI is different with different electro-facies models.


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Net2Gross Sand Count The preferred approach for determining net pay in laminated sediments of fluvial and turbidite formations is to delineate sand layers from borehole image data. New image interpretation software, Net2Gross, has been developed to estimate the sand and pay counts within the subsurface sedimentary sequence logged by XRMI™ X-tended range imager tool or OMRI™ oil mud imager tool. The software exploits the XRMI and OMRI tool’s ability to resolve thin laminations and sedimentary structures. It applies threshold techniques to the pre-processed high resolution XRMI/ OMRI image and constructs secondary images for sand and pay. The analyst retains the flexibility to calibrate these images to the gamma ray and porosity logs using the cumulative distributions from all the logs to determine valid threshold values for the images. The software also generates cumulative sand and pay counts versus depth. An R-sand interpretation is also available by combining image data with triple combo data. This provides quantitative water saturation in laminated and dispersed shale environments.

• Better agreement between core and log, net sand, and pay • Combines image data and triple combo for an R-sand interpretation which provides water saturation for both laminated and dispersed shales

The sand image is constructed by applying an upper and lower threshold to the conductivity amplitude image, after calibration of this image to the neutron, density and gamma ray logs using the cumulative distributions from the logs and image data to determine valid threshold values. Pixels lying between the lower and upper threshold values, and greater than an analyst-specified cutoff are classified as sand. Sand pixels are then upgraded to pay if all of the following conditions are satisfied: the pixel's image conductivity is below a specified threshold, porosity greater than a threshold depth proximal to the pixel exists, and deep resistivity greater than a threshold depth proximal to the pixel exists. Finally, cumulative sand and pay counts versus depth are constructed by simply counting the sand and pay pixels. In Track 1, the sand image is presented as a binary image, black for shale and white for sand. Track 2 presents the pay image in which sands interpreted to be pay are assigned the color red. Features • High-resolution net sand and net pay images and curves • Cumulative net sand and net pay curve • Logic to prevent interpretation of tight streaks as pay • Interactive histogram based calibration of logging curves • Accurate sand and net pay counts in laminated sediments of fluvial and turbidite formations

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ImagePerm ImagePerm is an image based approach providing a highresolution porosity and permeability curve as well as a highresolution porosity image and histograms. In addition, it provides a high resolution secondary porosity curve, which is useful for interpretation in the presence of vugs and fractures.

• High resolution micro porosity from MRIL® tool calibration • Image depth based histograms for rock facies interpretation • High resolution intergranular permeability • Permeabilty correction for secondary porosity

The basic approach is to calibrate the image data to image porosity using filtering techniques. The image data is averaged over a moving window, and a transform is constructed which calibrates the average image data to porosity. This transform is then applied to the “pixel-bypixel” image data and a moving adjustment for bias is made. The final result is shown in Track 5, which shows the EMIP (or XRMI™ X-tended range micro-imager tool) porosity image scaled 0 to .3. Track 4 compares the total porosity PHIT from the neutron density logs (lazy black curve) with the image porosity averaged around the borehole (red curve) at each depth. It can be seen the calibration is correct and the resolution is improved for all the tight, low porosity streaks.

• Rock type based high-resolution permeability • Describes porosity and permeability in vuggy carbonate facies • Helps identify thief zones in vuggy formations, thus aiding in well completion • Helps identify productive zones in carbonates • Better agreement between core and log, permeability, and porosity

A porosity histogram of the image data as shown in Track 6 is used to aid in the interpretation and detection of vuggy porosity. Secondary porosity should manifest itself in the histogram being bimodal with the highest porosity mode corresponding to secondary porosity. Given each image porosity histogram, the cumulative distribution can be computed and displayed. In particular, the cumulative distribution in Track 3 shows in red the variation in porosity of those 20% of the samples having the highest porosity. Without any sonic or core data, for illustrative purposes, these samples were assumed to be secondary porosity. This constant fraction is converted to a volume and displayed in Track 4 as the gray shaded portion of the display. This implementation is intended to support a highresolution prediction of permeability for carbonates. The Jennings-Lucia model which relates the porosity permeability transform to rock type has been implemented. One obtains rock type from looking at core data, or by calibration to core permeability. Track 2 shows the permeability from primary porosity as cyan, and from secondary porosity as shaded. The predicted permeability can either decrease or increase with secondary porosity, dependent upon the model selected. Features • High resolution image porosity curve and image • High resolution image secondary porosity curve


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Borehole Geophysics Wellbore Seismic High Resolution Seismic Imaging—(Near Offset VSP, Fixed Offset VSP, Walkaways, 3D VSP, Salt Proximity Surveys, Microseismic Surveys) Halliburton provides high-resolution images in the vicinity of the borehole using a number of different techniques depending on the objectives and the geologic environment. The techniques include vertical incidence vertical seismic profiles (VIVSP) in deviated wells, salt proximity surveys, tomographic velocity analysis, fixed offset VSP surveys (FOVSP), 2D walkaway surveys, 3D VSP, and ExactFrac® or microseismic surveys.

High Resolution Seismic Imaging Features • Generation of high-resolution multiple free images

Halliburton is an industry leader in providing advanced source and downhole array technologies for borehole seismic. Halliburton’s expertise serves to benefit operators with reduced rig time and improved data quality. Advanced source and receiver technology is crucial towards obtaining a more accurate and comprehensive geological picture of your well, field, or reservoir.

High Resolution Seismic Imaging Applications • Profiling salt dome flanks

Halliburton can offer custom built solutions for client’s seismic imaging field needs. For survey planning, we use the most advanced 3D wavefront modeling software available, GeoTomo’s VECON software.

• Anisotropy determination

Multi-component arrays can be mobilized downhole to more accurately record true amplitude information of both compressional and shear waves.

• Mapping of steep structures (such as salt flanks) • Detailed velocity cubes in areas of laterally changing velocity (shallow gas, permafrost, salt, etc.) • Map structure, stratigraphy, lithology, and fluids with higher resolution and confidence than can be obtained with surface seismic • Improve a poor data quality area or overcome no-data areas

• Detecting natural fractures • Enhanced seismic velocity analysis • Primary seismic reflector identification • Porosity and permeability estimation • AVO analysis • Determine height, length, and width of well frac or stimulation process Associated Answer Products • Vertical incidence VSP • Synthetic seismogram

Compressional and shear images can be used in conjunction for lithology and fluid identification. Surveys can be repeated for time-lapse 4D views of fluid movements.

• FWS™ full wave sonic processing • ExactFrac® services

Downhole seismic tools can also be used to passively listen to the reservoir and to map fluid movements, fault reactivation, or active fracture monitoring. A full array of tools is available for analyzing high resolution seismic data for reservoir imaging. Halliburton offers advanced pre-processing, including multi-component wavefield separation and final imaging using pre-stack depth migration (PSDM).

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Reservoir Geophysics

Synthetic Seismic and Sonic Log Calibration

Long Array Multi-Component Acquisition Tools Halliburton offers survey planning, data acquisition, and data processing using multi-component long seismic arrays. Each tool combines advanced-source technology with industry leading multi-component and anisotropic migration software for a complete package of advanced custom designed reservoir imaging systems. Systems include the GeoChain™ VSP downhole receiver array.

The synthetic seismogram obtains an accurate tie between well logs measured in depth and the surface seismic image measured in two-way time. Correlation between logs and seismic is important to verify interpreted horizons and to help determine the true phase of the surface seismic (important for advanced lithologic and fluid interpretations from seismic data).

GeoChain VSP Downhole Receiver Array The GeoChain vertical seismic profile (VSP) array is designed for large borehole imaging surveys and can be used in open and cased holes with standard seven-conductor cable even in deep and hostile environments. GeoChain VSP Receiver Array Features • Based on the proven ASR-1 downhole geophone • Can be used in wells up to 25,000 psi and with hole sizes from 3.5-in. to 22-in. • Unique ACS™ active cooling system allows continuous operation up to 356°F (180°C) • Up to 42 satellites can be used in the array with a maximum tool spacing of 200 ft • All satellite locking arms open and close simultaneously, and the entire string can lock into a 9.625-in. well in only 30 seconds • Can be run in the following configurations: No. of Tools

Sample Rate

5

1/2 ms

10

1 ms

21

2 ms

26

2.5 ms

32

3 ms

42

4 ms

Associated Answer Products • 3D VSP imaging • 2D VSP imaging • Interwell imaging

An accurate synthetic depends on sonic log calibration using data from a vertical seismic profile (VSP) or check shot survey. This calibration is necessary for a number of reasons such as: • Sonic log and surface seismic are measured at different frequencies (dispersion) • Sonic log and surface seismic can measure different rock and fluid volumes (fluid differences, invaded zones, damaged borehole, non-vertical ray paths, etc.) Calibration of the sonic log includes an analysis of the data to determine the cause of the differences (drift) between the sonic and the check shots. Depending on the cause of the drift, different methods of correction are used. The corrected sonic log is converted to interval velocity. Acoustic impedance is calculated using the corrected velocity log and the bulk density. Changes in acoustic impedance are used to create a reflection coefficient log, which is subsequently convolved with a desired wavelet to create a synthetic seismic trace. Recording of a shear sonic log or calculation of a synthetic shear log allows calculation of a 2D synthetic to analyze or predict AVO effects on the surface seismic. Perturbation of the rock parameters also allows study of the effects of fluid and lithology changes on the seismic character. Synthetic Seismic Features • Helps promote accurate tie between well logs and surface seismic including phase determination • Allows identification of multiples on the surface seismic • Allows study of fluid and lithology effects on the seismic character

• ExactFrac® (microseismic) services Associated Answer Products • Vertical incidence VSP • High resolution seismic imaging (walkaway, fixed offset, 3D VSP, salt proximity, AVO Studies) • FWS™ full wave sonic processing


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Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis The VIVSP analysis is a downhole seismic survey with the quality seismic data. The rugged, computerized logging surface source positioned vertically above the geophones systems precisely position the geophone tool in the well, anchored in the well. In a vertical well, it is known as a zero properly synchronize the energy sources, and accurately offset VSP (ZOVSP) with the source positioned in a single transfer the measured data to the surface. The data obtained location near the wellhead. In highly deviated wells, the from VSPs provide extremely important information for source is moved along with the downhole geophone tool to enhancing and supplementing surface seismic data. keep the source vertically positioned above the geophone VIVSP Features tool at each level. • Allows detailed analysis of the downgoing and upgoing VIVSP analysis is useful for facilitating more accurate timewavefield depth correlation between your well logs and your surface • Real seismic trace rather than synthetic for log seismic seismic. It is also useful for determining the phase of your correlation surface seismic and for identifying multiples. • Provides detailed velocity analysis VIVSP data provides an indispensable bridge between sonic log data and surface seismic data. In areas where it is difficult to obtain a good tie between the synthetic and the surface seismic, the VIVSP can be helpful to identify and resolve the differences. VIVSP is also very useful for predicting lithology, fluids, and pore pressure ahead of the bit. Velocity trends that are useful for predicting pore pressure are calibrated at the well. VIVSP data is typically higher frequency than the surface seismic and can be used to better understand the reflectivity seen in the surface seismic.

VSP Applications • Direct correlation between surface seismic data and logs recorded in depth • Calibrate wireline sonic data for correlating synthetic seismograms with conventional seismograms • Mapping geologic structure in the vicinity of the wellbore • Predict stratigraphy, lithology, and structure ahead of the drill bit to help save drilling time and costs • Improve poor data-quality area or overcome no-data area • Helps profile salt dome flanks • Helps detect natural fractures

VIVSP data can be useful for computing the dip of the reflecting horizons in the vicinity of the borehole.

• Aids seismic identification of lithology

This can be used to confirm dips seen on dipmeter tools and help project these dips away from the well.

• Enhanced seismic velocity analysis

In deviated wells, the VIVSP also delivers a high resolution 2D image beneath the wellbore. This image is typically higher frequency than the surface seismic, multiple free, and tied directly to the wellbore in depth. Halliburton uses advanced proprietary software to handle VSPs in the most demanding geologic environments (advanced editing, multi-component wavefield separation, interpolation, deconvolution, and migration tools). VSP software and processing can be used in the field, in a computing center linked to the wellsite, or in the client offices for special projects. VSP acquisition teams utilize customized energy sources and the most advanced seismic tools available to record high-

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• Prospect delineation • Primary seismic reflector identification • Analyze multiple patterns • Deconvolution operator for surface seismic data processing • Porosity and permeability estimation • 2D and 3D stratigraphic and structural imaging • Helps locate overthrust granite/sediment interface • AVO analysis Associated Answer Products • Synthetic seismogram • High resolution seismic imaging (walkaway, fixed offset, ocean bottom cable, salt proximity, AVO studies) • FWS™ full wave sonic processing


ExactFrac® Services Halliburton eases frac modeling concerns by taking a fullservice approach to logging, offering both dipole sonic and borehole seismic services. To give engineers the answers they require, our microseismic techniques provide real-time assessments of fracturing processes using two wells: • A stimulation well where actual frac jobs are under way • A monitor well equipped with a downhole geophone tool array with multiple sensors


These microseismic techniques provide accurate information on the length, height, and distance of the frac being generated in the formation and can dramatically optimize the placement of future wells. ExactFrac Services Features • Allows operators to optimize drilling program in field • Improves later frac jobs (only zone you need to frac) • Minimizes uncertainty in your fracturing program

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Acoustics and Rock Properties Anisotropy Analysis Sonic anisotropy data—the directional sound attenuating characteristics of the reservoir—is used to improve the timeto-depth correlation since both fast and slow shear waves may be present. It also helps to develop synthetic seismograms using both the fast and slow shear wave and their orientation to improve 3D seismic analysis and future seismic acquisition. The waveform data from the WaveSonic® crossed dipole sonic tool is analyzed with the anisotropy waveform processing model to obtain the fast and slow shear wave travel times and their orientation in the formation. The anisotropy analysis processing engine is a simultaneous inversion technique which uses all 64 dipole waveforms, from the in-line and crossed-line transmitter-receiver arrays. The objective function includes all combinations of all waveforms, so it maximizes the redundancy which improves the robustness of the processing method.

Sonic anisotropy and the orientation of the anisotropy can be used to determine the orientation of natural fractures. Sonic attributes such as P-wave slowness, fast, and slow shear wave travel time, can be used for identification of compressive fluids in the pore space. This allows planning of the best completion method and builds reservoir understanding to be applied to the next well. Applications • Analyze WaveSonic tool waveform data to identify fast and slow shear wave travel times and their orientation in the formation

HAL9130

The minimum and maximum principal stresses and stress field orientation are calculated by combining oriented slowness data with overburden and pore pressure data. This information is vital for geomechanical analysis, wellbore stability, and production enhancement treatment design.

This is an example of fracture anisotropy. The fast and slow shear wave travel times are presented in Track 3. The azimuth of the fast shear wave is presented in Track 2 along with its uncertainty. The percent anisotropy is presented in Track 4, and shaded when the anisotropy is greater than 5%. The anisotropy is also presented in an image on the far right-hand track. North is on the right and left-hand edges of the plot and South is in the middle. The color intensity is proportional with the magnitude of the anisotropy. The rose plots in Track 4 shows the change in azimuth of the anisotropy. The energy ratio curves shaded in Track 1 identify the anisotropy as being a result of natural fractures.

• Develop synthetic seismograms to improve 3D seismic analysis and future seismic acquisition • Identification of compressive fluids in the pore space to maximize completion planning

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Features • WaveSonic® tool provides simultaneous monopole and crossed dipole sonic information

Associated Answer Products • RockXpert™ analysis–sand production and fracture strength analysis

• The low frequency flexural wave travels at the true shear slowness of the formation—dispersion corrections for shear wave slowness are not required

• FracXpert™ analysis–fracture stimulation zoning analysis

• A low frequency monopole source is utilized, so the P-wave and flexural wave data have similar depths of investigations well beyond any near-wellbore alteration • The wellsite products from the WaveSonic tool are the X-X and Y-Y flexural (shear) wave slowness (time travel) and the monopole P-wave slowness • Depth shifting of the waveform data is not required since the X-X and Y-Y depth dipole transmitters are on a common depth

Inputs

Outputs

Navigation data, all in-line and cross-line dipole waveforms, processing window starting time and processing window width Fast and slow shear wave travel time and their corresponding orientations, anisotropy (as curve and image), rose plots of azimuth of the fast shear


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RockXpert2™ Analysis Knowledge of rock properties and borehole stresses as provided by Halliburton’s RockXpert2™ analysis allow drilling, completion, and stimulation optimization. It has been estimated that borehole stability problems cost the oil industry more than $2 billion annually.

Borehole Deviation

90

Sloughing or collapsed wellbores can stick downhole tools and tubulars, which lead to lost rig time, expensive fishing jobs, side-tracking, or even well abandonment. Inadvertent fracturing of weak formations can result in lost circulation, and improperly planned hydraulic fracturing operations can give disappointing production results.

These rock mechanical properties include Poisson’s Ratio, Young’s Modulus, shear modulus, and bulk modulus. The stresses include axial, tangential, radial, maximum horizontal, and minimum horizontal.

Shear Failure

70

Tensile Failure

60 50

Stable Borehole

40 30 20 10

HAL951

RockXpert2 analysis provides critical information for designing fracturing programs, planning drilling operations, and evaluating sanding potential. The RockXpert2 program uses well log data to calculate rock mechanical properties and borehole stresses.

80

0 5

7

9

11 13 15 17 19 21 Mud Weight - Pounds per Gallon

23

25

At any specified point along a proposed or existing well path, RockXpert2™ analysis can identify stable borehole conditions as a function of mud weight and borehole deviation.

The use of RockXpert2 analysis allows the customer to drill, complete, stimulate, and produce the well at the most economical cost. Wells can be drilled to avoid geomechanical problems including lost circulation zones, sanding potential, and borehole collapse, but the well can be completed, stimulated, and produced without causing tensile, shear, or cohesive failure, and pore collapse.

• Determines optimum mud weights required to prevent sanding and fracturing during drilling operations • Evaluate a well's sanding potential to determine whether gravel packs or frac packs are necessary

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HAL157

Applications • Reduce the risk of losses from borehole instability

RockXpert2™ logs indicate the safe mud weight range to provide sanding and formation breakdown, as shown in Track 2. The logs also include gamma and caliper curves in Track 1, predicted maximum borehole deviation in Track 3, and lithology information in Track 4.


Features • Provides valuable input to fracture-design programs that predict fracture geometry and that help select fracturing fluids, proppants, and pumping schedules • Determines the mud weights required to prevent sanding and fracturing during drilling • Provides optimal direction in which to drill deviated, horizontal, and extended-reach wells to maximize borehole stability and increase the effectiveness of subsequent hydraulic fracturing • Assists in evaluating a well’s sanding potential to determine whether a gravel pack or frac pack may be necessary to help maintain production at optimal levels

Inputs Outputs

• Helps assist in determining the maximum amount of drawdown to eliminate both sanding potential and borehole collapse • Computations use data from continuous well logs rather than from core or microfrac measurements made at discrete points • Computes stress magnitude and takes into account borehole orientation relative to stress-field orientation • Results can be input directly into Halliburton’s FracXpert™ program • Results can be normalized to core-analysis results. Halliburton maintains an advanced rock mechanics laboratory that provides comprehensive core analysis

Compressional wave travel time, ΔTC, shear wave travel time, ΔTS, bulk density, VSH, pressure gradients Poisson’s Ratio, Young’s Modulus, shear modulus, bulk modulus, fracture pressure, collapse pressure


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FracXpert™ Analysis FracXpert™ analysis provides total data integration for 3Dfracture modeling. The FracXpert log provides automatic zoning based upon stress contrasts and averages the design parameters for each zone. It includes a presentation of log data that includes lithology, porosity, saturations, permeability index, and borehole stress information. FracXpert analysis provides linkages between the actual well properties and the fracturing design models. The automatic zoning removes possible design errors based on incorrect observations by the stimulation design engineer. This extremely fast process allows different scenarios to be analyzed and processed in both FracXpert analysis and the fracture modeling programs. After the stimulation is performed, modifications can be made to both models to accurately account for the stimulation response. Early frac design models did not include important design criteria such as pumping rates, fluid efficiencies, or treatment volumes. The FracPro™ program incorporates all these additional job parameters to accurately model, optimize, and execute frac operations.

FracXpert analysis differentiates itself from other zoning type logs which usually do not have adequate log processing capabilities. In that case, the log analysis or the picking of the relevant logging parameters is still done by hand, and the quality depends heavily on the experience of the stimulation design engineer. Several consultants have a similar approach to hydraulic fracture design.

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HAL9131

The rock mechanical data is taken from the results of formation strength-borehole stability analysis programs such as RockXpert2™ analysis. The analyst needs to run a volumetric log analysis model to find both the shale volume needed for the rock mechanical programs and to compute the permeability.

The depth track provides zonal numbering, pay and bad hole flags, perforations, and perforation numbering. The zonal numbers are assigned to the selected zones as determined by the zoning process based on fracture tensile pressure. Track 1 contains CORAL™ lithology track consisting of shale, dolomite, limestone, sand, and porosity. Track 2 presents that calculated water saturation. Track 3 displays CORAL analysis results that include effective porosity, water, and hydrocarbons. Track 4 presents the fracture tensile pressure and gradient from RockXpert2™ analysis. Track 5 provides five different flow calculations to help determine the economic potential of each zone. Track 5 also displays two normalized curves that help interpret zones of interest: permeability feet (NKH) and porosity feet (NPORH). Both are normalized from 0 to 1 over the entire well.


Applications • Total data integration for 3D fracture modeling

• Economic models and reservoir simulation reports are generated for accurate comparisons

• Log processing using automatic zoning

• Stress information is gathered from FWS™ full wave sonic or dipole sonic logs

Features • Automatic zoning helps define different layers within the formation for more accurate and consistent results without bias of the user

• Software can use permeability from conventional saturation/effective porosity relationships or from nuclear magnetic resonance logs

• Outputs include a well log plot, tabular listings, and an ASCII data file for input to 3D models Inputs

Outputs

Poisson's Ratio, Young's Modulus, minimum horizontal stress, permeability, pore pressure, and shale volume Automatic zoned averaging of the rock mechanical properties and volumetric data. Text files for simulators and stimulation programs.


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AcidXpert™ Analysis AcidXpert™ analysis aids in the design of stimulation treatments on carbonate rocks. The AcidXpert process provides a standard log presentation and associated text files that allow importation into other analysis packages.

• Matrix acidizing requires basic triple combo data and volumetrics

The success of matrix acidizing treatments depends on the placement of acid for efficiently removing near-wellbore formation damage. The type and composition of the acid is selected due to the rock matrix involved. The acid should be placed so that all potentially productive intervals accept a sufficient quantity of the total acid volume. If significant permeability or formation damage variations are present in the interval to be treated, acid will enter the zones with the highest permeability or least formation damage, leaving little acid to treat what may be the most productive zones. AcidXpert analysis is a process to collect and interpret the available data to maximize the stimulation effort. AcidXpert analysis provides answers for the following questions:

• StiMRIL™ process requires the components of acid fracturing plus MRIL® data

• Acid fracturing requires the components necessary for Matrix acidizing plus FWS full wave sonic tool data

• With a complex lithology, how detrimental are the carbonate mineralogies to production enhancement? • Is there a wide variance in the rock mineralogies? • Is there sufficient permeability for the well to flow? • Are natural fractures present, and do they intersect the wellbore? • What is a reasonable expectation for production? • How should the stimulation treatment be modified for specific scenarios?

AcidXpert analysis automatic zoning provides a superior method for stimulation evaluation. Additionally, generated text files allow easy input into several analysis models including reservoir stimulation, economic, and stimulation design. There might be different stimulation scenarios depending upon the log data, and AcidXpert analysis allows these scenarios to be modeled efficiently and effectively. The minimal data required by AcidXpert analysis includes resistivity, density, and neutron log data along with volumetrics. Additional processing can be used if FWS™ full wave sonic logs, MRIL®, and imaging logs are available.

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HAL9132

• What factors require attention? Is the right information available to make this judgement?

Within the depth track on the left side of the log are perforations, perforation number, a bad-hole indicator, pay flag, and the numbering assigned to the selected zones as determined by the zoning process. The red lines across all the tracks delineate the zones that were chosen based upon solubility. Track 1 contains gamma ray and temperature. Track 2 is the solubility curve, a sum of the limestone and dolomite minerals on a depth-by-depth basis. The pink shading indicates zones that could effectively be treated by acid stimulation. Track 3 provides lithology data that was generated by CORAL™ analysis. Track 4 presents that calculated water saturation. Track 5 displays analysis results that include effective porosity, water, and hydrocarbons. Track 6 presents a calculated permeability and effective water permeability.


Applications • Design of stimulation treatments on carbonate rocks • Import standard log presentation and associated text files into other analysis packages • Collect and interpret available data for stimulation treatments

Inputs Outputs

Features • Automatic zoning based on the rock matrix, fracture initiation pressures, or permeability • Part of a comprehensive approach to acidization that improves well performance • The use of the automatically generated text files allows easy linkages to reservoir stimulation, reservoir performance, and economic models

Standard processed volumetric data including porosity, matrix lithology, permeability, and water saturation. Additional inputs can include sonic and MRIL® data. Standard zoned log presentation along with automatically generated text reports.


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Reservoir and Production Engineering Reservoir Testing Studio RTS™ Reservoir Testing Studio RTS™ reservoir testing studio provides real-time analysis of data while it is being acquired to improve test quality and shorten rig time. RTS analysis features Halliburton's proprietary Exact™ and FasTest® analysis service techniques as well as conventional Horner (radial) and spherical time plot well test routines. RTS studio is designed to work with Halliburton's InSite® real-time data management and distribution system. The InSite Anywhere® option provides real-time access to RTS analysis plots, from anywhere and at anytime, with a standard internet connection. A report generator compiles the pressure transient analysis into reports that contain summary tables, gradient plots, and all the analysis plots. The summary tables can be exported to Microsoft® Excel® spreadsheets or Microsoft Word® tables.

The following plots and analysis techniques are available with RTS analysis. Pressure Time Plot The pressure time plot is the primary display that documents the data to be analyzed. The data selections made are later summarized in tabular form. From these data selections, an initial estimate of the formation mobility is made using the raw data (Mraw drawdown mobility). The pressure time plot also includes a pressure stability plot with a wrapping scale from 0 to 10 or 0 to 1 psi so that the pressure can be observed on an expanded scale.

Applications • Analysis of drawdowns and buildup pressure transients • Determine pressure transient flow regime (spherical or radial) • Summary tables of test results • Pressure gradient analysis plots • Sample PVT closed chamber testing Features • QC pressure transient data • Makes data selections for gradient analysis • Provides project formation pressure (P*) • Estimates mobility (1,000 - 0.001 md/cp) • Estimates of anisotropy (kv/kh)

RTS™ analysis pressure time plot is used to make data selections, which are documented in summary tables. Additionally, the results are used to create gradient plots and calculate the drawdown mobility (md/cp).

• Documents results in a final report

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Exact™ Buildup Analysis The Exact™ buildup analysis can be used to estimate spherical mobility (Ms Ex) and formation pressure (P*Ex) over a wide range of mobilities (i.e., 0.001 to more than 1000 md/cp). Conventional methods of analysis use late time data which requires pressures to stabilize after storage effects have dissipated. For low mobility zones (less than 1 mDarcy/cp), this can require long buildup times, but Exact analysis can match the early time data thus shortening the test time required. In higher mobility, Exact analysis can also be used to provide accurate estimates of mobility and formation pressure. Exact Anisotropy Analysis Plot The Exact anisotropy plot is a buildup analysis method used for a vertical interference testing (VIT). The pressure recorded at a vertical monitoring probe is combined with the source (either probe or straddle packer) buildup analysis to determine the horizontal mobility (Mhrz ex) and the ration of vertical to horizontal mobility, Aniso (kv/kh) ex.

The RTS™ Exact™ analysis plot is a priority analysis technique designed to be used over the entire range of operation for formation testers. In addition to estimating the mobility from the buildup, the formation pressure can be estimated before the shut-in pressure is established, saving rig time.

Example of an Exact™ Anisotropy Analysis Plot


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FasTest® Buildup Analysis FasTest® buildup analysis can be used when mobility is above 1 mDarcy/cp. Originally developed for well test surge or impulse testing analysis, it is also well suited for SFT™ and RDT™ tool buildup analysis. FasTest analysis is considered more reliable than traditional methods because it does not depend on an accurate estimate of the drawdown period or rate. Therefore, it is ideal for buildups where the sample chamber is used to create the pressure impulse. FasTest analysis can: • Save rig time by terminating tests as soon as a sufficient amount of data is obtained • Analyze sample chamber pressure pulse to determine permeabilities up to at least 1 Darcy (Mfast) for both spherical or radial flow regimes • Determine flowline storage effects on measured pressure • Provide accurate calculated sandface pressure estimates (P*Fast) Horner Time Plots Horner time plots are the traditional technique for analyzing pressure transient analysis data. Both spherical and radial time domains are available with the projected formation pressure (P*), Horner mobility being determined from the slope of a line formed from a regression of the data on a radial or spherical time plot. Horner interpretation for wireline testers is generally used for zones with mobilities above 1md/cp.

RTS™ FasTest® analysis service plot is used for buildup analysis in more permeable zones (i.e., > 1md/cp). The FasTest analysis is very flexible and can be used for pretests as well as sample chamber surge tests. Either spherical or radial flow regimes can be used.

RTS™ analysis Horner plot offers a traditional method of analyzing pretest buildups. Either spherical or radial flow regimes can be used.

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Log-Log Derivative Analysis Plot This plot verifies the flow regime and data quality of the pressure transient. The FasTest® analysis service derivative and pressure differential of the buildup data is presented in this plot. Either a spherical time or conventional radial time

derivative can be chosen so that a stable horizontal line represents infinitely acting flow for either regime.

M spher

⎛ ⎜ ⎛ 1013 ⎞⎜ 1.5Vo φ c f =⎜ ⎟ ⎝ 4π ⎠⎜ t 2.5 ⎛ dp ⎞ ⎜ ⎟ ⎜ ⎝ dt ⎠ ⎝

1

⎞ 1. 5 ⎟ ⎟ ⎟ ⎟ ⎠

⎛ ⎞ ⎜ ⎟ ⎛ 1013 ⎞⎜ Vo ⎟ M radial = ⎜ ⎟ ⎝ 4π ⎠⎜ h t 2 ⎛ dp ⎞ ⎟ ⎜ ⎟⎟ ⎜ ⎝ dt ⎠ ⎠ ⎝

RTS™ analysis log-log derivative plot is based on the FasTest® analysis service derivative and is used to verify the flow regime of buildups and evaluate the quality of the pressure transient.


2-41

Applications • A true vertical depth survey log for correcting depth measurements

+ ++ + ++ + + ++ + ++ ++ ++ ++ + ++ + ++ ++ ++ ++ ++ + ++

0.09 0.08 0.07 0.06 0.05 0.04

7

6

5

4

++

++

++

0.03

3

++ ++ ++

0.02

++

0.01

2

+ + ++ ++ ++ +

1

+ +

0 0

500

1000

1500

2000

2500

Pretest Volume Change (cc)

Formation Test Summary Program (FTS) The FTS program compiles RTS™ pressure test analysis data and creates gradient plots and summary tables. When selections are made from real-time data, they are automatically added to the gradient analysis. This allows multiple zones, gradients, and contacts to be identified. A manual input mode is also available.

0.10

Pretest Volume Fraction (^Volume/Total Volume)

PVT Analysis A PVT plot is available for the RDT™ reservoir description tool service. This is a closed chamber in-situ sample analysis test that is performed automatically during the pumping process and after a sample is taken. The bubblepoint and fluid compressibility is determined.

3000

+ 3500

0 4000

Pressure (QPRS, psi)

PVT plots the volume fraction against the pressure. The linear portion of the plot determines the compressibility and when the curve deviates from this linear trend, the bubblepoint is detected.

• Identify multiple zones, gradients, and contacts

3200

PRESSURE GRADIENT PLOT

Features • Multiple gradient plots for each zone 3300

• Fluid contacts can be identified and annotated on plots • Minimizes errors because data is automatically imported from the RTS analysis program • Verifies the quality of pressure data by automatically producing the hydrostatic gradient

Tvd (ft)

• An unlimited number of gradient lines that can be generated from RTS analysis data

3400

3500

HAL9249

3600

3700 400

Legend Unassigned Pform Group 1: 0.377 Group 2: 0.261 Group 3: 0.275 Group 4: 0.957 Group 5: 0.268

600

800

1000

3,613.351 ft

1200

1400

1600

1800

Pressure (psi)

Pressure gradient plots allow multiple zones, gradients, and contacts to be identified. Plots are derived from RTS™ analysis data and are automatically added to the gradient analysis when data selections are made from real-time data. A manual input mode is also available.

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Example of Pressure Test Summary Hydrostatic Pressure

Test Identification

Equivalent Mud Weight

Test Pressures

Test Times Remarks

Test No.

MD (m)

TVD (m)

Phyds1 (psi)

Phyds2 (psi)

EqFmM w #/Gal

1.1

2892.90

2755.23

4219.07

4217.79

6.5

8.98

4301.96

3002.60

3053.43

286

342

395

10 cc Effective Pre Test

1.2

2892.90

2755.23

4219.07

4217.79

6.5

8.98

3050.07

2996.47

3053.41

470

487

627


2.1

2899.98

2761.96

4220.33

4224.27

6.49

8.96

4328.67

2985.81

3058.43

353

381

492

Good Test

2.2

2899.98

2761.96

4220.33

4224.27

6.49

8.96

3058.30

3036.94

3058.19

505

564

574


3.1

2909.48

2770.97

4234.52

4232.36

6.48

8.96

3074.09

1682.64

3064.64

437

512

1119

Tight Test

4.1

2984.55

2842.19

4312.47

4313.45

6.69

8.89

4396.87

3141.33

3242.76

308

381

506

Good Test

4.2

2984.55

2842.19

4312.47

4313.45

6.69

8.89

3242.76

3134.49

3242.66

506

580

708

Good Test

EqBhMw #/Gal

Pdd (psi)

Tfu (sec)

Tstop (sec)

Tdd (sec)

Pfu (psi)

Pstop (psi)

Legend: Phyds1 Initial Hydrostatic Pressure Phyds1 Final Hydrostatic Pressure Pdd Initial Drawdown Pressure Pfu Final Drawdown or Fillup Pressure Pstop Final Buildup Pressure

EqFmMw Equiv. Formation Mud Weight (PStop / (TVD*Constant)) EqBhMw Equivalent Borehole Mud Weight (Phyds1 / (TVD*Constant)) Tdd Initial Drawdown Time Tfu Final Drawdown or Fillup Time Tstop Final Buildup Time

The Pressure Test Summary table compiles all pressure selections from the RTS™ program. Pressure tests are documented in a single table that is plotted on the log. This data is also available in ASCII form that can be easily imported into a spreadsheet for analysis.

Example of Pressure Transient Analysis Summary Test Identification

PTA Pressure

PTA Mobilities

Dual Probe Anistropy Mh (md/cp)

ANISO (Kv/Kh)

Remarks

Test No.

MD (m)

TVD (m)

Psphere (psi)

Pfast (psi)

Ptight (psi)

Msphere (md/cp)

Mfast (md/cp)

Mtight (md/cp)

Msdd (md/cp)

1.1

2892.90

2755.23

3053.73

0.00

3052.98

2.10

0.00

5.30

11.69

Good Perm

1.2

2892.90

2755.23

3053.57

3053.59

0.00

3.52

3.96

3.96

34.81

Good Perm

2.1

2899.98

2761.96

3058.57

0.00

0.00

1.75

0.00

0.00

16.46

Good Perm

2.2

2899.98

2761.96

3063.21

0.00

0.00

1.79

0.00

0.00

26.41

Good Perm

3.1

2909.48

2770.97

0.00

0.00

3057.06

0.00

0.00

0.04

0.32

Low Perm

4.1

2984.55

2842.19

3243.07

0.00

0.00

1.27

0.00

0.00

4.48

Test performed at engineers request, Good Perm

4.2

2984.55

2842.19

3242.78

0.00

0.00

1.53

0.00

0.00

4.17

Good Perm

Legend: Psphere* Spherical Analysis Formation Pressure Pfast* FasTest Analysis Formation Pressure Ptight Tight Zone Analysis Formation Pressure Msdd Spherical Drawdown Mobility

Msphere Spherical Mobility Mfast FasTest Mobility Mtight Tight Zone Mobility Mh Horizontal Mobility

ANISO Anisotropy (Kv/Kh)

The Pressure Transient Analysis Summary table is a tabular listing of pressure buildup analysis data, including mobility estimates and formation pressure projections (P*). Data is also available in real time and as a document on the log.


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Well Testing Well testing is performed to determine formation productivity/deliverability, permeability, reservoir pressure, presence of skin damage, flow profile inside a formation and wellbore, reservoir geometry/size/drainage area, inter-well communication, and perforation efficiency.

Types of well tests include closed chamber or surge test with the zero-emission FasTest® system, shoot and pull test, drillstem test, cleanup test, slug test, early production test, multi-rate production/ injection well tests, reservoir limit test, permanent gauge test, and interference/pulse tests.

Well testing is usually performed right after a well is completed and when the productivity does not follow the expected trends. Well testing is also done periodically through the life of a well and field to assess well performance and to establish pressure and rate decline patterns.

For these tests to be reliable and effective, a well test design is critical to assuring the test objectives are feasible by selecting: • Proper completion equipment • Pressure gauges with the required sensitivity and accuracy

In pressure transient testing, the changes in pressure, temperature, and fluid properties caused by sudden changes in production rates of oil, gas, and water from a well (or wells) are measured and analyzed during a given time span.

• Type of well test

The most widespread type of pressure transient testing is a pressure buildup test in which a producing well is shut-in, and the pressure values are recorded with time. In a pressure drawdown test, a shut-in well is opened, and the pressure values are recorded with time.

The following well and reservoir models are considered when designing or analyzing well test data:

The basic requirements of a well test are:

• Hydraulic fracture wellbores

• Measuring the flow rate of the gas and the liquids produced or injected

• Any boundary configuration

• Controlling and adjusting the flow from the reservoir

• Layered reservoirs

• Measuring the pressures and temperatures using sensitive and accurate downhole instruments

• Wellbore with limited entry (partial completions)

• Obtaining samples of the reservoir fluids • Safely disposing of or storing the well effluent produced during the test Well Test Design In a well test design, all the production history and the available reservoir and wellbore properties of a well are included in a pressure transient testing design model. A given reservoir flow geometry based on the completion and production history is selected to simulate pressure and time data as close as the actual data which would be obtained from an ensuing well testing. For the unknown parameters, sensitivity runs should be conducted to cover the entire range of the expected values. Test duration and types should then be modified to provide a sufficient amount of data to be recommended for the ensuing pressure transient testing.

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• Flow rate and choke sizes • Duration of flow and shut-in periods

• Analytic and numeric models • Homogeneous or dual porosity formations • Horizontal, vertical, or deviated wellbores

• Radial and linear composite reservoirs

• Changing wellbore storage and/or skin • Turbulent flow and tidal effects • Well interference effects • Simultaneous analysis of a changing reservoir model before and after a stimulation or a workover application • Material balance effects The accuracy and the value obtained from a well test design depends on the following: • Experienced engineers performing the service • Availability of advanced well/reservoir models • Comprehensive well test design report • Comparisons with prior tests to establish trend • Parameter sensitivity evaluation to signify the importance of the values obtained


Features • The following features are included in a well test design report: – Optimum test times – Optimum flow rates – The right equipment suited for the job

• A well test design is a planned activity that uses the prewell test well and reservoir information to optimize the test type, procedure, and time • Success of a well test is greatly enhanced by coupling the well testing with the real- time operations (RTO)

– Models with sensitivities to reservoir, fluid, and wellbore parameters – Well test procedure

Inputs Outputs

Wellbore data, reservoir data, fluid properties, stimulation treatment, information geology, seismic and environmental controls, surface facilities, previous production/injection problems Well test design report


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Well Test Analysis A well test analysis report provides information about well productivity/deliverability, formation permeability, reservoir pressure, amount and type of damage, perforation efficiency, and flow type /profile inside a formation and wellbore. If the test was designed and conducted for a longer period, then reservoir geometry/size/drainage area and inter-well communication would also be evaluated and provided in the report. Well test and completion data can be deployed to get a more accurate reservoir description. In a well test report, Halliburton engineers identify opportunities to improve well performance, which often includes reservoir and well production projection with recommendations to enhance productivity. If a well test identifies wellbore damage, then productivity improvement projections will be simulated to compare acidizing with hydraulic fracturing and frac pack to evaluate if stimulation will improve production. If the cause of the problem stems from partial completion and perforation plugging, then reperforation, acidizing, and fracturing cases will be compared. The optimum production scenario based on the evaluated reservoir and wellbore parameters can also be included in the report. Well test analysis can provide initial reservoir pressure (pi), permeability thickness (kh), and skin (S). Additionally, the perforated wellbore length (hw), distance of horizontal wellbore to bottom of formation (Zw), and ratio of vertical to radial permeability (kZ/kr) are calculated for horizontal wells. The dual-porosity flow model provides values for λ and ω. Stimulated wells are characterized by the fracture half-length (Xf ), conductivity (CFD), and fracture skin. Distances to boundaries and the boundary type (no-flow, constant pressure, or leaky) can be provided for any of the models. In a composite reservoir, the size and the properties inside and outside of the composite zone will be provided. In a limited entry well, the effective interval producing into the wellbore and the plugged perforations are identified. In layered reservoirs, permeability, skin, pressure, and flow rate for each layer can be calculated. A well test analysis technique may include one or a combination of the following methods:

Halliburton well test analysis service differentiating factors include: • Experienced reservoir engineers performing the service • Customized and easy to use report • Advanced well/reservoir models • Analytic and/or numeric analysis techniques • Real-time analysis capabilities using a secured website that can be accessed using your computer anytime or anywhere Features • Enhanced reservoir and completion description with advanced and sophisticated reservoir models • Evaluation and/or analysis performed in batch or real time • Recommendations for well improvement based on reservoir, wellbore, completion, and the surface equipment • Fast turnaround at a reasonable cost to free up valuable engineering time • Experienced reservoir engineers available for any questions • Evaluation of the entire job • Follow-up briefing on analyses results and recommendations for future tests • A complete analysis report with: – Well test description – System evaluation – Discussion of each event – Gauge comparison – Analysis results – Well test data summary – Historical comparisons (when applicable) – Production improvement recommendations (when applicable) – Conclusions

• Conventional linear regression analysis • Type curve analysis • Non-linear regression • Closed-chamber DST analysis • Production analysis

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BHP [psia]

5000

Pressure vs Time

4700

9000

HAL7688

• Commingled layered reservoirs – The layers in a commingled formation are isolated from each other and do not communicate in the reservoir. They are hydraulically connected with each other through the wellbore

Gas Rate vs Time 0

1000

2000

3000

4000

5000

6000

Pressure [psia], Gas Rate [Mscf/D] vs Time [hr])

Permanent Gauge Analysis: History plot of pressure and rate showing analysis model match

• Cross-flow layered reservoirs – The layers in a cross-flow reservoir communicate with each other through both the formation and the wellbore. At any point in the reservoir, the interlayer cross flow is proportional to the pressure difference between the layers

3,000 ft 2,500 ft

3,000 ft

2,000 ft

HAL7755

At high flow rates, the high permeability layers produce at higher flow rates than the low permeability layers, and thus, they get depleted at a faster rate. At low flow rates or when the well is shut-in at surface, fluids from the low permeability layers invade the high permeability layers which were depleted more.

Pbar

4900

4800

Gas Rate [Mscf/D]

Multi-Layered Analysis In multi-layered reservoirs, hydrocarbon fluids exist in different layers. These layers could be located close or far from each other, in hydraulic communication or totally isolated from each other, and with similar or completely different properties. The pressure values in the layers could differ by just the hydrostatic head pressure difference or be totally different from each other. Multi-layer formations are divided into two main categories of:

Reservoir shape: Analysis results showing geologic boundary configuration

5500

Production Data Matching Theoretical Model Inflow Parameter

FLOWING BTM PRES psig

BHP [psia]

Halliburton provides a multi-rate, multi-layer test in conjunction with the production logging service. Layer pressure and flow rates are evaluated by the production logging service. This information is fed into the multi-layer well test analysis program to evaluate permeability, skin, and pressure for each layer.

FORM PERM (md ) 50 50 100 100 250 250

9000

Outflow Parameter SKIN ( ) 0 5 0 5 0 5

FLNCHOK ID (1/64 ) 12 16 20 26 36 64

8000

7000

Match Point

6000

Analysis Results

Skin

10 8 6

4500

4 2

-1000

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

Rate [Mscf/D]

Skin vs. Rate

Gas Rate [Mscf/D]

3500

Prod Index = 4.95 Mscf/D - psi Storage Constant = 0.00509 STB/psi True Skin = 1.96 True Delta P Skin = 71 psi Turb Skin = 4.58 Turb Delta P Skin = 165 psi Turb Factor = 0.00131 1/Mscf/D Initial Pressure = 6000 psia kh = 141 md-ft k = 4.7 md

5000

4000

HAL7689

14 12

3000 Constraints: Erosion:C=100.00

2000

0

2000

4000

6000

8000

10000

HAL7687

FLOW RATE bbl/d

4000

0

20

40

60

80

100

120

Inflow and outflow pressure—rate responses for various reservoir parameters showing production match point.

140

History plot (Pressure [psia], Gas Rate [Mscf/D] vs Time [hr])

Multi-rate test showing analysis results accounting for turbulent flow effects. Inputs Outputs

Test objectives, geologic information, prior production data, completion schematic, fluid property data, prior treatment data, well test downhole pressure gauge files, well test surface data report files Well test analysis report including recommendations for well performance improvement (when needed)


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Reservoir Evaluation SigmaSat™ Model This cased-hole interpretation model is designed for saturation analysis of a single well based on sigma logs from any supplier. Oil saturation can be determined in the presence of saline formation waters. Gas saturation can be determined under almost any conditions. Features • Saturation interpretation of any formation sigma data • Standard volumetric analysis or an adaptation of the Chevron variable matrix model • Inclusion of open-hole porosity and clay volume analyses • Stand-alone analysis using porosity and clay indicators from cased-hole monitoring tools or any available source • Determines volume of hydrocarbons produced from the reservoir and allows estimates of remaining reserves • Enhances reservoir production knowledge • Allows better understanding of hydrocarbon drainage efficiency from the reservoir

• Pinpoints changing oil/water and gas/oil contacts through time lapse monitoring • Finds flooded or swept zones Associated Answer Products and Pre-Processing Software • Pulse-height spectral gain stabilization and processing, plus environmental corrections (TMDLRL) • CarbOxSat™ model – similar model for saturation analysis of neutron decay logs

HAL11409

• Identifies potential hydrocarbon production zones that have not been drained or were bypassed or previously undiscovered

Track 1 indicates the amount of sand and shale by volume, along with the effective porosity. Track 2 is a porosity overlay track indicating hydrocarbon crossover. Track 3 shows sigma water apparent and sigma solids apparent. Track 4 shows an envelope of sigma wet and sigma hydrocarbon with sigma intrinsic in between, indicating the hydrocarbon. Track 5 indicates the total hydrocarbon saturation, and Track 6 shows total porosity, effective porosity, the effective volume of water, and the volume of hydrocarbon.

• TripleSat™ model – similar family of models utilizing both carbon/oxygen and neutron decay logs for use where three fluids are present in the reservoir

Inputs

Outputs

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Clay volume, total porosity, effective porosity, environmentally corrected intrinsic sigma Individual and combined clay volume, total porosity, effective porosity, capture-ratio porosity, inelastic ratio porosity, hydrocarbon volume, total and effective hydrocarbon saturation, water volume


CarbOxSat™ Model This interpretive model is specifically designed for saturation analysis of a single well based on Halliburton carbon/oxygen (C/O) logs. The CarbOxSat™ model is used for interpreting oil saturation in reservoirs where formation water salinity is fresh, mixed, or unknown. Features • Saturation interpretation of all Halliburton formation carbon/oxygen data • Halliburton’s lithology compensated Delta-C/O or traditional overlay method • Inclusion of open-hole porosity and clay volume analyses • Stand-alone analysis using porosity and clay indicators from cased-hole monitoring tools or any available source • Determines volume of hydrocarbons produced from the reservoir and allows estimates of remaining reserves • Enhances reservoir production knowledge • Allows better understanding of hydrocarbon drainage efficiency from the reservoir

• Pinpoints changing oil/water and gas/oil contacts through time lapse monitoring • Finds flooded or swept zones Associated Answer Products and Pre-Processing Software • Pulse-height spectral gain stabilization and processing (RMTERL) • Multi-pass stacking (RMTEAVG) • Environmental corrections (RMTECOR)

HAL11768

• Identifies potential hydrocarbon production zones that have not been drained or were bypassed or previously undiscovered

Track 1 contains the open-hole neutron and density porosity curves, as well as the gamma ray curve. Track 2 contains the cased-hole porosity indicators of a pseudo-density curve from the inelastic ratio, and a pseudo-neutron porosity from the capture ratio. Track 3 contains the delta-C/O envelope indicating the C/O interpretation. Track 5 shows the total hydrocarbon saturation, and Track 6 is a volumetrics track containing the volume of shale, effective porosity, and the bulk volume of water to provide water and hydrocarbon saturation.

• SigmaSat™ model – similar model for saturation analysis of neutron decay logs • TripleSat™ model – similar family of models utilizing both carbon/oxygen and neutron decay logs for use where three fluids are present in the reservoir Inputs

Outputs

Clay volume, total porosity, effective porosity, environmentally corrected carbon/oxygen and calcium/silica ratios Individual and combined clay volume, total porosity, effective porosity, capture-ratio porosity, inelastic ratio porosity, volume of oil, total and effective oil saturations, water volumes


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TripleSat™ Model This unique interpretation model is specifically designed for use with Halliburton’s reservoir monitoring tools. The TripleSat™ model employs a combination of C/O and sigma measurements and is used to calculate saturation when three fluids are present in the reservoir. Features • Utilizes simultaneously-recorded sigma and C/O measurements • Provides more accurate interpretation in oil producing reserves where steam or gas is present • Contains selectable sets of equations that can be optimized for one of the following: – Steamflood – Oil drainage from gas cap – Gasflood – Sea waterflood

• Permits inclusion of open-hole porosity and clay volume analyses • Allows stand-alone analysis using porosity and clay indicators from cased-hole monitoring tools or any available source • Allows accurate interpretation in reservoirs that have gas cap development or are under steamflood or gasflood • Permits interpretation in reservoirs with retrograde condensate production Associated Answer Products and Pre-Processing Software • SigmaSat™ model – neutron decay time saturation analysis • CarbOxSat™ model – carbon/oxygen saturation analysis

Inputs

Outputs

2-50

HAL9180

• Allows additional optimizations to be readily constructed, some using a Halliburton adaptation of the Chevron gas correction to carbon/oxygen logs

KernSat Interpretation Example. This well located in Kern County, California in the Kern River Field, is in an active steamflood hydrocarbon recovery project. This log is an example of our customized interpretation model KernSat. Track 4 of the example displays the computed oil saturation (shaded in green) and the gas saturation (shaded in red). These saturations were computed using a combination of carbon-oxygen ratio and formation sigma. Track 3 displays the carbon-oxygen and the calcium-silicon ratio curves. The green shading between the two curves indicates hydrocarbons in the formation. Also displayed in the track are the natural gamma ray measurement and the simultaneous recorded formation sigma. Tracks 1 and 2 display a comparison of the open-hole density and neutron porosities and the porosity ratio indicators measured by the RMT Elite™ analysis. Track 1 is the open-hole density neutron porosity. Steam measured in the formation at the time of the log is indicated by the gray shading between the curves. Tracks 2 displays the inelastic and capture ratios measured from the RMT Elite analysis. The red shading indicates the current location of steam in the reservoir. This example indicates that the steam chest has expanded when compared to the original formation contacts. The depth track recorded at the far left side of the log displays water flow measured by the RMT Elite analysis outside the casing.

Clay volume, total porosity, effective porosity, environmentally corrected carbon-oxygen and calcium-silica ratios, environmentally corrected sigma Individual and combined clay volume, total porosity, effective porosity, capture-ratio porosity, inelastic ratio porosity, volume of oil, total and effective oil saturations, water volumes, corrected three-phase saturations


Production Logging Analysis Production Logging Analysis Halliburton has several programs that are used to interpret production logs. The basic production logging interpretation is provided using Kappa Engineering's Emeraude software. The industry standard in production logging is Emeraude which allows for a common platform for communication and evaluation between service companies and operators. From vertical injectors to horizontal or highly deviated multiphase producers, Emeraude provides a comprehensive and intuitive set of tools to produce results from the log data from simple through to the most sophisticated toolstrings. The basic interpretation uses raw PL data from the spinner, fluid density, pressure, and temperature tools to determine flow rates of the well. The log at the right consists of seven passes logged at different multiple logging speeds as shown by the different colors for each pass. The basic interpretation process is explained as follows: • Spinner calibration and apparent velocity The user defines the spinner calibration zones to determine the spinner calibration with or without thresholds values. After each calibration, an apparent velocity curve is generated • Single and zoned PVT The next step is to use the PVT model to provide the properties of any phase at any temperature and pressure. Several different correlations may be used for each and every inflow zone

Basic raw data showing two sets of perforations (red), two sets of spinner calibration zones (yellow), and three rate calculation zones (grey). From the fluid density data, it is possible to see where there are major fluid composition changes (4480), with minor changes from 4480 to 4550. The spinner information also indicates fluid entry around 4480.

• Flow rates Using a nonlinear regression method, the rate calculations for each inflow zone is determined. This allows the user full flexibility in the number and type of input measurements. The basic calculation scheme successively solves the cumulative rates at selected depths inside the wellbore. The contributions of the user selected inflow zones are then obtained from successive differences above and below each zone. To further enhance the product, a global regression allows comparisons between zones • Interpretation models Emeraude offers a full range of flow models from single to three-phase flow. Specific models are provided to handle flow re-circulation as well as flow through standing water columns. Emeraude can be tightly controlled by the user to provide a solution to complex flow situations including fallback, three-phase, and deviated wellbores


2-51

This screen capture shows the spinner calibration in the sump. The positive and negative thresholds are applied to the other zones to correct for spinner friction.

This zone is above the top set of perforations, so the velocity at this zone should be the velocity of the total fluid flow. The calculated velocity will be corrected for tool position in later sections of the software.

2-52


Several programs were developed in-house for specialized tools but are linked to Kappa Engineering's Emeraude program. These specialized analysis programs are used to process specific logging tool data to determine fluid velocities and holdups.

• Log presentations can be customized to meet the specific requests or needs • Text files provide linkages to reservoir models and other analysis packages

• GHTA gas holdup tool analysis • FloImager® analysis service for CAT™ capacitance array tool data • SatImager™ analysis for spinner array tool (SAT) data The GHTA model is an analysis program used to process the data from the GHT™ gas holdup tool and create a gas holdup for further processing in Emeraude. The FloImager model uses data from the CAT tool to provide an accurate holdup calculation. Like the GHTA model, the output from the FloImager model is used seamlessly in the Emeraude software to further quantify the production rates. The SatImager model uses data from the SAT tool to provide an accurate image of the velocity profile in the wellbore. The SAT tool with six spinners allows interpretation of complex flow regimes including downflow and liquid fallback. Combining the FloImager and SatImager models in Emeraude provides an efficient method to evaluate complicated downhole flow regimes including deviated, horizontal, and three-phase. Features • Delivers a complete interpretation of production logs • Detailed analysis of downhole and surface production rates, both continuous and averaged, over the desired interval • Handles a multiple array of production logging sensors including the new generation fullbore holdup tools

Final Emeraude product showing two-phase flow showing the lower perforations taking fluid. Track 1 provides information about the holdups, or the cross-sectional area of the pipe that the phase is occupying. Track 2 is the continuous flow rate measurement in STB/day. Track 3 is the zonal average of the two phases while Track 4 shows the production of each zone. In this case the lower zone is taking a large amount of water that is being produced by the upper zone.

• Allows customized analysis using customer PVT inputs and slip velocities • Various presentations and stringent quality control promotes more accurate PL analysis of production and injection wells including the difficult three-phase flow in horizontal wells • Continuous logs provide more accurate determination of fluid entry points which allow for improved conformance treatments • Averaged and zonal production rates provide valuable information in determination of treatments and/or remedial work


2-53

FloImager® Analysis Service The FloImager® analysis service is a logging service product that uses the data from the CAT™ capacitance array tool to provide accurate three-phase holdup calculations. This application is extremely useful in highly deviated and horizontal wells having multiphase flow. Applications for detecting three-phase fluid entry can be done at any angle. There are a multitude of applications for the FloImager analysis service. In addition to measuring fluid holdup, the FloImager analysis service can be used to detect water entry and its orientation relative to high side of pipe at any well deviation. The FloImager analysis service can successfully show three-phase fluid segregation since each fluid has its own log response. The FloImager analysis service provides an accurate visualization of the undulating horizontal wellbore when TVD data is combined with CAT tool data. Combining the calculated fluid holdup with additional PL sensors allow a more accurate and complete three-phase analysis.

XX50

A B XY00

The FloImager analysis service improves interpretation of the flow patterns in all wells due to the increased number of sensors at the same depth. More accurate holdups can be determined because the relative position of the CAT tool is monitored, correcting the images and logs to the high side of the hole. FloImager 3D Software Analysis The FloImager 3D software provides a 3D method of viewing data from the FloImager service. The FloImager 3D software allows the customer to view, rotate, and manipulate CAT capacitance array tool data to understand the flow patterns and character of the well. Both the FloImager 3D and FloImager service use data from the CAT tool to provide accurate three-phase holdup calculations. FloImager 3D software allows a complete picture or profile of the downhole holdup pattern. This allows the viewer to approach the wellbore from any direction to allow multidimensional understanding of the flow characteristics. Since the sensors are normalized in the CAT tool, the same color pallet can be used for each sensor providing a precise image. The FloImager 3D software provides a superior technique for displaying multiphase holdup. However, since this segregation is dependent upon total fluid flow, each sensor has the ability to measure phase holdups of gas, oil, and water. Both the FloImager 3D and the FloImager service have several options to calculate total holdup of the wellbore, allowing the user to determine the best possible solution to this complicated issue.

2-54

XY50

Track 1 consists of a gamma ray (GR), relative bearing (RB), temperature (TEMP), pressure (PRES), and continuous spinner (FCON). RB is the relative bearing for arm 1 of the CAT™ tool and allows arm position relative to the high side of the hole to be determined. Track 2 provides the image of the flow as measured by the CAT tool. The image is positioned so that the high sides are on the left and right side of the track while the middle is on the low side. Since this is a horizontal well, it should be apparent that the heavier fluids should be on the bottom and lighter fluids should be on the top of the well. Track 3 shows the average of the 12 sensors (AVCAPN) along with two center sample holdup measurements fluid density (FDEN) and hydro tool (HYDR). Track 4 provides a cross-sectional view of the data in Track 2. The right side of the image is high side while the left is on the bottom. The holdups are also presented in the last track, water (YWE) and gas (YGE). This presentation allows quick method of determined fluid contacts and provides accurate calculation of fluid compositions. Lines A and B correspond to the Flo3D section.


Features • Multi-directional images available • Continuous display of the flowing fluids • More accurate three-phase holdup calculations • Images in all types of stratified and mixed flow • Designed for more accurate responses in both deviated and horizontal wells

• Continuous holdup curves, fluid distribution mapping, and a view of the fluid distribution in cross-section allows clear-cut understanding of the flow profiles and characteristics • Ability to obtain more reliable holdup measurements and high-resolution fluid entry detection, location, and orientation in deviated and horizontal wells

• Excellent wellbore coverage with array of 12 sensors allows superior data and improved flow characterization

A

B

High Side View

Low Side View

XX90

XY00

This output is from FloImager® 3D software analysis and shows 10 ft of the log from above. It is possible to see the changes in the holdup due either to wellbore trajectories or possible fluid inflow.

XY00

XX92 Gas Holdup = .223 Oil Holdup = .516 Water Holdup = .261

XX96 Gas Holdup = .221 Oil Holdup = .651 Water Holdup =.128

XX90 This presentation is a composite from FloImager® 3D software analysis. The first display is over the same zone as above looking downhole. The last two images are from the cross-section display that shows both the tool arm position and the calculated holdups for the three phases. The white dot is arm #1 which determines the relative bearing so that the data can be oriented to the high side of the wellbore.


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Open-Hole Wireline Services

Open-Hole Wireline Services Resistivity ACRt™ Array Compensated Resistivity Tool System The ACRt™ array compensated resistivity tool system represents the latest thinking in conventional array induction technology. Every aspect of mechanical, electrical, software, and signal processing design has been optimized to yield array induction measurements with unparalleled accuracy, stability, and dynamic range. The ACRt system is an asymmetric design that consists of a single transmitter operating at three frequencies and six receiver antennas with spacings from 6 to 80 in. A simple and robust skin effect method utilizes only the in-phase components of the received signals at all three frequencies. Each tool is individually characterized for thermal drift during manufacture. This characterization, in concert with sonde-mounted temperature sensors, provides the basis of a proprietary and highly accurate temperature compensation method. Real-time borehole corrections are usually derived from a caliper source and a sonde-mounted mud cell. When the caliper input is absent (e.g. downlogging), borehole corrections are derived from the short-spaced induction receiver data alone. The final step in the processing chain, 2D software focusing, produces five radial curves with matched vertical resolution and with radial focal depths of 10, 20, 30, 60, and 90 in. The ACRt sonde includes an integrated SP sensor. Applications • Accurate measures of formation resistivity at varying depths of investigation for enhanced estimates of Rt, Rxo, and Di

Real-time 10-20-30-60-90 in. radial curves from the ACRt™ system are displayed in track 2. Good sensitivity to shallow invasion is in evidence in the zones 10290 and 10385. RT, RXO, DI and the graphical invasion map are available in real time.

• Quantitative assessment of Sw, Sxo, and moveable water volumes • Qualitative assessment of permeability and rock quality • Array induction measurements are available in formations with resistivities from 0.2 to 2000 ohm-m and in water, air, or oil-filled boreholes • Analysis of finely-bedded formations


3-1

Features • State of the art processing scheme features: – 2D software focusing produce five resolutionmatched radial curves with radial focal depths of 10, 20, 30, 60 and 90 in. – Real-time inversion for Rt, Rxo, Di, and invasion “map” – Proprietary thermal correction scheme – Three frequency skin effect correction – Real-time borehole corrections with or without caliper inputs

• Optimized receiver antenna spacings provide improved sensitivity to shallow and mid-range mud filtrate invasion depths along with excellent deep response for Rt • Receiver coil spacings closely approximate computed radial curve depths, which results in fundamentally stable processing • Short array length reduces dependency on “speed correction” when encountering moderate overpulls • Environmental ratings of 350°F and 20,000 psi • Logging speeds up to 6,000 ft/hr

– Resolution-match filters of 1, 2 and 4 ft

ACRt™ Array Compensated Resistivity Tool Specifications Length ft (m)

Minimum Borehole Diameter in. (mm)

Maximum Borehole Diameter in. (mm)

Operating Pressure Rating psi (bar)

Operating Temperature Rating °F (°C)

Weight lb (kg)

Maximum Logging Speed ft/hr (m/hr)

19.5 (5.9)

4.75 (121)

12.25 (311)

20,000 (1400)

350 (177)

308 (140)

6,000 (1830)

3-2


HRAI™ High Resolution Array Induction Tool The HRAI™ high resolution array induction tool represents a significant engineering advance over the HRI™ high resolution induction tool. The HRAI tool leverages the proven features of the HRI tool “three-coil” receiver configuration while providing induction measurements with six radial focal depths. The sonde is a symmetrical design, with five upper and five lower receivers positioned around a center-mounted transmitter. Raw conductivity data is collected at two frequencies, 8 and 32 kHz, and the receiver antennas are spaced from 17 to 78 in.

• Each resistivity comes with a 1-ft, 2-ft, and 4-ft vertical resolution

A new speed correction algorithm implemented in the logging software enhances the accuracy of HRAI tool coil array data even during large overpulls in sticky boreholes. Long transmitter-receiver spacing and optimized array processing help to significantly reduce the effects of washouts, rugosity, and tool eccentricity.

• High logging speeds up to 6,000 ft/hour are possible

• Real-time Rt, Rxo, and Di curves and an invasion “map” are available • Real-time borehole corrections facilitated by a sondemounted mud resistivity sensor • Advanced “speed correction” algorithm for correcting array data for over-pulls in sticky boreholes • Vertical resolution-matched elemental measurements

Applications • Accurate measures of formation resistivity at varying depths of investigation for enhanced estimates of Rt, Rxo, and Di • Quantitative assessment of Sw, Sxo, and moveable water volumes • Qualitative assessment of permeability and rock quality

• Analysis of finely-bedded formations Features • Real-time 2D software focusing achieves an optimum balance of vertical resolution, radial focusing, and symmetry of response

HAL3960

• Array induction measurements are available in formations with resistivities from 0.2 to 2,000 ohm-m and in water, air, or oil-filled boreholes

Real-time answer products of HRAI™ tool: an invasion map in Track 4, Rt and Rxo in Track 3, and Track 2 shows the 2-ft resolution radial resistivity curves.

• Resolution-matched radial curves are computed with radial focal depths of 10, 20, 30, 60, 90 and 120 in.

HRAI™ High Resolution Array Induction Tool Specifications Logging Speed ft//hr (m)

Length ft (m)

Minimum Borehole Diameter in. (cm)

Operating Pressure psi (bar)

Operating Temperature °F (°C)

Weight lb (kg)

LOGIQ

6,000 (1830)

25.43 (7.75)

4.5 (11.43)

20,000 (1400)

350 (177)

400 (181)

DIT

6,000 (1830)

35 (10.67)

4.5 (11.43)

20,000 (1400)

300 (150)

586 (266.5)

Description


3-3

HRI™ High Resolution Induction Tool The HRI™ high resolution induction tool is an electrical wireline tool that belongs to the induction logging family of tools. It records apparent conductivity of the subsurface formations. Data processing converts the measured conductivity into resistivity. The HRI tool works well in boreholes drilled with water, air, or oil. Standard HRI tool presentation includes deep and medium resistivities derived from the raw conductivities. In conductive muds, a digitally focused resistivity log (DFL) and SP measurements are available.

• The DFL provides a shallow focused resistivity measurement with a radial investigation of 15 in. The vertical resolution of the DFL closely matches that of the HRI tool induction curves • A 1-ft vertical resolution improves estimates of Sw and the hydrocarbon reserves in thinly laminated pays

Applications • Reliable Rt in resistivity environments from 0.2 to 2,000 ohm-m provides improved estimates of water saturation • Quantitative moveable hydrocarbon volumetric analysis and radial fluid distribution around the borehole when DFL is available • High vertical resolution deep, medium conductivities and DFL logs enhance analysis in finely laminated reservoirs • Distinguishes between conductive water-bearing and hydrocarbon-bearing formations • Provides estimate of invasion diameter and Rxo Features • Sonde architecture consists of four transmitters and one receiver. The transmitter operates at 20 kHz • The single receiver is a “three-coil” configuration for enhanced vertical resolution • The tool measures both R and X components of the conductivities. X signals are used for skin effect correction • The signal processing chain includes corrections for formation skin and shoulder bed effects to produce the deep (HDRS) and medium (HMRS) resistivities Standard HRI™ log example showing deep and medium resistivities (Track 2) computed by correcting the raw conductivity data for skin, shoulder bed, and borehole effects.

HRI™ High Resolution Induction Tool Specifications

3-4

Length ft (m)

Diameter in. (mm)

Operating Pressure psi (bar)

Operating Temperature °F (°C)

Weight lb (kg)

33.3 (10.2)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

455 (206.4)


DLL™ Dual Laterolog Service Halliburton's proven DLL™ dual laterolog service provides a reliable means of measuring formation resistivity in conductive borehole fluids and/or where large contrasts exist between the formation and mud resistivities. The DLL service operates by focusing currents into the formation to produce a deep resistivity measurement (LLd) and a shallow resistivity measurement (LLs). The MSFL™ microspherically focused log is usually run in combination to provide a third shallow resistivity measurement. Together, these three measurements provide the resistivity profile around the borehole and permit the computation of Rt in presence of invasion.

Features • Rugged sonde construction and state-of-the-art electronics provide for accurate measurements of formation resistivity up to 40,000 ohm-m • Dual electrode arrays and an automatic current-focusing technique • The fundamental vertical resolution is 24 in. for both measurements which facilitates reservoir description of thinly bedded formations

Applications • Provides accurate, high resolution shallow (LLs) and deep (LLd) resistivity measurements in high Rt/Rm conditions (>100) or when formation resistivity exceeds the limits for conventional induction tools (> 2,000 ohm-m) • Quantitative assessment of Sw • When run with the MSFL log, provides estimates of Rt, Rxo, and diameter of invasion • Quantitative assessment of moveable water saturations (Sxo) and moveable hydrocarbon volumes

• Provides MSFL measurements to help delineate thin beds and provide estimates of Rxo • Offers qualitative indication of permeable zones and estimating invasion diameters (when run with the MSFL tool)

HAL9154

• Acquires improved formation resistivity measurements in saline borehole fluids and in high Rt/Rm (>100) contrast logging conditions or when formation resistivity exceeds the limits of induction tools (>2000 ohm-m)

DLL™ log example from a carbonate-evaporite sequence showing deep and medium laterolog curves presented along with the shallow MSFL™ log.

DLL™ Dual Laterolog Service Specifications

3-6

Length ft (m)

Diameter in. (mm)

Maximum Pressure psi (Mpa)

Maximum Temperature °F (°C)

Weight lb (kg)

33.9 (10.3)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

460 (208.7)


MSFL™ Micro-Spherically Focused Log and Microlog (ML) The MSFL™ micro-spherically focused log and microlog (ML) tool is a pad-type version of the spherically focused log (SFL) that was developed to eliminate borehole effects and achieve superior shallow resistivity measurements with high vertical resolution. Included with the MSFL tool is a ML sensor. The ML recorded 2-in. normal and 1.5-in. lateral resistivity measurements. The MSFL and ML tools are combined into one tool which can be run as a standalone service or in combination. The pads are arranged on opposing, powered caliper arms which provide accurate measures of borehole size.

• Non-rubber versions of the MSFL and ML tools are available that provide superior resistance to gas absorption and better durability and run life over older rubber pad versions • The tool can be run independently or in combination with other logging tools. When run in combination, the MSFL/ML tool can be placed anywhere in the toolstring

Applications • The MSFL tool provides measurements of Rxo in all types of conductive mud systems. Rxo is used quantitatively in computing Sxo and moveable water volumes • The ML tool is sensitive to the presence of mudcake and provides a qualitative indication of formation permeability • Evaluation of thinly bedded sand/shale sequences • Two powered caliper arms provide reliable estimates of borehole size Features • The MSFL tool records resistivity with a vertical resolution of 8 in. and a depth of investigation of 3 in. • The ML tool records resistivity with a vertical resolution of 2 in. and a depth of investigation of 1 in. • Both the MSFL and ML tools, by virtue of being padtype devices, offer measurements relatively free of environmental effects. This makes them particularly well suited for operations in highly conductive (saltsaturated) mud systems

MSFL™ Micro-Spherically Focused Log and Microlog (ML) Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

MSFL™ Tool

10.2 (3.1)

5 (127)

20,000 (137.9)

350 (176.7)

214 (96.4)

ML with HFDT™ Assembly1

27.5 (8.4)

5 (127)

20,000 (137.9)

350 (176.7)

720 (326.6)

ML with SDLT™ Assembly2

18.6 (5.7)

20,000 (137.9)

350 (176.7)

475 (215.5)

Tool

1 2

4.5 (114.3)

Weight, length, and diameter apply to the HFDT/Microlog assembly. Weight, length, and diameter apply to the SDLT/Microlog assembly.


3-7

HFDT™ High Frequency Dielectric Tool The HFDT™ high frequency dielectric tool is a pad-type electric logging tool used primarily in the determination of flushed-zone water saturation (Sxo). The HFDT tool transmits a continuous 1,000 MHz electromagnetic wave into the formation and measures the propagated wave amplitude and phase with respect to the transmitted signal. The principle measurement objectives are to determine the complex dielectric constant of the formation. Depth of investigation ranges from 1 cm to about 10 cm.

• Independent deployment of the pad and backup arm permit optimal alignment with other tools in the toolstring for more effective combination logging • Works in fresh, salt-saturated, and oil-based mud systems, freshwater and most saltwater formations, and in formations where water salinity is highly variable or unknown

Applications • Provides reliable Rxo measurements for determining flushed-zone water saturation (Sxo) and moveable hydrocarbon volumes • Determining irreducible water saturation (Swirr) in oilbased muds • Evaluation of thinly bedded sand/shale sequences • Determination of the cementation exponent (m) when combined with other micro-resistivity logs Features • Absolute and differential dielectric measurements are recorded, resulting in less sensitivity to borehole rugosity • Uniquely measures both the incident and reflected phase and amplitude signal • Phase-shift and attenuation measurements from three receivers for increased accuracy • Automatic gain control permits good log quality across a wide range of formation resistivity • Extendable pad sensor reduces borehole rugosity effects. • An accelerometer curve and composite profiles of resistivity and dielectric curves give indications of irregular tool motion, mudcake buildup, and pad lift-off

HFDT™ log computed on a sandstone matrix. Hydrocarbons are indicated when dielectric porosity FPHI falls below density/neutron porosity. In the above example, the high frequency dielectric clearly shows that the zones from 46 ft to 83 ft and 91 ft to 99 ft are hydrocarbon bearing while the zone from 132 ft to 142 ft is water filled.

HFDT™ High Frequency Dielectric Tool Specifications

3-8

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

27.5 (8.4)

4.75 (120.7)

20,000 (137.9)

320 (160)

720 (326.6)


Imaging EMI™ Electrical Micro Imaging Service The EMI™ Electrical Micro Imaging service provides highly detailed, core-like images of the formations encountered by the borehole. These images are produced by measuring and mapping formation micro-resistivity with each of the 150 pad-mounted button electrodes on six independent arms. The current of each button is recorded as a curve and sampled every 0.1-in. (120 samples/ft). These current variations are then converted to color or gray-scaled images. Conventional dipmeter information is embedded into the image data and is available for standard SED™ tool answer products. A navigation package is included in the EMI tool to provide accurate information on tool position and orientation within the borehole. Consistent, direct pad contact with the borehole wall is essential to obtaining high quality borehole image data. By virtue of independent arm linkages and pad articulation, optimum pad contact can be maintained with a minimum of pad pressure even in rugose, washed-out, or non-circular boreholes. This results in accurate, sharp images, more complete borehole coverage, and a reduced dependence on corrections for irregular tool motion effects (speed corrections). In addition, the EMI service uses six independent arms, making it possible to acquire quality image data in non-optimal hole conditions.

Features Electric borehole technology has the capability of resolving features impossible to resolve using conventional logging tools. Small fractures, vugs, bedding planes, depositional features, thin beds, and rock texture changes provide significant insights that can impact reservoir exploration and development. Associated Answer Products • SHIVA™ program • AutoDip™ service • TrendSetter™ service • Texture-profile • Manual dip picking • Image interpretation

• Offers detailed structural, stratigraphic, and sedimentological analysis for optimized offset well placement, completion tactics, and hydrocarbon depletion efficiency • Allows thin bed delineation and improved net pay estimations • Quantifies rock textures and electro-facies • Permits 2D and 3D borehole geometry and breakout presentations from 6 caliper measurements as well as characterization and evaluation of secondary porosity

HAL9155

Applications • Provides a variety of real-time and post-processing 2D and 3D image products to evaluate geological, petrophysical, and borehole properties

Static (Track 2) and dynamic (Track 5) enhancement of an EMI™ borehole image showing a sand-shale sequence and the computed dips (Track 4) of the sedimentary strata. Vertical fractures (drilling artifacts) are also seen in the enhanced images. High resolution data can provide insight into the texture of the formation and reveal details conventional logs cannot.

• Identifies orientation and connectivity of fracture systems


3-9

HAL9156

HAL9157

Fine structural and stratigraphic details of a thinly bedded reservoir are captured in this borehole image. The automatically picked dips do an excellent job of capturing dip trend details. There are over 100 dips selected in this 13-ft interval. Hand picking would be tedious, time consuming, and perhaps discretionary.

HAL9158

Soft sediment deformation and slumping are captured on the electric image. The AutoDip™ program does a good job of capturing the dip reversals and handling the high angle dips.

Structural and stratigraphic dips are well represented in this example. Slumping above the base of the sand (3295) is evident and current bedding above give evidence of the depositional environment.

EMI™ Electrical Micro Imaging Service Specifications Equipment

Length ft (m)

Diameter (minimum) in. (mm)



Weight lb (kg)

EMI™ Tool Only

24 (7.3)

5 (127.0)

20,000 (137.9)

350 (176.7)

496 (225)

EMI Toolstring

41 (12.5)

5 (127.0)

20,000 (137.9)

350 (176.7)

N/A

3-10


XRMI™ X-Tended Range Micro Imager Tool This new electrical wireline borehole imaging tool is designed to obtain superior quality images even in high Rt:Rm environments. The expanded operating range of the XRMI™ X-tended range micro imager tool over conventional electrical imaging tools is achieved through its new, state-of-the-art 32 bit digital signal acquisition architecture combined with a large increase in available power for the excitation current (EMEX).

Besides the new electronics, the mandrel architecture derived from Halliburton’s highly successful EMI™ imaging tool greatly helps the XRMI tool generate superior quality borehole images. Pads mounted on six independently articulated arms help maintain pad contact in rugose, washed-out, elliptical, or highly deviated boreholes. Further, high sampling rate (120 samples/ft) and adequate borehole coverage (67% in 8.5 in. holes) help obtain high resolution pictures of the borehole walls.

a

HAL13883

As a result, the signal to noise ratio of the raw measurements is improved by a factor of up to five, and the dynamic range is expanded by a factor of up to three. The resulting images offer superior fidelity even in highly resistive formations (Rt > 2000 ohm zm) or relatively salty borehole fluids (Rm < 0.1 ohm zm).

b

c

High resolution XRMI™ images showing the micro-textural geological details in the fabric of a limestone section in a test well from Permian Basin, West Texas: (a) vugular open porosity; (b) open natural fractures; and (c) stylolites. The Rt:Rm ratio exceeds 100,000 in this borehole.

Applications • Shows bedding dips that help rationalize the choice of next drilling location • Chooses the sidewall core zones, formation testing zones, and perforation intervals accurately by integrating images with other open-hole logs • Computes accurate high resolution net-to-gross • Optimizes offset well placement by evaluating structural and stratigraphic features and bedding orientation

• Rationalizes well stimulation and formation testing decisions by characterizing the secondary porosity (e.g. fractures and vugs) in reservoirs

HAL13882

• Provides more accurate net-to-gross estimations in laminated shaly sands and carbonates by delineating thin beds and laminations

• Optimizes drilling efficiency by evaluating and orienting borehole breakout • Optimizes the completion tactics and reservoir management by providing characterization of rock texture and electro-facies


3-11

HAL13884

An XRMI™ formation evaluation answer product generated by Halliburton’s proprietary software WXforecast. The first image track shows the static equalized image and the second image track exhibits the texture-enhanced high resolution image produced by the application texture-pro. Central dip-track shows the results of Auto-Dip™ service. The sharp change in the dip azimuths from west to east is interpreted to be due to slump faulting. The base of the channel sand is also a scoured surface.

XRMI™ X-Tended Range Micro Imager Tool Specifications Length ft (m)

Maximum OD in. (cm)

24.18 (7.37)

5 (12.7)

Minimum Hole Size in. (cm)

Maximum Hole Size in. (cm)

6 (15.240)

21 (53.34)

Maximum Pressure psi (Kpa)


Weight lb (kg)

20,000 (137 895)

350 (176.7)

496 (225)

Borehole coverage is 67% in 8.5 in. hole.

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OMRI™ Oil-Based Micro-Imager Tool The latest addition to Halliburton’s borehole imaging solutions is the OMRI™ tool for use in oil-based muds. The OMRI tool generates crisp, high-resolution digital images of the wellbore down to 1 in. of vertical resolution, instead of 1 ft of vertical resolution that is available with conventional logging tools. The extra resolution makes thin bed pay and other important features clearly visible.

Applications • High vertical resolution pay zone volumetrics (both fluids and minerals) • Pay zone detection (in extreme thin bed / “low contrast” pay zones) • Structural and stratigraphic dips • Sedimentary features and textures • Net-to-gross sand counts • Identification of faults and unconformities • Evaluation of sedimentary sequences and flow units • Lithologic unit thickness • Secondary porosity evaluation • Sequence stratigraphy analysis • Borehole stresses analysis

HAL18834

An advanced pad sensor generates six resistivity measurements per pad, each with a vertical resolution of 1 in. and a depth of investigation of about 3 in. Data is collected at 120 samples per foot with a proprietary signal acquisition scheme optimized for rugose hole conditions. The pads are mounted on six independent caliper arms which yield true assessments of borehole shape and stress, useful in frac jobs and completion designs. The sensor pads are mounted on the caliper arms with unique two-axis of articulation. This facilitates improved pad contact, and thus improved images, in less than ideal borehole conditions. This combination of features provides unparalleled image fidelity over the widest possible range of logging conditions.


3-13

Features • Identifies important reservoir characteristics, such as structural and stratigraphic dips, sedimentary geometry and texture, borehole stresses, and lithologic unit thickness • Recognizes features beyond resolution of conventional logs, including permeability barriers, sand attributes, clasts, vugs, and more • Quantifies important reservoir characteristics such as lithology, porosity, water saturation, permeability, fluid profile, and flow potential when integrated with other logs and well information • Provides detailed, accurate pictures of the reservoir that answer key geological and petrophysical questions • Identifies thin bed pay that cannot be seen with conventional logs, particularly in geologically younger, unconsolidated formations • Helps increase success rate in multi-well developments by answering questions about sedimentology and structural and stratigraphic analysis, which serve to enhance reservoir management decision making

HAL18835

• Optimizes design of completion programs in order to be more efficient and cost effective

OMRI™ Oil-Based Micro-Imager Tool Specifications Length ft (m)

Maximum OD in. (cm)



Minimum Hole in. (cm)

Maximum Hole in. (cm)

Weight lb (kg)

27.54 (8.39)

5.5 (13.97)

20,000 (137 895)

350 (176.7)

6.5 (16.5)

24 (60.96)

760 (344.73)

Borehole Conditions Recommended Logging Speed*

Borehole Fluids

Range of Mudcake Thickness

Mudcake Resistivity

High Data Rate

Low Data Rate

Tool Positioning

0 - 0.25 in.

> 10,000 ohm-m

30 ft/min (9.1 m/min)

20 ft/min (6.1 m/min)

Centralized

Salt

Fresh

Oil

Air

X

*Slower logging speed may be required for low resistivity environments or poor borehole conditions.

3-14


CAST-V™ Circumferential Acoustic Scanning Tool-Visualization

Applications • Provides complete borehole imaging for accurate, precise formation evaluation • Detailed structural, stratigraphic, and sedimentological analyses for optimized offset well placement, completion design, and hydrocarbon depletion efficiency

Associated Answer Products • Manual dip-picking • Image interpretation

HAL9159

The CAST-V™ circumferential acoustic scanning toolvisualization is an ultrasonic tool that provides highresolution images in both fresh and oil-based drilling fluids. The tool’s interchangeable head rotates a full 360° and contains a high-frequency acoustic transducer to provide a full 360° profile of the borehole. A second acoustic transducer is mounted in the scanner housing and is used to measure characteristics of the borehole fluid. A directional sub is provided to orient images to either the high side of the hole or to north. The image mode, run primarily in open hole, consists of 200 points horizontally by 40 samples/ft vertically. The CAST-V tool is designed to operate in conjunction with other DITS™ tools but must be run centralized in fluid filled boreholes.

CAST-V™ tool open-hole fractures example—3D projection with perspective view. Borehole breakout (in direction of minimum stress) normal to strike of fractures.

• Thin bed delineation and improved net pay estimations • 2D and 3D borehole geometry and breakout presentations from acoustic caliper measurements Features • Resolves features impossible to resolve using conventional logging tools. Small fractures, vugs, bedding planes, depositional features, thin beds, and rock texture changes provide significant insights that can impact reservoir exploration and development • Real-time fluid cell measures both borehole fluid transit time and fluid impedance. The fluid transit time is used to correct the internal radius measurements made from the scanner head while the acoustic impedance measurement is used as a quality control monitor

CAST-V™ Circumferential Acoustic Scanning Tool-Visualization Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

17.9 (5.5)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

316 (143.3)


3-15

SED™ Six Arm Dipmeter The SED™ six arm dipmeter is an electric logging tool that provides data used to compute formation dip. It provides six formation micro-resistivity measurements, tool orientation data, and six caliper curves. The six micro-resistivity measurements are taken at 60° increments around the borehole. This data is then correlated to identify bedding and other features in the formation. Applications • Evaluate magnitude and direction of structural and stratigraphic dip events for offset well placement, reservoir modeling, and reservoir management decisions • Improved evaluation of thinly laminated sand/shale sequences

Associated Answer Products • SHIVA™ program – standard analysis package to correlate raw micro-resistivity data and evaluate it for planar structural or sedimentological features. Results presented as vector (tadpole) plots. Available at the wellsite as well as in the computing centers • Omnidip – module of SHIVA program uses the tool’s high sampling density to identify nonplanar surfaces and describe current bedding characteristics and other nonplanar sedimentary structures • Resmapa – borehole imaging program that interpolates between the six micro-resistivity curves to produce a color oriented image of structural and sedimentological features

• Fracture detection • Directional data to provide TVD, drift surveys, and bottomhole location • Caliper data as input to 2D and 3D borehole profile plots as well as integrated borehole volumetrics Features • High resolution micro-resistivity measurements sampled at 0.1-in. • Independent arm linkage and swiveled pads provide optimum pad contact with a minimum of pad force • Tri-axial accelerometers and three magnetometers are employed to compute borehole drift, azimuth, and corrections for tool rotation and irregular motion • Available oil-based mud pads for acquiring dip logs in non-conductive drilling fluids

HAL9160

• Six independent caliper measurements describe borehole washout and breakout in precise detail

Standard processed SED™ log showing the raw resistivity data and results of dip analysis.

SED™ Six Arm Dipmeter Specifications

3-16

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

22.3 (6.8)

4.5 (114.3)

20,000 (137.9)

350 (176.7)

470 (213.2)


Nuclear SDL™ Spectral Density Log rb

CALIPER 6

The SDL™ spectral density log provides superior formation bulk density and borehole compensated photoelectric factor (Pe) measurements.

INCHES

16

2.0

GAMMA 0

API

3.0 c Pe

200

0

Dr 10 -0.25

0.25

QS 0.5

-4.5

QL 4.5

Applications • Determination of formation porosity

-0.5

X250

• Identification of formation lithology regardless of formation fluid type • Indication of gas when used in combination with a neutron log

X300

Features • Delineation of thinly bedded formations using the unfiltered Pe curve • Field engineers perform precise calibration and wellsite checks

X350

• Curves indicating data quality are displayed on a computer screen in real-time and are recorded on the log • Advanced correction algorithm is applied to density data

• Rugged construction and advanced gain stabilization help maintain measurement integrity under varying temperature conditions • Combinable with a complete family of tools that operates under the DITS™ digital interactive telemetry system

X400

HAL9374

• Rigid tungsten pad incorporates a 1.5-curie cesium-137 source and two high-efficiency scintillation detectors designed to maintain high gamma counts

X450

Typical Field Output of the SDL™ Tool Quartz

Calcite

Dolomite

23 L3 HA

Mineral Identification Plot


3-17

Associated Answer Products • The wellsite answer product is apparent bulk density of the formation and borehole compensated photoelectric factor

– ULTRA™ multi-mineral evaluation program – CORAL™ complex lithology analysis

• Bulk density or density porosity data is used with other open-hole sensors as input to Halliburton’s mineralogy, open-hole, and cased-hole saturation analysis to provide a complete formation evaluation product. These include:

– LARA™ laminated reservoir analysis – SASHA™ shaly sand analysis

SDL™ Spectral Density Log Specifications

3-18

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

19.3 (5.9)

4.5 (114.3)

20,000 (137.9)

350 (176.7)

420 (190.5)


DSN™ Dual-Spaced Neutron Tool

The DSN tool consists of an instrument section housing the electronics, two He3 detectors, and a source sub housing an americium-beryllium source which generates fast neutrons that penetrate the formation at an initial energy of 4.6 MeV. Thermal neutron tools are not as limited by the spacing and depth of investigation problems associated with epithermal neutron tools. Since thermal neutrons are detected, count rates are much higher than for epithermal neutrons. However, thermal neutron detectors are more sensitive to lithology and are affected by borehole and formation salinity. The dual detector method is used to compensate for these environmental effects. Applications • Gas detection • Porosity • Lithology

HAL1664

The DSN™ dual-spaced neutron tool is a thermal neutron tool designed to measure formation porosity from neutronnuclei interactions. Neutron porosity logs provide total fluid information for use with resistivity logs and/or pulsed neutron logs in determining formation water saturation. They can be combined with density logs to provide an indication of formation gas saturation and also with density and/or sonic logs to provide indications of formation lithology. In open holes, the DSN tool is usually combined with the SDLT™ spectral density logging tool and the NGRT™ natural gamma ray tool. In cased holes, the DSN tool is usually combined with the NGRT tool and DITS™ casing collar locator.

In this DSN™ log example, the subject well was logged twice. The resulting near/far ratio curves and the calculated porosity curves are overlaid to illustrate the high repeatability of DSN tool porosity measurements.

Features • Detector array contains two helium proportional counters • Optimized detector spacing, advanced calibration methods, and greater counting rates • Faster log runs • Delineation of thin-bed formations with enhanced vertical resolution (EVR) available in real-time or in post-processing • A combination of logging tools can be run to identify lithology, reveal gas zones, and calculate shale volumes


3-19

Associated Answer Products • Wellsite answer product is the neutron porosity NPHI • Neutron porosity data is also used with other open-hole sensors as input to Halliburton’s mineralogy, open-hole, and cased-hole saturation analysis to provide a complete formation evaluation product. These include:

– ULTRA™ multi-mineral evaluation program – CORAL™ complex lithology analysis – LARA™ laminated reservoir analysis – SASHA™ shaly sand analysis

DSN™ Dual-Spaced Neutron Tool Specifications

3-20

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

10.25 (3.1)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

196 (88.9)


DSEN™ Dual-Spaced Epithermal Neutron Log Tool The DSEN™ dual-spaced epithermal neutron log tool is a subsurface logging tool that provides a measurement of epithermal neutron porosity. It is used primarily in air-filled wells or in fluid-filled wells where shales and/or formation salinity adversely affect thermal neutron measurements. In open boreholes, the DSEN tool is usually combined with the SDLT™ spectral density logging tool and the NGRT™ natural gamma ray tool.

Associated Answer Products • Epithermal neutron porosity (wellsite) • Neutron porosity data is also used with other open-hole sensors as input to Halliburton’s mineralogy, open-hole, and cased-hole saturation analysis to provide a complete formation evaluation product. These include: – ULTRA™ multi-mineral evaluation program – CORAL™ complex lithology analysis

Applications • Neutron porosity measurements in water or gas filled boreholes


• Gas detection in the formation or in filled wellbores when combined with density measurements • Porosity curve measurements that are less affected by thermal neutron absorbers in shale, such as boron and gadolinium Features • Less affected by formation water salinity • Combinable with other tools • Optimized dual neutron detector design combines twodetector responses for enhanced accuracy • Uses a steady-state neutron generating source (radioactive americium-beryllium, AmBe) and two epithermal neutron detectors to investigate formation porosity • Provides reliable porosity measurements even in air, gas, and foam-filled boreholes • Provides consistent, repeatable data over entire porosity range

HAL1663

• Requires minimum corrections in high-temperature environments, such as steamfloods and high-porosity formations

DSEN™ log computed assuming a limestone matrix. The bottom of the well is liquid filled. From x534 to the top, the well is air filled. Formation gas is indicated when the density porosity becomes greater than the neutron porosity. This log reveals good gas zones from x586 to x427.

DSEN™ Dual-Spaced Epithermal Neutron Log Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

7.25 (2.2)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

170 (77.1)


3-21

CSNG™ Compensated Spectral Natural Gamma Ray The CSNG™ compensated spectral natural gamma ray tool measures the gamma ray spectrum from 0 to 3,000 keV. The tool uses full-spectrum processing to provide precise and accurate logs of potassium, uranium, and thorium concentrations. Measurement precision curves and tool diagnostics help validate logging data quality.

Associated Answer Products • Output from the CSNG spectral processing includes total gamma ray and elemental concentrations of potassium, uranium, and thorium • Clay typing, volumes, and cation exchange capacity can be compared using CLAMS analysis software

The CNSG tool's unique stabilizer system differentiates it from the competition by compensating for temperature related drift in the gamma ray energy gain and offset conversion. The full-spectrum processing performs additional refinement of the energy calibration and compensates for variations in detector resolution. Another unique feature of the CSNG tool is its ability to provide real-time outputs corrected for the borehole environment and converted to standard conditions (8.625-in. borehole, freshwater in borehole, no casing, and tool eccentered). Estimates of borehole potassium concentration and photoelectric absorption made during the log are helpful to confirm real-time corrections or to apply corrections in a recomputation mode. Also, removal of borehole potassium signal produces accurate total gamma ray and elemental yields in potassium muds. Applications • Detection of producible zones • Determine clay types, volumes, and cation exchange capacity using elemental concentration data and CLAMS™ clay and matrix analysis post-processing analysis Features • Measures and records energy of individual gamma rays

CSNG™ log with gamma ray contributions from thorium, potassium, and uranium

• Elemental yield calculations are insensitive to photoelectric absorption in barite muds or other high-Z materials • Filtering technique improves the statistical precision of the elemental yields • Forms a spectrum of gamma energies indicating the number of gamma rays recorded at each energy level • 0 to 3 MeV spectrum facilitates determination of potassium, uranium, and thorium weight concentrations in the formation • Reduced cross-correlation among elemental yields

3-22


LOGIQ® CSNG™ Compensated Spectral Natural Gamma Ray Specifications Housing

Makeup Length ft (m)

Diameter in. (mm)

Maximum Pressure* psi (Mpa)


Weight lb (kg)

Titanium

14.9 (4.5)

3.625 (92.1)

14,000 (96.5)

350 (176.7)

271 (122.9)

Low Z

12.9 (3.9)

3.625 (92.1)

8,000 (55.2)

275 (135)

260 (117.9)

HAL23446

*Please refer to the CSNG Pressure Rating Chart below.


3-23

Acoustics BSAT Borehole Compensated Sonic Array Tool Halliburton's BSAT service integrates two monopole transmitters with an array of five receivers. This tool configuration provides borehole compensation of the P-wave measurement. The full waveform data is digitally recorded for each receiver, thus permitting advanced data analysis and quality control for waveform amplitude, slowness, and arrival time in both open-hole and cased-hole applications.

• Can be used as CBL tool in combination with any LOGIQ® cased-hole services

The BSAT tool is over 12 ft shorter than many other acoustic logging tools. While not compromising data quality, the reduction in tool length helps speed up rig-up and rig-down times, especially when lubricator and pressure control equipment are required. The P-wave slowness is obtained using a robust waveform cross correlation coherency process which utilizes the waveform data from the entire receiver array. The process evaluates many attributes of the waveform data before selecting, in real time, the acoustic velocities of the formation. The BSAT tool can also be used for 3-ft to 5-ft CBL-VDL measurements and can be run in combination with any IQ tool services. Applications • P-wave slowness used for sonic porosity determination • Time-to-depth correlation • Synthetic seismograms • Identification of pore pressure changes • 3-ft to 5-ft CBL-VDL measurement • Instantaneous waveform attributes Features • Waveforms can be recorded at high logging speeds • The P-wave slowness is obtained using a robust waveform cross correlation semblance process • Downhole digitization helps eliminate the transmission noise and improve signal-to-noise ratio. Compression technique allows high uplink data transfer rate

Gamma ray, VpVs, and caliper presented in Track 1. Compressional and refracted shear are presented in Track 2. Semblance with compressive and shear slowness overlaid on the semblance image are presented in Track 3.

BSAT Borehole Compensated Sonic Array Tool Specifications

3-24

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

15.83 (4.82)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

318 (144.4)


WaveSonic® Tool The WaveSonic® crossed dipole sonic tool provides simultaneous monopole, XX dipole, and YY dipole sonic measurements. The dipole flexural wave propagation allows for the measurement of shear wave slowness in virtually all formation conditions. The compressional P-wave slowness, refracted shear wave slowness, and Stoneley wave properties are obtained from the monopole data. The shear wave slowness in two orthogonal directions can be obtained in real- time from the XX and YY dipole data. The WaveSonic tool is combinable with all standard open and cased-hole tool services. The WaveSonic tool requires a liquid filled borehole and can be used in freshwater, saltwater, or oilbased mud systems. The robust mechanical design of this tool allows for drillpipe conveyed logging, and it is not limited to the bottom of the toolstring. A hostile WaveSonic version is available for high-temperature and high-pressure applications. The shear wave slowness in the XX and YY directions and the monopole P-wave slowness are the basic well site deliverables. The tool has 32 broadband receivers, arranged in eight rings of four receivers, to provide high-quality waveform data. The tool provides 96 waveforms (32 monopole, 32 YY dipole, and 32 XX dipole) for each firing cycle, which are recorded by the surface system. The fast and slow shear wave travel times are obtained with advanced waveform processing methods in Halliburton's reservoir evaluation services centers, strategically located throughout the world. From the fast and slow shear wave travel times, and their orientation in the formation, the minimum and maximum principal stresses and stress field orientation can be obtained by combining oriented slowness data with overburden and analysis, wellbore stability, and production enhancement treatment design.


Natural gamma ray and caliper are presented in Track 1. Semblance quality data is presented in the depth track. The dipole X travel time, dipole Y travel time, and monopole P-wave travel time are presented in Track 2. Monopole semblance with the compressive wave slowness overlaid on the semblance image are presented in Track 3. The dipole X semblance with the XX shear wave slowness overlaid on the semblance image are presented in Track 4. The dipole Y semblance with the YY shear wave slowness overlaid on the semblance image are presented in Track 5.

3-25

Sonic anisotropy analysis provides the fast and slow shear wave travel times as a simultaneous solution of 64 waveforms (32 XX and 32 YY). Anisotropy and its orientation can be used to determine the minimum horizontal stress and the orientation of natural fractures. The sonic attributes of slowness, amplitude, and frequency content can be used for identification of fractures and compressive fluids and to measure various geomechanical properties. The fast and slow shear wave travel times and their orientation, combined with P-wave slowness, allows for better 3D seismic analysis.

• Broadband eight-level, quad receiver array for highquality waveform data

Applications • Determine fast and slow wave travel times and orientation in the formation

• RockXpert2™ sand production and fracture strength analysis

• All 96 waveforms for each set of transmitter firings are recorded at the surface for advanced waveform processing techniques • Combinable with all open-hole tools, including MRIL® and RDT™ tools and services Associated Answer Products • Shear slowness anisotropy analysis

• FracXpert™ fracture stimulation zoning analysis pore pressure data information is vital for geo-mechanical

• Calculate minimum and maximum principal stresses and stress field orientation

• Instantaneous waveform attributes

• Porosity estimation

• Stoneley derived permeability

• Fracture identification

• Stoneley reflection analysis

• Permeability (mobility) estimation

• Formation stress, borehole stability, and sanding potential

• AVO calibration • Synthetic seismogram Features • Programmable-frequency sources to minimize effects of near-wellbore alteration

WaveSonic® Tool Specification Length ft (m)

Diameter in. (mm)



Weight lb (kg)

34.0 (10.3)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

520 (236.3)

Hostile WaveSonic® Tool Specification

3-26

Tool Version

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

20 kpsi Tool

40.9 (12.4)

3.13 (79.4)

20,000 (137.9)

500 (260.0)

595 (269.9)

30 kpsi Tool

40.9 (12.4)

3.13 (79.4)

30,000 (206.8)

500 (260.0)

720 (326.6)


FWS™ Full Wave Sonic Tool The FWS™ tool provides compressional wave, refracted shear wave, and Stoneley wave properties of downhole formations for a wide range of petrophysical, geological, and geophysical applications. To minimize the number of logging trips required for complete formation evaluation, the FWS tool is compatible with all DITS™ logging tool strings. A liquid-filled borehole is required for sonic logging and can be used in fresh, salt, or oil-based mud systems. The long transmitter-to-receiver offset allows for the acquisition of borehole sonic data beyond the effects of any near-wellbore altered region. This long offset also allows for the acquisition of high-quality sonic data in enlarged boreholes where critical angle effects would affect sonic tools with short transmitter-to-receiver offsets.

• Slowness presentation – compressional slowness and refracted shear slowness, velocity ratio, and time-depth integration of the compressional and shear travel times, and other logging data such as gamma ray and caliper • Quality presentation – indicators which establish confidence levels for the slowness processing, including compressional slowness and semblance coherency and refracted shear and semblance quality gain curves for each receiver

HAL9170

The information obtained from the FWS tool is plotted in three separate log presentations:

The natural gamma ray, X-X caliper, Y-Y caliper, P-wave travel time and P-wave semblance quality are presented in Track 1. The monopole waveform data is presented in Track 2 in the MicroSeismogram™ format (X-Z) and in an X-Y waveform presentation in Track 3.

• Waveform presentation – waveforms from all four receivers can be presented. Gain curves reflecting the gain applied to the waveform by the automatic gain control (AGC) circuit, and correlation curves, including gamma ray and caliper information The FWS tool can be run in the cased-hole environment to obtain sonic properties through casing. Acoustic coupling of the pipe-to-formation is required for cased-hole applications. Applications • Identify wave properties of downhole formations • Acquisition of borehole sonic data


3-27

Features • Long transmitter-to-receiver offsets and 1 ft receiver-to-receiver spacings

• Lithology identification by means of velocity ratio, Δts/ Δtc, and location of gas zones, even in poor hole conditions and cased holes

• Detection of signals at all receivers for each transmitter pulse ensures constant source characteristics

• Indication of permeability variations with depth from Stoneley wave attenuation and slowness

• Automatic gain control of each receiver preserves signal amplitude • Downhole digitizing helps eliminate transmission noise and allows broadband frequency response • Low-frequency response allows detection of low frequency Stoneley waves and multiple Δt measurements per depth interval • Continuous uninterrupted recording of full waveform signals

• Detection of naturally fractured zones, determination of rock elastic constants, and estimation of formation strength and least horizontal stress • Prediction of vertical extent of hydraulic fractures • Improved vertical resolution for detection of thinner beds (Beds as thin as 3 in. can be identified with the t curves) • Calculates sonic porosity from P-wave slowness and can determine secondary porosity by combining sonic porosity with neutron and density porosity data

• Records various types of information including tool data, quality curves, and final results • Operator-selectable multiple modes of tool operation, digitally recorded waveform data, and improved porosity estimates using both Δtc and Δts

• Time-to-depth correlation for seismic correlation • Combining sonic slowness data with formation density data is the required input information needed for synthetic seismograms

FWS™ Full Wave Sonic Tool Specifications

3-28

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

28.6 (8.7)

3.625 (92.1)

20,000 (137.9)

350 (176.7)

460 (208.7)


NMR MRIL-XL™ and MRIL®-Prime Magnetic Resonance Image Logging Tools The MRIL-XL™ tool is the latest family member of Halliburton's wireline NMR logging tools. Both the MRILXL and MRIL®-Prime should be considered the first choices for primary formation evaluation in open holes. NMR logging answers the four basic, critical questions all well operators must answer to understand the economics of a newly drilled prospect: • Has the well penetrated reservoir rock? (What is the total and effective porosity in a complex lithology environment?)

• What is the ability of the reservoir to produce these hydrocarbons, i.e. will they flow in this type of formation? (What is the permeability?)

HAL18923

• What types of fluids (hydrocarbons) are present in the reservoir and how are they distributed?

MRIL-XL™ Service

• Will there be associated water production (BVI/FFI)? The MRIL-XL and MRIL-Prime tools utilize the very same principles as medical MRI by directly measuring the magnetic resonance of hydrogen atoms in fluids. Amplitude of the measured signals gives porosity, whereas the actual signature carries information on rock properties and fluid characteristics. Applications The MRIL® tools are used in open-hole logging programs to:

• Provide a permeability profile along the well. (Note that standard perm values are not calibrated; this requires integration with core data.) • Provide fluid-typing (gas-oil-water), find fluid contacts, identify changes in oil viscosity

HAL1716

• Obtain minerology-independent measurements of porosity. The MRIL tools truly measure the amount of fluid in the pore space and do not measure rock matrix. Unlike density, neutron, or sonic porosity devices, which require accurate matrix and fluid-density or Δt-matrix and Δt fluid to compute porosity, the MRIL tools are uniquely a minerology-independent porosity tool(s), yielding clay-bound water porosity, irreducible porosity (i.e. volume of bound fluid), free-fluid porosity, and total porosity

MRIL®-Prime Service

• Identify low-resistivity and/or low-contrast pay zones


3-29

Features As an eccentered NMR tool, the MRIL-XL™ signal penetration into the formation is effectively increased in large boreholes, and the effects of drilling mud are eliminated. MRIL-XL service is available with a standard 6-in. sonde to accommodate holes sizes from 7.875-in. to >12.25-in. and is especially effective in large deviated boreholes. MRIL®-Prime is available in two sizes (slim sonde has 4.875-in. OD and standard sonde has 6-in. OD) to accommodate hole sizes from 5.875-in. to 12.25-in. Both MRIL services may be operated at up to 9 RF-frequencies— allowing data acquisition to be fast and efficient.

• Multi-frequency capability allows operators to acquire much more accurate data by combining the measurements made in each volume (at each different frequency)

• Each frequency creates an independent volume of fluids in the formation, which allows the tool to log considerably faster than any single frequency NMR tool

These huge amounts of reservoir information from a single device are extremely valuable for optimizing stimulation and completion programs, thereby optimizing the productivity of each well drilled.

• Both MRIL services can acquire simultaneous T1 and T2 logs and all MRIL services have maximum temperature ratings of 350°F • Through-wire and switching sub adapters offer ultimate combinability with other Halliburton tools and competitor tools • Compatible with drillpipe or tubing conveyed type logging systems in highly deviated wells • Accurately measures porosity in mixed mineralogy reservoirs • Improves completion success in low-permeability reservoirs • Identifies pay zones in laminated, fine-grained sand, and shale formations • Increases access to reserves by providing complete and accurate analyses of low resistivity/low-contrast intervals • Identifies zones of water-free production

• Only product to allow combining of different measurements probing different NMR properties of the fluids and formation in one single pass—a major step forward in fluid identification and quantification • Has successfully pioneered the discovery of oil in zones which triple-combo has traditionally bypassed, leading to increased production of reserves and some spectacular discoveries in even mature production areas

Associated Answer Products • MRIAN™ MRI analysis – an integrated analysis which incorporates MRIL porosity from T1 and/or T2 plus resistivity data in the dual-water model • TDA™ time domain analysis – a MRIL only fluids and porosity analysis derived from analysis of the raw NMR echo train data only • DTW dual wait time analysis – an analysis of hydrocarbon type or types found within each reservoir. Obtained by operating the MRIL service using a short and long Tw (wait time, such as 1s and 12s) in a single logging pass • DTE dual echo time analysis – an analysis of hydrocarbon or other fluids within each reservoir. Obtained by operating the MRIL service using two different Te (inter-echo spacing, such as a short Te of 1.2ms and a longer Te of 6ms or longer)

MRIL®-Prime Magnetic Resonance Image Logging Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

6

52.9 (16.1)

6.00 (152.4)

20,000 (137.9)

350 (176.7)

1,475 (669.1)

4.875

50.4 (15.4)

4.875 (123.8)

20,000 (137.9)

350 (176.7)

1,275 (578.3)

Sonde in.

MRIL-XL™ Service Specifications

3-30

Sonde in.

Length ft (m)

Diameter in. (mm)

Maximum Pressure psi (MPa)


Weight lb (kg)

6.0

45.7 (13.49)

6.00 (152.4)

20,000 (137.9)

350 (176.7)

1,600 (726)


MRILab® Magnetic Resonance Image Fluid Analyzer Halliburton's patented MRILab® service is another breakthrough development of nuclear magnetic resonance imaging technology for oil and gas operators. The service provides laboratory-quality fluids measurements at reservoir conditions in real time by directly measuring the magnetic resonance parameter T1. Because contaminates mixed with crude oil modulate the T1 response, these measurements can be interpreted to determine when a clean sample can be taken and saved in Halliburton's RDT™ reservoir description tool sample chambers. This ability to provide downhole laboratory-quality fluid measurements makes the MRILab service an integral component of the RDT tool. The MRILab service allows operators to measure relaxation times on reservoir fluids in-situ at true reservoir conditions—an important industry first. The measured T1, T2, and the self-diffusion coefficient (D) of the reservoir fluids tie directly into important fluid characteristics such as viscosity and apparent Hydrogen Index. This makes the MRILab service approach superior to traditional reservoir fluid sample processing that involves transferring samples uphole at the wellsite for conventional laboratory analysis. These measurements are significant for completion and reservoir engineering as well as for reservoir understanding, and they are available at the wellsite immediately where they will have the most value. Features • Identifies connate oil vs. oil-based mud filtrate differentiation • Provides accurate fluid data for MRIL® log interpretation either wireline or LWD • Measures hydrocarbon viscosity in-situ • Complements MRIL logging service and extends the application of MRI technology in reservoir fluids determination

MRILab® service is a modular component to the RDT™ reservoir description tool, providing real-time fluid analysis while pumping out to determine optimal time to obtain the cleanest samples possible.

• Can be conveyed on wireline or drillpipe • Measures the magnetic resonance properties of reservoir fluids as the RDT pumps from the reservoir into the borehole or sample chamber • Measures T1 of fluid in the flowline while pumping with the RDT • Measures T2 and diffusivity of stagnant fluid in the flowline


3-31

• Available immediately at vastly reduced cost compared to conventional laboratory measurement. Surface laboratory PVT analysis is both expensive and can take weeks or months to produce results. The actual task of collecting a reasonably uncontaminated reservoir fluid sample can require significant rig time. And during that time the clock is running on the well operators' and other contractors' time, rental equipment, and personnel costs. It is not uncommon for physical drillstem tests for viscosity and other key fluid properties to cost the operator hundreds of thousands of dollars when all the expenses are calculated • More accurate measurements of native oil than other methods. Since the MRILab® measurements occur downhole on in-place and unaltered reservoir fluids, there is no direct human manipulation and no opportunity for the errors that can occur in surface lab work. The well operator can have confidence in the viscosity oil characterization measurement results on the native oil in place in the reservoir • Results are available in real-time at the rigsite or by remote viewing. Viscosity and oil characterization are important attributes usable for making completion decisions • Producing this information right away at the rigsite makes MRILab data infinitely more valuable than surface lab data that may be delayed for over a month. Similarly, the MRILab tool is equipped with real-time telemetry capability that makes the results of the measurements viewable remotely over a secure connection between client and the tool Health, Safety, and Environmental The ability to analyze the filtrate contamination level of reservoir fluids in real-time allows one to minimize the volume of fluid that is pumped from the formation into the wellbore before securing the fluid into the sample chamber. Further, real-time analysis of the reservoir fluids may reduce the number of samples that are required, thus eliminating the need for transfer and transport of hazardous fluid samples.

FluidXpert™ fluid analysis service – Real-time NMR fluid analysis from the MRILab® service while pumping out to determine optimal time to obtain sample. Available while pumping: real-time contamination estimation, fluid type probability, T1 spectra, Hydrogen Index, capacitance, pressures, temperature, and pump rate. Available in real time at the wellsite and in a customer's office via InSite Anywhere® service.

MRILab® Service Specifications

3-32

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

14 (4.3)

4.75 (120.7)

20,000 (137.9)

350 (176.7)

400 (181.4)


Borehole Geophysics Wellbore Seismic High Resolution Seismic Imaging—(Near Offset VSP, Fixed Offset VSP, Walkaways, 3D VSP, Salt Proximity Surveys, Microseismic Surveys) Halliburton provides high-resolution images in the vicinity of the borehole using a number of different techniques depending on the objectives and the geologic environment. The techniques include vertical incidence vertical seismic profiles (VIVSP) in deviated wells, salt proximity surveys, tomographic velocity analysis, fixed offset VSP surveys (FOVSP), 2D walkaway surveys, 3D VSP, and ExactFrac® or microseismic surveys.

High Resolution Seismic Imaging Features • Generation of high-resolution multiple free images

Halliburton is an industry leader in providing advanced source and downhole array technologies for borehole seismic. Halliburton’s expertise serves to benefit operators with reduced rig time and improved data quality. Advanced source and receiver technology is crucial towards obtaining a more accurate and comprehensive geological picture of your well, field, or reservoir.

High Resolution Seismic Imaging Applications • Profiling salt dome flanks

Halliburton can offer custom built solutions for client’s seismic imaging field needs. For survey planning, we use the most advanced 3D wavefront modeling software available, GeoTomo’s VECON software.

• Anisotropy determination

Multi-component arrays can be mobilized downhole to more accurately record true amplitude information of both compressional and shear waves.

• Mapping of steep structures (such as salt flanks) • Detailed velocity cubes in areas of laterally changing velocity (shallow gas, permafrost, salt, etc.) • Map structure, stratigraphy, lithology, and fluids with higher resolution and confidence than can be obtained with surface seismic • Improve a poor data quality area or overcome no-data areas

• Detecting natural fractures • Enhanced seismic velocity analysis • Primary seismic reflector identification • Porosity and permeability estimation • AVO analysis • Determine height, length, and width of well frac or stimulation process Associated Answer Products • Vertical incidence VSP • Synthetic seismogram

Compressional and shear images can be used in conjunction for lithology and fluid identification. Surveys can be repeated for time-lapse 4D views of fluid movements.

• FWS™ full wave sonic processing • ExactFrac® services

Downhole seismic tools can also be used to passively listen to the reservoir and to map fluid movements, fault reactivation, or active fracture monitoring. A full array of tools is available for analyzing high resolution seismic data for reservoir imaging. Halliburton offers advanced pre-processing, including multi-component wavefield separation and final imaging using pre-stack depth migration (PSDM).


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Reservoir Geophysics

Synthetic Seismic and Sonic Log Calibration

Long Array Multi-Component Acquisition Tools Halliburton offers survey planning, data acquisition, and data processing using multi-component long seismic arrays. Each tool combines advanced-source technology with industry leading multi-component and anisotropic migration software for a complete package of advanced custom designed reservoir imaging systems. Systems include the GeoChain™ VSP downhole receiver array.

The synthetic seismogram obtains an accurate tie between well logs measured in depth and the surface seismic image measured in two-way time. Correlation between logs and seismic is important to verify interpreted horizons and to help determine the true phase of the surface seismic (important for advanced lithologic and fluid interpretations from seismic data).

GeoChain VSP Downhole Receiver Array The GeoChain vertical seismic profile (VSP) array is designed for large borehole imaging surveys and can be used in open and cased holes with standard seven-conductor cable even in deep and hostile environments. GeoChain VSP Receiver Array Features • Based on the proven ASR-1 downhole geophone • Can be used in wells up to 25,000 psi and with hole sizes from 3.5-in. to 22-in. • Unique ACS™ active cooling system allows continuous operation up to 356°F (180°C) • Up to 42 satellites can be used in the array with a maximum tool spacing of 200 ft • All satellite locking arms open and close simultaneously, and the entire string can lock into a 9.625-in. well in only 30 seconds • Can be run in the following configurations: No. of Tools

Sample Rate

5

1/2 ms

10

1 ms

21

2 ms

26

2.5 ms

32

3 ms

42

4 ms

Associated Answer Products • 3D VSP imaging • 2D VSP imaging • Interwell imaging

An accurate synthetic depends on sonic log calibration using data from a vertical seismic profile (VSP) or check shot survey. This calibration is necessary for a number of reasons such as: • Sonic log and surface seismic are measured at different frequencies (dispersion) • Sonic log and surface seismic can measure different rock and fluid volumes (fluid differences, invaded zones, damaged borehole, non-vertical ray paths, etc.) Calibration of the sonic log includes an analysis of the data to determine the cause of the differences (drift) between the sonic and the check shots. Depending on the cause of the drift, different methods of correction are used. The corrected sonic log is converted to interval velocity. Acoustic impedance is calculated using the corrected velocity log and the bulk density. Changes in acoustic impedance are used to create a reflection coefficient log, which is subsequently convolved with a desired wavelet to create a synthetic seismic trace. Recording of a shear sonic log or calculation of a synthetic shear log allows calculation of a 2D synthetic to analyze or predict AVO effects on the surface seismic. Perturbation of the rock parameters also allows study of the effects of fluid and lithology changes on the seismic character. Synthetic Seismic Features • Helps promote accurate tie between well logs and surface seismic including phase determination • Allows identification of multiples on the surface seismic • Allows study of fluid and lithology effects on the seismic character

• ExactFrac® (microseismic) services Associated Answer Products • Vertical incidence VSP • High resolution seismic imaging (walkaway, fixed offset, 3D VSP, salt proximity, AVO Studies) • FWS™ full wave sonic processing

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Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis The VIVSP analysis is a downhole seismic survey with the quality seismic data. The rugged, computerized logging surface source positioned vertically above the geophones systems precisely position the geophone tool in the well, anchored in the well. In a vertical well, it is known as a zero properly synchronize the energy sources, and accurately offset VSP (ZOVSP) with the source positioned in a single transfer the measured data to the surface. The data obtained location near the wellhead. In highly deviated wells, the from VSPs provide extremely important information for source is moved along with the downhole geophone tool to enhancing and supplementing surface seismic data. keep the source vertically positioned above the geophone VIVSP Features tool at each level. • Allows detailed analysis of the downgoing and upgoing VIVSP analysis is useful for facilitating more accurate timewavefield depth correlation between your well logs and your surface • Real seismic trace rather than synthetic for log seismic seismic. It is also useful for determining the phase of your correlation surface seismic and for identifying multiples. • Provides detailed velocity analysis VIVSP data provides an indispensable bridge between sonic log data and surface seismic data. In areas where it is difficult to obtain a good tie between the synthetic and the surface seismic, the VIVSP can be helpful to identify and resolve the differences. VIVSP is also very useful for predicting lithology, fluids, and pore pressure ahead of the bit. Velocity trends that are useful for predicting pore pressure are calibrated at the well. VIVSP data is typically higher frequency than the surface seismic and can be used to better understand the reflectivity seen in the surface seismic.

VSP Applications • Direct correlation between surface seismic data and logs recorded in depth • Calibrate wireline sonic data for correlating synthetic seismograms with conventional seismograms • Mapping geologic structure in the vicinity of the wellbore • Predict stratigraphy, lithology, and structure ahead of the drill bit to help save drilling time and costs • Improve poor data-quality area or overcome no-data area • Helps profile salt dome flanks • Helps detect natural fractures

VIVSP data can be useful for computing the dip of the reflecting horizons in the vicinity of the borehole.

• Aids seismic identification of lithology

This can be used to confirm dips seen on dipmeter tools and help project these dips away from the well.

• Enhanced seismic velocity analysis

In deviated wells, the VIVSP also delivers a high resolution 2D image beneath the wellbore. This image is typically higher frequency than the surface seismic, multiple free, and tied directly to the wellbore in depth. Halliburton uses advanced proprietary software to handle VSPs in the most demanding geologic environments (advanced editing, multi-component wavefield separation, interpolation, deconvolution, and migration tools). VSP software and processing can be used in the field, in a computing center linked to the wellsite, or in the client offices for special projects. VSP acquisition teams utilize customized energy sources and the most advanced seismic tools available to record high-


• Prospect delineation • Primary seismic reflector identification • Analyze multiple patterns • Deconvolution operator for surface seismic data processing • Porosity and permeability estimation • 2D and 3D stratigraphic and structural imaging • Helps locate overthrust granite/sediment interface • AVO analysis Associated Answer Products • Synthetic seismogram • High resolution seismic imaging (walkaway, fixed offset, ocean bottom cable, salt proximity, AVO studies) • FWS™ full wave sonic processing

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ExactFrac® Services Halliburton eases frac modeling concerns by taking a fullservice approach to logging, offering both dipole sonic and borehole seismic services. To give engineers the answers they require, our microseismic techniques provide real-time assessments of fracturing processes using two wells: • A stimulation well where actual frac jobs are under way • A monitor well equipped with a downhole geophone tool array with multiple sensors

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These microseismic techniques provide accurate information on the length, height, and distance of the frac being generated in the formation and can dramatically optimize the placement of future wells. ExactFrac Services Features • Allows operators to optimize drilling program in field • Improves later frac jobs (only zone you need to frac) • Minimizes uncertainty in your fracturing program


Sampling RDT™ Reservoir Description Tool RDT™ reservoir description tool is a modular, combinable formation tester and fluid-sampling tool. The RDT tool provides accurate pressure measurements. High-quality clean and representative formation fluid samples are collected, along with a broad range of valuable reservoir data. This is accomplished through: • Pressure-gradient testing • Permeability anisotropy testing • Formation fluid properties monitoring • Zero Shock™ pressure/volume/temperature (PVT) sampling The RDT Zero Shock PVT sampling method eliminates unanticipated fluid expansion and pressure shocks during pumping and sampling through its advanced digital control feedback system, which maintains a constant flowrate throughout the sampling process. Two closely spaced probes are standard, providing redundant packer seals and probes. In-situ PVT bubblepoint testing is performed while pumping to determine the ideal sampling pressure for oil-bearing reservoirs. Sample chambers are filled against hydrostatic pressure and additional pump pressure can be applied to maintain the sample in the single-phase condition while retrieving reservoir fluid to surface. Bubblepoint, compressibility, density, and resistivity are fluid properties which are monitored while pumping. In addition, spherical mobility, horizontal mobility, and anisotropy are monitored. When the MRILab® section is added, additional fluid properties including Hydrogen Index (HI), T1 and T2 distributions, log mean T1, viscosity index, and capacitance are also monitored. Because these properties are monitored real-time, operators are able to identify the optimum point at which to divert fluid flow and collect samples.

• Verify reservoir isolation • Detect interwell communication • Quantify field-wide pressure trends Features • The 100 cc pre-test chamber allows for rate- or pressurecontrolled fluid entry to ensure accurate bubblepoint and PVT analyses. The large volume chamber also allows multiple pretests per pad set without releasing the pad from the borehole wall • Dual probe configuration provides improved horizontal and vertical permeability estimates due to probe proximity • Determine real-time horizontal and vertical mobilities while sampling or pre-testing • Dual probe configuration provides high reliability and redundancy with multiple quartz and strain gauge pressure measurements • Fluid type identification and contamination monitoring is used to discriminate between filtrate and formation fluid and to determine the optimal time to collect a fluid sample. Each multichamber section includes three 1,000 cc PVT sample chambers • Multiple fluid property sensor outputs are combined to yield reliable hydrocarbon/fluid typing even in oil- or synthetic-based mud • Powerful pump reduces cleanup time, contamination level, and saves rig time • Three flow control pump-out sections, configured for 4,000; 6,000; and 8,000 psi pump pressure provide extended range pressure sampling capabilities in highly depleted or overbalanced conditions • Zero Shock™ flowrate control ensures sample integrity

Applications • Identify depleted and overpressured zones • Assess reservoir fluid types and contacts • Collect uncontaminated, representative, PVT-quality reservoir fluid samples • Determine reservoir fluid PVT behavior • Determine formation permeability and anisotropy • Assess reservoir compartmentalization


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Pressure Testing and Zero Shock™ Sampling

DPS

Low Mobility and Laminated Pressure Testing and Zero Shock™ Sampling

Mini-DST and VIT Pressure Testing and Zero Shock™ Sampling

OPS OPS

QGS

QGS

FPS

FPS

DPS

QGS MCS

Mini-DST and VIT Pressure Testing and Zero Shock™ Sampling with Straddle Packer

MCS

DPS

QGS

SPS

QGS FPS

MRILab

MRILab

FPS

MCS MCS MCS

MCS MRILab MRILab

MCS MCS

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DPS Dual Probe Section The DPS section deploys two independent probe/pad assemblies against the borehole wall for pressure drawdown/ buildup analysis and pumping formation fluid. The DPS is designed to detect horizontal mobility (kh/μ), permeability (kh), and anisotropy (kv/kh) over an extended range of operation. The DPS pressure testing flowrate is precisely controlled with the advanced digital control feedback system, thus achieving steady-state pressure quickly and reducing required testing time. By running two dual probe sections in tandem, the RDT™ tool is used determine the pressure between the probes and profile permeability and anisotropy. This further enables an extended depth of investigation and detection of permeability barriers. Features • Design redundancy – two flow paths • Operational efficiency • Different pad configurations • Closely spaced – enhanced permeability • Probe shut-in valve – reduced flowline storage volume • Faster buildup times – tight zones • Resistivity fluid ID sensor • Drawdown rate control 0.1 to 15 cc/sec • Drawdown volume control 0.1 to100 cc Oval Pad Carbonate rocks, thinly bedded sands, and naturally fractured reservoirs can exhibit a very challenging logging environment when pressure testing and fluid sampling are required. The challenge is due to, at least, reservoir heterogeneity and the difficulty of sealing the probes in these reservoirs. The RDT utilizes a proprietary oval pad section (OPS) to help overcome all of these challenges. The oval pad spans a 9-in. vertical section of the borehole, giving it the sealing advantages of a straddle packer but still maintaining the operational flexibility of a probe. In particular, the oval pad design ensures an effective seal for the probe during formation testing and fluid sampling in the presence of vuggy and/or fractured carbonate rocks. In addition to the increased vertical sealing area, the oval shape can reduce the sampling time due to a focusing effect the pad has on nearwellbore flow. Simulations show that when the complete testing system performance is considered, the oval pad reduces pumping times compared to a standard probe and in some cases a straddle packer.


Straddle Packer The straddle packer section (SPS) offers advantages over probes in low permeability applications as well as heterogeneous environments. SPS incorporates a dual port design which offers unique benefits in non-horizontal wells when a density contrast exists between the drilling mud contaminant and reservoir fluids. The lighter fluid segregates towards the top of the packed-off interval. After initially pumping through both inlet ports and detecting reservoir fluid, one available option is to close the bottom port to flow only the lighter fluid through the top probe. Proper manipulation of the dual ports and taking advantage of naturally occurring fluid segregation of the fluids contained in the packed-off interval provides cleaner samples faster than samples attainable with only a single port tool. In carbonates, thinly bedded sands, and naturally fractured reservoirs, most of the production occurs from small features. Such features make sampling and reservoir characterization difficult with a probe. The probe is more likely to be placed in a location that is characteristic of the rock matrix, which usually results in a tight test. The SPS isolates a 1 m interval, which is normally ample to characterize heterogeneous rock. The primary advantage of an SPS is its ability to cover a vertical interval where a probe is a pinpoint evaluation by comparison. FPS Flow-Control Pump-Out Section Features • High pump rates-less contamination • Faster pump-out times-reduced rig time • Pump up or down (four-way valve) • Multiple pump capability and flexible location in string • Sampling flowrate – real-time control • Outlet gauge controls sample filling • Interchangeable pump pistons enable 4,000; 6,000; or 8,000 psi pumps • Instantaneous control (0.004 to 1.1 gpm) • Flowrate feedback control • Single phase samples QGS Quartz Gauge Section The quartz pressure transducer features 14.7 - 20,000 psi calibration at 350°F. Resolution is 0.02 psi with accuracy to ± [1 psi + 0.01% reading]. This sensor is just 0.75-in. OD × 2.25-in. long. Other properties include a low mass, which means shorter time to thermal stability and fast temperature compensation.

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MRILab® Section The MRILab® section measures in-situ reservoir fluid relaxation time at true reservoir conditions. The measured T1, T2, and the self-diffusion coefficient (D) of the reservoir fluids tie directly into important fluid characteristics such as viscosity index, fluid type, and contamination cleanup during pump-out. MCS Multi Chamber Section The MCS contains motorized chamber valves with three 1,000 cc sample chambers. The chambers are detachable, transportable, and approved by the US department of transportation (DOT) and national association of corrosion engineers (NACE). Single phase nitrogen-charged sample chambers are available. Nitrogen-charged sample chambers maintain the fluid sample at higher pressure than standard chambers while the fluid is cooled and retrieved to the surface. Nitrogen charged sample volume is approximately 550 cc at surface conditions.

CVS Chamber Valve Section The CVS contains motorized sample chamber shut-in valves, an expulsion valve, and a check valve which prevents backflush. The MCS carries up to two standard 2-3/4 gallon SFTT™ sample chambers typically used for large volume, non-PVT, water sampling. Associated Answer Products • PTA pressure transient analysis • In-situ real-time bubble point • Advanced analysis from Applied Formation Evaluation Centers

Sampling Tools Specifications Length ft (m)

Diameter in. (mm)

Minimum Hole Size in. (mm)

Maximum Hole Size in. (mm)



Weight lb (kg)

CVS

2.3 (0.7)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7)

75 (34.0)

4.75 (120.7)

6 (152.4)

18 (457.2)

17,000 (117.2)

350 (176.7)

QGS

4.2 (1.3)

20,000 (137.9)

400 (204.4)

10.6 (3.2)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7)

385 (174.6)

Slim Probe

5.0 @ Probe (127)

10.6

4.75 (120.7) 5.6 @ Pad (142.2)

6 (152.4)

17.5 (444.5)

20,000 (137.9)

350 (176.7)

385 (174.6)

6-in. Pad HPS

8.8 (2.7)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7)

296 (134.3)

FPS

12.0 (3.7)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7)

450 (204.1)

MCS

8.9 (2.7)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7)

290 (131.5)

PTS

7.0 (2.1)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7)

211 (95.7)

MRILab®

14.0 (4.3)

4.75 (120.7)

6 (152.4)

18 (457.2)

20,000 (137.9)

350 (176.7

450 (204.1)

SPS

18.6 (5.7)

4.75 (120.7)

6 (152.4)

12.25 (311.1)

20,000 (137.9)

350 (176.7)

858 (389.2)

Module

DPS

OPS

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102 (46.3)


SFT-IV™ Sequential Formation Tester IV Tool The SFT-IV™ sequential formation tester IV tool is used for gathering the quality formation data required to evaluate reservoir potential and plan well completions and is part of our comprehensive line of wireline formation testing services. This service includes a full suite of open-hole test tools designed to allow the best possible test in any formation under any condition.

• Temperature compensation crystal, attached to the pressure crystal, provides improved temperature compensation and pressure measurement accuracy • Crystal size and special construction features permit reliable transducer operation—even under harsh borehole conditions

Features • Surface controlled pre-test volumes (0 to 20 cc) • Multiple drawdown without pad resetting • Variable rate drawdown (0.1 to 0.33 cc/sec) • Backflushing of pre-test volume (0 to 20 cc) • Variable hydraulic pad seating pressure • Optional precision quartz gauge (14.7 to 12,000 ±1.0 psi accuracy) • All parameters necessary for a successful test—accuracy, adaptability, speed, and reliability—are designed into the test tool

HAL9152

• Pre-test does not start until the operator gives the command, allowing: – Verification of padset before starting pre-test – Evaluation of mudcake properties from padset data • Proprietary quartz transducer technology allows better response to pressure changes

The SFT-IV™ probe section is articulated to ensure that pad seals in deviated holes or washed out sections. It features surface selectable pretest volumes and up to three sample chambers.

SFT-IV™ Sequential Formation Tester IV Tool Specifications Length1 ft (m)

Diameter2 in. (mm)



17.8 (5.4)

5.5 (139.7)

12,000 (82.7)

350 (176.7)

Weight lb (kg) Varies

1 2

Without sample chambers. Standard configuration. Various chamber configurations are available for specific applications or formation conditions. Check with your local Halliburton representative for further information. The 2.75 gal (10.4 L) chambers are H2S compatible.


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SFTT™ Sequential Formation Test Tool The SFTT™ sequential formation test tool measures wellbore and formation fluid pressure at any point in the well with a petroquartz pressure transducer. The SFTT tool can also collect representative formation fluid samples for up to two test depths in one trip into the well. The following measurements are available for monitoring and recording at the surface system: • Hydrostatic (mud column) and formation pressures • Continuous recording of time so significant events during the test can be timed for computations • Pre-test volumes • Petroquartz pressures • Petroquartz pressure sample rate • Petroquartz transducer temperature

2 25 L9 HA

Features • Variable pre-test volumes (5 to 10 cc) • Drawdown rates (0.5 to 2 cc/sec) • Drawdown after padset established

The SFTT™ tool features ruggedized construction for measuring precise formation and wellbore-hydrostatic pressure readings. The SFTT tool can also collect reservoir fluid samples in two separate chambers for analysis of fluid properties with standard 2.75-gal chambers and optional 1.0, 5.0, and 8.0 gal chambers.

• Adaptable to H2S • Standard precision quartz gauge • Determine reservoir pressure • Identify gas and oil reservoir boundaries • Monitor reservoir intercommunication • Indicate areas of pressure depletion

• Determine chemical concentrations and reservoir fluid properties through laboratory analysis of retrieved formation samples

HAL703

• Estimate formation permeability by pressure/time curve correlation

The advanced Halliburton quartz gauge is standard and can measure pressures with an accuracy of ± (1.0 psi + 0.01% of the reading); resolution is 0.01 psi and a repeatability of 1.0 psi

• Measure flow and shut-in pressures vs. time

SFTT™ Sequential Formation Test Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

SFTT™-B

22.1 (6.7)

6.5 (165.1)

20,000 (137.9)

350 (176.7)

675 (306.2)

SFTT-C

18.9 (5.8)

6.5 (165.1)

20,000 (137.9)

350 (176.7)

525 (238.1)

Tool

The sequential formation test tool is also available for hostile environments. For more information, reference the HSFT™ hostile sequential formation tester tool on page 55.

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RSCT™ Rotary Sidewall Coring Tool The RSCT™ tool diamond-drills cores perpendicular to the borehole wall with continuous monitoring of the coring process. After gamma ray depth positioning, a backup shoe is extended to decentralize and hold the tool securely against the formation. A diamond bit rotating at 2,000 rpm cuts a 0.9375-in. OD, 1.75-in. long sample from the formation. Surface control of weight-on-bit optimizes drilling. After the sample has been cut, a slight vertical movement of the bit breaks the core sample from the formation. The bit containing the sample is then withdrawn into the tool and the core is punched into a receiver tube. An indicator reveals both the existence and length of the sample. The tool is then ready for the next selected core point.

HAL9183

The RSCT tool is used to obtain core samples in consolidated formations. A tubular shaped drill bit with diamond cutting edges is used to drill the core. The core is recovered as a cylindrical shaped plug of the formation. The system operates independently from other systems on the logging truck or skid. The only input required is a source of AC voltage. A recording device is necessary for recording gamma ray correlation data.

Applications Rotary core samples collected by the RSCT tool can be used to provide:

HAL9184

The downhole tool is controlled from the surface by use of the control panel.

• More accurate readings of porosity and permeability that reduce reservoir analysis variables. Microfractures in core samples taken with percussion tools cause false readings of porosity and permeability • Information useful in fine-tuning MRIL® data • Reliable data for rock mechanical analysis necessary for hydraulic fracturing design, wellbore stability analysis, and sand potential prediction


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Features • Allows 30 or more cores to be taken in one run • Can be run on Toolpusher™ service or coiled tubing to acquire cores in deviated, extended reach, and horizontal wells • A core length indicator takes the guesswork out of core recovery • Stand-alone tools can be run on third-party logging units • Originally designed to recover cores in hard rock formations inaccessible with percussion tools, the RSCT™ tool can be used with equal success in soft rock formations

• Gamma ray tool positioning provides accurate core point location • Core samples are undistorted with consistent cylindrical geometry which allows a wide range of petrophysical testing and analysis • Allows for evaluation of pre-existing formation damage by providing core samples free of distortions caused by percussion tools • HRSCT™ hostile rotary sidewall coring tool available for use in hostile environments

RSCT™ Rotary Sidewall Coring Tool Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

18.1 (5.5)

4.87 (123.7)

20,000 (137.9)

350 (176.7)

275 (124.7)


SWC™ Side Wall Coring Tool The SWC™ side wall coring tool allows geologists to take a sample of a prospective formation traversed by the borehole. These sidewall core samples can improve log analysis, help to identify a rock's type and origin, and can be used to determine the exact location of gas and oil, gas and water, or oil and water contacts within a reservoir. In some cases, sidewall cores can even discover productive reservoirs not evident on logs. The SWC tool consists of a propelling explosive material and hollow core barrels housed in the body of the gun. The tool is lowered to a predetermined depth and fired, one shot at a time. The barrels containing the core samples are then retrieved by means of a cable attaching the barrels to the gun. The SWC tool utilizes a single cable running through and inbetween the barrel back and barrel. The two ends of the cable are secured to the side rails of the gun, helping to reduce the number of broken cables. In addition, release rings adapted to the top of the barrel control entry depth and velocity and provide flexibility during the coring process.

• Matrix makeup • Grain size and cementing agents • Paleonthological data • API oil gravity • Gas and oil presence Porosity and permeability estimations can also be made using sidewall core analysis. However, these estimates should never be used to extensively evaluate porosity or permeability since there is a high probability that the core structure has been altered by the impact of the core barrel into the formation. Features • Area specific – can shoot 24 to 144 cores on a single trip into the well • Depth correlation via gamma ray or SP application • Sampling can be done at any time before casing is run • Allows sampling of very soft formations • Permits positive verification of formation type indicated by the other open-hole logs

Applications • Clay typing • Fluid saturation estimation

SWC™ Side Wall Coring Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

7.7 (2.4)

4.5 (114.3)

20,000 (137.9)

400 (204.4)

215 (97.5)


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HRSCT™ Hostile Rotary Side Wall Coring Tool The HRSCT™ hostile rotary sidewall coring tool provides a new approach for acquiring multiple sidewall core samples from an earth formation and special means for storing and identifying individual samples in multiple tubes for wireline operation. This apparatus is specifically designed with high efficiency to provide high-speed bit rotation combined with high torque for best drilling performance. The coring tool apparatus consist of control/power electronics and includes a hydraulic valve section, motor drive section, and the mandrel section. The descriptions of each section are as follows. Hydraulic Valve Section This section incorporates multiple solenoid valves for independent control of the tool functions such as, setting tool, tilting bit box, bit rotation, drilling/bit advance control, and core storage. The main feature of this section is the bit advance control mechanism which is based on applying bit weight and receiving positive feedback from the bit torque for the active control system. Small incremental increase and decrease in bit weight are possible to provide for smooth drilling without the risk of bit stalling.

Mandrel Section This section incorporates a bit box movable by actuators for tilting, advance/retract, bit break, and storage functions. The bit box incorporates several sets of bevel and spur gears to translate the direction of the rotation of the flexible shaft into normal direction to the axis of the wellbore. Finally, multiple core separator tubes are positioned in a carousel manner. The carousel rotates on demand from the hydraulic power section after depositing a core to place a washer for positive identification. The carousel stores up to sixty 2.12-in. cores that would otherwise be length prohibitive if a single tube is used. During the coring operation, the mandrel is secured to the borehole using two powerful backup pistons instead of a single backup arm. The backup pistons are sized so that minor slippage that could cause mandrel movement can be eliminated. This reduces the possibility of lodging and sticking the bit in the formation. Features • High temperature AC motor drives the bit for: – Full power across entire temperature range – Minimum post-job re-fit time • Software control offers “cruise control” option

Motor Drive Section This section consists of an electric motor with a small pump at one end, for providing hydraulic pressure for all the auxiliary functions. The other end of the motor is connected to a clutch mechanism used for engaging and disengaging the bit on demand. The output of the clutch is directly coupled to the bit box through a flexible steel drive shaft. The main feature of this drive system is that by eliminating the hydraulic pumps and motors, high drive train efficiencies of as much as 80% is possible without sacrificing performance. The clutch mechanism can also be adjusted to slip at the torque rating of the electric motor to eliminate motor/bit stalling while drilling.

• Surplus power: – 1500 rpm with 22-in.-lb torque for fast drill times • Excellent coring capacity: – 60 cores 2.12-in. L × 1.0 diameter • Fail-safe retract includes bit-box and backup pistons • Combinable • Sensor coring record includes: – ROP, bit torque, and RPMs – Drilled core length – Recovered core length Pressure

HRSCT™ Hostile Rotary Side Wall Coring Tool Specifications Maximum Temperature °F

Maximum Pressure psi

Push Pull Tension lb

Push Pull Compression lb

Maximum OD in.

Length ft

Minimum / Maximum Hole in.

40

20,000

100,000

50,000

4.75 nominal 5.125 at standoffs

30

6.25 - 12

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Hostile—Slimhole Formation Evaluation HEAT™ Hostile Environment Applications Tool Suite The HEAT™ hostile environment applications tools suite comprises six logging instruments—a cablehead-tension load cell and associated centralizer, decentralizer, flex-joint, and telemetry assemblies. Each HEAT tool contains an internal temperature sensor that provides quality control data related to operational characteristics and tool electronics. Such information is usually critical only in very hot well conditions—in particular, when temperatures over a prolonged period are near the 500°F limit of the toolstring. The following are tools in the HEAT suite: • HDIL™ Hostile Dual Induction Log (see page 5)

Features • HEAT suite tools are digital and smaller than standard logging tools—2.75-in. to 3.5-in. OD for HEAT suite versus 3.625-in. to 4.5-in. OD for standard tools • The HEAT sonic, neutron, and gamma ray tools can all operate in open and cased holes • Built to handle the severe conditions encountered in deep and hot hydrocarbon-bearing formations • Can be combined in almost any configuration to suit the borehole geometry and formation evaluation requirements of each job

• HEDL™ Hostile Environment Dual Laterolog • HFWS™ Hostile Full Wave Sonic Tool • HSDL™ Hostile Spectral Density Tool • HDSN™ Hostile Dual-Spaced Neutron Tool • HNGR™ Hostile Natural Gamma Ray Tool • HSFT™ Hostile Slim Formation Tester Tool


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HEDL™ Hostile Environment Dual Laterolog Tool The HEDL™ hostile environment dual laterolog tool is a wireline-deployed formation resistivity device designed for extreme borehole temperatures and pressures. It is the tool of choice when those resistivities routinely exceed 100 ohm•m, especially in highly conductive muds. The HEDL tool is combinable with other hostile environment tools, e.g. the density and neutron tools to permit simultaneous resistivity/porosity measurements in the reservoirs. The tool is designed to be run with the HETS™ hostile environment telemetry sub and must be located immediately below the HETS sub and a 2.75-in. diameter isolation sub. From top to bottom, the HEDL tool assembly consists of:

• Calibrated using three external resistor networks that simulate relatively low, medium, and high resistivities • Under conditions of high Rt and low Rm and at temperatures higher than 350°F, the HEDL tool provides the basic formation resistivity data to aid formation evaluation

• A flasked electronic assembly • An upper toroid sub • An alpha sub

Features • 2.75-in. diameter permits slimhole and through drillpipe logging of high-temperature/high-pressure wells • Performs two resistivity/porosity measurements: a deep laterolog (LLd) and a shallow laterolog (LLs) resistivity measurement

HAL9137

• A lower toroid sub

Typical HEDL™ log recorded in highly resistive carbonate formations

HEDL™ Hostile Environment Dual Laterolog Tool Specifications

3-48

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

21 (6.4)

2.75 (69.9)

25,000 (172.4)

450 (232.2)

300 (136.1)


HFWS™ Hostile Full Wave Sonic Tool The HFWS™ hostile full wave sonic tool is a 2.75-in. acoustic velocity logging tool that is a part of the HEAT™ suite hostile environment applications tool toolstring. The HFWS tool, along with all of the HEAT suite sensors, have a pressure rating of 25,000 psi (172 400 kPa). The HEAT suite logging tools are designed for continuous operation of six hours at 500°F (260°C).

The HFWS tool can be compared to having two sonic tools within the same toolstring—a long-spaced sonic tool for traditional full waveform open-hole sonic logging, and located within the transmitter-to-receiver offset, a cement bond tool that utilizes the second transmitter and two receivers. The upper transmitter and the lower four receivers array are utilized for FWS full wave sonic logging. The lower (second) transmitter and the upper two receivers are utilized for cement bond logging and short, offset compressional wave travel time. The long transmitter to-receiver offset allows for the acquisition of borehole sonic data beyond the effects of any near-wellbore altered region. The long offset also allows for the acquisition of high-quality sonic data in enlarged boreholes where critical angle effects would affect sonic tools with short transmitter-to-receiver offsets.

HAL9171

The HFWS tool, like the larger in diameter (3.625-in.) FWS™ full wave sonic tool, provides compressional wave, refracted shear wave, and Stoneley wave properties of downhole formations for a wide range of petrophysical, geological, and geophysical applications. To minimize the number of logging trips required for complete formation evaluation, the HFWS tool is compatible with all HEAT suite logging toolstrings. A liquid filled borehole is required for sonic logging, and can be used in fresh, salt, or oil-based mud systems.


Applications • Full waveform open-hole sonic logging • Cement bond logging • Acquisition of borehole sonic data


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Features • Advanced system design and software processing with long transmitter-to-receiver offsets and 1/2 ft receiver-toreceiver spacings • Detection of signals at all receivers for each transmitter pulse to promote constant source characteristics • Automatic gain control of each receiver helps preserve signal amplitude • Downhole digitizing helps eliminate transmission noise and allows broadband frequency response

• Facilitates continuous uninterrupted recording of full waveform signals • Ability to record various types of information including tool data, quality curves, and final results • Operator-selectable multiple modes of tool operation, digitally recorded waveform data, and improved porosity estimates using both Δtc and Δts

HAL9172

• Low-frequency response allows detection of low frequency Stoneley waves and multiple Δt measurements per depth interval

Gamma ray and caliper are presented in Track 1, compressional wave travel time (DTC) is presented in Track 4, and the P-wave semblance quality is presented in Track 3.

• Facilitates lithology identification by means of velocity ratio, Δts/Δtc, and location of gas zones, even in poor hole conditions and cased holes • Indication of permeability variations with depth from Stoneley wave attenuation and Δt • Detection of naturally fractured zones, determination of rock elastic constants, and estimation of formation strength and least horizontal stress • Prediction of vertical extent of hydraulic fractures using the RockXpert2™ analysis package

• Time-to-depth correlation for seismic correlation • Combining sonic slowness data with formation density data are the required input information for synthetic seismograms

HAL9173

• Improved vertical resolution for detection of thinner beds (Beds as thin as 3-in. can be identified with the t curves)

This is a hard rock example. Natural gamma ray, caliper, and VpVs are presented in Track 1. The P-wave travel time and the refracted shear wave travel time are presented in Track 2. The semblance quality is presented in an image format in Track 3 for the P-wave and refracted shear wave.

HFWS™ Hostile Full Wave Sonic Tool Specifications Length* ft (m)

Diameter in. (mm)


Maximum Temperature** °F (°C)

Weight lb (kg)

30.2 (9.2)

2.75 (69.9)

25,000 (172.4)

500 (260)

340 (154.2)

*Add 3.50 ft (1.1 m) for each in-line centralizer (usually two). ** 6 hour

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HSDL™ Hostile Spectral Density Log The HSDL™ hostile spectral density log is a section of the HEAT™ suite system. It is available with the source-detector pad either as a bottom-only in-line configuration (2.75-in. tool OD) or as a powered, extendable configuration (3.5-in. tool OD). It is fully combinable with all other HEAT suite tools. The HSDL log measures formation density, photoelectric factor (a lithology indicator), and borehole diameter. It measures formation density by emitting gamma rays into the formation and recording the energy of gamma rays reflected by the formation to the two detectors in the tool. The HSDL log measures borehole diameter with a spring-loaded caliper arm that opens and closes as the tool is pulled through changes in hole diameter.

• 2.75-in. OD for use in slimholes makes it possible to design a through-formation evaluation program for holes as small as 3.5-in. • Uses a new 4D technique to account for the density and photoelectric absorption of the formation and mudcake without assuming any correlation between these variables. Besides yielding a superior density, these calculations provide information for compensating the Pe measurement and computing useful quality indicators such as the two component density correction

Additionally, as for all Halliburton’s HEAT suite services, the HSDL log provides reliable data in temperatures up to 500°F and pressures as high as 25,000 psi that are encountered in hot hydrocarbon bearing formations. Applications • Determination of formation porosity • Identification of formation lithology regardless of formation fluid type • Indication of gas when used in combination with a neutron log Features • More precise delineation of thinly bedded formations using the unfiltered Pe curve • Curves indicating data quality are displayed on a computer screen in real-time and recorded on the log • Advanced correction algorithm is applied to density data in real-time

• Rugged construction and advanced gain stabilization help maintain measurement integrity under varying temperature conditions • Combinable with a complete family of tools that operates under the DITS™ digital interface telemetry system

HAL846

• Rigid tungsten pad incorporates a 1.5-curie cesium-137 source and two high-efficiency scintillation detectors designed to maintain high gamma counts

Typical Field Output of the HSDL™ Log

• Extensively characterized in test pits with a full set of correction charts available


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Associated Answer Products • The wellsite answer product is formation density and Pe • Density data is also used with open-hole sensors as input to Halliburton’s mineralogy, open-hole, and cased-hole saturation analysis to provide a complete formation evaluation product. These include:

– ULTRA™ multi-mineral evaluation program – CORAL™ complex lithology analysis – LARA™ laminated reservoir analysis – SASHA™ shaly sand analysis

HSDL™ Hostile Spectral Density Log Specifications Length ft (m)

Diameter (minimum) in. (mm)



Weight lb (kg)

In-Line Pad

13.8* (4.2)

2.75 (69.9)

25,000 (172.4)

500 (260)

176 (79.8)

Extendable Pad

23.8 (7.3)

3.50 (89.9)

25,000 (172.4)

500 (260)

456 (206.8)

Equipment

*Usually run with the HPDC-A—if so add 3.8 ft (1.2 m) **6 hour

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HDSN™ Hostile Dual-Spaced Neutron Tool The HDSN™ hostile dual-spaced neutron tool is a section of the HEAT™ suite system. The HDSN tool consists of combinable, high-quality, small-diameter tools capable of comprehensive formation evaluation in harsh environments. Applications • Provides a neutron porosity log, i.e. the porosity of the formation as indicated by the detection of neutron radiation induced in the formation by the tool • Investigates formation lithology, using a steady state, neutron-generating source of radioactive americiumberyllium (AmBe) and two thermal neutron detectors. Neutrons emitted from the source are slowed and scattered by the surrounding media, and the resulting neutron field is sampled at two locations. The neutron flux is converted to electrical signals for logging Features • Can be deployed in both open and cased-hole wells

• Uses caliper data from the decentralizer to correct porosity for hole size • Extensively characterized in test pits with a full set of correction charts available

HAL846

• Commonly run with the powered decentralizer to provide HDSN tool eccentering and to furnish a continuous standoff measurement that helps improve porosity calculations, especially over rugose intervals

Typical Field Output of the HDSN™ Tool

• Temperature and pressure ratings of 500°F (for 6 hours) and 25,000 psi, respectively to handle severe conditions encountered in deep and hot hydrocarbon-bearing formations • Specially designed He3 detectors minimize the effects of elevated temperature on observed count rates and computed porosity • 2.75-in. OD for use in slimholes • Small OD to design a through formation evaluation program for holes as small as 3.5 in. • Combinable in almost any configuration to suit borehole geometry and provide appropriate formation evaluation information


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Associated Answer Products • The wellsite answer product is the neutron porosity NPHI


• Neutron porosity data is also used with other open-hole sensors as input to Halliburton’s mineralogy, open-hole, and cased-hole saturation analysis to provide a complete formation evaluation product. These include:


HDSN™ Hostile Dual-Spaced Neutron Tool Specifications Length* ft (m)

Diameter in. (mm)



Weight lb (kg)

15.3 (4.6)

2.75 (69.9)

25,000 (172.4)

500 (260)

179 (81)

*The length and weight include the HGNI instrument section, which is required to run the HDSN™ tool. Add 7.04 ft (2.1 m) when run with the in-line, bowspring decentralizer. **6 hour

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HNGR™ Hostile Natural Gamma Ray Tool The HNGR™ hostile natural gamma ray tool is a section of the HEAT™ suite system. Along with the HGNI™ tool, the HNGR tool can be run alone or with any other hostile service in either an open or cased-hole. The HNGR tool is used to record naturally occurring gamma radiation. Gamma ray measurements are used for geologic correlation, depth control, and computing shale and clay volumes. Shale volume data can then be applied to correct the apparent porosities indicated by the acoustic, neutron, and density logs. When wellbore conditions are not favorable for a definitive SP response, a gamma ray curve is recorded in its place. Applications • Record natural gamma radiation Features • Commonly run with the powered decentralizer to press the toolstring along the borehole wall and to furnish a continuous standoff measurement

• 2.75-in. OD for use in slimholes makes it possible to design through-formation evaluation programs for holes as small as 3.5-in.

HAL846

• Temperature and pressure ratings of 500°F (for 6 hours) and 25,000 psi, respectively to handle severe conditions encountered in deep and hot hydrocarbon-bearing formations

• Combinable in almost any configuration to suit borehole geometry and provide appropriate formation evaluation information calibration and wellsite checks

Typical Field Output of the HNGR™ Tool

• Curves indicating data quality are displayed on a computer screen in real-time and recorded on the log

HNGR™ Hostile Natural Gamma Ray Tool Specifications Length* ft (m)

Diameter in. (mm)



Weight* lb (kg)

11.6 (3.5)

2.75 (69.9)

25,000 (172.4)

500 (260)

146 (66.2)

*The length and weight include the HGNI™ instrument section, which is required to run the HNGR™ tool. **6 hour


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Pressure/Time

The HSFT tool can take an unlimited number of pressure tests and up to two fluid samples per trip in the well. Formation pressures are determined using a high resolution, high temperature quartz gauge.

Depth: XX879 ft

6000 5000 4000 Legend Pressure Used Pressure Data Hydro Static 1 Draw Down Fill Up Stop Hydro Static 2

3000 2000 1000 0 0

100

200

300

400

500

600

700

HAL9144

Pressure (psi)

HSFT™ Hostile Sequential Formation Tester Tool The 3.125-in. OD HSFT™ tool is capable of formation testing in conditions where conventional tools cannot. The HSFT tool can be run in holes as slim as 4-in. and at temperatures and pressures up to 400°F and 25,000 psi.

800

ETIM (sec)

• Designed for wellbore diameters as small as 4 in. • With optional backup shoe, pad can extend to 12.25 in.

Spherical LogLog

Depth: XX879 ft

1e+07 1e+06 1e+05 10000 1000

Legend Derivative Plot Delta Pressure Match

100 10 1

100

10

HAL9139

Features • Maximum tool OD 3-1/8 in. tool design includes selfcontained standoffs, reducing the contact area between the tool and the borehole wall and minimizing the chance of differential sticking, especially in difficult hole conditions and depleted reservoirs

Real-time plot of HSFT™ tool data provides test monitoring and a drawdown mobility estimate.

Pressure (psi) and Derivative

The HSFT tool is fully combinable with the HEAT™ suite toolstring, allowing open-hole data acquisition and formation testing in the same trip in the well.

1000

Buildup Time (sec)

• Sampling flowrate controlled by air or fluid cushions

• Backup strain gauge provides redundancy • Low flowline volume reduces storage resulting in faster pressure tests in low mobility reservoirs, often encountered in high-pressure, high-temperature (HPHT) wells

Spherical FasTest 4980 4960 4940

Legend Pressure Used Pressure Data P*Fast Curve Fit

4920

• Self-cleaning sand screen design prevents snorkel plugging

Depth: XX879 ft

5000

HAL11253

• Tool, reinforced pad design, and quartz gauge proven reliable to 400°F

Real-time HSFT™ tool analysis plot identifies flow regime and aids operator in determining when to terminate test, resulting in saved rig time.

Pressure (psi)

• Two 1-gal sample chambers available

4900

• Extends pressure and temperature range over conventional testers

4880 0

5e-5 10e-5 15e-5 20e-5 25e-5 30e-5 35e-5 40e-5 45e-5 50e-5

Time (sec): T(-1.5)

• Combinable with HEAT suite resistivity, sonic, and porosity logs to increase rig time savings

Buildup analysis performed on HSFT™ tool data

• Low power consumption electronics reduces internal heat generation and extends tool operating time

HSFT™ Hostile Sequential Formation Tester Tool Specifications Length* ft (m)

Diameter in. (mm)



Weight lb (kg)

28.0 (8.5)

3.125 (79.4)

25,000 (172.4)

400 (204.4)

525 (231.8)

*HSFT™ tool only; does not include HPSU or sample chambers. Minimum toolstring length for pressures only, including gamma and telemetry sub 55 ft (16.8 m) HPSU length: 8.33 ft (2.5 m); weight 120 lb (54.4 kg); OD: 2.75 in. (69.9 mm).

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Auxiliary Services Multi-Conductor LockJar®* System The multi-conductor LockJar® system minimizes the risk of unproductive rig time in logging operations.

Unlike previous jars, the LockJar system arrives at the wellsite ready to run. Logging crews can be trained to use the tool in minutes, so a jar service technician is not required on location. There is even a hydraulic time delay that allows the crew to pull the toolstring through a tight spot without activating the tool.

HAL14045

The benefits of using wireline instruments to log oil and gas wells can diminish quickly if the logging string becomes stuck in the wellbore while tripping. Now, with multiconductor LockJar wireline technology available from Halliburton, that risk can be dramatically reduced.

The new LockJar system can be adjusted right at the wellsite to begin metering the jar with a pull from the surface of 1,700 to 4,000 lb. It can function reliably in reservoir temperatures up to 400°F and at pressures as high as 22,500 psi. However, those specifications can be easily increased because the tool is pressure balanced. Features • Mechanical lock helps prevent inadvertent triggering during logging operations • Hydraulic time delay allows actuation at any load above the mechanical lock setting and is not sensitive to pressure or temperature • Balanced pressure increases the hydrostatic pressure rating by providing compensation to prevent collapsing • Protected seal and impact surfaces enhance downhole reliability by minimizing friction from borehole fluids and problems associated with debris • All internal parts, including the jar mechanism and conductive path, are sealed and segregated from the wellbore • Permits operators to free-fall wireline in regions where persistent sticking problems have dictated the need for drillpipe-conveyed logging operations • System ready to run upon arrival *LockJar is a registered trademark of Evans Engineering, Inc.


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Operation In a typical open-hole logging string, the LockJar® system is placed immediately above the logging or formation testing tools. To augment the force with which the weight is thrown up hole after the jar is activated, it is mated with an enhancer. It has been demonstrated in the lab that the LockJar tool’s impulse is more than twice as powerful with up to five times more duration when the enhancer is added to the jar. The LockJar tool is usually run in the string in the following order from the cable head down: enhancer, cable mode and telemetry sub-assemblies, and the jar. In combination, they

create as large a mass as possible to help the jar release stuck logging tools. The enhancer stores energy in Belleville springs which propel the hammer into an anvil upon activation of the jar which generates the impact and impulse that are directed down towards the stuck point. Borehole Conditions • Borehole fluids: salt, fresh, oil, and air • Tool positioning: centralized eccentralized

Multi-Conductor LockJar® System Specifications Length ft (m)

Maximum OD in. (cm)

11.4 (3.49**)

3.625 (9.20)

Minimum Hole Size in. (cm)

Maximum Hole Size in. (cm)

4.0 (10.16)

N/A*



Weight lb (kg)

20,000 (137 895)

400 (204)

365 (165***)

*Tool not restricted on maximum hole size **Length of enhancer is 10.1 ft (3.07 m); combination jar and enhancer is 21.5 ft. (6.56 m). ***Weight of the enhancer is 290 lb (131.5 kg).

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RWCH™ Releaseable Wireline Cable Head The RWCH™ tool has an electrically activated wireline release system as opposed to the tension activated release system of conventional cable heads. Tension activated heads require a safety factor to avoid premature release of the wireline. This safety factor keeps you from utilizing the full safe load on the wireline when trying to free stuck tools from the borehole. The RWCH tool allows you to utilize this extra tension to free stuck tools. This additional tension has proven very successful at freeing stuck tools and avoiding fishing operations. This extra pull also allows you to safely run heavy toolstrings in deep wells. The RWCH tool can reduce the costs of obtaining wireline logs in areas that are prone to tool sticking. It has reduced the incidence of fishing for stuck tools in problem areas, saving customers expensive and risky fishing jobs. Features • Allows for greater pulling of stuck tools at any depth and in any conditions • Able to support heavy toolstrings by utilizing the full strength of the wireline, regardless of depth • Electrically controlled release from the surface

HA L91 88

• Contains a conventional 2.3125-in. fishing neck • Includes a special sub designed to allow easy rigup and rig-down

RWCH™ Operation

• Allows the maximum pull to be applied at any depth in the well regardless of the total depth if the backup weak point is not used • Allows the release to be aborted as long as the fusible alloy has not reached melting temperature

RWCH™ Releaseable Wireline Cable Head Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

6.3 (1.9)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

135 (61.2)


3-59

Toolpusher™ Logging (TPL) Service Today’s search for oil and gas is heavily influenced by the rapid growth of technology. New tools and equipment are being built, new production and recovery methods are being tested, and new exploration techniques are being developed. Drilling programs are becoming increasingly complex and many wells now commonly include highly deviated or horizontal sections. In these cases, obtaining quality formation evaluation data with conventional wireline methods may be impossible or impractical at best—severely restricting the options available to the operator. The Toolpusher™ logging (TPL) service provides an innovative solution to this significant problem. TPL service utilizes drillpipe to effectively transport conventional electric wireline logging tools to the zone of interest. This method eliminates many of the problems associated with conveying tools through highly deviated or horizontal sections of the well. It also helps eliminate problems caused by: • Wireline key seating • Differential sticking of tools or wireline

• Doglegs • Cuttings bridging off the wellbore The TPL service has successfully logged thousands of highly deviated and horizontal wells, including: • Wells with temperatures over 400°F (204°C) • Depths exceeding 24,000 ft (7315 m) • Logged intervals over 10,000 ft (3048 m) The Toolpusher latch assembly has been deployed and latched at angles of up to 97° with a maximum logged angle of over 104°. Average job time at 12,000 ft is 16 to 18 hours. Toolpusher service is designed to run both standard and modified wireline logging tools. The quick change, attached to the top of the logging toolstring, is attached to the bottom of a connector sub. Then the connector sub is attached to the drillpipe. The connector sub, available in three diameters, has slots cut through it so circulation can be accomplished at any time during a logging operation.

HAL607

• Swelling formations

• Heavy muds

Toolpusher™ Drillpipe Conveyed Logging System

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Toolpusher ™ service requires a variety of specialty subs and hardware. Among the subs are the downhole tension device, multiconductor swivel adapter, and offset, alignment, flex, knuckle, and pad locator subs. Some of the specialty hardware includes the rig floor display, spinning stand-offs, stiffening collars, hole finders, bullnoses, protective sleeves, and standoffs. The lists of equipment can get quite extensive. Each piece is utilized for special situations and the variety makes Toolpusher service a very versatile and adaptable system. Many toolstrings have unique hardware to assist in getting the best possible data. Toolpusher service was the first drillpipe conveyed logging system introduced in the field. It has a very long track record and has proven to be very reliable. Unlike our competitors, Toolpusher allows the customer to circulate at any time during the operation. The side-entry sub (SES) has a larger through-bore than the competition, which allows fishing operations to proceed as normal without restriction. Applications • Conventional open-hole and cased-hole logging

• No metal around female electrical connection reduces the possibility of shorting • Female wet connect is floating and spring loaded, eliminating the movement of the connection and reducing noise • New wiper glands to clean the male probe removes conductive films from the pin • Multiple o-ring seal after the connection is made to effectively seal the connection • Spring loaded sleeve protects downhole parts before latching • Male probe completely covered after latching to help seal out invading fluids • Employs conventional high-resolution wireline tools to provide formation data with quality equal to that of wireline-conveyed logs. Conventional rig tripping procedures are used to mechanically position logging tools in the zone of interest • Formation data is available in real-time at the wellsite. Also, zones of interest can be relogged by lowering the blocks

• Formation testing and coring

• Rig up on the drillpipe rather than multiple runs with conventional wireline can save time. Prior planning with your Halliburton representative can determine which method is more economical

• Vertical seismic profiling • Ultrasonic and electrical imaging • Cement and casing evaluation Features • Control of pull off tension allows the operator to pull test to check the mechanical latch

• Provides mud circulation throughout the operation. This reduces the risk of tools getting stuck and minimizes further hole deterioration

Toolpusher™ Logging (TPL) Service Specifications Tool Section

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

Side-Entry Sub SES

*

*

20,000 (137.9)

400 (204)

*

Positive Latch/Unlatch Quick Change Assembly

*

3.625 (92.1)

20,000 (137.9)

400 (204)

*

7-Conductor Pump Down Head

**

2.0 or 2.25 (50 or 57.1)

20,000 (137.9)

400 (204)

**

Multi Conductor Swivel Assembly

3.02 (0.9)

3.625 (92.1)

20,000 (137.9)

400 (204)

70 (31.8)

DITS™ Downhole Tension Device

3.78 (1.2)

3.625 (92.1)

20,000 (137.9)

350 (176.7)

96 (43.5)

DITS Single Knuckle Joint

3 (0.9)

3.625 (92.1)

20,000 (137.9)

400 (204)

50 (22.7)

DITS Flex Joint

5.64 (1.7)

3.625 (92.1)

20,000 (137.9)

400 (204)

140 (63.5)

DITS Double Knuckle Joint

5 (1.5)

3.625 (92.1)

20,000 (137.9)

400 (204)

75 (34)

*Size selection is based on casing size and drillpipe size and type. **Length and weight are variable depending upon the latching conditions.


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CTL™ Coiled Tubing Logging As the only major service company that designs, manufactures, and operates its own coiled tubing equipment, Halliburton incorporates important input from field personnel and customers into designing features that are strategically directed toward the most effective possible job performance. Deploying logging tools on coiled tubing is one of the more innovative uses of Halliburton coiled tubing. Installing logging cable inside the coiled tubing allows tools to be deployed into highly deviated wells and permits a variety of remedial functions. CTL logging differentiates itself from drillpipe conveyed logging by offering:

• Single-trip underbalanced perforating with long gunstrings • Setting plugs and packers in deviated wells with pinpoint depth control Features • Purpose-built coiled tubing cableheads – Shear pin release – Flow-release • High pressure surface termination assemblies – Standard integral plumbing – DNV certified

• Continuous circulation capabilities • Pressure control while moving pipe

• Self-contained unit, requires no rig

• Electrical connections made at the surface to eliminate wet latches

• Can continuously pump fluids into well while moving pipe

• Tolerance for high mud solids content

• Land or offshore system designs

• Relogging of any interval, eliminating multiple latch runs

• No workover rig required when using coiled tubing

• Constant speed logging capability

• Can be and is typically used on live wells (no kill fluids introduced into well)

• Reduced potential damage to formation

Applications • Cement bond logging in highly deviated wells

• Acts as tool transport medium for deviated and horizontal wells

• Production logging to determine water entry points in highly deviated wells

• Advanced data acquisition system to monitor key job parameters on tubing management

• Open-hole logging in deviated air-drilled wells that need pressure control

Coiled Tubing Cablehead Specifications 1.50 in. (38.1 mm)

2.00 in. (50.8 mm)

2.50 in. (63.5 mm)

Coiled Tubing Size

1.00 to 1.50-in. (25.4 to 38.1 mm)

1.50-in. and above (38.1 mm and above)

1.50-in. and above (38.1 mm and above)

Top Connection

Roll-on or OECO “A” Box

Roll-on or OECO “A” Box

OECO “A” Box or AMMT Box

Bottom Connection

1-3/16-in. (30.2 mm) 12 UN Type “A” Pin

1-3/16-in. (30.2 mm) 12 UN Type “A” Pin or 3-5/8-in. (92.1 mm) DITS™ Tool

1-3/16-in. (30.2 mm) 12 UN Type “A” Pin

Fishing Neck Size

1.0-in. (25.4 mm) External

1.375-in. (34.9 mm) External

1.812-in. (46.0 mm) Internal

Emergency Release Force Range

3,200 to 10,000 lb (1,451.5 to 4,536 kg)

5,000 to 30,000 lb (2,268 to 13,608 kg)

Flow-release in conjunction with shear pins

7/32-in (5.6 mm) or 5/16-in. (7.9 mm) monoconductor

5/16-in. (7.9 mm) monoconductor or 3/8-in. (9.5 mm), 7/16-in. (11.1 mm), 0.457-in. (11.6 mm), or 15/32-in. (11.9 mm) multiconductor

7/32-in (5.6 mm) or 5/16-in. (7.9 mm) monoconductor or 3/8-in. (9.5 mm), 7/16-in. (11.1 mm), 0.457-in. (11.6 mm), or 15/32-in. (11.9 mm) multiconductor

Tool OD

Logging Cable

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BHPT™ Borehole Properties Tool The BHPT™ borehole properties tool is a DITS™ tools compatible electric logging tool, which provides signals used to determine characteristics of wellbore fluids. The primary outputs of a BHPT log are pressure, temperature, and borehole fluid resistivity. This information has long been requested by our clients and now is available during the first logging pass in a newly drilled well. The BHPT tool is normally run in conjunction with other logging services but may also be used as a stand-alone logging tool requiring the use of a telemetry sub. Open-hole, cased-hole, and drillpipe conveyed logging environments will accommodate the BHPT tool and two external diameters are available. The open-hole version is standard 3.625-in. and a smaller 3.375-in. version may be necessary in heavy 4.5-in. casing and slimhole applications. Downhole pressure and temperature readings can assist clients in blowout prevention, mud weight corrections, determining formation fracture pressures, thief-zone identification, determining wellbore fluid pressure gradients in deviated holes, thermal gradient calculation, bottomhole temperature, and detection of dynamic fluid environments within the wellbore, including location of gas entry points in air-drilled wells.

Pre- and post-job maintenance requires flushing the pressure entry port to remove mud debris and create a pressure buffer to the sensor. Calibrations involve coefficient entry and internal resistor network readings.

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The resistivity sensor provides accurate, real-time information about mud resistivity at any depth and temperature in the wellbore. This information is required during water saturation calculations. The Rm data may be used in invasion diameter calculations and also to identify abnormal induction and laterolog readings caused by borehole fluid effects. In cased-hole environments, the resistivity sensor can locate fluid levels and contact depth of static oil and water.

Typical Field Output of the BHPT™ Tool

The BHPT tool can be used at any location in the logging stack depending on the data acquisition depth priorities with the exception that it must be run below the telemetry sub. The BHPT tool is available in two diameter sizes: a 3.375-in. tool and a 3.625-in. tool. The 3.625-in. BHPT tool is used specifically in open-hole applications. The smaller diameter 3.375-in. tool is used in cased-hole wells (with heavy 4.25-in. casing), and in slimhole applications.


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Features • Outputs real-time pressure, temperature, and mud resistivity data in the case that no similar measurements are taken in the toolstring configuration

The resistivity sensor provides accurate, real-time downhole temperature and mud resistivity information at any depth. This resistivity measurement can be used to:

• Aids in blowout prevention

• Make invasion diameter calculations

• Makes mud-weight corrections

• Identify abnormal induction and laterolog measurements (caused by borehole fluid effects)

• Determines formation fracture pressures • Identifies thief zone • Determines wellbore fluid-pressure gradients in deviated holes

• Make water saturation calculations

• Locate fluid levels and contact depth of static oil and water in cased-hole wells

• Determines thermal-gradient calculation

Associated Answer Products • Absolute pressure and differential pressure

• Determines bottomhole temperature

• Absolute temperature and differential temperature

• Detects dynamic fluid environments within the wellbore, which also includes locating gas entry points in airdrilled wells

• Mud resistivity

BHPT™ Borehole Properties Tool Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

5.02 (1.5)

3.375 (85.7)

20,000 (137.9)

350 (176.7)

95 (43.1) Cased-Hole

5.02 (1.5)

3.625 (92.1)

20,000 (137.9)

350 (176.7)

107 (48.5) Open-Hole


FIAC™ Four Independent Arm Caliper Tool The FIAC™ four independent arm caliper tool is a four-arm caliper which provides information on the borehole geometry of the wellbore. Unlike other X-Y caliper services, the FIAC tool has four independent caliper measurements. The FIAC tool, run as a separate or combined service, provides an accurate measurement of the borehole diameter in four orthogonal directions with respect to the tool body. This survey is useful in calculating cement volume, selecting packer seats for formation sampling, and identifying and locating washouts and bridges in the borehole, as well as identify borehole ovality.

When the FIAC tool is combined with the SDDT™ navigation package, the borehole geometry information is oriented with respect to both magnetic north and the highside of the wellbore. The borehole azimuth, borehole deviation, and relative bearing of the X and Y caliper data are presented in a continuous log presentation. This allows the correlation of the borehole geometry with the drilling process, such as correlation of the long axis of the borehole to the high-side/low-side of the well. The FIAC tool differs from the competition by providing four independent caliper measurements, whereas with types of other four arm calipers, the X-X and Y-Y arms are paired together to provide only two diameter measurements.


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Borehole size may range from 3.625-in. diameter to 22-in. diameter. The caliper arms are mounted at 90° angles to each other and provide a continuous X-Y (borehole axis is Z) borehole measurement. This tool is combinable with any other DITS™ standard tools.

A borehole geometry presentation is created by combining the FIAC™ and SDDT™ data. Orientation data from the SDDT navigation tool is presented in Track 1, the deviation and hole azimuth are presented as text values every 50 ft and as continuous curves. The averaged X and Y calipers are presented in the depth track. The two independent X-X calipers are presented in Track 2 along with a bit size data. The two independent Y-Y calipers are presented in Track 3 along with the bit size data. This presentation illustrates an oval borehole with the long axis of the borehole aligned with the high-side/low-side of the deviated well. The short axis of the borehole is smaller than bit size, indicating the presence of mudcake.

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Features • Four independent caliper measurements to provide needed borehole geometry data • Combined with a navigation package the borehole geometry profile can be oriented with respect to magnetic north as well as to the high side of deviated or horizontal wells

• Helps optimize drilling and mud systems by the evaluation of borehole geometry along with mud weight and type, bit type, and ROP • More accurate borehole volume and annular volume determinations for the required cement volume • Identification of packer seats for sampling and testing

• Borehole geometry information can be used to monitor hole size and shape with wellbore deviation and azimuth for basic geo-mechanical analysis

FIAC™ Four Independent Arm Caliper Tool Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

13.9 (4.2)

3.63 (92.2)

20,000 (137.9)

400 (204.4)

310 (140.6)


SDDT™ Stand-Alone DITS™ Directional Tool The SDDT™ stand-alone DITS™ directional tool is a full navigational package that consists of three orthogonal fluxgate accelerometers and three orthogonal magnetometers.

Halliburton’s proven DITS™ digital interactive telemetry system.

Features An enormous amount of data is acquired while logging. The SDDT tool transmits this data to the surface unit via

The SDDT tool provides accurate information to help determine tool position, motion, direction, and orientation within the borehole.

SDDT™ Stand-Alone DITS™ Directional Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

12.5 (3.8)

3.63 (92.9)

20,000 (137.9)

350 (176.7)

240 (108.9)


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Cased-Hole Wireline Services

Cased-Hole Wireline Services Formation Evaluation TMD-L™ Thermal Multigate Decay-Lithology Logging Tool

Using induced gamma spectroscopy and decay time measurement, the TMD-L tool determines oil saturation in reservoirs with high salinity. Reservoir monitoring includes measurement of initial and current fluid contacts and predicts how the fluids will move in the future. Accurate monitoring of fluid movement in a producing hydrocarbon reservoir can also yield major economic benefits through improved recovery (such as better reservoir management, better placement of infill wells, and break-through deferral) as well as lower costs from fewer wells and reduced water and gas handling. The TMD-L tool differs from the competition by applying alpha-processing which optimally combines near and far detector responses to provide a sigma curve with the accuracy of the far detector and the vertical resolution and precision of the near detector.

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The TMD-L™ tool is a new-generation pulsed-neutron logging tool which measures the thermal neutron capture cross-sections (sigma) of both the formation and the borehole. The sigma parameter is a measure of the ability of the formation to absorb thermal neutrons. Because of the strong correlation between the open-hole resistivity log and the sigma log, the sigma log is considered to be the casedhole equivalent of the conductivity log.

Example of Gravel Pack Evaluation with Silicon Activation

This leading-edge detector technology results in full spectrum monitoring for greater amounts of information, faster logging speeds, and higher accuracy. Applications • Cased-hole formation evaluation • Lithology determination • Enhanced oil recovery monitoring • Gas vs. tight determination • Water-flow detection


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Features • Larger diameter detectors to produce higher count rates • Recording of each detector's decay curve with 61 time gates; time gates span the entire burst cycle—from build up through decay

• Quality indicators for monitoring tool operation and algorithm performance

• A different background measurement scheme to sample the background more frequently

• Combinable with standard PL sensors to provide extensive interpretation support, save time at the rig site, and provide special tool configurations for special challenges

• Recording of gamma ray spectra for the far-spaced or near-spaced detectors during several time windows

• Identifies problems earlier to reduce production downtime

• Ability to mount gamma ray detector below the generator and running the tool inverted to facilitate water-flow measurements

• Optimizes and verifies completions for improved production • Can help recommend remedial activities, such as further stimulation or conformance operations to:

• Simultaneous inelastic and capture spectral measurements

– Optimize production

• Modular hardware design allows custom configurations

– Estimate reserves for better financial planning

• Accurate water saturation interpretation over a broad range of borehole conditions and porosities

– Explore old wells for additional reserves – Help maximize customer return on investment

• Improved interpretation to help distinguish between gas reservoirs and low-porosity formations • Improved repeatability, lithology determination, enhanced oil recovery monitoring, and spectral waterflow determination

Associated Answer Products • SigmaSat™ sigma saturation analysis • Chi Modeling® computation service

TMD-L™ Thermal Multigate Decay-Lithology Logging Tool Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

18 (5.5)

1.6875 (42.86)

15,000 (103.4)

325 (162.7)

70 (31.75)


RMT Elite™ Reservoir Monitor Tool The RMT Elite™ reservoir monitor tool is a unique throughtubing carbon/oxygen (C/O) system, offering two to three times higher measurement resolution than other throughtubing C/O logging systems. Its high-density Bismuth germanium oxide (BGO) detectors allow the RMT Elite tool to achieve resolutions previously available only with larger diameter C/O systems. As a result, the RMT Elite tool can be used to run continuous passes in low porosity formations where other systems can only be run in a stationary mode. The RMT Elite tool can also be conveyed into a well with tubing completions unlike larger C/O systems that can only log through casing. Utilizing induced gamma spectroscopy and decay time measurements, this pulsed-neutron device is primarily used to determine oil saturation in reservoirs. For reservoirs having low, mixed, or unknown salinity-formation water, the inelastic or C/O mode is used. For higher salinities, the capture mode is used, producing a TMD-L™ thermal multigate decay-lithology-type log. In addition, the RMT Elite tool can be used in either operating mode to perform elemental analyses from the measured spectra to identify lithology in all types of reservoirs. Because the RMT Elite tool is so accurate and precise, it allows operators to achieve logging speeds two to five times faster than competing systems. Applications • Discriminate formation fluid contacts

• Locate water and oil zones in waterfloods where mixed salinities exist between formation and flood waters • Evaluate saturations in formations behind casings when open-hole logs are not available • Monitor steam and CO2 flood/breakthrough • Inside/outside casing water detection • Verify gravel pack integrity via silicon activation • Accurately determine oil and gas saturations in high salinity or fresh water formations • Identify bypassed reserves

HAL5680

• Evaluate hydrocarbon zone saturations in fresh, mixed, or unknown water salinity environments

RMT Elite™ Primary Log Presentation—Track 1 of the display is used for plotting basic correlation curves. In this example the simultaneously recorded formation sigma and the potassium yield curve (YK) are plotted. Also plotted in the track is the oxygen activation curve (OAI), which is used to detect water flow. Track 2 of the log is used to display the raw carbon to oxygen ratio (COIR) and the calcium to silicon ratio (LIRI). The green shading between the curves is a quick look representation of hydrocarbons. Track 3 of the log displays yield curves computed from the capture spectra for silicon (YSi), calcium (YCa) and hydrogen (YH). Track 4 displays inelastic and capture near to far detector ratio curves. These curves are used to identify gas in the formation (shaded in red).

• Pinpoint formation fluid contacts • Identify lithologies and mineralogies


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Features • Below-tubing and in-tubing logging capability without sacrificing quality and accuracy • 2.125-in. tool size allows use of a large detector and passage through 2.875-in. tubing • Two detectors provide a near-to-far inelastic ratio, capture ratio, and two C/O measurements. • Dual operating modes – Inelastic mode—(optimized for C/O formation measurements) C/O, elemental yields, ΣFM, porosity from ratios, and oxygen activation – Capture mode—(optimized for Sigma formation measurements) ΣFM, elemental yields, porosity from ratios, and oxygen activation • Accurately evaluates the time-lapse performance of hydrocarbon-producing reservoirs • No well-kill fluids are necessary

• CarbOxSat™ model oil saturation analysis using C/O measurements • SigmaSat™ model water saturation analysis using capture cross section measurements (Σ) • TripleSat™ model three-phase oil, gas, and water saturations using both C/O and Σ measurements • Chi Modeling® computation service Additionally, complex lithology and mineralogy answers can be provided by integrating RMT Elite tool elemental yield data in Halliburton’s ULTRA™ multi-mineral evaluation program software.

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Associated Answer Products RMT Elite™ tool data can be used alone in postlogging analysis, however, the addition of open-hole and cased-hole logging data often serves to enhance analysis results. For example, analysis options allow total and effective porosity to be computed from open-hole or cased-hole porosity data, TMD-L™ data, or external inputs. Also, a simple twoporosity log cross plot option is available to improve effective porosity estimates. Formation saturation analysis using the RMT Elite tool and porosity data can be provided via Halliburton’s cased-hole formation evaluation interpretation in the following software models.

RMT Elite™ Quality Log Presentation—Track 1 of the presentation are curves that represent the accuracy of spectral gain stabilization measured from ratios of the iron edge (FERC) and the hydrogen peak (HPLI). Track 2 is a plot of the COIR and LIRI from the near space detector. Track 3 is used to plot additional yield curves computed from the capture spectra. Plotted on this example are the Iron yield (YFe) and the chlorine yield (YCl). Tracks 4 and 5 are used to plot the total inelastic and capture count rates for the near and far detectors. Track 6 is used to plot the simultaneous measured near formation sigma (SGFN) and the far formation sigma (SGFF).

RMT Elite™ Reservoir Monitor Tool Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

14.22 (4.33)

2.125 (53.975)

15,000 (103.4)

325 (163)

77 (34.9)


Spectra Flow™ Logging Service (SpFl) The Spectra Flow™ logging service directly detects and evaluates water movement behind and inside the casing of both production and injection wells. The service is capable of measuring water-flow direction up and down, linear flow velocity, and volume flow rate of water moving vertically.

The Spectra Flow tool is a uniquely reconfigured pulseneutron capture/spectral through-tubing device with a source to detect spacing to make quantitative water-flow measurements. The tool has two logging methods— continuous logging and stationary impulse testing. This combination of high-resolution water detection plus unique pulsed-neutron timing allows the use of the continuous logging method. In this method, the linear velocity of water-flow is determined from the ratio of oxygen activation measured with the near and far detectors. The stationary impulse method is a travel time measurement that automatically switches the neutron generator on/off and measures the fluid velocity with respect to time. Independent velocities are measured for each detector. Since calibration of the detectors is not required for measurement accuracy, this method has better results than any other system.

HAL1031

Water velocity measurements using spectral data are provided with continuous logs and stationary impulse stepdown tests. Water-flow greater than 3 ft/min can be detected and, depending on the flow volume and location, quantitative velocities as low as 5 ft/min can be measured. For velocities over 50 ft/min, improved accuracy is obtained by using the more distant natural gamma ray detector. A modular tool design allows the Spectra Flow service to be run in combination with production logging tools. Multiple configuration options allow the service to be tailored to the types of flows encountered downhole.

The above Spectra Flow™ impulse velocity test calculates accurate velocity by measuring the time of activated water compared to nonactivated water passing by Spectra Flow detectors. Velocities are calculated for the two spectral measurements, the total activation measurement, and the natural gamma ray detector. Both simultaneous up and down flow can be measured. Track 3 displays the spectral measurements of activated oxygen. Track 2 contains the gamma ray, near and far oxygen activation (OAIN and OAIF), generator voltage, and near and far total activation measurement (TNA and TFA) curves. Track 1 shows the water-flow velocity curves from each of the measurements in Track 2 (VSN for OAIN, VSF for OAIF, VTN for TNA, VTF for TFA, and VGR for GR).

Other logging techniques used to discover fluid movement behind the casing involve measuring acoustical noise, temperature, and radioactive tracers. Running one or a combination of these services can be done successfully, but the interpretation of the data is frequently not easy. Spectra Flow logs eliminate the need to inject tracer materials, have sufficient resolution, a deeper depth of investigation, and appear to be more practical for detecting low flow rates than traditional methods.


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Applications • The detection and quantification of water flowing in cement channels (in producing or injection wells)

• Modular design allows tool to be configured for detecting water sources from above or below; can also be configured to measure both up and down water sources simultaneously

• Identification of water-flow between tubing and casing

• Pure spectral measurement isolates only gamma rays produced for oxygen recording

• Detecting water entries • Detecting thief zones

• Gamma rays produced as a result of oxygen activation are recorded spectrally, allowing elimination of all other sources of gamma rays

• Discovering cross flow between zones • Detecting leaking plugs and packers

• Because it measures spectrally, it can determine Compton downscattering, allowing qualitative determination of whether flow is inside or outside the pipe

• CO2 flow measurements Features • Specially designed for quantitative water-flow measurements • Modified detector section for the pulsed neutron capture tool includes source-to-detector spacing to eliminate effects of stationary water in the borehole and/or the formation

Associated Answer Products • QW (Calculates water-flow rate and velocity)

• Fully combinable with a complete string of production log sensors

Spectra Flow™ Logging Service (SpFl) Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

18 (5.5)

1.6875 (42.8625)

15,000 (103.4)

325 (162.8)

70 (31.8)


DSN™ Dual-Spaced Neutron Tool The DSN™ dual spaced neutron tool is a thermal neutron tool designed to measure formation porosity from neutronnuclei interactions. Neutron porosity logs provide total fluid information for use with resistivity logs and/or pulsed neutron logs in determining formation water saturation. They can be combined with density logs to provide an indication of formation gas saturation and also with density and/or sonic logs to provide indications of formation lithology. In open holes, the DSN tool is usually combined with the SDLT™ spectral density logging tool and the NGRT™ natural gamma ray tool. In cased holes, the DSN tool is usually combined with the NGRT tool and DITS™ casing collar locator.

Applications • Gas detection • Porosity • Lithology

HAL1664

The DSN tool consists of an instrument section housing the electronics, two He3 detectors, and a source sub housing an americium-beryllium source which generates fast neutrons that penetrate the formation at an initial energy of 4.6 MeV. Thermal neutron tools are not as limited by the spacing and depth of investigation problems associated with epithermal neutron tools. Since thermal neutrons are detected, count rates are much higher than for epithermal neutrons. However, thermal neutron detectors are more sensitive to lithology and are affected by borehole and formation salinity. The dual detector method is used to compensate for these environmental effects.

In this DSN™ log example, the subject well was logged twice. The resulting near/far ratio curves and the calculated porosity curves are overlaid to illustrate high repeatability of DSN porosity measurements.

Features • Detector array contains two helium proportional counters • Optimized detector spacing, advanced calibration methods, and greater counting rates • Faster log runs • Delineation of thin-bed formations with enhanced vertical resolution (EVR) available in real-time or in post-processing • A combination of logging tools can be run to identify lithology, reveal gas zones, and calculate shale volumes


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Associated Answer Products • The wellsite answer product is the neutron porosity NPHI


• Neutron porosity data is also used with other open-hole sensors as input to Halliburton’s mineralogy, open-hole, and cased-hole saturation analysis to provide a complete formation evaluation product. These include:


DSN™ Dual-Spaced Neutron Tool Specifications

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Length ft (m)

Diameter in. (mm)



Weight lb (kg)

10.25 (3.1)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

196 (88.9)


FCMT™ Formation Compaction Monitoring Tool The FCMT™ formation compaction monitoring tool is a through-tubing instrument that can be run in production wells. The tool uses multiple gamma ray detectors to determine the location of and precise distance between radioactive markers planted in the formation or casing. Compaction of the formation can be measured by changes in the distance between the markers. Vertical compaction and the lateral displacement of markers can also be monitored using the FCMT tool. Applications • Determine the location of and precise distance between radioactive markers planted in the formation or casing • Monitor vertical compaction and lateral displacement of markers Features • Unique construction allows spacing between detectors to be easily altered to fit the application • Available in three-detector or four-detector arrays to help make necessary configuration changes easy to implement • Measures tool temperature to correct for thermal expansion

• A pair of induction-type casing collar locators (CCLs) provides additional compaction/depth measurements

HAL9762

• Depth measurements are corrected for irregular tool motions using a uni-axial accelerometer

Track 1 consists of the processed gamma ray reading from detector 1. It shows the high spikes of the radioactive tags with the upper three tags being placed in the formation while the lower three tags were placed in the casing. Three different methods are used to determine spacing between radioactive tags. The next track shows the depth of each tag plus the distance between tags as calculated by special processing. This processing can be extremely accurate as long as the tag placement is close to the spacing between gamma ray detectors. The red numbers in Track 3 indicate the average of all the different methods to calculate distance between the tags. Track 4 is the average of all the methods less the HES method. The last track is raw gamma ray data from the three detectors. The tool configuration in this case consisted of three gamma ray detectors with 1 ft spacing between the first two detectors and 30 ft between the second and third. Distance between each detector is corrected for temperature affects and is used in the post-processing software.

FCMT™ Formation Compaction Monitoring Tool Specifications Length* ft (m)

Diameter in. (mm)



Weight** lb (kg)

–

1.68 (42.7)

15,000 (103.4)

350 (176.7)

–

* Specified by customer ** Depends on configuration


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CASE™ Casing Evaluation and Inspection Software CASE™ casing evaluation and inspection software is a series of programs that will use data from either the rotating ultrasonic tools (FASTCAST™ or CAST-V™ tools) or the multi-finger caliper tools to provide accurate casing evaluation. When the ultrasonic data is recorded in the casing mode, CASE software provides precise casing ID and thickness presentations that allow easy interpretation of casing damage. When the ultrasonic data is acquired in the image mode or with multi-finger caliper tools, CASE software provides a detailed interpretation of the interior casing damage. With both the FASTCAST and CAST-V tools in the image mode, they can be used to monitor wear on the inner surface of the casing string. Its high vertical and horizontal resolutions nearly eliminate the chance of missing flaws in a string of pipe, thus preventing possible long-term problems. In the cased-hole mode, the ultrasonic tools provide accurate casing ID and casing thickness measurements. With these two measurements, it is possible to determine the total damage to the casing and proportionate it to either inside casing wear, outside casing corrosion, or a combination of the two. The CASE software family provides detailed information on the condition of the casing, preventing minor problems from becoming major problems. The software consists of several different programs to provide the best possible interpretation of casing damage. With both ultrasonic and caliper data, slight tool eccentering problems will lead to an inaccurate analysis. Spiral or patterns similar to a barbershop pole are indications of eccentricity problems, not necessarily casing wear. The program HoleShape corrects the travel time data for tool eccentering. The correction increases the detail of the travel time image leading to an improved visual interpretation of casing defects. The CASE program will use the corrected travel time, the pipe thickness, and fluid travel time to evaluate the casing condition and determine the percent of casing wear. With this program, the results are presented both calculated and normalized for each size and weight of the casing present. If the casing is perfect (no damage in radius or thickness), then the normalized radius and thickness measurements will be zero. If the casing has internal corrosion, the radius measurement will be larger than the known, and the thickness will be smaller. Therefore, the normalized data will

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show the loss of casing wall as an increase in the pipe radius and a decrease in pipe thickness. This information allows us to grade the pipe based on the total loss of metal, and can determine if the damage is inside/outside or a combination of both for the casing in question. These grades are based on industry standards or can be adjusted based on customer requirements. The final program in this family is the CASE_JOINT program that finds, counts, and displays data based on each joint. For casing evaluation, collars provide problems with the standard casing analysis logs. There are usually gaps between adjacent joints, additional metal in the collars, and possible damage near the collars from when the joints were made up. This program will determine the joint makeup point, and allow determination of both joint and collar damage based on the grading used in CASE software. The CHIME program combines all these programs and also has the ability to provide graphical displays of damage from both the ultrasonic and caliper tools. In addition, the CASE programs generate both spreadsheets and text files that list minimum, maximum, and average values of both the internal radius and the thickness of the casing not only on a joint-by-joint listing but also as a depth-by-depth listing. These files will allow continuous monitoring and comparisons of casing wear throughout the life of the well. Features • Delivers a more reliable indication of casing condition • Works with existing logging procedures for FASTCAST, CAST-V, and MIT tool data • Improves casing evaluation for both inner and outer defects • Corrects for tool eccentricity thus helping to distinguish even minute casing problems • Log presentations can be customized to meet the specific requests or needs. Presentations include raw data, segmented curves, and images, including 3D displays • Joint and depth listings of defects allow easy input into other programs or a simple method to monitor known casing deformities Health, Safety, and Environmental • Helps customers to monitor and prevent catastrophic casing problems • Proper CASE software usage allows monitoring of casing erosion / corrosion / rectification


Y000

Y030

Y030

Y050

This CASE™ processed log effortlessly shows where a packer was set and did not release properly. The metal was peeled up when the packer was pulled, which is highlighted by the green stripe box in the depth track. This zone is expanded on the log on the left. Track 1 provides gamma ray for correlation along with eccentricity and ovality. Eccentricity consists of tool and casing eccentricity, while ovality measures casing ovality. INTDAMG is the percent of pipe wear on a scale from 0 to 50 percent. The AVRAD is the average radius calculated from the 200 radius measurements from the CAST-V™ tool. Track 2 is the amplitude of the first arrival and can be used to visually indicate casing damage. Track 3 is an eccentricity corrected travel time for the first arrival. This will be used in determining casing ID or radius. Track 4 shows the minimum, maximum, and average of the normalized pipe radius PRADN. The normalized pipe radius is shown in Track 5 where red is showing the packer damage and blue is showing metal buildup from the packer damage. The last track shows the pipe grading where the damage is color coded with the following percentages: white< 20% 80% damage. This allows an easy indication of pipe wear. The images below were generated from CHIME showing the casing damage in 3D view.


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Through Casing Acoustic Services WaveSonic® Tool The WaveSonic® crossed dipole sonic tool provides simultaneous monopole, XX dipole, and YY dipole sonic measurements. The dipole flexural wave propagation allows for the measurement of shear wave slowness in virtually all formation conditions. The compressional P-wave slowness, refracted shear wave slowness, and Stoneley wave properties are obtained from the monopole data. The shear wave slowness in two orthogonal directions can be obtained in real- time from the XX and YY dipole data. The WaveSonic tool is combinable with all standard open and cased-hole tool services. The WaveSonic tool requires a liquid filled borehole and can be used in fresh water, salt water, or oil based mud systems. The robust mechanical design of this tool allows for drillpipe conveyed logging, and it is not limited to the bottom of the toolstring. A hostile WaveSonic® version is available for high temperature and high pressures applications. The shear wave slowness in the XX and YY directions and the monopole P-wave slowness are the basic well site deliverables. The tool has 32 broadband receivers, arranged in eight rings of four receivers, to provide high-quality waveform data. The tool provides 96 waveforms (32 monopole, 32 YY dipole, and 32 XX dipole) for each firing cycle, which are recorded by the surface system. The fast and slow shear wave travel times are obtained with advanced waveform processing methods in Halliburton's Reservoir Evaluation Services centers, strategically located throughout the world. From the fast and slow shear wave travel times, and their orientation in the formation, the minimum and maximum principal stresses and stress field orientation can be obtained by combining oriented slowness data with overburden and analysis, wellbore stability, and production enhancement treatment design.

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Natural gamma ray and caliper are presented in Track 1. Semblance quality data is presented in the depth track. The dipole X travel time, dipole Y travel time, and monopole P-wave travel time are presented in Track 2. Monopole semblance with the compressive wave slowness overlaid on the semblance image are presented in Track 3. The dipole X semblance with the XX shear wave slowness overlaid on the semblance image are presented in Track 4. The dipole Y semblance with the YY shear wave slowness overlaid on the semblance image are presented in Track 5.


Sonic anisotropy analysis provides the fast and slow shear wave travel times as a simultaneous solution of 64 waveforms(32 XX and 32 YY). Anisotropy and its orientation can be used to determine the minimum horizontal stress and the orientation of natural fractures. The sonic attributes of slowness, amplitude and frequency content can be used for identification of fractures and compressive fluids and to measure various geomechanical properties. The fast and slow shear wave travel times and their orientation, combined with P-wave slowness, allows for better 3D seismic analysis.

• Broadband eight-level, quad receiver array for highquality waveform data

Applications • Determine fast and slow wave travel times and orientation in the formation

• RockXpert2™ sand production and fracture strength analysis

• All 96 waveforms for each set of transmitter firings are recorded at the surface for advanced waveform processing techniques • Combinable with all open-hole tools, including MRIL® and RDT™ tools and services Associated Answer Products • Shear slowness anisotropy analysis

• FracXpert™ fracture stimulation zoning analysis pore pressure data information is vital for geo-mechanical

• Calculate minimum and maximum principal stresses and stress field orientation

• Instantaneous waveform attributes

• Porosity estimation

• Stoneley derived permeability

• Fracture identification

• Stoneley reflection analysis

• Permeability (mobility) estimation

• Formation stress, borehole stability and sanding potential

• AVO calibration • Synthetic seismogram Features • Programmable-frequency sources to minimize effects of near-wellbore alteration

WaveSonic® Tool Specifications Length ft (m)

Diameter in. (mm)

Maximum Pressure psi (mpa)


Weight lb (kg)

34.0 (10.3)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

520 (236.3)

Hostile WaveSonic® Tool Specifications Tool Version

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

20 KPSI Tool

40.9 (12.4)

3.13 (79.4)

20,000 (137.9)

500 (260.0)

595 (269.9)

30 KPSI Tool

40.9 (12.4)

3.13 (79.4)

30,000 (206.8)

500 (260.0)

720 (326.6)


4-13

FWS™ Full Wave Sonic Tool The FWS™ tool provides compressional wave, refracted shear wave, and Stoneley wave properties of downhole formations for a wide range of petrophysical, geological, and geophysical applications. To minimize the number of logging trips required for complete formation evaluation, the FWS tool is compatible with all DITS™ logging tool strings. A liquid-filled borehole is required for sonic logging and can be used in fresh water, salt water, or oil-based mud systems. The long transmitter-to-receiver offset allows for the acquisition of borehole sonic data beyond the effects of any near-wellbore altered region. This long offset also allows for the acquisition of high-quality sonic data in enlarged boreholes where critical angle effects would affect sonic tools with short transmitter-to-receiver offsets.

• Slowness presentation – compressional slowness and refracted shear slowness, velocity ratio, and time-depth integration of the compressional and shear travel times, and other logging data such as gamma ray and caliper • Quality presentation – indicators which establish confidence levels for the slowness processing, including compressional slowness and semblance coherency and refracted shear and semblance quality gain curves for each receiver

HAL9170

The information obtained from the FWS tool is plotted in three separate log presentations:


• Waveform presentation – waveforms from all four receivers can be presented. Gain curves reflecting the gain applied to the waveform by the automatic gain control (AGC) circuit, and correlation curves, including gamma ray and caliper information The FWS tool can be run in the cased-hole environment to obtain sonic properties through casing. Acoustic coupling of the pipe-to-formation is required for cased-hole applications. Applications • Identify wave properties of downhole formations • Acquisition of borehole sonic data

4-14


Features • Long transmitter-to-receiver offsets and 1 ft receiver-to-receiver spacings • Detection of signals at all receivers for each transmitter pulse ensures constant source characteristics • Automatic gain control of each receiver preserves signal amplitude • Downhole digitizing helps eliminate transmission noise and allows broadband frequency response • Low-frequency response allows detection of low frequency Stoneley waves and multiple Δt measurements per depth interval • Continuous uninterrupted recording of full waveform signals • Records various types of information including tool data, quality curves, and final results • Operator-selectable multiple modes of tool operation, digitally recorded waveform data, and improved porosity estimates using both Δtc and Δts

• Lithology identification by means of velocity ratio, Δts/ Δtc, and location of gas zones, even in poor hole conditions and cased holes • Indication of permeability variations with depth from Stoneley wave attenuation and slowness • Detection of naturally fractured zones, determination of rock elastic constants, and estimation of formation strength and least horizontal stress • Prediction of vertical extent of hydraulic fractures • Improved vertical resolution for detection of thinner beds (Beds as thin as 3 in. can be identified with the t curves) • Calculates sonic porosity from P-wave slowness and can determine secondary porosity by combining sonic porosity with neutron and density porosity data • Time-to-depth correlation for seismic correlation • Combining sonic slowness data with formation density data is the required input information needed for synthetic seismograms

FWS™ Full Wave Sonic Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

28.6 (8.7)

3.625 (92.1)

20,000 (137.9)

350 (176.7)

460 (208.7)


4-15

HFWS™ Hostile Full Wave Sonic Tool The HFWS™ tool is a 2.75-in. acoustic velocity logging tool that is a part of the HEAT™ suite hostile environment applications tool toolstring. The HFWS tool, along with all of the HEAT suite sensors, have a pressure rating of 25,000 psi (172 400 kPa). The HEAT suite logging tools are designed for continuous operation of six hours at 500°F (260°C).

The HFWS tool can be compared to having two sonic tools within the same toolstring—a long-spaced sonic tool for traditional full waveform open-hole sonic logging, and located within the transmitter-to-receiver offset, a cement bond tool that utilizes the second transmitter and two receivers. The upper transmitter and the lower four receivers array are utilized for full wave sonic logging. The lower (second) transmitter and the upper two receivers are utilized for cement bond logging and short, offset compressional wave travel time. The long transmitter-to-receiver offset allows for the acquisition of borehole sonic data beyond the effects of any near-wellbore altered region. The long offset also allows for the acquisition of high-quality sonic data in enlarged boreholes where critical angle effects would affect sonic tools with short transmitter-to-receiver offsets.

HAL9171

The HFWS tool, like the larger in diameter (3.625-in.) FWS™ full wave sonic tool, provides compressional wave, refracted shear wave, and Stoneley wave properties of downhole formations for a wide range of petrophysical, geological, and geophysical applications. To minimize the number of logging trips required for complete formation evaluation, the HFWS tool is compatible with all HEAT suite logging toolstrings. A liquid filled borehole is required for sonic logging, and can be used in fresh water, salt water, or oil-based mud systems.


Applications • Full waveform open-hole sonic logging • Cement bond logging • Acquisition of borehole sonic data

4-16


Features • Advanced system design and software processing with long transmitter-to-receiver offsets and 1/2 ft receiver-toreceiver spacings • Detection of signals at all receivers for each transmitter pulse to promote constant source characteristics • Automatic gain control of each receiver helps preserve signal amplitude • Downhole digitizing helps eliminate transmission noise and allows broadband frequency response

• Facilitates continuous uninterrupted recording of full waveform signals • Ability to record various types of information including tool data, quality curves, and final results • Operator-selectable multiple modes of tool operation, digitally recorded waveform data, and improved porosity estimates using both Δtc and Δts

HAL9172

• Low-frequency response allows detection of low frequency Stoneley waves and multiple Δt measurements per depth interval

Gamma ray and caliper are presented in Track 1, compressional wave travel time (DTC) is presented in Track 4, and the P-wave semblance quality is presented in Track 3.

• Facilitates lithology identification by means of velocity ratio, Δts/Δtc, and location of gas zones, even in poor hole conditions and cased holes • Indication of permeability variations with depth from Stoneley wave attenuation and Δt • Detection of naturally fractured zones, determination of rock elastic constants, and estimation of formation strength and least horizontal stress • Prediction of vertical extent of hydraulic fractures using the RockXpert2™ analysis package • Improved vertical resolution for detection of thinner beds (Beds as thin as 3-in. can be identified with the t curves) • Combining sonic slowness data with formation density data are the required input information for synthetic seismograms

HAL9173

• Time-to-depth correlation for seismic correlation

This is a hard rock example. Natural gamma ray, caliper, and VpVs are presented in Track 1. The P-wave travel time and the refracted shear wave travel time are presented in Track 2. The semblance quality is presented in an image format in Track 3 for the P-wave and refracted shear wave.

HFWS™ Hostile Full Wave Sonic Specifications Length* ft (m)

Diameter in. (mm)


30.2 2.75 25,000 (9.2) (69.9) (172.4) * Add 3.50 ft (1.1 m) for each in-line centralizer (usually two). **6 hour



Weight lb (kg)

500 (260)

340 (154.2)

4-17

Production Logging Production Logging Tools A wide range of production logging tools for use in all type of downhole environments are available: • Production logging tools for vertical, deviated, and horizontal wells • Full range of sensors and running hardware for memory and electric line PL logging

• Fluid identification / flow composition tools – gas holdup, capacitance water holdup, radioactive fluid density, differential pressure density, capacitance array • Flow condition / well diagnostic tools – pressure, temperature, X-Y caliper, inclinometer • Correlation tools – gamma ray, casing collar locator Memory Production Logging The memory production logging string is normally deployed on slickline or coiled tubing. Simultaneous telemetry transmits the signals from standard sensors to a battery powered memory tool at the top of the toolstring. The memory tool is programmed using a computer and interfaces to record log values with intervals as short as 0.1 seconds or as long as many hours between readings. Once the logging operation is complete, the procedure for merging the log-time and depth-time data is rapid.

HAL9253

Applications • Flow rate measurements – continuous flowmeters, basket flowmeters, fullbore flowmeters, spinner array tool (SAT)

This example provides a display of typical production logging tool data. For a complete interpretation temperature, pressure, holdup, and fluid velocity readings are necessary. Track 1 consists of the gamma ray (GR1), pressure (PR1), and temperature (TEMP1). The pressure data shows that this well has not achieved a steady production rate at this time. Tracks 2 through 4 provide data concerning the fluid holdup as measured by the CAT™ tool, radioactive fluid density, and fluid capacitance tool. Tracks 5 and 6 provide information about the fluid movement and cable speed. Track 2 consists of the average capacitance reading from four different passes of the CAT tool. Higher readings indicate hydrocarbons while water is around 450 counts or the right side of the track. Track 3 is the fluid density from four passes of the radioactive fluid density tool. Likewise, Track 4 consists of four passes of the fluid capacitance tool where low counts indicate water while the higher counts indicate hydrocarbons. Track 5 consists of four passes of the continuous spinner with pass 1 and 2 showing a nonsteady state. Track 6 shows the speed of the tool, and since the well was logged with a coiled tubing the two speeds are about 30 fpm down and 20 fpm up.

Electric Line Production Logging Using a computerized LOGIQ™-CH system, calibration, recording, and printing of well logs can be done in real time. When operating in this mode, the downhole telemetry transfers data from the toolstring to the surface system via electric line.

4-18


Features • Great selection of flowmeter types and sizes, including the SAT tool for deviated or horizontal wells

• Greater consistency of data sets as a result of using the same sensors for electric line and memory operations

• High sensitivity and low threshold velocity flowmeters

• The same telemetry platform is used to run production logging tools with casing inspection and/or pulse neutron tools, either sequentially in one trip in the hole or simultaneously if required

• Standard and compact tool sizes • Multiple logging sensors in one string. All PL sensors can run simultaneously except the bottom only tools • Advanced sensors such as the GHT™ gas holdup tool, CAT™ capacitance array tool, and spinner array tool (SAT) for horizontal and undulating wells • Conveyance flexibility – toolstring can be deployed on electric line, slickline, coiled tubing, or drillpipe

• Faster telemetry, accurate, safe, reliable operations

Associated Answer Products • Hard copy log of multiple sensor measurements • Wellsite production log analysis • Advanced production log analysis at Applied Formation Evaluation Centers

Production Logging Tools Specifications Summary PL Tool Category

Correlation

Flow Condition / Well Diagnostic

Fluid Identification

Tool Type

Tool Length in. (mm)

Casing Collar Locator

18.5 (470)

Production Gamma Ray

23.1 (586)

Dual Caliper

37.5 (953)

2 to 9 in.

0.015 in.

0.1 in. <150°C; 0.2 in. <165°C; 0.3 in. <177°C

14.5 (6.6)

Quartz Pressure Gauge

19.01 (483)

0 to 15,000 psi

0.008 psi and <0.005°C

0.02% FS

8.8 (4)

Linearity <0.01% FS

Fast Response Platinum Resistance Thermometer

12.5 (318)

50 to 350°F (10 to 177°C)

0.006°F (0.003°C)

0.9°F (0.5°C)

10 (4.5)

Response time <0.5 sec

Inclinometer Accelerometer

10.7 (272)

+2 g to -1 g

0.004 g

0.01 g

Enhanced Capacitance Water Holdup Tool

26.2 (665)

Yw 0 to 100% best Yw<40%

0.1% external limitation

±1.0% for Yw < 40%

10 (4.5)

Radioactive Fluid Density Tool

22.9 (582)

0 to 1.25 g/cc

0.01 g/cc

± 0.03 g/cc

9.6 (4.3)

Differential Pressure Fluid Density Tool

51.9 (1318)

0 to 1.5 g/cc

0.001 g/cc

± 0.03 g/cc

Capacitance Array Tool

51.43 (1306)

Gas Holdup Tool

24 (610)

Range of Measurement

Resolution

Accuracy

Sensitivity Threshold 20 keV approx.

See details under flow imager, 12 capacitance sensors in 360° with RB information


0 to 100% gas holdup within 2.9 to 9.9 in. pipe (3 1/2 in. 9.2 lb/ft and 10 3/4 in. 51 lb/ft)

1%

± 3%

Weight lb (kg)

Others

12.1 (5.5)

Acquisition time: 1 sec typical

9.4 (4.25)

Sensitivity: 1 counts/API

Max well angle 70° 17.3 (7.8)

12 miniature capacitance sensor

8 (3.6)

1 sec typical

4-19

Production Logging Tools Specifications Summary PL Tool Category

Tool Type Inline Spinner Flowmeter

Tool Length in. (mm) 21 (533)

Continuous Spinner Flowmeter (Bearing)

Flowmeter

Combination Tool

Deployment Tools

Weight lb (kg)


Resolution

Accuracy

Max fluid velocity 3,450 ft/min

Threshold approx 8 ft/min in water

10 pulses/rev

10.6 (4.8)

Spinner shroud OD 1 11/16, 2 1/8, 3 1/8 in.



10 pulses/rev

3.5 (1.6) mechanical section only


10 pulses/rev



10 pulses/rev

10 (4.5)

Available for different casing size 4 1/2 to 9 5/8 in. (114 to 244 mm)

10 (4.5)


Continuous Spinner Flowmeter (Jeweled)

9 (229)



Caged Full Bore Flowmeter 3 Arm

34.9 (886)

500 ft/min (2.54 m/s), 28,250 BPD in 7-in. casing; with solid shaft tool can work up to 1,200 ft/min

1.7 ft/min approx (0.01m/s), 100 BPD in 7-in. casing


34.9 (886)



10 pulses/rev

Diverter Flowmeter

70.7 (1796)

Minimum 6-8 m3 per day. Maximum approx. 400 m3/d (6 psi drop ~120 lb uplift in 5 1/2-in. casing)


10 pulses/rev

Spinner Array Tool

46 (1168)

3 1/2 to 7-in. casing

12 ft/min in water

3/8-in. spinner 3 pulses/rev

Quartz Pressure CCL

19.01 (483)

Capacitance / Temperature / Flow

Approx. 18.5 (470) w/o flow mech section

Head Tension Unit

22.8 (580)

3 1/2 to 9 5/8 in. (90 to 244 mm) Approx 15 (6.8)

Same as capacitance / temperature flow individual tool. Flowmeter mechanical section can be any type of continuous or full bore flowmeter.

Hysteresis 5% FS

6 miniature spinner equispaced around circumference

8.8 (4.0)

Same as quartz pressure gauge and CCL individual tools

-400 kg (compr.) to +1000 kg

Others

Approx 5.4 (2.5) w/o flow mech section

Temperature Drift 5% FS

10 (4.5)

Repeatability ±2% FS

Roller Centralizer

Different roller centralizers are available with 3 or 4 arms with single or double rollers in each arm. Also have different centralization force as per operational requirement. Approx Length - 33.25 in. (845 mm) and weight around 12 lb.

Spring Centralizer

Different compact spring bows are available with 3 to 6 springs. Also have different centralization force as per operational requirement. Approx Length - 28 in. (711 mm) and weight around 10 lb.

Swivel Knuckle Joints

This is a monoconductor swivel joint which allows free rotation between the upper and lower heads while maintaining electrical continuity through the tool. Different sizes available, Approx Length - 11 in. (280 mm) and weight 4 lb. 7 (178)

Ball type knuckle for deployment in deviated well

3.5 (1.6)

1. Tools specified have nominal OD of 1 1//16 in. Tools with OD of 1 3/8 in. are also available. 2. All tools have maximum pressure rating of 15,000 psi and maximum temperature rating of 350°F or 177°C. For higher pressure or higher temperature tools contact your local Halliburton representative. 3. Telemetry is very high speed capable of running 62 tools in combination (virtually no limit on tool combination for telemetry).

4-20


FloImager® Service The FloImager® service provides three-phase holdup calculations using data from the CAT™ capacitance array tool. This service is extremely useful in highly deviated and horizontal wells having multiphase flow. Applications for detecting three-phase fluid entry can be done at any angle. The CAT tool is an electric line, tractor, or coiled tubing conveyed production logging instrument developed in partnership with Sondex. It consists of an array of 12 microcapacitance sensors which are radially distributed in the wellbore to accurately measure fluid holdup. This holdup measurement is fullbore. Consequently, tool position does not affect the readings in horizontal wells as would be the case with a center sample device.

Applications • Detect water entry and its orientation relative to the high side of the pipe in any well deviation • Successfully show three-phase fluid segregation since each fluid has its own log response • Provide an accurate visualization of the undulating horizontal wellbore when TVD data is combined with CAT tool data • Allows a complete three-phase analysis by combining the calculated fluid holdup with additional PL sensors • Improve interpretation of flow patterns in all wells due to the increased number of sensors at the same depth. Since the relative position of the CAT tool is known at all times, the images and logs are corrected to the high side of the hole, allowing accurate holdups to be determined


HAL9135

The CAT tool is uniquely versatile in that sensors are distributed across 12 bow springs, allowing cross-sectional measurements in tubing and in casing, logging up or logging down. This process can be repeated as often as necessary. Readings can also be taken with the tool stationary at any depth. The CAT tool can be run in combination with the spinner array tool (SAT), reservoir monitoring tools, and other conventional production logging sensors.

Track 1 consists of a gamma ray (GR), relative bearing (RB), temperature (TEMP), pressure (PRES), and continuous spinner (FCON). RB is the relative bearing for arm 1 of the CAT™ tool and allows arm position relative to the high side of the hole to be determined. Track 2 provides the image of the flow as measured by the CAT tool. The image is positioned so that the high sides are on the left and right side of the track while the middle is on the low side. Since this is a horizontal well, it should be apparent that the heavier fluids should be on the bottom and lighter fluids should be on the top of the well. Track 3 shows the average of the 12 sensors (AVCAPN) along with the two center sample holdup measurements fluid density (FDEN) and Hydro tool (HYDR). Track 4 provides a cross-sectional view of the data in Track 2. The right side of the image is high side while the left is on the bottom. Additionally two holdup curves are shown, water (YWE) and gas (YGE). These holdups are also presented in the last track. This presentation allows quick method of determine fluid contacts and provide an accurate calculation of the fluid compositions.

4-21

Features • Makes both vertical and cross-sectional images available

Associated Answer Products • Production logging analysis (PLA)

• Valuable data can be obtained in deviated or horizontal wells when run in combination with traditional PL sensors. Running the SAT tool in combination allows a complete analysis regardless of well geometry

• FloImager® 3D imaging product, CD-based 3D viewer • Reliable water holdup measurements in highly deviated and horizontal wellbores

• Permits more accurate three-phase holdups • Shows images in all types of stratified flow • Has unsurpassed responses in both deviated and horizontal wellbores • Can produce video-like images of the fluid distribution across the borehole with further processing

FloImager® Service Specifications

4-22

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

4.63 (1.4)

1.69 (42.9)

15,000 (103.4)

350 (176.7)

17.3 (7.8)


GHT™ Gas Holdup Tool Representing a major improvement over center sample production logging tools for horizontal and highly deviated wells, the GHT™ gas holdup tool is a unique tool that directly and accurately determines the volumetric fraction of gas over a cross-sectional volume element of the wellbore. This instrument operates in horizontal, highly deviated, and vertical cased wells in any flow regime. It measures gas holdup directly and with greater accuracy using real-time downhole pressure and temperature, casing ID, and gas gravity measurements to generate a 0% to 100% gas holdup log in stratified or homogenized flows. The superior information provided by the GHT tool mitigates against the ambiguities that an interpreter of conventional production logs sometimes encounters.

HAL9226

Applications • Fast, accurate flow analysis • Highly deviated horizontal and vertical cased wells • Reservoir evaluation Features • Determines gas holdup, independent of flow patterns or wellbore angles • Provides an improved true fullbore measurement • Helps identify water entry in gas wells • Converts a complex three-phase flow analysis into a simple dual-phase analysis

GHT™ tool and data in a vertical low-velocity well with multiple flow patterns. Track 1 consists of gamma ray, temperature, and pressure. Since GHT data is corrected for PVT relationships, it is extremely important to have these temperature and pressure sensors run in combination with GHT tool. Tracks 2 and 3 show the wellbore diagram consisting of formation, cement, casing, and perforations. Track 4 highlights the comparison of calculated gas holdups between the fluid density tool and the GHT tool. Track 5 shows the raw fluid density data. The raw GHT tool count rates are presented in Track 6. The last track provides the spinner data indicating fluid movement.

• Improve understanding of actual downhole flow conditions in wells producing gas • Real-time gas holdup measurements expedite the evaluation of well production • Helps avoid costly errors in judgment based on inaccurate flow analysis

GHT™ Gas Holdup Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

2 (0.6)

1.687 (42.8)

15,000 (103.4)

350 (176.7)

10.8 (4.9)


4-23

MPL™ Memory Production Logging Tool

The MPL system is comprised of the downhole data acquisition system, which includes memory production logging tools recording time-based data to the memory section. The standard memory section has 128 MB of memory and can be extended up to 1 GB of memory. It can run 62 tools at the same time. This new memory system can log production logging tools with casing or cement evaluation tools if required. It also includes the surface data acquisition system, comprising a depth and time recorder which records both time (from an internal clock) and depth pulses from a low current optical encoder. The unit can also be configured to record weight, tension, and other surface inputs. The Advanced Measurement System (AMS) can be included, comprising depth, time, weight, tension, and casing collar locator recording and a job log. Some sample capacities are shown below. Time Interval sec/sample

8.0 MB

4.0 MB

0.1

15 hours

7.5 hours

0.5

70 hours

35 hours

1.0

120 hours

60 hours

HAL964

MPL™ memory production logging is a system where slickline, conventional coiled tubing, or drillpipe conveyed tools acquire data without the need for electric line.

This memory production log was obtained for an operator looking to cut high water production in a formation with a three-phase downhole flow regime. The MPL™ service captures logging data on a memory recorder. The data is equal in quality to data obtained with electric line services.

Times given assume 6 PL tools and quartz pressure. Times are calculated to the nearest whole hour. Sample capacities might be limited by battery type. 4 MB tool all 12 ch sampling at 1sec = 49.5 hours.

Applications • Downhole well problem diagnostics • Production/injection profiles • Treatment (stimulation) evaluation • Multiple rate production logs • Fall off tests • Reservoir information

HAL965

• Data for reservoir simulation

Computing center analysis of the MPL™ data reveals that the bottom set of perforations is producing mostly water and only 2% of the total oil production and 6% of the gas. Remedial work to plug off the bottom zone should decrease water production and reduce water disposal costs without greatly affecting hydrocarbon production.

4-24


Features • Highly portable and easily deployed and can also be deployed on electric line if slickline is not available

• Utilization of slickline simplifies the pressure control equipment

• Utilizes the same conventional sensors as the standard electric line toolstring providing data of the same accuracy and resolution

• Very high memory enabling combination of production logging tools with casing or cement evaluation tools like MIT/MTT or CBL/RCBL tools

• Can be deployed with coiled tubing in highly deviated or horizontal wells. Suitable for offshore locations where there are limitations in space, weight-lifting capacity, and height restrictions

Associated Answer Products • Raw data hard copy log • Production log analysis, an AFE analyzed hardcopy log

MPL™ Memory Production Logging Tools Specifications Summary PL Tool Category

Correlation

Flow Condition / Well Diagnostic

Fluid Identification

Tool Type

Tool Length in. (mm)


18.5 (470)

Production Gamma Ray

23.1 (586)

Dual Caliper

37.5 (953)

2 to 9 in.

0.015 in.

0.1 in. <150°C; 0.2 in. <165°C; 0.3 in. <177°C

14.5 (6.6)

Quartz Pressure Gauge

19.01 (483)

0 to 15,000 psi

0.008 psi and <0.005°C

0.02% FS

8.8 (4)

Linearity <0.01% FS

Fast Response Platinum Resistance Thermometer

12.5 (318)

50 to 350°F (10 to 177°C)

0.006°F (0.003°C)

0.9°F (0.5°C)

10 (4.5)

Response time <0.5 sec

Inclinometer Accelerometer

10.7 (272)

+2 g to -1 g

0.004 g

0.01 g

Enhanced Capacitance Water Holdup Tool

26.2 (665)

Yw 0 to 100% best Yw<40%

0.1% external limitation

±1.0% for Yw < 40%

10 (4.5)

Radioactive Fluid Density Tool

22.9 (582)

0 to 1.25 g/cc

0.01 g/cc

± 0.03 g/cc

9.6 (4.3)

Differential Pressure Fluid Density Tool

51.9 (1318)

0 to 1.5 g/cc

0.001 g/cc

± 0.03 g/cc

Capacitance Array Tool

51.43 (1306)

Gas Holdup Tool

24 (610)


Resolution

Accuracy

Sensitivity Threshold 20 keV approx.

See details under flow imager, 12 capacitance sensors in 360° with RB information


0 to 100% gas holdup within 2.9 to 9.9 in. pipe (3 1/2 in. 9.2 lb/ft and 10 3/4 in. 51 lb/ft)

1%

± 3%

Weight lb (kg)

Others

12.1 (5.5)

Acquisition time: 1 sec typical

9.4 (4.25)

Sensitivity: 1 counts/API

Max well angle 70° 17.3 (7.8)

12 miniature capacitance sensor

8 (3.6)

1 sec typical

4-25

MPL™ Memory Production Logging Tools Specifications Summary PL Tool Category

Tool Type Inline Spinner Flowmeter

Tool Length in. (mm) 21 (533)

Continuous Spinner Flowmeter (Bearing)

Flowmeter

Combination Tool

Deployment Tools

Weight lb (kg)


Resolution

Accuracy



10 pulses/rev

10.6 (4.8)




10 pulses/rev



10 pulses/rev



10 pulses/rev

10 (4.5)


10 (4.5)


Continuous Spinner Flowmeter (Jeweled)

9 (229)




34.9 (886)




34.9 (886)



10 pulses/rev

Diverter Flowmeter

70.7 (1796)

Minimum 6-8 m3 per day. Maximum approx. 400 m3/d (6 psi drop ~120 lb uplift in 5 1/2-in. casing)


10 pulses/rev

Spinner Array Tool

46 (1168)

3 1/2 to 7-in. casing

12 ft/min in water

3/8-in. spinner 3 pulses/rev

Quartz Pressure CCL

19.01 (483)

Capacitance / Temperature / Flow

Approx. 18.5 (470) w/o flow mech section

Head Tension Unit

22.8 (580)

3 1/2 to 9 5/8 in. (90 to 244 mm) Approx 15 (6.8)

Same as capacitance / temperature flow individual tool. Flowmeter mechanical section can be any type of continuous or full bore flowmeter.

Hysteresis 5% FS

6 miniature spinner equispaced around circumference

8.8 (4.0)

Same as quartz pressure gauge and CCL individual tools

-400 kg (compr.) to +1000 kg

Others

Approx 5.4 (2.5) w/o flow mech section

Temperature Drift 5% FS

10 (4.5)

Repeatability ±2% FS

Roller Centralizer

Different roller centralizers are available with 3 or 4 arms with single or double rollers in each arm. Also have different centralization force as per operational requirement. Approx Length - 33.25 in. (845 mm) and weight around 12 lb.

Spring Centralizer

Different compact spring bows are available with 3 to 6 springs. Also have different centralization force as per operational requirement. Approx Length - 28 in. (711 mm) and weight around 10 lb.

Swivel Knuckle Joints

This is a monoconductor swivel joint which allows free rotation between the upper and lower heads while maintaining electrical continuity through the tool. Different sizes available, Approx Length - 11 in. (280 mm) and weight 4 lb. 7 (178)

Ball type knuckle for deployment in deviated well

3.5 (1.6)

1. Tools specified have nominal OD of 1 1//16 in. Tools with OD of 1 3/8 in. are also available. 2. All tools have maximum pressure rating of 15,000 psi and maximum temperature rating of 350°F or 177°C. For higher pressure or higher temperature tools contact your local Halliburton representative. 3. Telemetry is very high speed capable of running 62 tools in combination (virtually no limit on tool combination for telemetry).

4-26


Quartz Pressure Tool For high-precision downhole pressure measurement, Halliburton offers a quartz gauge tool that employs quartzdyne transducers, an industry standard quartz crystal pressure sensor. The tool provides both pressure and gauge temperature outputs. Fluid pressure applied to the quartz tension member changes the resonant frequency of the quartz crystal. Thermal compensation of the sensor and measurement of its temperature allows the calculation of very accurate, highresolution downhole pressures.

HAL9250

Applications • Measuring shut-in and flowing pressures at prescribed depth levels • Diagnosing well problems Features • Detects minimum pressure changes and temperature variations • Conveyance flexibility with the following methods: slickline, wireline, coiled tubing, and drillpipe • Resistance to corrosion Associated Answer Products • Plots that are available at the wellsite include flowing pressure surveys, static pressure gradient surveys, log-log pressure buildup, and derivative pressure plots

This log example shows how the quartz pressure tool can help determine flowing conditions. Track 1 shows the gamma ray (GR1) and four collar locator logs (CCL1-4) showing depth correlation. Track 2 provides four quartz pressure readings from continuous passes in this horizontal well. Normally in a stabilized well, the pressures have a common gradient as shown in Pass 4. Pass 1 and 2 indicate that this well has not been stabilized after shut-in. Track 3 has the four temperature passes with both fluid entry (higher temperatures) and gas entry (lower temperatures) in Pass 1. Track 4 includes some of the results from the CAT™ tool that can be used to determine fluid holdups.

• Advanced pressure transient analysis can also be done utilizing Sapphire software

Quartz Pressure Tool Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

Memory

1.0 (0.3)

1.65 (42)

15,000 (103.4)

350 (176.7)

6.5 (2.95)

SRO

1.9 (0.59)

1.65 (42)

15,000 (103.4)

350 (176.7)

9.6 (4.35)

Section


4-27

Casing and Tubing Evaluation MAC™ Multi-Arm Caliper Tool

Applications • Detail the condition of casing or tubing with accurate internal radius measurements

HAL10363

Halliburton offers a wide variety of multi-arm calipers that provide high-resolution details about the condition of the casing or tubing, including accurate measurements of its internal radius. The MAC™ tool is available for most casing and tubing sizes. The tool can operate 24 to 80 arms and is deployed on wireline, slickline, or coiled tubing. All data collected is used to generate 3D images of the casing or tubing.

• 3D images of casing or tubing

This 3D view shows an enlarged OD caused by perforating the well.

Features • Comes in several sizes to work in a wide range of casing • Can be deployed on wireline, slickline, or coiled tubing • Can obtain data in horizontal wells • Can be combined with production logging or cement bond tool • Accurately identifies casing damage such as holes, splits, or cracks and their depth in the wellbore • Provides a method for mapping perforations Associated Answer Products • MITview (multifinger imaging tool presentation package)

HAL10364

• Can be used for scale evaluation

This 3D image shows general deep corrosion with light deposits in the body possibly caused from cable movement.

• MITpro (multifinger imaging tool software)

MAC™ Multi-Arm Caliper Specifications Number of Arms

Length ft (m)

Diameter in. (mm)

24

3.75 (1.1)

1.69

15,000

150

20

(42.9)

(103.4)

(65.6)

(9.1)

40

5.5 (1.7)

2.75

15,000

150

62

(69.9)

(103.4)

(65.6)

(28.1)

60

80

4-28



Weight lb (kg)

5.75

4.00

15,000

150

100

(1.8)

(101.6)

(103.4)

(65.6)

(45.4)

3.33

8.00

15,000

150

93

(1.0)

(203.2)

(103.4)

(65.6)

(42.2)


CAST-V™ Circumferential Acoustic Scanning Tool-Visualization The CAST-V™ tool is an ultrasonic tool that provides highresolution images in both open and cased holes. The tool’s interchangeable head rotates a full 360° and contains a highfrequency acoustic transducer to provide a full 360° profile of the borehole or cement. A second acoustic transducer is mounted in the tool housing and is used to measure characteristics of the borehole fluid. A directional sub is provided to orient images to either the high side of the hole or to north. The image mode, run primarily in open hole, consists of 200 points horizontally by 40 samples per foot vertically while the cased-hole mode measures 100 points by 4 samples/ft. The CAST-V tool is designed to operate in conjunction with other DITS™ tools. The system provides high-resolution images indicating texture changes in the borehole wall or on the interior portion of the casing. These images can be used to identify fractures in the formation or slight internal defects in casing.

The CAST-V tool must be run centralized in fluid filled boreholes. It must be the bottom tool in any combination. Its operation is limited by factors such as high mud density and dissolved gases that increase the attenuation of the tool’s acoustic pulses as they travel through the borehole fluid. CAST-V tool differs from other ultrasonic type tools in the cased-hole mode by several different ways. It has 100 shots per depth frame versus 72 (maximum) and includes a realtime fluid travel time (FTT) measurement. The competition down logs FTT and then plugs the results into the uplog. All measurements are made real-time with no mode selection to determine what is or what is not being processed. It is fully combinable with all DITS tools, especially the M305 FWS™ tool for the CBL portion. The complete navigation package is standard with service. The competitor’s standard service does not include a navigation package—they additionally charge for running the service.

HAL9227

The CAST-V tool in the cased-hole mode also determines the casing thickness for pipe inspection. Simultaneously the CAST-V tool determines the type of material in the annular space between the casing and borehole wall.

The casing-evaluation presentation includes casing ovality, eccentricity, hole deviation, and gamma ray in Track 1. In this instance, the eccentricity is composed of both tool and casing eccentricity due to formation movement. Track 2 shows a cross-sectional presentation of the pipe shape. A cross-sectional of the pipe wall is presented in Track 3. Track 4 provides the average, minimum, and maximum value of the pipe radius that is shown in Track 5. Track 6 provides the average, minimum, and maximum value of the pipe thickness that is the image plotted in last Track 7. On the image logs red shows pipe thinning while blue indicates pipe thickening.

Applications • Simultaneous ultrasonic pipe inspection and cement evaluation • 2D and 3D borehole imaging • Process images, histograms, and curve-type data


4-29

Features • Allows 100 shots per depth frame measurement, providing complete circumferential coverage in casedhole cement evaluation and pipe inspection • Near real-time evaluation of complex and lightweight cements is accomplished through ACE™ processing • Combinable with all DITS™ tools. This can reduce rigtime when run with the M305 FWS™ tool for the cement bond log • Simultaneous cement evaluation and casing inspection capability • Real-time fluid cell measures both borehole fluid transit time and fluid impedance for measured data correction • Real-time casing thickness, casing OD, and ID Associated Answer Products • ACE™ processing for cement evaluation

The CAST-V™ tool is also useful in cement evaluation. See page 33 for more information on Cement Evaluation tools.

HAL9230

• CASE™ evaluation for casing inspection

The cement-evaluation presentation includes casing ovality and tool eccentricity in Track 1 along with the gamma ray. Conventional CBL amplitude and amplified amplitude data is presented in Track 2. Track 3 provides the typical CBL waveform showing both pipe to cement bond along with cement to formation bond. Data from the CAST-V™ scanner is displayed in Tracks 4 and 5. Track 4 provides information regarding the average impedance of the ZP image in Track 5. Likewise a CBI is a bond index from the same image and provides a quick indication of the percent of bond. The image in Track 5 is the Z map from 0 to 360° (left to right) with 0° representing the high side of the hole. The center of the track is scaled at 180°, which represents the low side of the hole.

CAST-V™ Circumferential Acoustic Scanning Tool-Visualization Specifications

4-30

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

17.9 (5.5)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

316 (143.3)


The FASTCAST™ Fast Circumferential Acoustic Scanning Tool The FASTCAST™ tool provides the same industry leading measurements and products for cement evaluation or pipe inspection as the CAST-V™ tool but at speeds up to five times faster. The FASTCAST tool data acquisition system is versatile and programmable at the wellsite, fully optimized for speed, based on the customer’s requirements and on the characteristics of the borehole. With a resolution improved by at the most a factor of 12 in pipe inspection mode, the FASTCAST tool can provide 100% coverage of casings up to 20-in. in diameter.

vertical resolution can be the traditional 3 in. but can be refined down to 0.1 in. Similarly, the number of waveforms per scan can be adjusted to provide full horizontal coverage down to the beam footprint of 0.25 in. The optimum coverage being identified, the job planner allows the engineer to acquire the data at the maximum logging speed suited for the application. Other features that open a wide range of new possibilities for looking at details further away from the casing / cement interface are the user-configurable waveform length and sampling interval.

The FASTCAST tool provides true measured full coverage unavailable by most other acoustic, electric, or mechanical devices. The factors that influence the logging speed are: • Horizontal coverage • Borehole size – smaller holes are logged faster because they require less shots / scan for the same amount of horizontal coverage • Vertical resolutions – lower resolution implying higher speed In open hole, the FASTCAST tool provides complete borehole imaging for accurate, precise, formation evaluation.

The FASTCAST tool in cement evaluation mode is used primarily to determine cement bonding and image channels in cement directly behind casing, but it can also be used to measure casing characteristics such as thickness and internal and external diameters. Images can be oriented to either tool body or the high side of the hole in any operating mode. When combined with a CBL tool, the cement evaluation log can be acquired at 60 ft/min or twice as fast as previous generation tools, yet providing the same quality product as the CAST-V tool for all cement types, including foam, through the Halliburton proprietary ACE™ processing. This increased logging speed results in a significant reduction in operating cost to the operator through minimized unproductive rig time. The FASTCAST tool in pipe inspection mode is optimized to provide the hole coverage suited to the application. The


HAL17810

In cased-hole, ultrasonic pipe inspection and cement evaluation can be obtained simultaneously.

4-31

The FASTCAST™ Tool Specifications Casing Data

CAST-V™

Casing OD in.

Casing Weight lb / ft

With or Without CBL, 100 shots / scan, 4 spf

The FASTCAST™ Tool Logging Speed (ft/min)

Standalone, Full Horizontal Coverage (4 spf)

With CBL and Full Horizontal Coverage (4 spf)

Standalone, Full Horizontal and Vertical Coverage (12 spf) 41

5.500

17

32

123

60

6.000

20

32

123

60

41

7.000

29

30

103

60

34

9.625

43

24

82

60

27

13.375

68

15

55

43

18

18.625

106

9

45

45

15

Temperature °F (°C)

Pressure psi (kPa)

Tool OD in. (mm)

Length in. (m)

Weight lb (kg)

Min Hole ID in. (mm)

Max Hole ID* in. (mm)

Vertical sampling in.

Logging speed ft/min

350 (175)

20,000 (137 900)

3.625 (92)

215 (5.46)

316 (143)

4.25 (108)

22.00 (559)

0.1 to 3.0

60 typical

*With interchangeable transducer head

4-32


Cement Evaluation Cement Bond Log (CBL) Cement bond tools (CBT) are sonic logging tools that have one omni-directional transmitter and two omni-directional receivers. Cement bond log tools are used to evaluate the effectiveness of cementing operations. The transit time measurement of the acoustic signal at the 3-ft receiver is used for two purposes: verification of the centralization of the CBL in free, non-bonded casing; and to identify fast formations in acoustically bonded intervals. In other than fast formations or free pipe, the transit time measurement is undefined. Correlation of the waveform data with other petrophysical measurements, such as gamma ray, porosity, or resistivity data, are used to identify the acoustic coupling of the cement to both the casing and formation. ACE™ advanced waveform processing methods can be used for concentric casing string evaluation. Cement bond logging tools come in a number of different tool diameters, pressure, and temperature ratings. Small diameter CBL tools are available for both through-tubing logging operations and small diameter casing completions. Applications • Measuring the attenuation of the acoustic energy in the casing-to-cement interface • Evaluating the cement-to-formation coupling by the correlation of the waveform data to other petrophysical measurements • Locating free pipe and top of cement • Evaluating the mud displacement processes


HAL9231

• Indicating channels or intervals with only a partial bond

This log example illustrates nearly free pipe, an apparent top of cement around X80, and below Y26 it is well bonded. Track 1 consists of the gamma ray for correlation and travel time which is used for quality control. Track 2 consists of the amplitude curve and amplified amplitude which indicates cement to casing bond. Track 3 consists of the CBL waveform which indicates both casing to cement bond along with cement to formation bond. Straight lines in the CBL waveform along with high amplitude readings indicate poor cement to casing bond.

4-33

Features • Runs in combination with a gamma ray and a collar locator for depth correlation purposes • Optional neutron correlation logs can be used in formations where there is minimal gamma ray contrast • Digital telemetry versions are combinable with the CAST-V™ tool for simultaneous ultrasonic cement and casing evaluation

• Cement sheath evaluation in a wide range of casing sizes from small diameter tubing to over 20-in. casing • Accurate correlation to open-hole measurements • Digital recording of the waveform data for real-time data transmission and advanced interpretational methods

• CBL tools are available that can be run on all types of wireline from large diameter 0.9375-in. slammer heptacables to 0.22-in. sour gas service monoconductor cables

Cement Bond Log (CBL) Specifications Sonde

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

FWST-A™ Full Wave Sonic Tool

20.4 (6.2)

3.63 (92.2)

20,000 (137.9)

350 (176.7)

365 (165.6)

HFWS-A™ Hostile Full Wave Sonic Tool

30.2 (9.2)

2.75 (69.9)

25,000 (172.4)

500* (260.0)

340 (154.2)

*6 hour

4-34


Radial Cement Bond Tools Cement bond tools (CBT) are sonic logging tools that have one omni-directional transmitter and two omni-directional receivers. In addition, the radial cement bond log (RCBL) tool has eight radial receivers and the RCBS tool has six. Radial cement bond tools are used to evaluate the effectiveness of cementing operations. The transit time measurement of the acoustic signal at the 3-ft receiver is used for two purposes—to verify the centralization of the radial cement bond tool in free, nonbonded casing, and to identify fast formations in acoustically bonded intervals. In other than fast formations or free pipe, the transit time measurement is undefined. Correlation of the waveform data with other petrophysical measurements, such as gamma ray, porosity, or resistivity data is used to identify the acoustic coupling of the cement to both the casing and formation. ACE™ advanced waveform processing methods can be used for concentric casing string evaluation. Applications • Indicating channels or intervals using radial receivers • Measuring the attenuation of the acoustic energy in the casing to cement interface

• Locating free pipe and top of cement • Evaluating the mud displacement processes

HAL9232

• Evaluating the cement to formation coupling by the correlation of the waveform data to other petrophysical measurements

Results from a specially designed test well for the RCBL and RCBS tools.


4-35

Features • It runs in combination with a gamma ray and a collar locator for depth correlation purposes • Optional neutron correlation logs or DSN™ dual-spaced neutron tool logs can be used in formations where there is minimal gamma ray contrast • DSN tool can be run for formation evaluation

• Cement sheath evaluation in a wide range of tubing or casing sizes from small diameter tubing to 13.38-in. casing, including channel identification • Accurate correlation to open-hole measurements • Digital recording of the waveform data for real-time data transmission and advanced interpretational methods

• It can be run on all types of wireline from large diameter 0.9375-in. slammer hepta-cables to 0.22-in. sour gas service monoconductor cables

Radial Cement Bond Tool Specifications Length ft (m)

With Centralizers ft (m)

OD in. (cm)



Weight lb (kg)

Maximum Casing in. (cm)

Minimum Casing in. (cm)

RCBS

15 (4.57)

21.6 (6.58)

1.69 (4.29)

20,000 (137.9)

350 (176.68)

75 (34)

7.5 (19)

RCBS-P1

13.12 (4)

17.72 (5.4)

1.69 (4.29)

20,000 (137.9)

450 (232)

78 (35.38)

RCBS-P2

8.75 (2.68)

13.15 (4)

2.75 (6.98)

20,000 (137.9)

350 (176.68)

RCBL

13.83 (4.23)

20.43 (6.23)

3.125 (7.94)

20,000 (137.9)

HTHP*

13.175 (4.2)

3.125 (7.94)

30,000 (206.8X)

Sonde

Borehole Fluids Salt

Fresh

Oil

2 (5.1)

X

X

X

7 (17.78)

2.875 (7.3)

X

X

X

106.5 (48.31)

9.625 (24.45)

4 (10.16)

X

X

X

375 (190)

215 (97.5)

13.38 (33.98)

3.75 (9.53)

X

X

X

400 (204.4)

151.65 (68.79)

13.4 (34)

3.75 (9.53)

X

X

X

Air

*Supplies are limited. Please contact your local Halliburton representative for more information.

4-36


ACE™ Advanced Cement Evaluation Process The ACE™ advanced cement evaluation process helps provide quick, accurate information concerning cement bond for all standard logging tools and procedures for any type of cement mixtures, including foam, latex, and other complex slurries.

and the activity level of the data. Through this process, the activity level is determined and will allow easy differentiation between solids and fluids. In addition, new bond-index curves and special log presentations have been developed to make interpretation quick and unambiguous.

Traditional cement sheath interpretation, using the standard cement bond log (CBL) or any other cement evaluation tool has severe limitations when used to evaluate complex cements. Lightweight, foamed, or complex cements affect the traditional methods of determining zonal isolation, which may create the misleading impression that the cement bond is inadequate. This can lead to the ordering of expensive and completely unnecessary remedial cementing.

The ACE process works on every cement evaluation tool that Halliburton offers as well as effectively evaluating data from other service companies. Not only does this method work on data from both the rotating (FASTCAST, CAST-V tools), and/or stationary ultrasonic logs (PET tool), it also provides detailed information using standard CBL logs, sonic logs, dipole sonics, segmented bond logs, and the newer generation of radial bond logs (RBT).

The ACE process is a new way of interpreting the cement evaluation tool data that is already being recorded during the logging runs. Although the ACE process was originally developed for lightweight cements, experience and experiments have shown that it provides a superior method for interpreting any type of cement. Above all it gives clear answers to the most urgent questions:

ACE analysis has been proven effective on cementing jobs in all parts of the world and on every type of cement now in use. It saves time and money by eliminating countless unnecessary squeeze jobs and associated expenses. Reducing the amount of unnecessary remedial cement operations will allow the customer to reduce operational expenses and contribute to the bottom line.

How good is my zonal isolation?

Features • Uses every cement evaluation tool to provide detailed information about cement bond

Do I need a squeeze job? The ACE process yields its greatest benefit when evaluating both the cement to pipe bond and the cement to formation bond. To properly evaluate the cement to casing bond, the FASTCAST™ and CAST-V™ ultrasonic tools along with the ACE process provide the best solution. However, both segmented and radial bond tools can be evaluated with the ACE process and still provide excellent information regarding the cement to pipe bond. The CBL and other sonic tools are used to determine the cement to formation bond along with the cement to casing bond. The ACE process uses the sonic waveforms to highlight the differences between bonded, partially bonded, micro-annulus, and free pipe. The ACE process can help determine the presence of cement between two casing strings, which was extremely difficult to quantify with previous logs and/or interpretation procedures. These extraordinary results are the product of a new technique based on a statistical-variation process to distinguish cement from fluid, even when both have the same raw value. This process actually will use two different methods to determine zonal isolation—the original tool data


• Works with existing logging procedures • Enhances current logs to achieve a better understanding of zonal isolation • Delivers a reliable cement bond index • Works for any cement—conventional, complex, lightweight, or foam • Helps improve cement interpretation for multiple casing strings • Delivers answers in minutes on location, using your log or data tape • Helps provide accurate and dependable cement bond interpretation regardless of the service company • Saves time and money by helping eliminate countless unnecessary squeeze jobs and associated expenses • Reduces the customer’s operational expenses and contributes to the bottom line by helping to eliminate unnecessary remedial cement operations

4-37

Track 1 presents correlation data (GR), quality control (ECTY), and the average impedance (ZAVG) which provides a quick interpretation of the cement placement. Track 2 presents the amplitude (AMP), amplified amplitude (AAMP), filtered cement bond index (FCBI), as well as the computed cement bond index (FCEMBI). Track 3 contains a standard CBL waveform display (WMSG). Track 4 is the total CBL waveform (WMSGT) which is the ACE™ processing which highlights the collar response. The ultrasonic impedance map (ZP) is presented in Track 5, which indicates the impedance of the material behind pipe. Track 6 (DZ) is the variance of the impedance map which highlights the differences between solids (cement) and liquids. Track 7 (CEMT) shows the result of both the impedance and variance in determination of solids vs. fluids. Fluids are designated as blue, while cement is indicated by the brown color. Tracks 8 to 16 provide 5 segmented curves from the impedance image broken into 9 segments around the wellbore. High activity indicates solids, and low activity indicates fluid. In the zone F notice how the curves have both low impedance and low activity compared to the data immediately above it in zone C.

4-38


Mechanical Services Pipe Recovery Chemical Cutter Chemical cutters eject a circular stream of bromine trifluoride (BrF3) to dissolve pipe with a clean cut that leaves no debris and does not require milling prior to pipe retrieval. Built-in flexibility allows the tool to be adapted for many special cutting applications where other cutting methods may be ineffective or undesirable. Chemical cutters provide a clean pipe cut. Chemical cutters can also shorten operating time and reduce rig costs by eliminating the flare associated with explosive cutters and the related need to dress flares with a mill run before fishing operations can start. Additionally, chemical cutters can be used to release specially designed permanent packers such as Halliburton’s AHR™ cut-to-release packer. They can be used to cut pipe and casing during plug and abandonment operations, sever duplex22 nickel/chromium tubing or other high-grade tubulars for salvage or reuse, and replace or retrieve old or deteriorating pipe in environmentally sensitive areas. Applications • Re-establishing circulation during drilling operations by chemically punching drill collars or heavy weight pipe • Removing metal restrictions blocking the well in open or cased holes with downward chemical junk shot

• Cutting drillpipe after freepoint and backoff operations when sensitive washover and fishing operations are anticipated

• Can pass through normal restrictions and still make a clean cut on standard size tubulars below the restriction

• Cutting large pipe (7-in. or larger OD) utilizing a special wagon wheel configuration

• Performs under a wide range of temperatures, pressures, and depths

• Using chemical cutter/tubing hanger combination in high pressure situations when normal operations may cause pipe to drop after being cut

• Does not damage adjacent string during cutting

• Cutting standard-diameter pipe through normal restrictions

• Severs pipe flare-free for retrieval through a packer or other restriction

• Shooting large holes in tubulars for gravel pack production

• Does not change ID or OD of the cut

Chemical cutters require the following inputs or samples to perform properly:

• Capable of cutting high-grade tubulars

• Well sketch

• Specially designed slip assembly maintains mechanical tool stability and helps ensure that pieces of metal are not ejected from the tool in case of accidental firing

• Type of pipe to be cut (ID, OD, metal composition, any plastic coatings) • Any other restrictions or problems • Temperature and pressure at cutting depth • Type of fluid in the well, including any solvents or paraffins in the well • Any other ID restrictions above the depth to be cut Features • Standard cutting head sizes from 0.75-in. to 5.5-in. OD • Unique holddown system to centralize the tool for even cuts without damaging pipe • Deployment via electric wireline, coiled tubing, rigid tubing, or slickline


• Produces no debris or drillpipe deformation which might require milling

• Manufacture from high-grade, heat treated steel that will not rupture even if tool is accidentally fired at the surface • Unique safety sleeve that virtually eliminates possibility of exposing the cutting head to operators and equipment • Guiding rope system that helps ensure personnel are always at a safe distance from the tool when it is being placed into or removed from the well • Safety features based on worst-case scenarios and tested under actual conditions to help provide quick responses to any situation

4-39

Caution: Prior to every chemical cutter job, Halliburton

strongly recommends checking for restrictions in the well by performing a gauge run and string shot.

Halliburton’s chemical cutter supplier is Pipe Recovery Systems Inc. (PRS).

Selection Guide for Coiled Tubing Chemical Cutter Tool Specifications

Coiled Tubing Specifications

Tool Size in. (Anchor And Sev Head)

Max. Extension of Wedges/Slips in.

OD in.

ID in.

Weight lb/ft

*11/16

0.92

1

0.782 - 0.810

0.918 - 1.037

*3/4

1.05

1

0.826 - 0.866

0.688 - 0.848

*13/16

1.09

1 1/4

0.938 - 1.076

1.081 - 1.823

*7/8

1.11

1 1/4

1.032 - 1.076

1.081 - 1.328

*15/16

1.15

1 1/4

1.100 - 1.116

0.840 - 0.941

*1

1.33

1 1/2

1.188 - 1.282

1.619 - 2.239

*1 1/16

1.35

1 1/2

1.188 - 1.282

1.619 - 2.239

*1 1/8

1.42

1 1/2

1.282 - 1.334

1.256 - 1.619

*1 3/16

1.51

1 3/4

1.374 - 1.500

2.169 - 3.136

*1 1/4

1.61

1-3/4

1.400 - 1.532

1.910 - 2.944

1 3/8

1.80

2

1.594 - 1.688

3.072 - 3.896

1 1/2

2.04

2

1.732 - 1.782

2.201 - 2.671

1 11/16

2.20

2 3/8

1.969 - 2.025

4.112 - 4.709

1 7/8

2.55

2 3/8

2.063 - 2.157

2.638 - 4.709

2 1/8

2.60

2 7/8

2.469 - 2.563

4.530 - 5.793

2 5/8

3.35

3 1/2

3.094 - 3.150

6.215 - 7.148

* Denotes wedge type anchor

Selection Guide for CS Hydril Tubing 1.050 - 1.660 OD Tool Specifications in.

Tubing Specifications

Tool Size (Anchor And Sev Head)

Max. Extension of Wedges/Slips

OD in.

ID in.

Weight lb/ft

*11/16 *3/4

0.92

1.05

0.824

1.200

1.05

1.315

0.957

2.250

*13/16

1.09

1.315

1.049

1.800

*1 1/16

1.35

1.660

1.278

3.020

*1 3/16

1.51

1.660

1.380 - 1.410

2.100 - 2.400

* Denotes wedge type anchor

4-40


Selection Guide — Tubing for D/A Chemical Cutter Tool Specifications

Tubing Specifications

Tool Size (Anchor And Sev Head) in.

Max. Extension of Wedges/Slips in.

OD in.

ID in.

Weight lb/ft

1 3/8

1.80

1.90

1.500 - 1.650

2.40 - 3.64

2 1/16

1.670 - 1.751

3.25 - 3.40

1 1/2

2.04 2 3/8

1.703 - 1.995

4.70 - 7.70

1 9/16

2.10

2 3/8

1.853 - 1.995

4.70 - 6.20

1 11/16

2.20

2 3/8

1.939 - 1.995

4.70 - 5.30

1 3/4

2.50

2 7/8

2.059 - 2.441

6.50 - 10.70

1 7/8

2.55

2 7/8

2.059 - 2.441

6.50 - 10.70

2

2.58

2 7/8

2.195 - 2.441

6.50 - 9.50

2 1/8

2.60

2 7/8

2.323 - 2.441

6.50 - 7.90

2 E.R.

2.85

3 1/2

2.480 - 2.750

12.95 - 16.70

2 1/8 E.R.

3.10

3 1/2

2.480 - 2.992

9.30 - 16.70

2 3/16

3.10

3 1/2

2.480 - 2.992

9.30 - 16.70

2 1/4

3.15

3 1/2

2.602 - 2.992

9.30 - 15.50

2 3/8

3.25

3 1/2

2.602 - 3.068

7.70 - 15.50

*2 5/8

3.35

3 1/2

2.922 - 3.068

7.70 - 10.30

*2 7/8

3.65

4

3.240 - 3.476

11.00 - 15.70

*3 1/8

3.92

4

3.340 - 3.548

9.50 - 14.00

*3 1/4

4.04

4 1/2

3.640 - 3.958

12.60 - 20.00

*3 3/8

4.16

4 1/2

3.697 - 4.000

11.60 - 17.70

*3 1/2

4.28

4 1/2

3.826 - 4.090

9.50 - 15.50

*3 5/8

4.40

4 1/2

3.920 - 4.090

9.50 - 13.50

*3 7/8

4.68

5

4.154 - 4.408

15.00 - 21.00

*4

4.80

5

4.276 - 4.560

11.50 - 19.50

*4 3/16

4.92

5 1/2

4.548 - 4.778

20.00 - 26.00

*4 7/16

5.14

5 1/2

4.670 - 4.950

15.50 - 23.00

*4 9/16

5.14

5 1/2

4.892 - 5.044

13.00 - 17.00

5 1/2

6.50

7

6.004 - 6.214

28.00 - 35.00

5 3/4

6.50

7

6.276 - 6.456

20.00 - 26.00

6 3/8

7.37

7 5/8

6.765 - 7.125

20.00 - 33.70

* 6-slip anchor only


4-41

Tubing Cutters Jet Research Center’s tubing cutters are designed to cleanly sever a wide range of tubing quickly and efficiently. These proven design cutters are the world’s most widely used and have a performance record that is unsurpassed. The tubing cutter range includes industry-leading ceramic cap designs for minimum debris to economic cast iron versions for costeffective solutions. JRC tubing cutters offer high reliability in field applications with a minimum amount of set-up or configuration based on well parameters. JRC tubing cutters and method of assembly are patented technology (US Patent 5,129,322). Tubing cutters can be used with JRC’s proprietary RED® rig environment detonator, offering a high level of protection against stray voltage or inadvertent RFinitiation. Features • High strength ceramic cap provides 20,000 psi pressure rating • Breakup characteristic of the ceramic design leaves minimal debris in the well • Cutter design features minimum flare characteristic for ease of recovery • Extensive cutter range offers selection based on well conditions • Cutters available for high strength and chrome material • Special designs available to match unique well conditions

HAL11763

• Detonator options available to satisfy all applications

Tubing Cutters

4-42


Tubing Cutters Recommended Target Tubing Tubing OD in.

Cutter OD in.

Rating psi / °F

Explosive weight g

Housing Material

Shipping Class

Description

2 1/16

1 9/16-in. Tubing Cutter

100083086

1.563

15,000/400

4

Ceramic

2 3/8


100000352

1.688

20,000/400

8.5

2 3/8

1 11/16-in. Tubing Cutter (Cast Iron)

101288527

1.688

12,500/400

2 3/8


100000570

1.719

2 3/8


100000353

2 3/8


2 7/8

Part No.

Grade

Wall Th

(Incl Coupl.) lb/ft

1.4S UN0441

P105

0.216

3.25

Ceramic

1.4S UN0441

P105

0.190 0.254

4.70 - 5.95

8.5

Cast Iron

1.4S UN0441

P105

0.190 0.254

4.70 - 5.95

20,000/400

8.5

Ceramic

1.4S UN0441

P105

0.190 0.254

4.70 - 5.95

1.813

20,000/400

8.5

Ceramic

1.4S UN0441

P105

0.190 0.254

4.70 - 5.95

101290400

1.813

12,500/400

8.5

Cast Iron

1.4S UN0441

P105

0.190 0.254

4.70 - 5.95


100000354

2.031

20,000/400

15.4

Ceramic

1.4S UN0441

P105

0.308

6.50 - 8.70

2 7/8


100000355

2.125

20,000/400

15.4

Ceramic

1.4S UN0441

P105

0.217

6.50

2 7/8


101290402

2.125

12,500/400

15.4

Cast Iron

1.4S UN0441

P105

0.217

6.50

2 7/8

2 1/8-in. Hastelloy Tubing Cutter

100000430

2.125

20,000/400

33

Ceramic

1.1D UN0059

Chrome

0.276

7.90

2 7/8


100000356

2.250

20,000/400

13

Ceramic

1.4S UN0441

P105

0.217

6.50

2 7/8


101290405

2.250

12,500/400

13

Cast Iron

1.4S UN0441

P105

0.217

6.50

3 1/2


101290406

2.500

12,500/400

22.5

Cast Iron

1.4S UN0441

P105

0.254 0.449

9.3 - 15.50

3 1/2


100116367

2.594

20,000/400

22.5

Ceramic

1.4S UN0441

P105

0.254 0.289

9.30 - 10.30

3 1/2

2.70-in. Tubing Cutter

100011034

2.700

20,000/400

22.5

Ceramic

1.4S UN0441

P105

0.254 0.289

9.30 - 10.30

3 1/2

2.70-in. Hastelloy Tubing Cutter

100000431

2.700

20,000/400

46

Ceramic

1.1D UN0059

Chrome

0.254 0.289

9.30 - 10.30


4-43

Super Tubing Cutters Jet Research Center’s super tubing cutters are designed where well conditions prevent the use of a conventional tubing cutter based on unexpected or severe restrictions. In this situation, a specially designed cutting charge is used. The cutter is based on a conventionally shaped charge assembly but has additional explosive in the form of a pelletized charge in the base of the cutter. It is a smaller diameter than a conventional charge for the pipe to be cut. The cutter can easily pass through tight restrictions and still achieve severance. Based on the design constraints, some tubing deformation at the cut point is likely with this cutter. Super tubing cutters can be used with JRC’s proprietary RED® rig environment detonator, offering a high level of protection against stray voltage or inadvertent RF initiation. Features • High strength steel cap provides 20,000 psi pressure rating • Reduced diameter easily passes wellbore restrictions • Detonator options available to satisfy all applications • Two cutter sizes for common tubing sizes

HAL11763

• Special designs available to match unique well conditions

Super Tubing Cutters

4-44


Super Tubing Cutters Tubing OD in.

Description

2 3/8

1 9/16-in. Super Cutter

2 7/8

1 13/16-in. Super Cutter

Recommended Target Tubing

Cutter OD in.

Rating psi / °F

Explosive weight g

Housing Material (S-Steel)

Shipping Class

100005493 +100158162

1.563

20,000/400

40

S

100008057 +100158161

1.813

20,000/400

40

S

Part No.

Grade

Wall Th

(Incl Coupl.) lb/ft

1.4S UN0441

N80

0.190 0.254

4.70 - 5.95

1.4S UN0441

N80

0.217 0.308

6.50 - 8.70

Accessories Tubing Cutter Accessories

HP Accessories

Safety Accessories

Detonator - Resistorized

100000432

Extension Mandrel - Steel

101293227

Shunt Plug

100010861

Firing Head, 1 1/2-in. OD

100000434

Adapter for RED - Steel

101293230

Safety Tube

100010862

Extension Mandrel

100008258

Detonator - RED®

101272595

Adapter for RED Detonator

101293676

Notes: 1. Undersized cutters may not make a full cut. 2. Always run effective centralization for optimum results. 3. Field assembly required due to shipping features. 4. CAUTION: Not recommended for casing sizes less than 7 in.


4-45

Coiled Tubing Cutters Jet Research Center’s coiled tubing cutters are designed to cleanly sever common sizes of tubing quickly and economically. These proven design cutters are widely used and have an unsurpassed performance record. Features • High strength steel components allow successful trip inside the coiled tubing • Corrosion resistant components • Cutters sizes available for 1, 1.25, 1.5 and 1.75-in. coiled tubing • 13.75-in. cutter suitable for cutting 1.5-in. (1.900) NU API tubing • Compatible with industry standard wireline accessories

HAL11764

• Can be designed with high temperature explosives for special applications

Coiled Tubing Cutters

4-46


Coiled Tubing Cutters Recommended Target Tubing Cutter OD in.

Rating psi / °F

Explosive weight g

Housing Material (S-Steel)

100118388

0.718

10,000/325

1

S

0.948-in. Coiled Tubing Cutter

100118389

0.948

10,000/325

2.9

1.50

1 3/16-in. Coiled Tubing Cutter

100000429

1.188

10,000/325

1.75


100000569

1.375

1.90


100000569

1.375

Tubing OD in.

Description

1.00

0.718-in. Coiled Tubing Cutter

1.25

Part No.

Shipping Class

Grade

Wall Th

Weight (Incl Coupl.) lb/ft

1.4S UN0441

N80

0.081

0.786

S

1.4S UN0441

N80

0.095

1.172

4.7

S

1.4S UN0441

N80

0.109

1.619

15,000/400

4

S

1.4S UN0441

N80

0.134

2.313

15,000/400

4

S

1.4S UN0441

P105

0.145

2.900

Accessories Accessories

Safety Accessories

Detonator - Resistorized

100010855

Safety Tube for Detonator

5/8-in. OD Cont Sub (1.59 cm)

100005498 0.5-20 UNF-2A (thread)

5/8-in. Shunt Plug

100158234 100158235

3/4-in. OD Cont Sub (1.91 cm)

100158243 0.555-28P-36-SA (thread)

3/4-in. Shunt Plug

120042542

1-in. OD Cont Sub (2.54 cm)

100014497 0.812-16 UN-2A (thread)

1-in. Shunt Plug

120042541

Notes: 1. Always run effective centralization for optimum results. 2. Undersized cutters may not make a full cut. 3. When more than one cutter is available for the specification, always select the largest diameter cutter.


4-47

Casing and Drillpipe Cutters Jet Research Center’s casing and drillpipe cutters feature the same level of engineering detail and design as the industryleading JRC tubing cutters. They are designed to cleanly sever a wide range of casing efficiently, using a minimum amount of explosive. The designs feature high specification aluminum alloy case material that breaks up substantially upon detonation. JRC casing and drillpipe cutters offer high levels of safety and reliability in field applications with a minimum amount of set-up or configuration based on well parameters. JRC developed the industry standard shock attenuating mandrel for use with the range of casing and drillpipe cutters and patented this technology (US patent 5,117,911). Casing and drillpipe cutters can be used with JRC’s proprietary RED® rig environment detonator, offering a high level of protection against stray voltage or inadvertent RF-initiation. Features • Shock attenuating mandrel helps protect associated wireline tools • Cutter designed for minimum pipe flare • Extensive cutter range offers selection based on well conditions • Cutters available for high-strength and chrome pipes • Special designs available to match unique well conditions

HAL11765

• Detonator options available to satisfy all applications

Casing and Drillpipe Cutters

4-48


Wafer Casing Cutters (1.1D) Cutter OD in.

Rating psi / °F

Explosive Weight g

Housing Material (S-Steel, A-Aluminum)

Shipping Class

100116368

2.375

12,500/400

22

S/A

2 15/16-in. Drill Pipe Cutter

100127821

2.938

7,500/400

47.4

4 1/2 DP


100127821

2.938

7,500/400

4 1/2 DP

3 15/16- in. Drill Pipe Cutter

100000140

3.313

7,500/400

5 DP


100000140

3.313

7,500/400

4 1/2

3 5/8-in. Casing Cutter

101293449

3.625

5

4-in. Casing Cutter

101293457

5 DP

4-in. Casing Cutter

5 1/2

Tubing OD in.

Description

3 1/2 DP


4

Part No.

Recommended Target Tubing Grade

Wall Th

Weight (Incl Coupl.) lb/ft

1.4S UN0441

G105

0.254 0.449

9.5 - 15.5

A

1.1D UN0059

L80

0.262 0.380

11.85 15.7

47.4

A

1.1D UN0059

G105

0.271 0.430

13.75 20.00

61

A

1.1D UN0059

G105

0.430

20.00

61

A

1.1D UN0059

G105

0.296 0.500

16.25 25.60

7,500/400

54

A

1.1D UN0059

L80

0.205 0.337

9.50 15.10

4.000

9,000/400

110

S/A

1.1D UN0059

L80

0.2530.437

11.50 21.40

101293457

4.000

9,000/400

110

S/A

1.1D UN0059

G105

0.296 0.362

16.25 19.50


100014494

4.500

9,000/400

104

S/A

1.1D UN0059

L80

0.304 0.415

17.00 23.00

5 1/2


101293484

4.750

9,000/400

100

S/A

1.1D UN0059

L80

0.244 0.304

14.00 17.00

5 3/4


101293484

4.750

9,000/400

100

S/A

1.1D UN0059

L80

0.330 0.430

19.50 25.20

6


101293491

5.375

9,000/400

240

S/A

1.1D UN0059

L80

0.224 0.275

14.00 17.00

6 5/8


101293491

5.375

9,000/400

240

S/A

1.1D UN0059

L80

0.475

32.00

6 5/8


101293515

5.500

9,000/400

253

A

1.1D UN0059

L80

0.228 0.417

20.00 28.00

7


101293515

5.500

9,000/400

253

A

1.1D UN0059

L80

0.408 0.540

29.00 38.00

7

6- in. Casing Cutter

101293536

6.000

9,000/400

280

A

1.1D UN0059

L80

0.317 0.408

23.00 29.00

7 5/8


101293544

6.125

9,700/400

253

A

1.1D UN0059

L80

0.375 0.500

29.70 39.00

8 5/8


101293553

7.250

8,000/400

373

A

1.1D UN0059

L80

0.400 0.595

36.00 52.00

9 5/8


101293555

8.188

8,000/400

407

A

1.1D UN0059

L80

0.435 0.545

43.50 53.50

Accessories Tubing Cutter Accessories Detonator - Resistorized

HP Accessories

Safety Accessories

100000432

Extension Mandrel - Steel

101293227

Shunt Plug

100010861

Adapter for Resistorized Detonator

100014468

Adapter for Resistorized Detonator - Steel

101293240

Safety Tube

100010862

Firing Head, 1 1/2-in. OD

100000434

Adapter for RED - Steel

101295134

Extension Mandrel

100008258

Detonator - RED®

101272595

Adapter for RED Detonator

101295128

Notes: 1. Always run effective centralization for optimum results. 2. Undersized cutters may not make a full cut. 3. When more than one cutter is available for the specified target, always select the largest diameter cutter.


4-49

C-4 Casing Cutters Jet Research Center’s C-4 casing cutters are designed to allow air transportation (via commercial aircraft) of the explosives in individual packages. Air freight allows for rapid shipment of urgently needed cutters and is considerably less expensive than transportation by sea. Upon arrival at the location, the explosive can then be placed in the cutter body and run in the well. The C-4 cutters then function as traditional cutters, except for their reduced temperature limitation. This product line uses the same safe-arming procedures as the popular tubing, drillpipe, and normal casing cutters. It allows the detonator to be electronically connected safely before the detonator is placed in proximity to the cutting charge. Applications • Emergency situation where cutter must be flown to wellsite • Temperature limitation of 225°F • Pressure limitations depend on the size of the cutter Features • Patented shock absorber mandrel helps protect CCLs and other associated hardware • Aluminum case components allow easy breakup of components into debris • Detonation options available to satisfy all applications • Available in sizes to cut 4.5-in. to 9.625-in. casing

HAL11765

• Upon request, test shots can be made in special pipe to verify performance

C-4 Casing Cutters

4-50


Drill Collar Severing Tool Jet Research Center developed the dual end severing tool for severing thick wall tubulars over 20 years ago. The technique is based on the colliding shock wave principle. Since its inception, the drill collar severing tool has been continuously refined, resulting in the industry-leading severance device for cutting drill collars and drillpipe in a wide variety of stuck pipe scenarios. The latest refinement to the tool has resulted in a standard explosive column length with superior performance. The secret to the success of the tool lies in the precisely-timed detonation of two equal and opposing shock fronts. The colliding shock is matched to a cartridge assembly at the mid-point of the assembly, designed to help focus the energy transmitted to the target. JRC developed the industry standard shock attenuating mandrel for use with drill collar severing tools and patented this technology (US patent 5,117,911). Drill collar severing tools can be used with JRC’s proprietary RED® rig environment detonator, offering a high level of protection against stray voltage or inadvertent RF initiation. Applications Cutting drill collars and drillpipe in situations involving stuck pipe Features • Redesigned in 2002 for maximum performance • Full range of sizes for virtually any severing requirement • Suitable for hostile environment up to 400°F, 20,000 psi • Higher temperature tools available for extreme temperature application • Shock attenuating mandrel helps protect wireline tools. • Quick assembly and deployment

• Air freight classification (1.4s) provides rapid mobilization

HAL11766

• Industry standard connections can be run on any wireline unit

Drill Collar Severing Tool


4-51

Drill Collar Capability Chart

Tool OD in. (cm) 1 3/8 (3.5)

1 3/4 (4.4)

2 (5.1)

2 5/8 (6.7)

Temperature and Pressure Rating HMX - 400°F (204°C) 20,000 psi (138 Mpa) for 1 hour* HNS - 475°F (246°C) 20,000 psi (138 Mpa) for 1 hour* HMX - 400°F (204°C) 20,000 psi (138 Mpa) for 1 hour* HNS - 475°F (246°C) 20,000 psi (138 Mpa) for 1 hour* HMX - 400°F (204°C) 20,000 psi (138 Mpa) for 1 hour* HNS - 475°F (246°C) 20,000 psi (138 Mpa) for 1 hour* HMX - 400°F (204°C) 20,000 psi (138 Mpa) for 1 hour* HNS - 475°F (246°C) 20,000 psi (138 Mpa) for 1 hour*

Length in.

Designed to Sever up to in.

Explosive Pellet Weight g

Cartridge Assembly Explosive Weight g

36

3 1/2 OD DCs

20.7 × 28 pellets

4.8 × 2

589.2

36

6 1/2 OD DCs

22.7 × 44 pellets

12.7 × 2

1024.2

36

8 OD DCs

22.7 × 64 pellets

17.4 × 2

1487.8

36

11 OD DCs

21.5 × 110 pellets

28.5 × 2

2422.1

Loaded Tool Weight g

* For high pressure application, in excess of 15,000 psi, JRC recommends the use of high pressure steel rated accessories.

4-52


Junk Shot Jet Research Center’s junk shots have been field proven time after time in a wide variety of applications all over the world. The junk shot charge has been used to overcome some of the most challenging fishing operations encountered, ranging from breaking up complete drilling bits to underreamer arms. The junk shot is a large downward shooting shaped charge secured inside a pressure housing.When placed on top of the junk, it functions in a similar manner as a perforating charge, but the explosive effect is substantially greater with the ability to destroy large targets. In almost any situation, the use of the junk shot charge to break up obstacles downhole reduces costly fishing time, returning the rig to full operation. Applications Break up obstacles downhole and return rig to full operation Features • Main charge run on wireline, drillstring, or tubing with a secondary wireline initiator for maximum effect • Two sizes of charge available: 5.25-in. OD and 7.75-in. OD • Can be transported via air charter or standard ground services • Pressure rated to 18,000 psi

HAL11767

• Tools may be clustered for special applications

• Temperature rated to 400°F for one hour • Offers a high degree of safety due to its two-stage deployment • Offers a safe assembly method through the use of JRC’s safe arming equipment • Can be run on wireline or tubing • Can be fired electronically or hydraulically

Junk Shot


4-53

Plug Setting Equipment EZ Drill® Bridge Plugs EZ Drill® bridge plugs consist of an EZ Drill SV packer from which the sliding valve has been removed and a bridging plug has been added. This combination offers excellent downhole pressure control and drillability. Applications Downhole pressure control and drillability Features • Built from cast iron, brass, aluminum, and rubber • Ability to be set on: – Electric wireline – Slickline – Coiled tubing – Jointed pipe with a mechanical or hydraulic setting tool

HAL9254

• Can be used with conventional tricone bits or junk-style mills

EZ Drill® Bridge Plug

4-54


Fas Drill® Bridge Plugs The Fas Drill® bridge plug allows oil and gas operators to run multiple drillable bridge plugs in a well for stimulation and workover operations, then drill out in one fast, easy operation. Fas Drill bridge plugs are used in a manner similar to conventional, drillable bridge plugs and can be set on tubing, on drillpipe, or with conventional tools, such as electric wireline. An adaptor kit is required for setting tools. Setting equipment and operation are identical for both versions. Standard Fas Drill bridge plugs have operational limits of 250°F with 5,000 psi differential from either direction. HPHT models have operating limits of 350°F with an 8,000 or 10,000 psi differential. Applications Run multiple drillable bridge plugs for stimulation and workover operations Features • Consists of composites and a packer set, giving it minimal ferrous metal content • Can be set with electric wireline setting tools, slickline setting tools, coiled tubing setting tools, or mechanical setting tools • Isolates lower zones during squeeze cementing operations on land-based or offshore rigs in vertical or deviated wells

HAL12041

• Functions as a bridge plug in multizone stimulation treatments

Fas Drill® Bridge Plug


4-55

4-56


Perforating Solutions maintains an unequalled success and safety record while continuously developing and introducing new and innovative products for tubing conveyed and wireline perforating.

2007

Shaped Charges

1995

MaxForce™ Millennium™

2000

Super DP DP (HNS) 1990

Halliburton shaped charges lead the way in quality, reliability and performance. Halliburton ballistic engineers at Jet Research Center continue to develop and manufacture perforating systems for virtually any reservoir environment or intervention technique. Halliburton also has the capability and expertise to develop custom charges to maximize effective penetration into specific reservoirs.

MaxForce™ Shaped Charges The new MaxForce™ line of super-deep penetrating charges is Jet Research Center's latest advancement in shaped charge evolution. The MaxForce line of charges is manufactured with the highest level of quality assurance that results in a lower standard deviation to provide consistent charge performance.

5 1678 HAL

Features MaxForce deeper penetration charges: • Increase productivity • Penetrate past any near wellbore damage with deeper penetration • Potentially intersect more natural fractures with deeper penetration • Reduce pressure drop at perforations, which can potentially delay scale, paraffin, or asphaltene deposits

Perforating Solutions

5-1



Dominator® Shaped Charges The Dominator® shaped charges are designed to optimize perforating performance in reservoir rock and increase hydrocarbon production. To achieve that goal, Dominator charges were evaluated in terms of geometry and flow performance in sandstone targets at simulated downhole conditions instead of by their ability to penetrate API 19B Section I unstressed concrete. As a result, these new shaped charges far exceed the performance of current, comparable charges.

Using the perforation flow laboratory in the design process also avoided the pitfalls associated with translating data from surface shot concrete targets to productivity estimations in downhole reservoirs.

Rearmost portion of jet Flash X-ray of a charge during detonation sequence

HAL15957

Dominator shaped charges were developed at Halliburton’s Jet Research Center (JRC) Perforation Flow Laboratory by firing perforating charges into real rock under simulated downhole conditions that included rock effective stress, wellbore underbalance, and rock pore pressure. By analyzing post-shot results from the testing program, it was possible to rapidly develop a design with favorable jet characteristics.

Jet tip HAL15999

To maximize well inflow performance for a specific reservoir, it is necessary to engineer the shaped-charge explosive jet-tip velocity profile with consideration to the target properties (compressive strength, particle grain size, pore fluid type, etc.). Optimized shaped charge design combined with perforating best practices per Halliburton’s PerfPro® process ensure that all perforations are surged at the optimum underbalance pressure to minimize perforation skin effects. Naturally, shaped charges engineered for a given reservoir should be validated with API 19B Section IV testing (i.e. Perforation Flow Laboratory) at as close to in-situ properties as possible.

Stretching jet

HAL15956

A Revolutionary Approach to Charge Development

Expanding case fragments

Actual charge performance in formation core samples comparing standard charge on left vs the Dominator® charge on the right.

The improvement in penetration performance is evident from the results. In one example, penetration increased by an average of 52% in the gas-filled samples and by an average of 37% in liquid-filled samples. These penetration results, along with improvement in core flow efficiency, contribute to increased flow performance.

5-2


Mirage® Shaped Charges

Previous BH guns systems required that the shaped charges be positioned and retained in the charge tube holder using bend tabs. The bend tab is a significant source of gun debris because of the metal slivers generated during gun detonation.

HAL16361

The Mirage® line of BH shaped charges was introduced as an improved low debris system. The Mirage line provides more of a total perforating system debris reduction solution. With the Mirage line, gun debris associated with all components of the perforating assembly is reduced.

Initial (Copper) 7-in. BH Liner Technology

In addition to metallurgical considerations, the geometry of the Mirage shaped charge liner is carefully controlled during the manufacturing process such that those portions of the liner that might contribute to slug creation are removed. This process results in a charge liner with a controlled geometry liner (CGL).

HAL16360

The improved Mirage system incorporates a new twist lock feature in the charge tube holder, eliminating the debris associated with the bend tabs.

Current (Brass) 7-in. BH Liner Technology

Latest (Mirage®) 7-in. BH Liner Technology

HAL16270

“Thinned” region after forming

HAL16366

“Thick” region controlled to reduce debris

Mirage® Super Hole Perforator


5-3

The LD zinc charge cases with the Mirage® system have been optimized to reduce the particle size distribution as shown below.

Case Debris Comparison (One Charge) 70.0 Mirage Case Debris LD Zinc Case Debris

60.0

Steel Case Debris

Mass Retained (g)

50.0

40.0

30.0

20.0

HAL16267

10.0

0.0 > 0.500

> 0.375

> 0.250

> 0.187

> 0.094

> 0.066

> 0.033

> 0.011

<.011

Particle Size (in.)

5-4


Maxim™ Shaped Charges

As completion targets in deep water environments go deeper, drilling challenges are compounded forcing operators in many cases to set the casing shoe point higher than planned in order to safely reach deeper primary targets. Unfortunately, this scenario results in secondary pay zones that have multiple strings of casing across portions or the entire length of the pay zone. This situation presents a serious technical challenge because the typical big-hole (BH) perforating system cannot efficiently penetrate multiple casing strings and still produce an adequate casing exit hole. The results utilizing conventional BH perforating systems in the past yielded a large exit hole in the first casing string and a very small exit hole in the second casing string with minimal formation penetration.

HAL16362

The newly developed Maxim perforating system resulted in a casing exit-hole size of 0.66-in. with an impressive formation penetration of 6.0-in. These results show a significant 136% improvement in casing exit-hole size and 270% improvement in flow area on a per foot basis.

Existing Dual String Technology

HAL16359

The completion of wells in unconsolidated formations generally requires some form of sand control or gravel packing for flow assurance. For a cased and perforated sand control completion, the perforating strategy typically calls for perforations with the largest possible exit hole in the casing with as high a shot density (spf) as possible. The large casing exit hole improves the likelihood of placing sand or gravel into the perforation tunnel and the higher spf increases the effective flow area resulting in lower pressure drop across the completion during production.

Maxim™ Dual String Technology

Expanding Case Fragments

Revolutionary Shaped Charge Liner Design Meets the Challenge Shaped charge design engineers at Halliburton's Jet Research Center (JRC) have unleashed the power of Maxim™ shaped charges by utilizing hydro-code modeling software and flash X-ray imaging to develop a proprietary shaped charge liner that optimizes the casing exit-hole size when penetrating multiple casing strings.

A standard 5-in. 12 spf 28 gram BH gun system was tested under the completion configuration described resulting in a casing exit-hole of 0.28-in.

Jet Tip

Rearmost Portion of Jet

HAL15955

The effectiveness of the new Maxim shaped charge concept was demonstrated with the development of a 5-in. 8 spf 47 gram charge for a completion scenario with 7-5/8-in. 47.1 lb/ft P-110 and 9-5/8-in. 47 lb/ft P-110 casing.

Stretching Jet

Flash X-ray and hydro-code simulation of a shaped charge during detonation sequence.

Maxim™ Charge Performance Data Charge Part No.

Gun OD

SPF

Explosive Load

Inner Casing

Exit Hole

Outer Casing

Exit Hole

Penetration*

101350449

5.00

8

47

7 5/8 47.1# P-110

0.75

9 5/8 47 P-110

0.66

6.00

101357518

5.75

10

56.5

8 5/8 60.8# P-110

0.78

11 3/4 65# P-110

0.63

7.50

101357518

7.00

14

56.5

9 5/8 473 lL-80

0.61

13 3/8 72# P-110

0.68

8.77

*Penetration is in cement measured from the OD of the outer casing.


5-5

KISS™ Low-Damage Perforating Charge The KISS™ charge provides all the benefits expected from big-hole charges—yet produces significantly less damage in unconsolidated formations.

In an extensive series of lab tests comparing KISS lowdamage charges with conventional big-hole perforating charges under simulated downhole conditions, the KISS charge more than proved its superiority. In these tests: • KISS charges created holes in the casing that were equal to or larger in diameter than those created by conventional big-hole perforating charges.

HAL5945

KISS charges limit perforating damage with minimal penetrator design charges, reducing damaged material eightfold. Damaged material is near the casing with 200% of the cross-sectional area a possibility. Penetration past the cement is not a problem, and lower explosive weight charges are less susceptible to carrier failure.

The unique KISS™ perforating charge is designed to just penetrate the formation while the high pressure gas breaks through the crushed zone in the tunnel and creates fractures in the formation.

• Perforation depth was appropriately reduced, so there was far less damage to the formation as well as a significantly reduced crushed zone (less than 1/3 of a conventional big-hole charge). • KISS charges easily penetrated 2-in. thick cement sheaths, proving they can be effective even in wellbores where washouts have occurred. • Less damage occurred to the cement surrounding the entrance hole, and the cement damage area was smaller. Features • Can be run in standard VannGun® perforating guns and conveyed on tubing or wireline • Complements Halliburton’s StimGun™ service by producing an instantaneous, high-pressure surge into the formation to enhance perforating and stimulation results • Specialists help determine if the KISS low damage perforating charge would be a productive choice for a specific well • Low impact on unconsolidated formations for a positive impact on completions • Better gravel packs due to greatly improved fluid injectivity—whether running a conventional gravel pack, a FracPac™ system, or a high-rate water pack • Reduced fines movement • Reduced sand production

5-6


Charge Performance Data Gun Size

Phasing

JRC P/N

Explosive Load (Grams)

Charge Name

Casing Size (in.)

Target Strength (psi)

EHD (in.)

Total Target Penetration (in.)

Penetration Normalized to 5000 psi (5% per 1000)

* Unofficial Data

CAPSULE GUNS Dyna-Star®

1-11/16”

0

100005450

1-11/16”

4 SPF RDX DP

13.4

4-1/2”

5149

0.39

10.50

1-11/16”

0

100005450

1-11/16” Dyna-Star 4 SPF RDX DP

13.4

4-1/2”

5909

0.40

12.46

13.03

QC

1-11/16”

0

100005449

1-11/16” Dyna-Star 6 SPF HMX DP

13.5

4-1/2”

6384

0.41

11.97

12.80

QC

1-11/16”

0

101398891

1-11/16” MILLENNIUM™ Dyna-Star 6 SPF HMX

8

4-1/2”

5426

0.29

24.00

24.51

1-11/16”

0

101521848

1-11/16” MaxForce™ Deep Star™ 8 SPF HMX

8

4-1/2”

7170

0.27

19.90

2-1/8”

0

101210198

2-1/8” MILLENNIUM Deep Star HMX

15.9

5-1/2”

5435

0.40

30.60

31.27

QC

2-1/8”

0

101383082

2-1/8” MILLENNIUM Dyna-Star 6 SPF HMX

15.9

5-1/2”

5633

0.39

29.07

29.99

QC

2-1/8”

0

100008259

2-1/8” Dyna-Star 6 SPF HMX DP

15.5

5-1/2”

5326

0.38

14.84

15.08

QC

2-1/8”

0

100005448


15.5

5-1/2”

5538

0.42

16.61

17.06

RP43

2-1/8”

0

100005448


15.5

5-1/2”

5292

0.35

15.50

19B

2-1/8”

90

101210198

2-1/8” MILLENNIUM Deep Star 4 SPF HMX DP

15.9

5-1/2”

5820

0.31

20.60

19B

101210198

2-1/8” MILLENNIUM Deep Star 5.8 SPF HMX PENTAPHASE Oscillating Spiral

15.9

5-1/2”

6740

0.30

20.60

19B

2-1/8”

0/45/90

19B

QC 19B

PORTED GUNS 3-1/8”

90

101410556

3-1/8” GSC 4 SPF RDX DP

12

4-1/2”

5500

0.34

20.90

21.42

QC

4”

90

101288857

4" MILLENNIUM EXPRESS GSC

19.5

5-1/2”

5600

0.51

27.18

27.95

QC

SLICKWALL GUNS 3-1/8”

60 / 90

101366678

3-1/8” MILLENNIUM IS 4 SPF HMX

21

4-1/2”

6200

0.40

38.30

40.60

QC

3-1/8”

90

101204537

4” Basic MILLENNIUM EXPRESS 4 SPF RDX

19.5

5-1/2”

6277

0.50

16.65

17.71

QC

4”

90

101204537

4” Basic MILLENNIUM EXPRESS 4 SPF RDX

19.5

5-1/2”

6277

0.50

24.94

26.53

QC

3-1/8”

60 / 90

101310802

4” Twisted Strip MILLENNIUM EXPRESS 4 SPF RDX W/ TWIST LOCK 1/2 RUBBER JACKET

19.5

5-1/2”

6277

0.50

16.65

17.71

QC

4”

60 / 90

101310802

4” Twisted Strip MILLENNIUM EXPRESS 4 SPF RDX W/ TWIST LOCK 1/2 RUBBER JACKET

19.5

5-1/2”

6277

0.50

24.94

26.53

QC

1-9/16”

0

100157028


3.4

4-1/2”

5967

0.21

11.34

11.89

RP43

1-9/16”

60

100157028


3.4

2-7/8”

6949

0.23

8.30

19B

1-9/16”

60

384465

1-9/16” 4 SPF HMX BH

3.2

2-7/8”

7533

0.34

2.50

19B

2”

60

101208224

2” MILLENNIUM IS HMX

6.8

2-7/8”

6019

0.22

18.30

19B

2”

60

101603801

2" MaxForce IS HMX

7

2-7/8”

5697

0.24

20.30

19B

2”

60

101206246

2” IS 6 SPF-HMX BH

6.8

3-1/2”

7332

0.48

3.00

19B

2-3/8”

60

101590845

2-3/8” MaxForce IS 6 SPF HMX

10

3-1/2”

5663

0.28

19.90

19B

2-3/8”

60

101591373


10

3-1/2”

5663

0.48

5.80

19B

2-1/2”

60

101418095

2 1/2” MILLENNIUM II IS 6 SPF HMX

11.1

3-1/2”

5996

0.32

24.50

19B

2-1/2”

60

101244923

2-1/2” 6 SPF HNS DP

11.1

3-1/2'

7128

0.26

12.60

19B

2-1/2”

60

384466


11

3-1/2'

7469

0.58

2.40

19B

2-3/4”

60

101233817

2-3/4” MILLENNIUM 6 SPF HMX

15

4-1/2”

6394

0.30

26.00

2-3/4”

60

101318485

2-3/4” 6 SPF MILLENNIUM HNS

15.1

4-1/2”

5694

0.30

27.55

28.51

QC

2-3/4”

60

101206793

2-3/4” 6 SPF RDX BH

14.7

4-1/2”

6109

0.67

5.50

5.80

RP43

2-3/4”

60

101270158


15

4-1/2”

7381

0.65

4.20

2-7/8”

60

101233817

2-3/4” MILLENNIUM 6 SPF HMX (Hvy Wall Gun)

15

4-1/2”

6388

0.31

27.30

19B

2-7/8”

60

101233817

2-3/4” MILLENNIUM 6 SPF HMX (Hvy Wall Gun)

15

4-1/2”

5124

0.35

30.00

19B 3

2-7/8”

60

101388407

2-7/8” MILLENNIUM 6 SPF HNS

18.5

4-1/2”

6859

0.28

22.80

3-1/8”

60

101366678

3-1/8” MILLENNIUM™ IS 6 SPF HMX

21

4-1/2”

6200

0.40

38.30

SCALLOPED GUNS


19B

19B

19B 40.60

QC

5-7

Charge Performance Data Charge Name


Casing Size (in.)

EHD (in.)

101618998

3-1/8” MILLENNIUM Express IS DP 6 SPF RDX

21

4-1/2”

101618994

3-1/8” MILLENNIUM Express IS SDP 6 SPF RDX

21

4-1/2”

135/45

101351605

3-1/8” Mirage® 10 SPF HMX BH/LD

14

3-3/8”

60

101233819


25

5”

6100

0.64

3.80

4.01

QC

4-1/2”

6215

0.48

40.40

42.85

RP43

3-3/8”

60

101233819


25

3-3/8”

60

101600039

3-3/8” MILLENNIUM Express IS 6 SPF RDX DP

23

4-1/2”

5754

0.45

37.50

4-1/2”

5704

0.42

25.60

26.5

3-3/8”

60

101589595

3-3/8” MILLENNIUM Express IS 6 SPF RDX SDP

23

4-1/2”

5219

0.39

43.00

43.5

3-3/8”

60

101365876

3-3/8” MILLENNIUM 6 SPF HNS

25

4-1/2”

6578

0.31

22.10

3-3/8”

60

3-3/8”

60

101320459

3-3/8” 6 SPF RDX DP

22

4-1/2”

7538

0.34

17.60

100005333


22

4-1/2”

6138

0.41

20.30

21.46

RP43

3-3/8”

60

3-3/8”

60

100005332

3-3/8” 6 SPF HMX DP

26

5-1/2”

9846

0.38

18.28

22.71

RP43

100008014

3-3/8” 6 SPF RDX SUPER DP

24

4-1/2”

5251

0.39

28.45

28.81

3-3/8”

RP43

60

100008249

3-3/8” 6 SPF HMX SUPER DP

25

4-1/2”

5967

0.40

26.20

3-3/8”

60

100008249

3-3/8” 6 SPF HMX SUPER DP

25

5”

6097

0.40

28.70

30.27

RP43

3-3/8”

135/45

101351605

3-3/8” Mirage 12 SPF HMX BH/LD

14

5-1/2”

6100

0.63

4.15

4.38

QC

3-3/8”

60

100005321


24

4-1/2”

6101

0.86

4.66

4.92

QC

3-3/8”

60

100157017


24

4-1/2”

6490

0.88

4.76

5.11

QC

3-3/8”

150/30

100008251

3-3/8” Omni 12 SPF RDX BH

14

5-1/2”

7802

0.62

5.33

6.08

RP43

3-3/8”

150/30

100005312

3-3/8” Omni 12 SPF HMX BH

14

5-1/2”

6300

0.64

5.24

5.58

QC

3-1/2”

135/45

101542642

3-1/2” Mirage 12 SPF HMX BH/LD

15

5-1/2”

6100

0.65

4.20

4.43

QC

4”

90

101210636

4” MILLENNIUM HMX (4 SPF)

39

5-1/2”

5490

0.39

44.60

45.69

RP43

4”

90

101210636


39

5-1/2”

6365

0.38

43.40

4”

60

100005322


32

7”

5277

0.6

40.50

4”

60

100005327


32

5-1/2”

5568

0.45

37.00

4-1/2”

60

101210636


39

7”

6775

0.37

39.60

4-1/2”

150/30

101210674


22.7

7”

8484

0.38

26.80

4-5/8”

180

101446899

4-5/8” KleenZone® G-FORCE® HMX

39

7"

5208

0.36

42.80

4-5/8”

350/10

101446899

4-5/8” KleenZone G-FORCE HMX

39

7"

5412

0.35

41.70

4-5/8”

60

101210636


39

7”

5502

0.37

52.00

4-5/8”

60

101210636


39

7”

5518

0.35

43.60

4-5/8”

60

101287306

4” 5 SPF HNS DP

39

7”

7559

0.33

31.20

4-5/8”

60

100005322


32

7”

5325

0.43

30.46

30.95

RP43

4-5/8”

60

100005327


32

7”

5809

0.46

39.50

41.10

QC

4-5/8”

60

101332806


32

7”

5814

0.45

30.30

31.53

QC

4-5/8”

150/30

101210674


22.7

7”

8484

0.38

26.80

31.47

RP43

4-5/8”

150/30

101210674


22.7

7”

6322

0.38

24.40

4-5/8”

150/30

100005324

4-5/8” Omni 12 SPF RDX DP

22.7

7”

9080

0.36

16.25

19.57

RP43

4-5/8”

150/30

100005325

4-5/8” Omni 12 SPF RDX DP/LD

22.7

7”

5685

0.32

17.41

18.01

RP43

4-5/8”

150/30

100014352

4-5/8” Omni 12 SPF HMX DP

22.7

7”

9080

0.37

16.09

19.37

RP43

4-5/8”

150/30

101343830

4-5/8” Omni 12 SPF HNS DP

7”

5020

0.35

28.00

28.03

QC

4-5/8”

150/30

100005340

4-5/8” Omni 12 SPF HMX DP/LD

22.7

7”

5685

0.30

18.37

19.00

RP43

4-5/8”

150/30

100005319


25

7”

6840

0.74

6.41

7.00

RP43

4-5/8”

150/30

100005326

4-5/8” Omni 12 SPF RDX BH/LD

22.7

7”

7346

0.65

5.51

6.16

RP43

4-5/8”

150/30

100157006


25

7”

5723

0.75

7.02

7.27

QC

4-5/8”

150/30

100005311

4-5/8” Omni 12 SPF RDX SH

28

7”

6982

0.93

6.30

6.92

RP43

4-5/8”

150/30

100156995

4-5/8” Omni 12 SPF HMX SH

28

7”

5016

0.96

5.10

5.10

RP43

Phasing

JRC P/N

3-1/8”

60

3-1/8”

60

3-1/8”

5-8




Gun Size

* Unofficial Data

19B QC QC 19B 19B

19B

19B 41.06

QC 19B 4 19B

31.47

RP43 19B 19B

53.31

RP43 19B 19B

19B


Charge Performance Data Charge Name


Casing Size (in.)


EHD (in.)



101228756

4-5/8” 12 SPF RDX SUPER HOLE/LD

28

7”

5124

0.81

5.40

5.43

QC

101233690

4-5/8” 12 SPF HMX SUPER HOLE/LD

28

7”

5622

0.85

5.30

5.46

RP43

135/45

100156990


20

7”

5553

0.73

6.18

6.35

RP43

180

101287306


39

7-5/8”

6349

0.29

30.20

5”

150/30

100005311

4-5/8” Omni 12 SPF RDX SUPER HOLE

28

7”

5192

0.91

6.90

6.97

RP43

5”

150/30

100005319


25

7”

6508

0.84

8.80

9.46

QC

5”

150/30

100156995

4-5/8” Omni 12 SPF HMX SUPER HOLE

28

7”

6487

1.00

6.00

6.45

QC

5”

150/30

100005311

4-5/8” Omni 12 SPF RDX SUPER HOLE

28

7-5/8”

7877

0.83

6.65

7.61

RP43

5”

135

101307494

5" Mirage® 12 SPF RDX SUPER HOLE/LD

32

7-5/8”

6345

0.90

6.00

19B

5”

120 Cluster

101292616

5" 21 SPF RDX BH

21

7-5/8”

5411

0.72

5.30

19B 1

5-1/8”

135

101307494

5" Mirage 12 SPF RDX SUPER HOLE/LD

32

7-5/8”

5576

0.88

6.60

5-1/8”

231.4

100157007

5-1/8” 14 SPF RDX SUPER HOLE

32

7-5/8”

5138

0.93

5.11

5.15

RP43

5-1/8”

231.4

100157011

5-1/8” 14 SPF HMX SUPER HOLE

32

7-5/8”

5250

0.94

5.83

5.90

RP43

5-1/8”

120 Cluster

101292616


21

7-5/8”

6246

0.74

5.65

5.99

QC

5-3/4”

150/30

100157007

5-1/8” 14 SPF RDX SUPER HOLE

32

8-5/8”

6498

0.75

5.87

6.31

QC

6-1/2”

135/45 138

101304878

6-1/2” Mirage 12 or 14 SPF RDX BH/LD

47

8-5/8”

7043

1.07

5.60

19B

6-1/2”

135/45 138

101304878


47

9-5/8”

5088

0.91

6.80

19B 2

7”

135/45

101207997

7” MILLENNIUM™ 12 SPF HMX

39

9-5/8”

7006

0.36

43.30

7”

135/45

101207997

7” MILLENNIUM 12 SPF HMX

39

9-5/8”

6397

0.42

38.70

19B

7”

135/45 138

101304878


47

9-5/8”

6178

1.07

6.10

19B

7”

135/45 138

101213474

7” 12 or 14 SPF RDX SUPER HOLE

56.5

9-5/8”

5975

1.29

5.80

19B

7”

135/45 138

101484232

7” Mirage 14 SPF RDX BH/LD

39

9-5/8”

6270

1.04

6.30

19B

7”

138

101212693

7” 12 SPF RDX SUPER HOLE/LD

56.5

9-5/8”

6040

1.16

5.00

19B

7”

60/120

101414821

7” Mirage 18 SPF HMX/LD

45

9-7/8”

5893

1.02

6.50

19B

Gun Size

Phasing

JRC P/N

4-5/8”

150/30

4-5/8”

150/30

4-5/8” 4-5/8”

* Unofficial Data

19B

19B

47.63

RP43

Registered 19B data except fired in 7-5/8” 47# P110 casing Registered 19B data except fired in 9-5/8” 71# N-80 casing Registered 19B data except fired in air Registered third party 19B data MaxForce™, G-Force®,and KleenZone® are proprietary to Halliburton Charge performance will vary due to well conditions. For realistic data, contact JRC “Perforation Flow Lab” testing services. Penetration normalization is not certified by API for 19B. RP43 Test are not endorsed by API and will not be available on new or improved JRC Charges.


5-9

Gun Systems VannGun® Assemblies 1 9/16 in. to 7 in. and 4 SPF to 21 SPF 7.00"

6.50"

6.00" 5.75"

5.125" 5.00" 4.75" 4.625" 4.50" 4.25" 4.00"

3.375" 3.125" 2.875" 2.75" 2.50"

2.00"

1.563”

5-10


VannGun® Phasing and Shot Patterns* 0° Phasing 4 and 5 SPF

HAL10590

4 SPF

5 SPF

6"

6"

6"

6"

12"

12"

0º

180º

360º

0º

180º

360º

60° Phasing 4, 5, and 6 SPF 4 SPF

5 SPF 6"

6"

6"

12"

12"

HAL15978

6"

0º

60º

120º

180º 240°

300º

360º

0º

60º

120º

300º

360º

180º 240°

300º

360º

6 SPF 6"

6"

12"

0º

60º

120º

180º 240°

*Other shot densities and phasings are available upon request.


5-11

90° Phasing 4 SPF 4 SPF 6"

6"

HAL15981

12"

0º

90º

180º

270°

360º

180° Phasing 4 and 8 SPF 4 SPF

8 SPF 6"

6"

6"

12"

12"

HAL15982

6"

0º

5-12

180º

360º

0º

180º

360º


60° Phasing 6 SPF Two Planes 6 SPF 6"

HAL15356

6"

12"

0º

45º 90º 135º 180º 225° 270º 315º 360º

45°/135° Phasing 5, 6, 8, 12, and 18 SPF 5 SPF

6 SPF 6"

6"

6"

12"

12"

HAL15355

6"

0º

45º 90º 135º 180º 225° 270º 315º 360º

8 SPF

0º

12 SPF

18 SPF

6"

6"

6"

6"

6"

6"

12"

12"

12"

0º

45º 90º 135º 180º 225° 270º 315º 360º

0º 51.4°


102.9° 205.7° 308.6° 154.3° 257.1° 360º

45º 90º 135º 180º 225° 270º 315º 360º

0º

45º 90º 135º 180º 225° 270º 315º 360º

5-13

140°/160° Phasing 11 SPF 11 SPF 6"

HAL15983

6"

12"

0º

100º

180°

110º

260°

360°

250°

51.4°/154.3° Phasing 12 SPF 12 SPF 6"

6"

HAL15357

12"

0º 51.4°

102.9° 205.7° 308.6° 154.3° 257.1° 360º

30°/150° Phasing 12 SPF 12 SPF 6"

HAL15354

6"

12"

0º

5-14

60° 120º 180º 240° 300º 360° 30º 90º 150° 210° 270º 330°


25.7°/128.5° Phasing 14 SPF 14 SPF 6"

6"

HAL15993

12"

0º

51º 103º 154º 206º 257° 309º 360º 26º 77º 129º 180º 231º 283° 334º

60°/120° Phasing 18 and 21 SPF 21 SPF

18 SPF 6"

6"

6"

12"

12"

HAL15984

6"

0º

60º

120º

180º 240°

300º

360º

0º

60º

120º

180º 240°

300º

360º

138° Phasing 14 SPF 14 SPF 6"

6"

HAL15985

12"

0º


45º 90º 135º 180º 225° 270º 315º 360º

5-15

Tensile ratings on the following tables are based on the box x pin connection.

1 9/16-in. Premium VannGun® Assemblies Charge Part No.

Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread

100157028

HMX

Millennium™

4

0°

Premium

Vann

101210199

HMX

BH

Pressure Rating psi (bar)

Tensile Strength lb (kg)

20,000 (1379)

70,000 (31 746)

60° 90° 180° 0°

Premium

Industry Standard

20,000 (1379)

70,000 (31 746)

60°

Weights Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

4 spf Millennium 4 (1.22)

21 (9)

17 (8)

7 (2.13)

31 (14)

24 (11)

11 (3.35)

46 (21)

34 (15)

15 (4.57)

60 (27)

44 (20)

21 (6.40)

81 (37)

59 (27)

90° 180° 100157028

HMX

Millennium

101210199

HMX

BH

5-16

6

60°

Premium

Vann

20,000 (1379)

70,000 (31 746)

60°

Premium

Industry Standard

20,000 (1379)

70,000 (31 746)


21 (10)

17 (8)

7 (2.13)

32 (14)

24 (11)

11 (3.35)

48 (22)

34 (15)

15 (4.57)

63 (28)

44 (20)

21 (6.40)

85 (39)

59 (27)


2-in. Premium VannGun® Assemblies Charge Part No.

Explosive Type

Charge Type

SPF

101208224

HMX

Millennium™

4

101603801

HMX

MaxForce™

100008017

HMX

SDP

100157018

HNS

DP

101206246

HMX

BH

Phasing

Gun Material Type

0°

Premium

Gun Thread



Vann

20,000 (1379)

70,000 (31 746)

60° 90° 180° 0°

Premium

Industry Standard

20,000 (1379)

70,000 (31 746)

60°


Loaded lb (kg)

Spacer lb (kg)


28 (13)

23 (10)

7 (2.13)

44 (20)

35 (16)

11 (3.35)

66 (30)

51 (23)

15 (4.57)

87 (39)

63 (29)

21 (6.40)

120 (54)

92 (42)

90° 180° 101208224

HMX

Millennium

101603801

HMX

MaxForce

100008017

HMX

100157018 101206246

6

60°

Premium

Vann

20,000 (1379)

70,000 (31 746)

60°

Premium

Industry Standard

20,000 (1379)

70,000 (31 746)


28 (13)

23 (10)

SDP

7 (2.13)

44 (20)

35 (16)

HNS

DP

11 (3.35)

66 (30)

51 (23)

HMX

BH

15 (4.57)

87 (39)

63 (29)

21 (6.40)

120 (54)

92 (42)

60°

Premium

Vann

20,000 (1379)

70,000 (31 746)

6 spf Reduced Swell Gas Gun

60°

Premium

Industry Standard

20,000 (1379)

70,000 (31 746)

2 (.61)

14 (6.3)

11 (4.9)

SDP

4 (1.22)

25 (11.3)

20 (9.1)

HNS

DP

5 (1.52)

31 (14)

24 (10.9)

HMX

BH

6 (1.83)

36 (16.3)

28 (12.7)

7 (2.13)

42 (19)

32 (14.5)

8 (2.44)

48 (21.7)

36 (16.3)

9 (2.74)

53 (24)

40 (18.2)

11 (3.35)

65 (29.5)

48 (21.8)

101208224

HMX

Millennium

101603801

HMX

MaxForce

100008017

HMX

100157018 101206246


6

5-17


Explosive Type

Charge Type

SPF

101206251

HMX

Millennium™

4

101332418

HMX

SDP

101244923

HNS

DP

Phasing

Gun Material Type

0°

Premium

Gun Thread



Vann

20,000 (1379)

121,000 (54 875)

60° 90° 180° 0°

Premium

Industry Standard

20,000 (1379)

121,000 (54 875)

60°


Loaded lb (kg)

Spacer lb (kg)


43 (20)

34 (15)

7 (2.13)

67 (30)

52 (24)

11 (3.35)

98 (44)

75 (34)

15 (4.57)

129 (59)

98 (44)

21 (6.40)

176 (80)

133 (60)

90° 180° 101418095

HMX

Millennium II™

6

60°

60°

101206251

HMX

Millennium

101332418

HMX

SDP

101244923

HNS

DP

101418095

5-18

HMX

Millennium II

6

60°

60°

6

60°

Premium

Premium

Premium

Premium

Premium

Vann

Industry Standard

Vann

Industry Standard

Industry Standard

20,000 (1379)

20,000 (1379)

20,000 (1379)

20,000 (1379)

20,000 (1379)

121,000 (54 875)

121,000 (54 875)

6 spf Millennium II 4 (1.22)

43 (20)

34 (15)

7 (2.13)

67 (30)

52 (24)

11 (3.35)

98 (44)

75 (34)

15 (4.57)

129 (59)

98 (44)

21 (6.40)

176 (80)

133 (60)

121,000 (54 875)

121,000 (54 875)

121,000 (54 875)


45 (20)

34 (15)

7 (2.13)

70 (32)

52 (24)

11 (3.35)

104 (47)

75 (34)

15 (4.57)

133 (60)

98 (44)

21 (6.4)

189 (86)

133 (60)

6 spf Reduced Swell Gas Gun 4 (1.22)

43 (20)

34 (15)

7 (2.13)

67 (30)

52 (24)

11 (3.35)

98 (44)

75 (34)

15 (4.57)

129 (59)

98 (44)



Explosive Type

Charge Type

SPF

101233817

HMX

Millennium™

4

101318485

HNS

Millennium

100157026

RDX

SDP

100010399

HMX

SDP

101251723

HNS

SDP

101206793

RDX

101270158

HMX

6

Phasing

Gun Material Type

60° 120°

60° Two Row

Gun Thread



Standard

Industry Standard

18,000 (1241)

116,700 (52 934)

Standard

Industry Standard

18,000 (1241)

116,700 (52 934)

Premium

Vann

20,000 (1379)


Loaded lb (kg)

Spacer lb (kg)


59 (27)

50 (23)

5 (1.53)

74 (34)

63 (29)

6 (1.83)

88 (40)

75 (34)

7 (2.13)

95 (43)

79 (35)

8 (2.44)

102 (46)

82 (37)

9 (2.74)

115 (52)

93 (42)

10 (3.05)

125 (57)

99 (45)

11 (3.35)

134 (61)

105 (48)

15 (4.57)

172 (83)

145 (66)

21 (6.71)

241 (114)

193 (88)

134,000 (60 771)

6 spf SDP 4 (1.22)

59 (27)

50 (23)

8 (2.44)

102 (46)

82 (37)

BH

11 (3.35)

134 (61)

105 (48)

BH

16 (4.88)

183 (83)

145 (66)

22 (6.71)

252 (114)

193 (88)

101233817

HMX

Millennium

101318485

HNS

Millennium


60° Two Row

6

Standard

Vann

18,000 (1241)

116,700 (52 934)

60°

Premium

Vann

22,000 (1517)

134,000 (60 771)

60°

Standard

Vann

18,000 (1241)

116,700 (52 934)

4 (1.22)

59 (27)

50 (23)

60°

Standard

Industry Standard

18,000 (1241)

116,700 (52 934)

7 (2.13)

95 (43)

79 (35)

8 (2.44)

102 (46)

82 (37)

11 (3.35)

134 (61)

105 (48)

15 (4.57)

172 (83)

145 (66)

16 (4.88)

183 (83)

145 (66)

22 (6.71)

252 (114)

193 (88)

6 spf Millennium

5-19


Explosive Type

Charge Type

SPF

101233817

HMX

Millennium™

6

101318485

HNS

Millennium

101388406

HMX

Millennium

101388407

HNS

Millennium

101414743

HMX

Dominator®

101233817

HMX

Millennium

101318485

HNS

Millennium

101414743

HMX

Dominator

5-20

6

6

Phasing

Gun Material Type

Gun Thread



60°

Premium

Vann

22,000 (1517)

142,000 (64 399)

60°

Premium

Industry Standard

22,000 (1517)

142,000 (64 399)

60°

Premium

Vann

25,000 (1724)

142,000 (64 399)

60°

Premium

Industry Standard

25,000 (1724)

142,000 (64 399)

60°

Premium

Vann

25,000 (1724)

142,000 (64 399)

60°

Premium

Industry Standard

25,000 (1724)

142,000 (64 399)


Loaded lb (kg)

Spacer lb (kg)


62 (28)

54 (24)

8 (2.44)

106 (48)

86 (39)

11 (3.35)

138 (63)

110 (50)

16 (4.88)

186 (84)

150 (68)

22 (6.71)

258 (117)

198 (90)

6 spf Millennium II 4 (1.22)

62 (28)

54 (24)

8 (2.44)

106 (48)

86 (39)

11 (3.35)

138 (63)

110 (50)

16 (4.88)

186 (84)

150 (68)

22 (6.71)

258 (117)

198 (90)

6 spf Millennium Gas Gun 4 (1.22)

64 (29)

55 (25)

8 (2.44)

112 (51)

92 (42)

11 (3.35)

148 (67)

120 (54)

16 (4.88)

204 (93)

166 (75)

22 (6.71)

281 (127)

221 (100)



Explosive Type

Charge Type

SPF

101320459

RDX

DP

4

Phasing

Gun Material Type

60°

Premium

Gun Thread



Vann

25,000 (1724)

238,000 (107 937)

90°

Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

4 spf DP 4 (1.22)

86 (39)

77 (35)

7 (2.44)

126 (57)

109 (50)

8 (2.44)

144 (65)

125 (57)

90°

11 (3.35)

187 (85)

160 (73)

180°

15 (4.88)

240 (109)

205 (93)

16 (4.88)

256 (116)

219 (99)

21 (6.41)

329 (150)

277 (126)

22 (6.71)

361 (164)

290 (132)

180° 60°

60°

Standard

Standard

Vann

Industry Standard

20,000 (1379)

20,000 (1379)

218,000 (98 883)

218,000 (98 883)

90°

4

Weights

60°

SDP

101293450

RDX

SDP/LD

90°

4 (1.22)

86 (39)

77 (35)

101233819

HMX

Millennium™

180°

7 (2.44)

126 (57)

109 (50)

101365876

HNS

Millennium

60°

8 (2.44)

144 (65)

125 (57)

90°

11 (3.35)

187 (85)

160 (73)

180°

15 (4.88)

240 (109)

205 (93)

16 (4.88)

256 (116)

219 (99)

21 (6.41)

329 (150)

277 (126)

22 (6.71)

361 (164)

290 (132)

Standard

Standard

Vann

218,000 (98 883)

RDX

60°

Premium

20,000 (1379)

100008014

Vann

Industry Standard

20,000 (1379)

20,000 (1379)

218,000 (98 883)

218,000 (98 883)

90°

101600039

RDX

Millennium Express

101589595

RDX

Millennium Express


4

60°

Standard

Industry Standard

20,000 (1379)

4 spf SDP and Millennium

218,000 (98 883)

6 spf DP 4 (1.22)

86 (39)

77 (35)

7 (2.44)

126 (57)

109 (50)

8 (2.44)

144 (65)

125 (57)

11 (3.35)

187 (85)

160 (73)

15 (4.88)

240 (109)

205 (93)

16 (4.88)

256 (116)

219 (99)

21 (6.41)

329 (150)

277 (126)

22 (6.71)

361 (164)

290 (132)

5-21

3 3/8-in. Premium VannGun® Assemblies Weights

Charge Part No.

Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



101320459

RDX

DP

6

60°

Premium

Vann

25,000 (1724)

238,000 (107 955)

100008014

RDX

SDP

60°

Standard

Vann

20,000 (1379)

218,000 (98 883)

4 (1.22)

86 (39)

77 (35)

101293450

RDX

SDP/LD

60°

Standard

Industry Standard

20,000 (1379)

218,000 (98 883)

7 (2.44)

126 (57)

109 (50)

101233819

HMX

Millennium™

60° Two Row

Premium

Vann

25,000 (1724)

238,000 (107 955)

8 (2.44)

144 (65)

125 (57)

101309223

HMX

Dominator®

60° Two Row

Standard

Vann

20,000 (1379)

218,000 (98 883)

11 (3.35)

187 (85)

160 (73)

101365876

HNS

Millennium

15 (4.88)

240 (109)

205 (93)

100005321

RDX

BH

16 (4.88)

256 (116)

219 (99)

100157017

HMX

BH

21 (6.41)

329 (150)

277 (126)

22 (6.71)

365 (166)

290 (132)

100008251

RDX

BH

100005312

HMX

BH

101351605

HMX

BH/LD

5-22

12

30°/150° OMNI™

Premium

Vann

23,000 (1586)

238,000 (107 955)

30°/150° OMNI

Standard

Vann

20,000 (1379)

218,000 (98 883)

Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

6 spf SDP and Millennium

12 spf BH 4 (1.22)

89 (40)

77 (35)

8 (2.44)

150 (68)

125 (57)

11 (3.35)

197 (88)

160 (73)

16 (4.88)

271 (123)

219 (99)

22 (6.71)

365 (166)

290 (132)



Explosive Type

Charge Type

100005322

RDX

DP

100005327

HMX

DP

60°

101332806

HNS

DP

90°

100008014

RDX

SDP

90°

101293450

RDX

100008249

HMX

SPF

Phasing

4

60° 90°

Gun Material Type

Gun Thread



Premium

Vann

20,000 (1379)

278,000 (126 077)

Standard

Vann

18,000 (1241)

240,387 (109 038)


Loaded lb (kg)

Spacer lb (kg)

4 spf DP 4 (1.22)

107 (49)

99 (45)

8 (2.44)

173 (78)

155 (70)

11 (3.35)

223 (101)

197 (89)

SDP/LD

16 (4.88)

297 (135)

267 (121)

SDP

22 (6.71)

404 (183)

351 (159)

Standard

Industry Standard

18,000 (1241)

240,387 (109 038)

4 spf SDP 4 (1.22)

110 (50)

99 (45)

8 (2.44)

179 (81)

155 (70)

11 (3.35)

230 (104)

197 (89)

16 (4.88)

309 (140)

267 (121)

22 (6.71)

420 (191)

351 (159)

60°

Premium

Vann

20,000 (1379)

278,000 (126 077)

DP

60°

Standard

Vann

18,000 (1241)

240,387 (109 038)

4 (1.22)

111 (50)

99 (45)

HNS

DP

60°

Standard

Industry Standard

18,000 (1241)

240,387 (109 038)

8 (2.44)

189 (86)

155 (70)

100008014

RDX

SDP

11 (3.35)

233 (106)

197 (89)

101293450

RDX

SDP/LD

16 (4.88)

319 (144)

267 (121)

100008249

HMX

SDP

22 (6.71)

424 (192)

351 (159)

100005322

RDX

DP

100005327

HMX

101332806

6

6 spf DP

6 spf SDP


4 (1.22)

114 (52)

99 (45)

8 (2.44)

189 (86)

155 (70)

11 (3.35)

244 (111)

197 (89)

16 (4.88)

336 (152)

267 (121)

22 (6.71)

448 (203)

351 (159)

5-23


Explosive Charge Type Type

101355271

RDX

DP

101210636

HMX

Millennium™

101287306

HNS

101356077

HNS

SPF

Phasing

Gun Material Type

Gun Thread



5

60°

Standard

Vann

18,000 (1241)

240,387 (109 038)

60°

Standard

Industry Standard

18,000 (1241)

240,387 (109 038)


Loaded lb (kg)

Spacer lb (kg)

5 spf SDP 4 (1.22)

107 (49)

99 (45)

DP

8 (2.44)

173 (78)

155 (70)

Dominator®

11 (3.35)

223 (101)

197 (89)

16 (4.88)

297 (135)

267 (121)

22 (6.71)

404 (183)

351 (159)

101293450

RDX

SDP/LD

100008249

HMX

SDP

100005322

RDX

100005327

6

60°

Standard

Vann

18,000 (1241)

240,387 (109 038)

60°

Standard

Industry Standard

18,000 (1241)

240,387 (109 038)

6 spf DP 4 (1.22)

111 (50)

99 (45)

DP

7 (2.44)

126 (57)

109 (50)

HMX

DP

11 (3.35)

233 (106)

197 (89)

101332806

HNS

DP

15 (4.88)

240 (109)

205 (93)

100008014

RDX

SDP

21 (6.41)

329 (150)

277 (126)

101233819

HMX

Millennium

101293450

RDX

SDP/LD

101262511

HNS

SDP

100008249

HMX

SDP

100005319

RDX

BH

100005324

RDX

DP

100005325

RDX

100005340

12

45°/135°

Standard

Vann

18,000 (1241)

240,387 (109 038)

45°/135°

Standard

Industry Standard

18,000 (1241)

240,387 (109 038)

12 spf SDP 4 (1.22)

111 (50)

99 (45)

DP/LD

7 (2.44)

126 (57)

109 (50)

HMX

DP/LD

11 (3.35)

233 (106)

197 (89)

100014352

HMX

DP

15 (4.88)

240 (109)

205 (93)

100157006

HMX

BH

21 (6.41)

329 (150)

277 (126)

101210674

HMX

Millennium

5-24



Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



101210636

HMX

Millennium™

5

60°

Premium

Vann

20,000 (1379)

414,000 (187 755)

101287306

HNS

Millennium

60°

Standard

Vann

19,000 (1310)

385,000 (174 633)

100005322

RDX

DP

100005327

HMX

DP

101332806

HNS

100008014

6

60°

Premium

Vann

20,000 (1379)

414,000 (187 755)

60°

Standard

Vann

19,000 (1310)

385,000 (174 633)


Loaded lb (kg)

Spacer lb (kg)

5 spf 39 g Millennium 4 (1.22)

156 (71)

135 (61)

8 (2.44)

257 (117)

208 (94)

11 (3.35)

333 (151)

265 (120)

16 (4.88)

447 (203)

357 (162)

22 (6.71)

611 (277)

469 (213)

6 spf 32 g DP 4 (1.22)

147 (67)

134 (61)

DP

8 (2.44)

235 (107)

207 (94)

RDX

SDP

11 (3.35)

301 (137)

262 (119)

101293450

RDX

SDP/LD

16 (4.88)

405 (184)

354 (161)

100008249

HMX

SDP

22 (6.71)

544 (247)

464 (210)

100005311

RDX

SH

101228756

RDX

SH/LD

100156995

HMX

101233690

HMX

8

45°/135°

Premium

Vann

20,000 (1379)

414,000 (187 755)

45°/135°

Standard

Vann

19,000 (1310)

385,000 (174 633)

8 spf SH 4 (1.22)

151 (69)

134 (61)

SH

8 (2.44)

245 (111)

207 (94)

SH/LD

11 (3.35)

316 (143)

262 (119)

16 (4.88)

420 (191)

353 (160)

22 (6.71)

574 (260)

462 (210)


5-25


Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



100005319

RDX

BH

11

140°/160°

Premium

Vann

16,000 (1103)

414,000 (187 755)

100005326

RDX

BH/LD

140°/160°

Standard

Vann

14,000 (965)

385,000 (174 633)

100157006

HMX

120038060


Loaded lb (kg)

Spacer lb (kg)

11 spf BH 4 (1.22)

153 (69)

129 (59)

BH

8 (2.44)

252 (114)

197 (89)

HMX

BH/LD

11 (3.35)

326 (148)

248 (112)

100005324

RDX

DP

16 (4.88)

438 (199)

334 (151)

100014352

HMX

DP

22 (6.71)

600 (272)

436 (198)

101210674

HMX

Millennium™

101343830

HNS

DP

100005324

RDX

DP

100005325

RDX

DP/LD

100014352

HMX

100005340

12

30°/150° OMNI™

Premium

Vann

20,000 (1379)

414,000 (187 755)

30°/150° OMNI

Standard

Vann

19,000 (1310)

385,000 (174 633)


158 (72)

127 (58)

DP

8 (2.44)

262 (119)

194 (88)

HMX

DP/LD

11 (3.35)

340 (154)

244 (111)

101210674

HMX

Millennium

16 (4.88)

459 (208)

327 (148)

101343830

HNS

DP

22 (6.71)

626 (284)

427 (194)

100005319

RDX

BH

100005326

RDX

BH/LD

4 (1.22)

154 (70)

127 (58)

100157006

HMX

BH

8 (2.44)

254 (115)

194 (88)

120038060

HMX

BH/LD

11 (3.35)

328 (149)

244 (111)

100005311

RDX

SH

16 (4.88)

442 (200)

327 (148)

101228756

RDX

SH/LD

22 (6.71)

602 (273)

427 (194)

100156995

HMX

SH

101233690

HMX

SH/LD

5-26

12 spf BH

12 spf SH 4 (1.22)

150 (68)

127 (58)

8 (2.44)

245 (111)

194 (88)

11 (3.35)

315 (143)

244 (111)

16 (4.88)

422 (191)

327 (148)

22 (6.71)

575 (261)

427 (194)



Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



100005311

RDX

SH

14

25.7°/ 128.5°

Premium

Vann

20,000 (1379)

414,000 (187 755)

100156995

HMX

SH

25.7°/ 128.5°

Standard

Vann

19,000 (1310)

385,000 (174 633)

100156990

RDX

BH

100157005

HMX

DP


18

45°/135°

Premium

Vann

20,000 (1379)

414,000 (187 755)

45°/135°

Standard

Vann

19,000 (1310)

385,000 (174 633)


Loaded lb (kg)

Spacer lb (kg)

14 spf SH 4 (1.22)

150 (68)

124 (56)

8 (2.44)

244 (111)

188 (85)

11 (3.35)

315 (143)

235 (107)

16 (4.88)

422 (192)

314 (142)

22 (6.71)

575 (261)

410 (186)

18 spf 4 (1.22)

139 (63)

118 (54)

8 (2.44)

222 (101)

176 (80)

11 (3.35)

285 (129)

219 (99)

16 (4.88)

379 (172)

291 (132)

22 (6.71)

513 (233)

378 (171)

5-27


Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



100005324

RDX

DP

12

30°/150° OMNI™

Premium

Vann

21,000 (1447)

516,000 (234 014)

100005325

RDX

DP/LD

30°/150° OMNI

Standard

Vann

19,000 (1310)

480,000 (217 724)

100014352

HMX

100005340


Loaded lb (kg)

Spacer lb (kg)

12 spf BH 4 (1.22)

169 (77)

144 (65)

DP

8 (2.44)

284 (129)

228 (103)

HMX

DP/LD

11 (3.35)

370 (168)

291 (132)

101210674

HMX

Millennium™

16 (4.88)

505 (229)

395 (179)

101343830

HNS

DP

22 (6.71)

685 (311)

521 (236)

100005319

RDX

BH

100005326

RDX

BH/LD

4 (1.22)

166 (75)

144 (65)

100157006

HMX

BH

8 (2.44)

277 (126)

228 (103)

120038060

HMX

BH/LD

11 (3.35)

361 (164)

291 (132)

100005311

RDX

SH

16 (4.88)

491 (223)

395 (179)

101228756

RDX

SH/LD

22 (6.71)

666 (302)

521 (236)

100156995

HMX

SH

101233690

HMX

SH/LD

12 spf DP


173 (78)

144 (65)

8 (2.44)

292 (132)

228 (103)

11 (3.35)

381 (173)

291 (132)

16 (4.88)

522 (237)

395 (179)

22 (6.71)

709 (321)

521 (236)

12 spf SH

5-28

4 (1.22)

165 (75)

144 (65)

8 (2.44)

275 (125)

228 (103)

11 (3.35)

357 (162)

291 (132)

16 (4.88)

485 (220)

395 (179)

22 (6.71)

657 (298)

521 (236)



Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread

101321963

RDX

Maxim™

6

45°/135°

Premium

Vann

101350449

RDX

Maxim

8

30°/150° OMNI™

Premium

Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

6 spf SH

20,000 (1379)

18,000 (1241)

4 (1.22)

175 (79)

152 (69)

8 (2.44)

280 (127)

230 (104)

11 (3.35)

359 (163)

288 (131)

16 (4.88)

490 (222)

385 (175)

22 (6.71)

648 (294)

502 (228)

427,000 (193 651)

427,000 (193 651)

12 spf SH 4 (1.22)

175 (79)

152 (69)

8 (2.44)

280 (127)

230 (104)

SH

101228756

RDX

SH/LD

11 (3.35)

359 (163)

288 (131)

100156995

HMX

SH

16 (4.88)

490 (222)

385 (175)

101233690

HMX

SH/LD

22 (6.71)

648 (294)

502 (228)

101307494

RDX

Mirage®

100005311

RDX

SH

101228756

RDX

SH/LD

4 (1.22)

177 (80)

152 (69)

100156995

HMX

SH

8 (2.44)

286 (130)

230 (104)

101233690

HMX

SH/LD

11 (3.35)

368 (167)

288 (131)

16 (4.88)

504 (228)

386 (175)

22 (6.71)

667 (302)

503 (228)

25.7°/ 128.5°

Premium

Vann

Weights

RDX

14

Premium

Vann


100005311


12

45°/135°


Vann

17,000 (1172)

427,000 (193 651)

14 spf SH

5-29


Explosive Type

Charge Type

SPF

101268719

RDX

SH

18

Phasing

Gun Material Type

60°/120°

Premium

Gun Thread



Vann

17,000 (1172)

427,000 (193 651)

3/Plane

101292616

RDX

BH

21

60°/120° 3/Plane

5-30

Premium

Vann

16,000 (1103)


Loaded lb (kg)

Spacer lb (kg)

18 spf SH 4 (1.22)

181 (82)

152 (69)

8 (2.44)

296 (134)

229 (104)

11 (3.35)

383 (174)

288 (130)

16 (4.88)

527 (239)

385 (174)

22 (6.71)

701 (318)

501 (227)

427,000 (193 651)

21 spf BH 4 (1.22)

185 (84)

152 (69)

8 (2.44)

304 (138)

229 (104)

11 (3.35)

393 (178)

287 (130)

16 (4.88)

540 (245)

384 (174)

22 (6.71)

717 (325)

500 (227)



Explosive Type

Charge Type

SPF

101240223

RDX

SH

6

100005319

RDX

BH

100005326

RDX

BH/LD

100157006

HMX

120038060

12

Phasing

Gun Material Type

135°

Premium

Gun Thread



Vann

18,000 (1241)

520,000 (235 868)

OMNI™

Premium

Vann

16,000 (1103)

520,000 (239 929)

OMNI

Premium

Industry Standard

16,000 (1103)

520,000 (239 929)


Loaded lb (kg)

Spacer lb (kg)

6 spf SH 4 (1.22)

185 (84)

152 (69)

8 (2.44)

304 (138)

229 (104)

11 (3.35)

393 (178)

287 (130)

16 (4.88)

540 (245)

384 (174)

22 (6.71)

717 (325)

500 (227)

12 spf 22.7 g 4 (1.22)

181 (82)

157 (71)

BH

8 (2.44)

290 (132)

239 (108)

HMX

BH/LD

11 (3.35)

372 (169)

300 (136)

100005324

RDX

DP

16 (4.88)

505 (229)

401 (182)

100005325

RDX

DP/LD

22 (6.71)

672 (305)

523 (237)

100014352

HMX

DP

100005340

HMX

DP/LD

4 (1.22)

180 (81)

157 (71)

101210674

HMX

Millennium™

8 (2.44)

287 (130)

239 (108)

101343830

HNS

DP

11 (3.35)

368 (167)

300 (136)

100005311

RDX

SH

16 (4.88)

499 (226)

401 (182)

101228756

RDX

SH/LD

22 (6.71)

663 (301)

523 (237)

100156995

HMX

SH

101233690

HMX

SH/LD

101307494

RDX

Mirage®


12 spf 28 g SH

5-31


Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



100157007

RDX

SH

14

25.7°/ 128.5°

Premium

Vann

16,000 (1103)

520,000 (239 929)

100157011

HMX

SH


Loaded lb (kg)

Spacer lb (kg)

14 spf 28 g SH 4 (1.22)

182 (82)

157 (71)

8 (2.44)

292 (133)

238 (108)

11 (3.35)

375 (170)

298 (135)

16 (4.88)

511 (232)

399 (181)

22 (6.71)

679 (308)

520 (236)

14 spf 32 g SH

101292616

RDX

BH

21

60°/120° 3/Plane

5-32

Premium

Vann

16,000 (1103)

4 (1.22)

186 (84)

157 (71)

8 (2.44)

302 (137)

238 (108)

11 (3.35)

389 (176)

298 (135)

16 (4.88)

531 (241)

399 (181)

22 (6.71)

708 (321)

520 (236)

520,000 (239 929)

21 spf 4 (1.22)

190 (86)

156 (71)

8 (2.44)

311 (141)

236 (107)

11 (3.35)

402 (182)

296 (134)

16 (4.88)

553 (251)

395 (179)

22 (6.71)

734 (333)

515 (234)


5 3/4-in. Premium VannGun® Assemblies Phasing

Gun Material Type

14

25.7°/ 128.5°

10

45°/135°

Charge Part No.

Explosive Type

Charge Type

SPF

100157007

RDX

SH

101307494

RDX

Mirage®

101357518

RDX

Maxim™

101292616

RDX

BH

21

60°/120°

Gun Thread



Premium

Vann

17,000 (1172)

512,000 (232 200)

Premium

Vann

17,000 (1172)

512,000 (232 200)

Premium

Vann

16,000 (1103)


Loaded lb (kg)

Spacer lb (kg)

14 spf SH 4 (1.22)

216 (98)

192 (87)

8 (2.44)

344 (156)

293 (133)

11 (3.35)

442 (200)

369 (167)

16 (4.88)

647 (294)

496 (225)

22 (6.71)

859 (389)

648 (294)

512,000 (232 200)

21 spf SH 4 (1.22)

216 (98)

192 (87)

8 (2.44)

344 (156)

293 (133)

11 (3.35)

442 (200)

369 (167)

16 (4.88)

647 (294)

496 (225)

22 (6.71)

859 (389)

648 (294)

6-in. Premium VannGun® Assemblies Weights

Charge Part No.

Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



100156993

RDX

DP

12

51.4°/ 154.2°

Premium

Vann

15,000 (1034)

672,000 (304 762)

100156994

HMX

DP

4 (1.22)

272 (123)

216 (98)

100156992

HMX

BH

8 (2.44)

447 (203)

318 (144)

100156991

RDX

BH

15 (4.57)

706 (320)

497 (225)

Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

12 spf DP

12 spf BH


4 (1.22)

251 (114)

216 (98)

8 (2.44)

398 (181)

318 (144)

15 (4.57)

608 (276)

497 (225)

5-33

6 1/2-in. Premium VannGun® Assemblies Weights

Charge Part No.

Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



101228037

RDX

Mirage®

12

45°/135°

Premium

Vann

15,000 (1034)

480,000 (217 687)

101304878

RDX

Mirage

4 (1.22)

275 (125)

240 (109)

101213474

RDX

SH

8 (2.44)

431 (195)

354 (160)

101212693

RDX

SH/LD

16 (4.88)

733 (333)

582 (264)

101357518

RDX

Maxim™

Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

12 spf BH Mirage

12 spf SH/LD

14

138°

Premium

Vann

15,000 (1034)

480,000 (217 687)

4 (1.22)

277 (126)

240 (109)

8 (2.44)

435 (197)

354 (160)

16 (4.88)

743 (337)

582 (264)

14 spf SH Mirage

101228037

RDX

Mirage

101304878

RDX

Mirage SH

4 (1.22)

277 (124)

240 (109)

101213474

RDX

SH

8 (2.44)

437 (198)

354 (160)

101357518

RDX

Maxim

16 (4.88)

754 (342)

582 (264)

14 spf SH

5-34

4 (1.22)

283 (128)

240 (109)

8 (2.44)

451 (205)

354 (160)

16 (4.88)

784 (355)

582 (264)


6 1/2-in. High-Pressure Premium VannGun® Assemblies Phasing

Gun Material Type

45°/135°

Premium

Gun Thread



Vann

20,000 (1379)

719,000 (326 132)

Weights

Charge Part No.

Explosive Type

Charge Type

SPF

101228037

RDX

Mirage®

12

101304878

RDX

Mirage SH

4 (1.22)

298 (135)

268 (121)

101213474

RDX

SH

8 (2.44)

476 (216)

410 (186)

101212693

RDX

SH/LD

16 (4.88)

824 (370)

684 (310)

101357518

RDX

Maxim™

Length ft (m)

Loaded lb (kg)

Spacer lb (kg)

12 spf BH Mirage

12 spf SH/LD

14

138°

Premium

Vann

20,000 (1379)

480,000 (217 687)

4 (1.22)

300 (136)

268 (121)

8 (2.44)

481 (218)

410 (186)

16 (4.88)

834 (378)

684 (310)

101228037

RDX

Mirage

101304878

RDX

Mirage SH

4 (1.22)

300 (136)

268 (121)

101213474

RDX

SH

8 (2.44)

482 (219)

410 (186)

101357518

RDX

Maxim

16 (4.88)

841 (382)

684 (310)

14 spf SH Mirage

14 spf SH


4 (1.22)

305 (138)

268 (121)

8 (2.44)

496 (225)

410 (186)

16 (4.88)

871 (395)

684 (310)

5-35


Explosive Type

Charge Type

SPF

100005325

RDX

DP/LD

12

100005340

HMX

DP/LD

101228037

RDX

101304878

Phasing

Gun Material Type

Gun Thread



45°/135°

Premium

Vann

13,000 (897)

802,000 (363 719)

45°/135°

Premium

Industry Standard

13,000 (897)

802,000 (363 719)


Loaded lb (kg)

Spacer lb (kg)

12 spf BH Mirage 4 (1.22)

326 (148)

292 (132)

Mirage®

8 (2.44)

494 (224)

421 (191)

RDX

Mirage

16 (4.88)

831 (377)

679 (308)

101213474

RDX

SH

101212693

RDX

SH/LD

4 (1.22)

328 (149)

292 (132)

101207997

HMX

Millennium™

8 (2.44)

499 (226)

421 (191)

101357518

RDX

Maxim™

16 (4.88)

841 (381)

679 (308)

12 spf SH/LD

12 spf Millennium

14

138°

Premium

Vann

13,000 (897)

802,000 (363 719)

4 (1.22)

356 (161)

292 (132)

8 (2.44)

565 (256)

421 (191)

16 (4.88)

984 (446)

679 (308)

101228037

RDX

Mirage

101304878

RDX

Mirage SH

4 (1.22)

328 (149)

291 (132)

101213474

RDX

SH

8 (2.44)

501 (227)

420 (190)

101357518

RDX

Maxim

16 (4.88)

847 (384)

677 (307)

14 spf SH Mirage

14 spf SH

5-36

4 (1.22)

334 (151)

291 (132)

8 (2.44)

515 (234)

420 (190)

16 (4.88)

877 (398)

677 (307)



Explosive Type

Charge Type

SPF

Phasing

Gun Material Type

Gun Thread



101414821

HMX

Mirage®

18

60°/120°

Premium

Vann

13,000 (897)

802,000 (363 719)

101414821

HMX

Mirage


18

60°/120°

Premium

Vann

20,000 (1379)

802,000 (363 719)


Loaded lb (kg)

Spacer lb (kg)

18 spf SH Mirage 4 (1.22)

334 (151)

291 (132)

8 (2.44)

515 (234)

420 (190)

16 (4.88)

877 (398)

677 (307)

18 spf SH Mirage XHP 4 (1.22)

334 (151)

291 (132)

8 (2.44)

515 (234)

420 (190)

16 (4.88)

877 (398)

677 (307)

5-37

Gun Washover/Fishing Specifications Gun Size in.

1.563

2

2.5

2.75

3.125

3.375

4

4.625

5

5.125

Gun OD in.* (Gun OD after shooting)

Maximum Shot (Density) per foot SPF

1.745

4

1.76

6

2.166

4

2.203

6

TBD*

4

2.67

6

2.97

4

2.79

5

3.09

6

3.25

9

3.68

4

3.68

6

3.53

12

4.26

6

4.87

5

4.88

6

4.86

8

4.87

11

4.96

12

4.79

14

5.2

12

5.3

14

5.23

18

5.41

6

5.21

12

5.38

14

Minimum Casing Size (for washing over w/o milling guns) 4 in.

4 in.

4.5 in. 13.5 #/ft

4.5 in. 9.5 #/ft

5 in. 15 #/ft

5.5 in. 23 #/ft

6 5/8 in. 35 #/ft

7 in. 35 #/ft

7 in. 26 #/ft/**

7 5/8 in. 39 #/ft

5.36

21

6

6.79

12

9 5/8 in.

6.5

6.76

14

9 5/8 in. 71.8 #/ft

7.14

12

7.15

14

7

9 5/8 in. 58.4 #/ft

*Worst Case-Atmospheric pressure, submerged in water. **It is possible to washover 5 in. guns in 7 in. 29-lb casing, but washover pipe to be used is not a common size and is difficult to find.

5-38


Gun Swell Information Gun OD

SPF

1 9/16

6 4

2

6

Charge Shot Phase deg 60

100157028

0

100157028

0

100008017

60

100008017

0

101208224

60 2.38

6

60

2 1/2

6

60

4

22 LS

5

Charge Part No.

180

101208224

6

Explosive Weight gm

Tested In Air/Water

Millennium™

3.4

water air

SDP 6.8 Millennium

Maximum Swell in. 1.760 1.705 2.246 2.221

water

2.177 2.225

MaxForce®

7

air

2.193

101590845

MaxForce

10

water

2.529

101206251

DP

11

water

2.680

101418095*

Millennium II™

11.1

air

2.705

100158220 100158220 100157026

100005329 60

Type

101603801*

100005329 2 3/4

Test Results

100158220

DP LD SDP DP DP LD

13

2.781

13

2.810

14.7 12.5 12.5

BH

14.7

100010399

SDP

14.7

101233817 101233817

Millennium

2.971 2.853

air

13

101206793

60 LS

water

2.898 2.893 2.850

water

2.954

15

2.892

15

2.915

2 7/8

6

60

101233817

Millennium

15

water

3.047

2 7/8 HW

6

60

101233817

Millennium

15

air

3.044

2.88

6

60

101388407

Millennium HNS

18.5

water

3.060

3 1/8

6

60

101388406

Millennium

17.5

HMX

3.333

25

water

3.497

15

water

3.42

32

air

3.676

3.38

5

60

101320075

Dominator®

G-Force®

180

101233817

Millennium

60 4

3 3/8 6

8

12 3 1/2 4

6

100005327

90

100005327

180

100008249

DP

32 32

SDP

25

3.592 water

3.555 3.546

100005333

DP

22

60

100008249

SDP

25

101207640

SDP LD

24

3.615

60 LS

100008249

SDP

25

3.600

101233819

Millennium

25

101309223

Dominator

25 14

3.458

BH

14

3.520

60

12

100005322

180 30/150 60

100008251 100008251 100005312

air

3.600

water

14

101309223

Dominator

25

3.610

3.645 3.695

3.568 air

3.845

4

90

101210636

Millennium

39

water

4.260

7

150

101228756

SH LD

28

water

4.280


5-39

Gun Swell Information Gun OD 4.25

Charge

SPF

Shot Phase deg

Charge Part No.

Type

101228756

SH LD

28

water

4.487

180

100005327

DP

32

water

4.696

4

10/350

101466192

KleenZone™

39

water

4.705

60

101210636

Millennium™

39

air

4.944

45/135

101321963

SH

56.5

water

4.904

32

air

4.876

32

water

4.806

23

air

4.860

60

8

180

4 5/8

100005327 100005327

100005326 100005311

11

140/160

100005324 100014352

12

7

DP LD SH DP

23

4.780

28

4.770

22.7

4.868

23

4.834

100005340

DP LD

22.7

100005326

BH LD

22.7

100005311

SH

101228756

SH LD

100005311

SH

45/135

100156990

BH

20

8

135

101350449

Maxim™

47

12

30/150

100005311

14

25.7/128.5

60/120

4.925 4.840 4.813

25.7/128.5

100005311

water

28

18

21

6 1/2 HP

30/150

DP

14

18

6 1/2

Maximum Swell in.

150

100005326

5 3/4

Tested In Air/Water

8

6

5 1/8

Explosive Weight gm

G-Force®

5

5

Test Results

4.895 4.790 4.730 water

5.202 5.196

SH 28

101228756

SH LD

101269719

SH

101292616

BH

21

5.207 water

5.304 5.229 5.198

6

45/135

101240223

SH

56.5

5.413

12

30/150

100005326

BH LD

22.7

5.210

14

25.7/128.5

100157007

SH

32

21

60/120

101292616

BH

20

14

25.7/128.5

101272769

SH LD

34

water

5.945

21

3/plane 60

101292616

BH

21

water

6.065

14

138

101304878

Mirage BH

47

®

water

water

12

45/135

101212693

SH LD

56.5

12

45/135

101212693

SH LD

56.5

water

12

45/135

101210063

SH LD

56.5

water

45

water

14

138

101213474

SH

18

3/plane 60

101498239

BH LD

5.332 5.268

6.685 6.715 6.762 7.125 7.143 7.130

*Special gun length requirements The above chart was taken from actual tests conducted by Halliburton Technology on RDX and HMX charges. It can be used as a general guideline for all explosives. If you have questions regarding these systems, or systems that are not listed, please contact your local Halliburton representative. All tests were conducted at ambient temperature and pressure.

5-40


Capsule Gun Systems Dyna-Star® Capsule Gun Jet Research Center’s Dyna-Star® capsule gun is an economical, second-generation capsule perforating system. This system is partially expendable and uses a stainless steel strip in its through-tubing technology. Applications • 2.125-in. and 1.6875-in. gun systems at 4-spf and 6-spf • 1.6875-in. system rated at 14,000 psi and up to 370°F (HMX version) in dry gas or fluid • 2.125-in. system rated at 15,000 psi and up to 370°F (HMX version) in dry gas or fluid • Rated up to 370°F (HMX version) in dry gas or fluid— may be used in hostile environments only if special precautions are taken. Contact JRC for more information Features • Deep penetrating charges • Uses same charges as the Dyna-Cap® four-wire strip gun to minimize inventory • Available in 0° phasing • Rollover sleeves to keep the gun in its optimum orientation • Can cut guns to required length in the field • Economical operation • Can use 18-ft long strips without tandem

HAL11757

• Ease of gun retrieval after shooting

Dyna-Star® Capsule Gun


5-41

Deep Star™ Capsule Gun Jet Research Center's Deep Star™ perforating system is a third-generation, state-of-the-art, through-tubing capsule perforating system with improved charge performance and running characteristics. Applications • 2.125-in. and 1.6875-in. OD gun systems • Rated at 15,000 psi and 350°F in dry gas, fluid, or hostile environments • Higher ratings available upon request • Designed for deep, high temperature, high pressure wells Features • Extremely deep penetrating charges • Higher shot densities without charge interference (up to 8-spf with the 1.6875-in. system-patent pending) attained using hydrodynamic modeling techniques • Most available in seven phasings: 0°, 90° downside, 90° spiral, triphase (patented), pentaphase, heptaphase, and octaphase • Compatible interval coverage with the innovative “gullwing” tandem (patented), which minimizes strip deformation, allowing easier retrieval • Hardware offset in conjunction with charge center gravity to optimize gun stability and orientation • Corrosion-resistant steel alloy charge cases and carrier strips permit the use of the Deep Star system in hostile environments • No gaps in shot pattern at joints in strips

HAL11758

• Ease of gun removal after shooting

2.125-in. 90° Spiral Phase Deep Star™ Capsule Gun

5-42


1.6875-in. and 2.125-in. Deep Star™ Debris Fill Data 1.2

1.0

Inches of Fill Per Charge

2.125-in. 0.8

0.6

0.4 1.6875-in.

HAL11759

0.2

0 1

2

3

4

5

6 Pipe ID (inches)

8

7

9

10

11

Deep Star™ Fill Data (Shot in Water) Pipe OD in.

Pipe Weight lb/ft

Pipe ID in.

Fill per 1 11/16-in. Charge in. (mm)

Fill per 2 1/8-in. Charge in. (mm)

2 3/8

4.7

1.995

0.322 (8.17)

0.920 (23.37)

2 7/8

6.5

2.441

0.215 (5.45)

0.615 (15.61)

3 1/2

9.3

2.992

0.143 (3.63)

0.409 (10.39)

4

11.0

3.476

0.106 (2.69)

0.303 (7.70)

4 1/2

11.6

4.000

0.080 (2.03)

0.229 (5.81)

5

15.0

4.408

0.066 (1.67)

0.188 (4.79)

5 1/2

17.0

4.892

0.053 (1.36)

0.153 (3.89)

7

32.0

6.094

0.034 (0.88)

0.099 (2.50)

7 5/8

33.7

6.765

0.028 (0.71)

0.080 (2.03)

9 5/8

47.0

8.681

0.017 (0.43)

0.049 (1.23)

Notes: 1. Fill data is approximate. 2. When shot in gas, the debris is smaller and will occupy less volume.


5-43

Ported Gun Perforating System Jet Research Center’s ported gun perforating systems provide users with economical, reusable guns for multi-purpose applications. Applications • Multi-zone shooting on a single run with select fire subs • Hostile environment • Short guns available for squeeze applications Features • Charges are protected from well fluids, formation pressure, and abrasion • Debris retained in hollow carrier • Carrier protects casing from detonation shock • Charges for high-temperature environments are available upon request • Charges are tested to API standards • Charges are designed to minimize internal damage to the gun body, prolonging life • The gun design has minimized charge interference Options • 3.125-in. to 5-in. gun sizes • Big-hole and deep penetrating charges

HAL11760

• 90° and 120° phasing (other phase angles available upon request)

3.125-in. Ported Gun

5-44


Firing Heads Detonation Interruption Device The detonation interruption device (DID) provides added safety for the VannSystem® service by helping to prevent firing at surface conditions. This device contains a eutectic metal that has a very low melting point. When the metal is in a solid state, the firing head could detonate, but the explosive train will not transmit through the interrupt device to the guns. Features • Compatible with other firing heads • Disables transmission of explosive train at the surface • Used with redundant firing heads Operation The eutectic metal will remain solid as the assembly lowers into the hole (assuming the tool temperature is below 117°F). When exposed to the bottomhole temperature (minimum 135°F for operational purposes), the metal becomes liquid, allowing the transfer of the explosive train from the firing head to the gun.

HAL10519

To help prevent accidental gun detonation when lowering or retrieving unfired guns, the metal returns to a solid state upon reaching a cooler surface temperature. Note: The eutectic material utilized actually melts at 117°F. At 117°F or above, the DID assembly will not prevent detonation. For safe operation, it should be assumed that detonation transfer will occur if the tool is at or above 110°F.

Detonation Interruption Device

Detonation Interruption Device (DID) Specifications SAP No.

Thread Size and Type in. (mm)

Maximum OD in. (mm)


Maximum Operating Pressure psi (bar)

Minimum Required Temperature Rating °F (°C)


100155745

2 (50.8) 6 Acme 2G

2.50 (63.5)

1.58 (0.48)

N/A

135 (57)

121,000 (54 885)

101204860

2 3/8 (60.33) 6P Acme Box × Pin

2.75 (69.85)

3.70 (1.13)

20,000 (1380)

135 (57)

140,000 (63 400)

100155746

2 7/8 (73.03) 6P Acme Box × Pin

3.375 (85.73)

3.04 (0.93)

25,000 (1725)

135 (57)

246,000 (111 500)

Maximum temperature is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-45

Mechanical Firing Head The extended mechanical firing head (MFH) is a special application tool. It should be used only when well conditions preclude the use of an alternate firing device. Whenever it is used on a job, the MFH must be used according to Halliburton standard operating procedures. Operation The operation of the MFH depends on the amount of force delivered to the firing pin by the detonating bar. This firing pin must be hit with enough force to shear the spiral pin, which holds the firing pin in place, and to detonate the initiator. The firing pin is driven into a percussion detonator, which fires the guns.

HAL15376

HAL15358

The detonation interruption device (DID) and a minimum of 10 ft of safety spacer must always be used with the MFH.

Mechanical Firing Head (MFH)

Firing Head Sub-Assembly

Mechanical Firing Head (MFH) Specifications SAP No.


Maximum OD in. (mm)

Makeup Length (w/Tubing Sub) ft (m)


Minimum ID (No-Go) in. (mm)

Tensile Strength (FH Body) lb (kg)

100155741

1 7/16 (36.51) 8 UN 2 B Box × 1.90 (48.26) NU 10 Rd Pin

2.0 (50.8)

1.48 (.45)

20,000 (1380)

1.53 (38.86)

60,000 (27 200)

100005223

1.90 (48.26) NU 10 Rd Pin × 2 3/8 (60.33) 6P Acme Box

2.75 (69.85)

4.92 (1.50)

20,000 (1380)

1.56 (39.62)

140,000 (63 400)

100005228

2 3/8 (60.33) EUE 8 Rd Pin × 2 7/8 (73.03) 6P Acme Box

3.375 (85.73)

4.92 (1.50)

20,000 (1380)

1.56 (39.62)

238,000 (107 900)

Burst and collapse pressures are determined by handling sub. Temperature rating is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative.

5-46


Model II-D Mechanical Firing Head The model II-D mechanical firing head is a pressure-assisted mechanical firing head. The detonating bar strikes the firing pin, releasing the firing piston. Hydrostatic pressure then forces the firing piston into the initiator. Features • Cannot be detonated accidentally at surface • Ideal for use in mud environments where spudding may be necessary • Used in deviated wells Operation The model II-D firing head requires a minimum of 1,500 psi hydrostatic pressure in the tubing to actuate the firing head properly.

HAL15377

HAL15378

Adding more pressure to the tubing after the detonating bar has struck the firing pin will not actuate the firing head.

Model II-D Mechanical Firing Head

Model II-D Mechanical Firing Head Assembly

Model II-D Mechanical Firing Head Specifications SAP No.


Maximum OD in. (mm)


Makeup Length (w/tubing sub) ft (m)


Minimum Operating Pressure psi (bar)

Tensile Strength (FH body) lb (kg)

100014156

1.90 (48.26) EUE 10 Rd Pin × 2 3/8 (60.33) 6P Acme Box

2.75 (69.85)

1.56 (39.62)

4.92 (1.50)

20,000 (1380)

1,500 (103)

140,000 (63 400)

100005227

2 3/8 (60.33) EUE 8 Rd Pin × 2 7/8 (73.03) 6P Acme

3.375 (85.73)

1.56 (39.62)

4.92 (1.50)

20,000 (1380)

1,500 (103)

238,000 (107 900)



5-47

Model III-D Mechanical Firing Head The model III-D mechanical firing head is a pressure-assisted mechanical firing head. The detonating bar strikes the firing pin, releasing the firing piston. Hydrostatic pressure then forces the firing piston into the initiator. The model III-D firing head requires a minimal amount of hydrostatic pressure to actuate the firing head. Features • Cannot be detonated accidentally at surface • Requires minimal hydrostatic pressure to actuate the firing head Operation The model III-D firing head requires a minimum of 250 psi hydrostatic pressure in the tubing to actuate the firing head properly. This minimal actuating pressure is ideal for applications that require maximum differential pressures.

HAL15379

HAL15380

If a detonating bar is dropped on the model III-D firing head with less than 250 psi hydrostatic pressure in the tubing, and the head does not fire, increasing the hydrostatic pressure in the tubing may cause it to fire.

Model III-D Mechanical Firing Head

Model III-D Mechanical Firing Head Assembly

Model III-D Mechanical Firing Head Specifications SAP No.


Maximum OD in. (mm)


Makeup Length (w/Tubing Sub) ft (m)




100155742


2.75 (69.85)

1.56 (39.62)

4.92 (1.50)

8,000 (550)

250 (17)

140,000 (63 400)

100005191


3.375 (85.73)

1.56 (39.62)

4.92 (1.50)

8,000 (550)

250 (17)

238,000 (107 900)


5-48


Pressure-Actuated Firing Head The 1 11/16-in. pressure-actuated firing head (PAF) can run with small-OD tubing or coiled tubing to detonate small-OD perforating guns. The PAF is detonated by applied pressure. Features • Can be run on the top and bottom of the gun assembly • Initiates a bridge-plug setting tool • Initiates tubing cutters • Detonates tubing punch charges for squeeze or circulating jobs • Can be run to remain closed after detonation • Can be modified to be run as a slickline-retrievable firing head and a time-delay firing head (TDF) Operation The 1 11/16-in. PAF consists of an upper housing with circulating ports, a firing piston that is shear-pinned in place across the circulating ports, and an initiator contained in a lower housing.

HAL10561

Pressure applied to the tubing string shears the shear set, which forces the firing piston into the initiator to detonate the explosive component attached to the PAF. The downward movement of the firing piston opens the circulating ports.

Pressure-Actuated Firing Head (PAF)

Pressure-Actuated Firing Head (PAF) Specifications SAP No.


Maximum OD in. (mm)

No. and ID of Ports in. (mm)

Flow Area of Ports in.2 (cm2)





Collapse Pressure psi (bar)

100005224

1.315 (33.40) NU-10 Rd Pin × 17/16 (36.51) 8 UN-2 B Box

1.688 (42.88)

2 @ 0.75 (19.05)

0.88 (5.68)

0.73 (0.22)

17,000 (1170)

2,200 (150)

65,000 (29 400)

27,000 (1860)

Temperature rating is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-49

Model K and K-II Firing Heads The model K and K-II firing heads were developed for conditions that are unfavorable for dropping a detonating bar in a horizontal well. The model K and K-II firing heads are pressuresensitive tools designed to hydraulically detonate at a prescribed pressure. These firing heads use tubing pressure applied to a piston-type firing pin. Features • Allows the operator to determine the exact time of firing the guns since the firing heads require a predetermined pressure before the guns can fire • Works with full-opening or non-fullopening downhole tools • Ideal for balanced or overbalanced perforating • Can be used for dual completions, drillstem testing, or production perforating

• Can be run on the top or bottom of the perforating assembly • Can be easily redressed Operation The model K and K-II firing heads are designed to provide a reliable and costeffective method for firing guns using hydrostatic pressure. Each firing head contains a firing piston that is shearpinned in place above an initiator. The number of shear pins used varies for each well situation. When enough hydrostatic pressure is applied to the piston, the shear pins shear, thereby allowing the firing pin on the lower end of the piston to be driven into the initiator. This action detonates the guns. These firing heads do not have a built-in delay.

HAL15381

• Well-suited for highly deviated well completions

Model K-II Firing Head

Model K Firing Head Specifications SAP No.


Maximum OD in. (mm)






100014211

2 7/8 (73.03) EUE 8 Rd Box × 2 7/8 (73.03) 6P Acme Box

3.375 (85.73)

1.25 (0.38)

13,000 (895)

4,000 (275)

220,000 (99 700)

30,000 (2070)

Model K-II Firing Head Specifications SAP No.


Maximum OD in. (mm)






100005190


2.75 (69.85)

1.24 (0.38)

19,500 (1345)

4,000 (275)

187,000 (84 800)

25,000 (1725)

100014215


3.375 (85.73)

1.64 (0.50)

19,500 (1345)

4,000 (275)

220,000 (99 700)

30,000 (2070)


5-50


Model KV-II Firing Head The model KV-II firing head makes the firing of the guns and the opening of the vent one operation rather than two. This tool allows the operator more accurate control of when the vent opens in relation to when the guns fire. Features • Useful in wells with open perforations where it is not possible to pressure up on the wellbore to actuate a firing head • Useful in perforating and stimulation jobs where the tubing pressure exceeds the limitations of the casing • Useful because the firing head and vent operate at one pressure • Ideal for deviated wells

In many tubing conveyed perforating applications, it is either desirable or necessary to keep the tubing closed until the guns have been detonated. In the past, the tubing was kept closed by a firing head with some type of vent assembly. Coordination between the two tools was sometimes hard to achieve, and the vent often opened either too soon or too late. The model KV-II firing head combines a firing head and a vent assembly. In the model KV-II firing head, a piston is sheared to cause the guns to detonate and the ports to open and equalize (or vent) pressure. This venting feature allows operators to run the tubing in the hole dry if needed. In the standard KV-II firing head, the ports in the tool open the instant the firing head is actuated and the guns detonate. To delay the gun detonation, one or more delay devices may be added to the assembly.

HAL15459

• Piston mechanically locked after firing

Operation

Model KV-II Firing Head

Model KV-II Firing Head Specifications SAP No.


Maximum OD in. (mm)

Flow Area in.2 (cm2)

Minimum Makeup Length ft (m)



Maximum Differential Pressure psi (bar)


100014153


2.75 (69.85)

2.79 (18.0)

1.33 (0.41)

25,000 (1725)

3,000 (206)

15,000 (1035)

145,000 (65 700)

100014155


3.375 (85.73)

3.14 (20.27)

1.43 (0.44)

25,000 (1725)

4,000 (275)

15,000 (1035)

235,000 (106 600)



5-51

Time-Delay Firer Operation

The time-delay firer (TDF) allows under- or overbalanced perforating through the use of a pressure-actuated firing head with a time-delay fuse. The delay fuse allows 4 to 6 minutes for adjusting the actuating pressure in the tubing to achieve the desired pressure before firing the guns.

The TDF is run with a predetermined number of shear pins for specific well conditions. The tubing is pressured to the maximum actuating pressure slowly. The maximum pressure shears the pins in the shear set and forces the firing piston into the primer. The primer ignites the pyrotechnic delay fuse. The delay fuse burns for a predetermined time (between 4 and 6 minutes) depending on the bottomhole temperature and detonates the perforating assembly.

Features • Allows independent perforating of selected zones • Allows maximum use of under- or overbalanced pressure • Can be run in heavy mud systems • Can be used with full-opening or non-full-opening tools • Reduces cost by allowing the running of multiple guns without gun spacers • Ideal for production completions, drillstem testing, and dual completions

HAL15382

• Recommended for running on the top and bottom of gun assemblies • Allows additional time-delay elements as needed for increasing delay time

Time-Delay Firer (TDF)

Time-Delay Firer (TDF) Specifications SAP No.


Maximum OD in. (mm)




Temperature Rating °F (°C)



100014157

1 7/16 (36.51) 8 UN-2 B Box × 1.315 (33.4) NU-10 Rd Pin

1.688 (42.88)

2.16 (0.65)

21,500 (1482)

2,200 (150)

425 (218) for 200 hours

56,000 (25 400)

26,300 (1813)

100005231

1.90 (48.26) EUE 10 Rd Pin × 2 (50.8) 6P Acme Box

2.50 (63.5)

1.69 (0.52)

25,000 (1723)

4,000 (275)

425 (218) for 200 hours

120,000 (54 432)

30,000 (2070)

100005230


3.375 (85.73)

1.81 (0.55)

13,000 (895)

4,000 (275)

350 (176) for 500 hours

220,000 (99 700)

30,000 (2070)

Temperature rating is determined by explosives or elastomers. These ratings are guidelines only. For more information, consult your local Halliburton representative.

5-52


Multiaction-Delay Firing Head The multiaction-delay firing head is a pressure-actuated redundant firing system that can be run with any one of several other firing heads. Features • Allows the use of a redundant firing head without having a firing head on the bottom of the gun string • Allows multiple redundancy when a multiaction firing head is placed on both the top and bottom of the gun string • Allows operators to postpone the decision of whether to use the bar drop or pressure side of the firing head as the primary firing mechanism • Allows use of additional delay elements Operation

HAL10511

One side of the multiaction firing head will always be pressure-actuated. The other side of the firing head may be a bar drop-type head or another pressure-actuated firing head. Either side of the firing head may be used as the primary or backup firing system.

Multiaction-Delay Firing Head

Multiaction-Delay Firing Head Specifications SAP No.


Maximum OD in. (mm)






100155753

2 3/8 (60.33) 6P Acme Box × Pin

3.10 (78.74)

3.41 (1.04)

18,000 (1240)

4,000 (275)

170,000 (77 100)

22,000 (1515)

100155750

2 7/8 (73.03) 6P Acme Box × Pin

3.375 (85.73)

3.41 (1.04)

25,000 (1725)

4,000 (275)

201,000 (91 100)

29,000 (2000)



5-53

Annulus Pressure Firer-Control Line The annulus pressure firer-control line (APF-C) was developed as a dual-firing system that allows the perforating guns to be detonated by annular pressure, a drop bar, or tubing pressure. The APF-C system consists of a pressure transfer reservoir, a sleeve through the packer mandrel, an adapter below the packer, and a control line to transmit pressure from the annulus above the packer to the APF-C firing head assembly on top of the guns. Any of the mechanical or pressure-firing heads can be attached to the top of the APF-C firing head. Features • Can be used with non-full-opening test tools and partially filled tubing strings • Can be used for drillstem testing or shoot-and-pull for gravel packs

• Can be run with a mechanical or pressure-actuated firing head as a secondary firing mechanism • Enhances safety because the annulusoperated portion is pressure balanced before the packer is set and the tester valve is opened Operation The APF-C system depends on the transfer of annular pressure through the packer down to the APF-C firing head. This pressure creates a differential pressure across the mandrel where the firing piston is housed. When the predetermined differential pressure is reached, the pins shear and the mandrel moves up and releases the firing piston, which is driven down by rathole pressure. The piston strikes the firing pin which detonates the initiator. The operation of the drop bar or pressure-actuated firing head depends on which firing head system is used.

• Can be used wherever a pressureactuated tool is desirable • Ideal for deviated wells

HAL10515

• Provides a system of two firing heads on top of the guns

Annulus Pressure Firer-Control Line (APF-C) Firing Head

Annulus Pressure Firer-Control Line (APF-C) Specifications SAP No.


Maximum OD in. (mm)






100156138

2 7/8 (73.03) 6P Acme Box × Pin

3.68 (93.47)

3.70 (1.13)

20,000 (1380)

250 (17)

174,000 (78 900)

17,000 (1170)


5-54


Annulus Pressure Transfer Reservoir The annulus pressure transfer reservoir (APTR) is an integral component of the annulus pressure firer-control line (APF-C). The APTR is the mechanism that transmits pressure from above the packer to a differential pressure or pressureactuated firing (PAF) head on top of the perforating assembly. Features • Features a full-opening ID • Compatible with mud environments • Adapted for RTTS™ and CHAMP® IV packers

Annulus Pressure Transfer Reservoir

• Ideal for applications that require a partial fluid column in the tubing string • Eliminates the need for nitrogen Operation

Packer Bottom Connection

Packer Top Connection

Lower Control-Line Housing

HAL15440

HAL15439

The APTR transmits annulus pressure into a microannulus created by the packer mandrel and the APTR mandrel. The pressure is ported to a control-line sub on the lower end of the packer. A stainless steel control line connects the APTR to the pressure-responsive firing head on the perforating assembly.

Annulus Pressure Transfer Reservoir (APTR)

Annulus Pressure Transfer Reservoir (APTR) Specifications SAP No.

Maximum OD in. (mm)

Minimum ID in. (mm)

Top Assembly

Lower Assembly

Length Above Packer ft (m)

Length Below Packer ft (m)


Burst Pressure psi (bar)


100156028

5.00 (127.00)

2.00 (50.8)

3 1/2 4 IF Box x 3 7/8 6 Stub Acme Pin

2 7/8 (73.03) EUE 8 Rd Box x Pin

5.09 (1.55)

1.02 (0.31)

328,000 (148 700)

18,000 (1240)

15,000 (1035)

101016453

6.12 (155.45)

2.37 (60.20)

4 1/2 4 IF Box x Pin

4 1/2 (114.3) 4-IF Box x 3 1/2 (88.90) EUE 8 Rd Pin

4.34 (1.32)

1.33 (0.41)

587,000 (266 200)

22,000 (1515)

19,000 (1310)

Temperature rating is determined by o-rings. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-55

Slimhole Annulus Pressure Firer—Internal Control 5-in. Annulus Pressure Transfer Reservoir The slimhole annulus pressure transfer reservoir (APTR) system assembles in a similar manner to the 7-in. and 9 5/8-in. APTR systems. Only two design changes have been implemented in the new 5-in. APTR system. First, a series of concentric tubes below the packer replaces the control line from larger APTR systems. Second, a single tube mandrel runs through the packer, replacing the series of threaded tube mandrels from the larger APTR systems.

Ball Valve

Annular Pressure Transfer Sub Safety Joint

3 1/8-in. Internal Control

Retrievable Packer

Concentric tubes eliminate the need for an external control line in slimhole casing. 3 1/8-in. Annulus Pressure Transfer Reservoir— Internal Control The slimhole 3 1/8-in. (APF-IC) firing head is designed for use with the 5-in. APTR system with internal control. The firing head design remains the same as the 3 3/8-in. APF-C with diameter reductions in many of the component parts to achieve a true 3.13-in. OD.

Flow Ports

Firing Head

®

HAL15403

VannGun Assembly

Slimhole Annulus Pressure Firer— Internal Control (APF-IC) Installation

Slimhole Annulus Pressure Firer—Internal Control (APF-IC) Specifications SAP No.

Thread Size and Type

Max OD in. (mm)

Min ID in. (mm)

No. of Ports







101301541

2 3/4-in. 6P Acme Box × Pin

3.13 (79.5)

1.25 (31.75)

2

56.41 (17.2)

20,000 (1378)

250 (17)

87,000 (39 463)

N/A

10,000 (689)

Temperature Rating 325°F (20K psi) with Extreme Environment Kit (162°C 1.406 kg/cm2 with Extreme Environment Kit) Call Technology for temperatures above 325°F (162°C).

5-56


Differential Firing Head The differential firing head (DFH) was designed to allow underbalanced perforating with a differential pressureactuated firing system. The DFH works by requiring the internal pressure to be greater than the external pressure. This condition can be created when pressure is applied to the ID or when the OD pressure is reduced. The pressure required to actuate the DFH may be lower than that used for other pressure-operated firing heads because it is operated by differential pressure. Features • Allows underbalanced perforating in horizontal wells without a packer • Ideal for perforating with a sucker rod or submersible pump in place • Offers added safety because it is pressure-balanced when being run into the well

• Can be used when equipment or well conditions will not permit the use of high pressures • Allows the use of time-delay elements as needed Operation The DFH is actuated after a predetermined differential pressure is created in the firing head ID. This differential pressure can be created when surface pressure is applied to the tubing or by reducing the hydrostatic pressure in the annulus. When the predetermined differential pressure is reached, the shear pins holding the dog retainer piston will shear, allowing the dog retainer to move up. The upward movement releases the dogs holding the firing piston in place, and the internal pressure drives the firing piston into the initiator.

HAL10518

• Helps allow maximum underbalanced pressure in lowpressure wells when mechanical firing is not desirable

Differential Firing Head (DFH)

Differential Firing Head (DFH) Specifications SAP No.


Maximum OD in. (mm)


Maximum Operating Pressure (Differential) psi (bar)

Minimum Operating Pressure (Differential) psi (bar)




120002262


3.0 (76.20)

1.94 (0.59)

10,000 (690)

1,000 (69)

130,000 (58 900)

20,000 (1380)

20,000 (1380)

100014232


3.38 (85.73)

1.98 (0.60)

5,000 (345)

1,000 (69)

220,000 (99 700)

20,000 (1380)

20,000 (1380)

Temperature rating is determined by explosives or o-rings. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-57

Hydraulic Actuator Firing Head and Swivel-Type Hydraulic Actuator Firing Head

Features • Allows packerless completions

• Reusable • Rotation of explosive assembly from tubing string possible with swivel type Operation A stainless steel or ceramic ball is dropped from the surface or is circulated downhole into the hammer piston. Pressure applied to the tubing string shears the retaining pins and forces the hammer piston into the firing pin. The firing pin detonates the initiator, which starts the detonation of the perforating assembly. Circulation is regained as soon as the firing pin has been sheared.

• Makes actuation easily observable

Hydraulic Actuator Firing Head (HAF)

HAL10563

The smaller swivel-type hydraulic actuator firing head (SHAF) has a swivel incorporated into the firing head assembly. The added swivel feature allows the lower portion of the firing head and the attached explosive assembly to rotate independently from the tubing string.

• Useful in coiled tubing conveyed completions, deviated wells, and through-tubing perforating

HAL15384

The hydraulic actuator firing head (HAF) is a pressure-balanced tool that automatically fills the tubing string while it is running in the well. A stainless steel or ceramic ball is dropped from the surface or circulated into position. Pressure applied to the tubing string actuates the HAF.

Swivel-Type Hydraulic Actuator Firing Head (SHAF)

Hydraulic Actuator Firing Head (HAF) Specifications SAP No.


Maximum OD in. (mm)

Ball OD in. (mm)

No. and ID Flow Area of Ports of Ports in. (mm) in.2 (cm2)


1.315 (33.40) NU-10 Rd Pin × 1.69 0.625 2 @ 0.5 0.39 2.84 17/16 (36.51) (42.88) (15.875) (12.70) (2.52) (0.87) 8UN-2B Box 1.315 (33.40) NU-10 Rd Pin × 1.69 0.625 2 @ 0.5 0.39 2.18 100156025 17/16 (36.51) (42.88) (15.875) (12.70) (2.52) (0.66) 8UN-2B Box 1.90 (48.26) EUE-10 Rd 3/4 TPF Pin 2.75 0.625 2 @ 0.5 0.39 2.28 101007031 2 3/8 (60.33) 6P Acme (69.85) (15.875) (12.70) (2.52) (0.691) Box 2 3/8 (60.33) EUE 3.38 1.375 4 @ 1.0 3.14 2.40 8 Rd Pin × 100156150 (85.85) (34.925) (25.40) (20.26) (0.73) 2 7/8 (73.03) 6P Acme Box 2 7/8 (73.03) EUE 8 Rd 3.38 1.375 4 @ 1.0 3.14 2.40 101313489 Pin × 2 7/8 (73.03) 6P (85.85) (34.925) (25.40) (20.26) (0.73) Acme Box Temperature rating is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative. 100156011 (Swivel Type)

5-58

Maximum Operating Pressure (differential) psi (bar)

Actuating Pressure psi (bar)

Tensile Rating lb (kg)

20,000 (1379)

3,200 (221)

50,000 (22 680)

20,000 (1379)

3,200 (221)

50,000 (22 680)

20,000 (1379)

3,200 (221)

113,000 (51 256)

20,000 (1379)

2,000 (138)

135,600 (61 507)

20,000 (1379)

2,000 (138)

216,000 (97 976)


Mechanical Metering Hydraulic-Delay Firing Head The mechanical metering hydraulic-delay (MMHD) firing head provides a retrievable firing system with an adjustable delay for situations where longer delay times are needed. Delay time can be adjusted from 1 to 6 hours. The tool is designed with a 1/2 gallon fluid chamber below a weighted piston. The piston meters downward until it travels into a larger bore which allows it to free-fall and initiate a mechanical firing head. Delay time is affected by temperature, tool weight above the piston, and the number of jets used (maximum of two), and the adjustments can be made by running one or two fluid metering jets or by changing the amount of fluid. Features • Adjustable time-delay—May vary from 1 up to 6 hours • Retrievability—Firing head can be pulled and another one run without affecting the rest of the bottomhole assembly • Safety—With the ability to run the firing head and the guns separately, this system greatly reduces the chance of accidental or premature firing of guns Operation

HAL6559

The MMHD assembly is run into the well using normal monobore completion techniques. The mechanical metering hydraulic-delay firing head is conveyed on a slickline or electric line. For safety and flexibility, the tool will not start metering until it is landed on the top gun. Once in place and released, the firing head starts to meter. The running tools can either be pulled into the lubricator, pulled completely out of the hole, or simply pulled up the hole to a safe distance and secured to await detonation. After the guns have fired, the firing head can be quickly relatched and retrieved using the same conveyance methods as during deployment.

Mechanical Metering HydraulicDelay (MMHD) Firing Head

Mechanical Metering Hydraulic-Delay (MMHD) Firing Head Assembly Specifications SAP No.

Maximum OD in. (cm)

Stinger Fishing Neck in. (cm)

Maximum Stroke Length in. (cm)

Maximum Metering Stroke* Length (Available for Delay) in. (cm)

Overall Length* (Extended) ft (m)

Maximum Operating Pressure (Differential) psi (bar)

Temp Rating °F (°C)


Total Volume (Silicon) gal (liter)

Assembly Weight lb (kg)

101201927

Dependent on centralizers

1.75 (4.45)

54.86 (139.34)

46.50 (118.11)

12.44 (3.79)

13,000 (896.6)

350 (176.67)

51,100 (23 100)

1/2 (1.89)

152 (68.95)

*Length from top sub to firing head body (does not include weight bars and/or skirt) Delay time of 1 hour minimum is recommended for safe operation of system. Delay time of 6 maximum hours is dependent on temperature, silicon fluid, and number of jets. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-59

Slickline-Retrievable Mechanical Firing Head The slickline-retrievable mechanical firing head (SLRMFH) is designed to give customers flexibility in completing a well. It can be run attached to the guns, separately from the guns, or using an auto-release firing mechanism. The firing head latches onto the guns and provides a positive indication that it is attached. The SLRMFH can be retrieved if the firing head needs to be replaced. The system can be run with either a mechanically operated firing head or a pressure-operated firing head. It is designed so that 80% of the parts are used in all three applications allowing for more flexibility with less inventory. Features • Saves rig time—If for any reason the firing head needs replacement, the guns remain in the hole and the firing head can be retrieved • Positive engagement—When the firing head is run separately, the operator can tell when the firing head is latched onto the guns • Safety—Guns can be run separately from the firing head adding a safety feature for the guns at the surface

The SLRMFH was designed for 3 1/2and 2 7/8-in. tubing strings. It can be run with either a mechanical drop firing head, or a pressure-operated firing head such as the 1 11/16 timedelay firer (TDF). The top gun is assembled with the J-slot stinger. The guns are run into the well on tubing and then correlated on depth. The running tool is latched to the firing head at surface and run in on wireline/slickline. As the firing head is lowered, it comes in contact with the J-slot stinger. The skirt on the firing head then automatically latches into position connecting the firing head with the J-slot stinger. An overpull is applied to give a positive latch indication. The running tool is released by jarring down and the slickline is pulled out of the well. The guns are fired by pressure or mechanical means. The firing head can be retrieved by relatching to the firing head and jarring up. The jarring action shears the brass screws freeing the firing head from the J-slot stinger. If the firing head does not actuate, another firing head may be run as many times as required.

HAL6560

• Flexibility—Guns can be run separately or attached. Unlimited number of runs can be made to replace firing head if needed

Operation

Slickline-Retrievable Mechanical Firing Head (SLRMFH)

5-60


Slickline-Retrievable Mechanical Firing Head (SLRMFH) Specifications

SAP No.

Minimum Overall Maximum ID Length OD (No-Go) (Max) in. (cm) in. (cm) ft (m)



Minimum Operating Pressure Auto Release psi (bar)

Maximum Differential Pressure Auto Release psi (bar)

Tensile Strength of FH Body lb (kg)

Maximum Sustained Force Required to Shear Two Lugs lb (kg)

Weight lb (kg)

w/ Model III-D Mechanical FH

101226902

2.31 (5.87)

1.56 (3.96)

20.05 (6.11)

8,000 (550)

250 (17.2)

N/A

N/A

30,000 (13 600)

4,000 (1800)

120 (54.4)

w/ Pressure Actuated FH

101227170

2.31 (5.87)

1.56 (3.96)

20.05 (6.11)

17,000 (1170)

2,200 (150)

N/A

N/A

30,000 (13 600)

4,000 (1800)

100 (45.4)

w/ Model III-D Mechanical FH and Auto Release

101227212

2.31 (5.87)

1.56 (3.96)

20.05 (6.11)

8,000 (550)

250 (17.2)

1,500 (100)

10,000 (690)

30,000 (13 600)

4,000 (1800)

120 (54.4)

Burst and collapse pressures are determined by tubing. Temperature rating is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-61

Slickline-Retrievable Time-Delay Firer Firing Head The slickline-retrievable time-delay firer (TDF) firing head is a combination of two assemblies: the slickline-retrievable firing head and a 1 11/16-in. TDF firing head. It is a pressure-actuated firing head with a built-in pyrotechnic time-delay assembly. Features • Allows the guns to be run in the hole without any type of firing mechanism installed • Allows the retrieval and reinstallation of a malfunctioning firing head without pulling the guns • Allows greatly reduced actuating pressures of the firing head because the firing head does not have to be in place when the guns are run Operation This firing head does not have to be run until after all pressure testing has been done and the heavy fluids have been displaced, which allows a reduced actuating pressure for the firing head.

HAL15434

HAL15385

This assembly allows the operator to run guns in the hole on the end of tubing without a firing head. This assembly can be run in on slickline and attached to the firing head after the tubing is in the hole. It can also be retrieved on slickline.

Slickline Retrievable Time-Delay Firer (TDF) Firing Head

Stinger Assembly

1 11/16-in. Slickline-Retrievable Time-Delay Firer (TDF) Firing Head Specifications SAP No.

Maximum OD in. (mm)

Overall Length (1 fuse) ft (m)

Additional Length per Fuse ft (m)





100155739

1.688 (42.88)

3.83 (1.17)

0.87 (0.27)

425 for 200 hours (218 for 200 hours)

17,000 (1170)

2,200 (150)

23,000 (1590)

The assembly certification sheet which specifies the batch number and pin values is supplied with each assembly.

3 3/8-in. Vann™ Jet Stinger Specifications SAP No.


Maximum OD in. (mm)


Makeup Length with 2-ft Sub ft (m)




Weight with 2-ft Sub lb (kg)

100155952


3.38 (85.85)

1.37 (34.80)

5.37 (1.64)

20,000 (1380)

None

238,000 (107 900)

73 (33)

Burst and collapse pressures are determined by handling sub. Temperature rating is determined by explosives.

5-62


Extended Delay Fuses A delay fuse is an explosive device with a slow-burning fuse. Extended and modular delay fuses add time between the actuation of the firing head and the actual detonation of the guns. Each delay fuse lasts six minutes at 70°F. Features • Increases delay time when nitrogen is used to actuate the firing head to give additional time to bleed the nitrogen pressure down to the desired level • Allows time for necessary actions to take place downhole such as increasing pressure to open a pressure-actuated vent assembly Operation The extended delay assemblies contain one delay fuse and can be run with any other firing assembly. They are installed between the firing head and the guns.

HAL15383

The modular delays are assembled with the firing head in one housing and become an integral part of the firing system. The modular delays are used primarily with the multiactiondelay firing head, the 1 11/16-in. time-delay firer (TDF) firing head, and the slickline-retrievable TDF firing head.

Extended Delay Fuses Assembly

Extended Delay Fuses Specifications SAP No.


Maximum OD in. (mm)



Temperature Rating Delay Fuse °F (°C)



100005229

2 (50.8) 6P Acme Box × Pin

2.5 (62.5)

1.10 (0.34)

25,000 (1725)

425 (218) for 200 hours

197,000 (89 300)

30,000 (2070)

100009426

2 7/8 (73.03) 6P Acme Box × Pin

3.375 (85.73)

1.10 (0.34)

25,000 (1725)

425 (218) for 200 hours

270,000 (122 400)

30,000 (2070)

These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-63

Modular Mechanical Firing Head The modular mechanical firing head is designed to be a retrievable firing system utilizing a standard mechanical firing head with a specialized drop bar for detonation. This system will allow the operator the flexibility to run the gun assemblies independently of the firing system. Once the guns are in place, the firing head is set on the top module and released. The perforation assembly is detonated by use of a special fluted bar dropped from surface. The most common application for this system is to be run with the modular guns in a monobore completion. Special consideration must be given to job set-up and execution to ensure that this tool functions properly. Features • Safety—With the ability to run the firing head and the guns separately, this system helps to greatly reduce the chance of accidental or premature firing of the guns • Retrievability—In the event of a mechanical malfunction, the firing head can be pulled, and another one run without interfering with the rest of the bottomhole assembly Applications

The firing pin and hammer are pressure balanced; and therefore, are not limited to any specific depth and/or hydrostatic pressure beyond the tool specifications.

HAL8325

The modular mechanical firing head is designed to be run on slickline and set on the top gun in a monobore completion by use of a JDC hydraulic running tool. The system is designed with the hammer held above the firing pin with brass shear screws. The two shear screws are rated at 875 lb each. The tool is actuated by dropping a specifically designed drop bar fitted for the proper casing. (Do not use a standard 1 1/4-in. drop bar.) The bar strikes the stinger with sufficient force to shear the brass screws and drive it into the firing pin.

Modular Mechanical Firing Head

5-64


Modular Mechanical Firing Head Specifications SAP No.

Stinger Fishing Neck 2-in. Stinger in. (mm)

Stinger Fishing Neck 2 1/2-in. Stinger in. (mm)



Overall Length* in. (mm)

Maximum Stroke Length in. (mm)

Shear Rating For Brass lb (kg)

120021629

1.38 (35.05)

1.75 (44.45)

13,000 (896.6)

59,000 (26 762)

72.30 (1836.42)

7.88 (200.15)

1,700 (771)

*Will vary with skirt Maximum OD dependent on centralizers used. Temperature rating is determined by explosives. Weight dependent on centralizers and skirts.

Drop Bar Options

Skirt-Centralizer Selection Chart

SAP No.

Casing and Tubing Size and Weight in./lb (cm/kg)

Casing ID in. (mm)

Total Bar OD in. (mm)

N/A

2 7/8 / 6.4 (7.30 / 2.9)

2.441 (62.0)

N/A

101227709

3 1/2 / 9.2 (8.89 / 4.17)

2.992 (76.0)

2.50 (63.5)

120125486

4 1/2 / 9.5-13.5 (11.43 / 4.3-6.12)

4.090 (103.9)

3.75 (95.3)

101227719

5 / 15-18 (12.7 / 6.80-8.16)

4.408 (111.9)

4.125 (104.8)

101227720

5 1/2 / 15.5-23 (13.97 / 7.03-10.43)

4.950 (125.7)

4.50 (114.3)

SAP No.

Skirt OD in. (mm)

101207195

2 (50.8)

Centralizer OD in. (mm) N/A 3.00 (76.2) 101207187

101201882

2.5 (63.5)

3.50 (88.9) 101207198 3.75 (95.3) 100014297

101228625

2 3/4 (69.9)

101201884

3 1/8 (79.4)

3.25 (82.6) 101213087 3.50 (88.9) 100014299 3.875 (98.4) 101207193 3.75 (95.3) 100009581

101226987

3 3/8 (85.7)

4.00 (10.16) 100156785 4.40 (111.8) 100010177

101205671


4 5/8 (117.4)

5.61 (142.5) 100156224 5.75 (146.1) 100156225

5-65

Side-Pocket Mandrel Firing Head The side-pocket mandrel firing head (SPMFH) is designed for well conditions that preclude the use of a pressureactuated firing head run with a Y-block. The side-pocket mandrel firing system is used on single-string, multizone completions and standard dual completions. A modified model III-D mechanical firing head is attached to the short string side of a side-pocket mandrel. The firing head is detonated with a kickover tool run on slickline. Features • Selectively fires multiple intervals • Eliminates the need for nitrogen • Allows maximum underbalance for low-pressure formations • Offers economical value Operation

HAL15453

The model III-D mechanical firing head is made up on the short string side of the side-pocket mandrel. When the perforating assembly is ready to be detonated, the operator runs a kickover tool down the long string on slickline. After the kickover tool is located in the side-pocket mandrel, the slickline operator jars down. The kickover tool hits the releasing pin on the model III-D. The firing piston is forced into the initiator by the hydrostatic pressure in the tubing string to detonate the VannGun® assembly.

Side-Pocket Mandrel Firing Head (SPMFH)

Side-Pocket Mandrel Firing Head (SPMFH) Specifications SAP No.

Thread Size and Type (Long String Side) in. (mm)

Maximum OD in. (mm)

Minimum ID in. (mm)

Overall Length ft (m)

100155737 (Firing Head)


2.75 (69.85)

N/A

2.36 (0.72)

221.00284 (7-in. Side-Pocket Mandrel)

2 3/8 (60.33) 4.7 lb OECO-B Box × Box

5.54 (140.72)

1.926 (48.92)

5.79 (1.76)

221.00285 (9.625-in. Side-Pocket Mandrel)

2 3/8 (60.33) 4.7 lb OECO-B Box × Box

6.62 (168.15)

1.926 (48.92)

5.79 (1.76)

101306060

3 1/2 CJ Hydril

8.00 (203.20)

N/A

N/A


5-66


Annulus Pressure Crossover Assembly The annulus pressure crossover assembly (APCA) allows the use of annulus pressure to actuate any one of several firing heads. This assembly is compatible with retrievable packers of all types and sizes. Features • May be used as the annulus firing system on wells with non-full-opening test tools and a partially filled drillstring Annulus Pressure Crossover Assembly

• May be used as the annulus firing system on horizontal wells • Allows the use of below-packer venting devices along with this assembly

Packer

Note: Not recommended for mud environment Operation The APCA creates a pressure chamber above the firing head that is equalized with the pressure in the casing annulus. Once the packer has been set, the pressure on the annulus can be increased to actuate a pressure-actuated firing head. The pressures in the annulus and the tubing can also be manipulated to create the differential pressure necessary to actuate a differential-type firing head.

Ported Sealing Sub

HAL15449

Tubing

Time-Delay Firer

HAL15448

VannGun® Assembly Annulus Pressure Crossover Assembly (APCA)

Annulus Pressure Crossover Assembly (APCA) Specifications SAP No.


Maximum OD in. (mm)

Minimum ID

Flow Area in.² (cm²)

Minimum Makeup Length ft (m)






100014175

2 3/8 (60.33) EUE 8 Rd

3.56 (90.42)

Non-fullbore

2.25 (14.52)

9.15 (2.79)

12.35 (3.76)

10,000 (689)

104,000 (47 173)

11,200 (772)

11,700 (806)

100155786

2 7/8 (73.03) EUE 8 Rd

5.0 (127)

Non-fullbore

4.75 (30.65)

9.40 (2.87)

12.60 (3.84)

9,500 (655)

145,000 (65 770)

10,500 (723)

11,100 (765)

101241465

3 1/2 (88.9) API IF Tool Joint

5.015 (127.381)

Non-fullbore

4.75 (30.65)

9.40 (2.87)

12.60 (3.84)

10,500 (723)

145,000 (65 770)

13,210 (910)

22,500 (1551)

Maximum operating pressure is determined by tubulars. Temperature rating is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-67

EZ Cycle™ Multi-Pressure Cycle Firing Head The EZ Cycle™ firing head is a pressure-operated tool that can be cycled several times prior to firing the perforating guns. Several pressure operations can also be performed on the well including tubing testing, packer setting, and packer testing prior to firing the perforating guns. Even if pressure operations are higher than the operating pressure of the firing head, the EZ Cycle firing head should not fire until it has completed all of the preset cycles. The firing head is cycled by applying pressure at the tool to overcome a nitrogen-charged chamber which operates the cycling piston back and forth until the entire release rod has been pulled from the piston collet. Each EZ Cycle firing head assembly includes a nitrogen chamber, cycling grapple piston, and firing piston with firing pin initiator assembly. Features • Ideal for completions and drillstem testing • Time-delay elements can be used as needed for delay time • Can be used in underbalanced or overbalanced perforating jobs • It is a surface-safe firing head because it requires pressure to energize the firing piston • Operates at low pressure • Can be deployed connected to the gun assembly or run separate on slickline or coiled tubing • Allows the retrieval and reinstallation of a malfunctioning firing head without pulling the guns

HAL14095

• Can be used when equipment or well conditions will not permit the use of high pressures

EZ Cycle™ Firing Head Assembly

5-68


Operating the EZ Cycle™ Firing Head The tool is run in hole with a pre-charged nitrogen chamber, which is set according to the maximum bottomhole pressure. After positioning gun on depth and all operations prior to firing guns have been completed, the firing head is cycled to detonate the perforating guns. Pressure applied at the tool will move the cycle piston and traveling grapple up 0.375 in. pulling the release rod up 0.375 in. Releasing the applied pressure will allow the nitrogen charge to move the cycle

piston and traveling grapple down engaging another 0.375 in. of the release rod. These steps are continued until the release rod is completely retrieved from the firing piston collet. At this point, the bottomhole pressure will drive the firing piston into the firing pin detonating the initiator and the guns.

3.00 in. Multi-Pressure Cycle Firing Head Assembly Specifications Upper Connection (External Fishneck) in. (cm)

2.313 (5.875)

Lower Thread Size and Type in. (cm)

2 3/8 (6.0325) 6P Acme Box

Makeup Length in. (cm)

77.32 (196.393)

Maximum OD in. (cm)

3.00 (7.62)

Minimum ID in. (cm)


N/A

400 (204.4)

Operating Pressure Range psi (bar)

Low Pressure Assembly

High Pressure Assembly

1,000-5,000 (68.95344.74)

5.00020,000 (344.741378.95)

Tensile Rating* lb (kg)

Burst Pressure* psi (bar)

Collapse Rating* psi (bar)

100,000 (18 143)

40,000 (1379)

40,000 (1379)

*Call your local Halliburton representative if conditions exceed this value.


5-69

Pump-Through Firing Head The 1 11/16-in. pump-through firing head is designed to be run on coiled tubing and is used for breaking the ceramic flapper valve disk on a one-trip coiled tubing operation. The firing head originates from proven technology in the 1 11/16-in. pressure actuated pressure firing head. The components were hardened to withstand pumping erosion, and an outer tube is incorporated to allow fluid circulation to the bottom of the tool. A miniature shaped charge is set in the bottom of the firing head to shoot into the ceramic disk. The assembly is actuated by dropping a ball through the coiled tubing, which seats in the assembly to allow a pressure differential to actuate the firing head and shape charge. Application

HAL15777

The pump-through firing head can be used to circulate debris off of a barrier, such as a ceramic disk, and then shoot into the barrier to break it up. This function is primarily developed toward circulating sand and other debris off of a ceramic disk in a production well, and then shooting into the disk to allow access below.

Firing Head Assembly 1 11/16-in. Pump Through

Pump-Through Firing Head Specifications Thread Size and Maximum OD Minimum ID* Type in. (mm) in. (mm) in. (mm) 1.315 (33.40) NU-10RD Pin

2.3 (58.42)

0. 44 (11.18)


Flow Area (before firing) in.2 (mm2)

Temperature Rating

Axial Load Rating lb (kg)


Overall Length in. (mm)

Mass lb (kg)

Maximum Flow Rate bbl/min (m3/min)

3,000 (207) ± 10% at 70°F

0.15 (96.77)

As per explosives

54,400 (24 700)

23,200 (1600)

22.69 (576.32)

16.9 (7.68)

2.5 (0.397)

*Through ball seat Minimum Operating Pressure is not applicable. Burst Pressure is not applicable.

5-70


Ancillary Equipment Fill Disk Assembly The fill disk assembly (FDA) is used where either packer selection or well conditions preclude the use of a venting device. The FDA is used in place of a perforated sub and replaces the balanced isolation tool (BIT) in wells with reasonably clean fluids. The glass disk prevents debris from settling on the firing head. Pressure is equalized across the glass disk. The FDA is run between the firing head and packer. The recommended minimum distance from the FDA to the firing head is 30 ft (9.14 m). Features • Allows debris to be circulated off the glass disk through the flow ports above the glass disk

Operation The FDA consists of a ported housing with a glass disk installed in the ID across the lower set of ports. The disk is not sealed, so pressure can equalize across the glass. Any debris falling out of the tubing or fluid above the glass should land on the glass disk. This debris can be circulated off the disk, or if it is not a large amount, it will be displaced out the ports by the detonating bar falling through it. Once the bar breaks through the disk, it should fall in clean fluid all the way to the firing head. In mud systems or wells with a known debris problem, the balanced isolation tool is recommended in place of the FDA.

• Acts as a perforated sub for circulating fluid displacement with nitrogen and swabbing HAL8352

• Can be run with either a mechanical or pressure-actuated firing head

Fill Disk Assembly (FDA)

Fill Disk Assembly (FDA) Specifications SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)

Flow Area in.² (cm²)

Number of Ports



100005295

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.01 (76.45)

1.98 (50.29)

6.28 (40.54)

8

120,000 (54 431)

0.76 (0.23)

100005297

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.51 (89.15)

2.44 (61.98)

7.88 (50.8)

8

150,000 (68 039)

0.71 (0.22)

100005299

3 1/2 (88.90) EUE 8 Rd Box × Pin

4.20 (106.68)

3.0 (76.20)

14.13 (91.20)

8

200,000 (90 718)

0.69 (0.21)


5-71

Balanced Isolation Tool The balanced isolation tool (BIT) assembly is used where either packer selection or well conditions preclude the use of a venting device. The BIT assembly replaces the fill disk assembly and is used in place of a perforated sub. The BIT helps prevent contamination of the fluid below it from the fluid above it. Debris or solids in the fluid above should not pass through the glass disk that is in the floating piston. The glass disk helps prevent debris from setting on the firing head. Pressure is balanced across the glass barrier through equalizing ports in the piston. The BIT assembly is run between the firing head and packer. The recommended minimum distance from the BIT to the firing head is 30 ft (9.14 m). Features • Allows mud and debris to be circulated off the glass barrier through the flow ports above the glass barrier

Operation The basic components of the BIT are a floating piston with a glass disk, a ported lower housing, and a top housing. The BIT is run with clean fluid below it. The upward travel of the floating piston is limited by the bottom of the top sub. A pressure increase above the glass barrier causes the piston to move down and forces fluid below the glass barrier out of the bleeder ports. A pressure increase below the glass barrier forces the piston to move up or forces fluid out of the bleeder ports. The piston moves up or down within its limits to help prevent the glass barrier from breaking. The glass barrier remains intact until the bar passes through it. As fluid enters or leaves the tubing through the ports, debris on the glass barrier is washed off.

• Allows displacement of the tubing with a lighter fluid or nitrogen before firing the guns • Allows swabbing of the tubing to achieve differential pressure • Allows stopping and circulating at any depth since flow ports are always open

HAL15460

• Can be run with either a mechanical or pressure-actuated firing head

Balanced Isolation Tool (BIT)

5-72


Balanced Isolation Tool (BIT) Specifications SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)

No. of Ports

Total Flow Area in.2 (cm2)



120022203

1.90 (48.26) EUE 10 Rd Box × Pin

2.50 (63.50)

1.61 (40.89)

4

2.03 (13.10)

2.09 (0.64)

110,000 (49 800)

101318220

2 3/8 (60.33) EUE 8 Rd Box × Pin

2.895 (73.4)

1.99 (50.54)

4

3.09 (19.96)

2.02 (0.62)

100,000 (45 300)

100014322

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.10 (78.74)

1.99 (50.54)

4

3.14 (20.27)

2.15 (0.65)

155,000 (70 200)

100014323

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.75 (95.25)

2.44 (61.98)

4

4.68 (30.19)

2.41 (0.73)

200,000 (90 700)

100156936

3 1/2 (88.90) EUE 8 Rd Box × Pin

4.25 (107.95)

3.0 (76.20)

4

7.07 (45.60)

2.41 (0.73)

280,000 (126 000)



5-73

Ratchet Gun Connector In addition to perforating new wells, Halliburton’s ratchet gun connector system is ideal for reperforating producing wells since the well does not have to be killed and can be left on production. It also allows perforating with all production equipment in place. Connections are made inside the lubricator using a left-hand quick connect locking mechanism. Features • Can be snubbed into and retrieved from a live well • Utilizes standard blowout preventers • Can perforate long and multiple intervals in a single trip • Does not have to kill producing zone to run or retrieve guns • Perforates new wells • Reperforates producing wells with all production equipment in place • Perforates underbalanced or overbalanced assemblies • VannGun® sections are quickly connected together

HAL22573

HAL22574

• Can be used with hydraulic workover (HWO)

Ratchet Gun Connector Assembly Using Sealed Imitation Assembly

Ratchet Gun Connector Assembly Using NonSealed Insert Assembly

Ratchet Gun Connector Specifications SAP No.


Maximum OD in. (mm)




101000794

2 3/8 (60.33) 6P Acme Box × Pin

2.35 (59.69)

2.11 (0.64)

13,000 (896)

100,000 (45 360)

101000793

2 7/8 (73.03) 6P Acme Box × Pin

3.375 (85.73)

2.11 (0.64)

13,000 (896)

220,000 (100 000)

Temperature rating is determined by explosive. These ratings are guidelines only. For more information, consult your local Halliburton representative.

5-74


AutoLatch™ Release Gun Connector The AutoLatch™ release gun connector is designed to join VannGun® assemblies and enables VannGun sections to be run in and out of new or producing wells.

Features

Using the AutoLatch system, VannGun assemblies are connected without rotation and can be operated with standard blowout preventer (BOP) rams, making this connector ideal for snubbing guns into and out of the wellbore with coiled tubing or a hydraulic workover (HWO) unit.

• Utilizes standard BOPs

The AutoLatch connector can also be used to run VannGun assemblies on wireline when the length of the perforating assembly is limited by the lubricator length. The VannGun assemblies can be run in sections (limited by the weight rating of the wireline) and then, retrieved in sections. This system reduces the number of wireline runs to perforate longer intervals.

• Can be used to perforate new or existing wells • Can snub VannGun assemblies into and out of the well • Can be used with coiled tubing, HWO, or wireline

Stop/Release Pads

• Can retrieve VannGun assemblies without killing a producing zone • Can perforate in underbalanced or overbalanced conditions • May be used for monobore completions

Spring Housing

• Can be used when oriented perforations are required

Operating Spring Shear Screws

• Sections are quickly connected for time savings • Can be designed to accommodate different BOP configuration

Stinger Assembly Collet Fingers Collet Retainer Housing

AutoLatch™ Release Gun Connector Specifications

Upper Assembly: 101205866 Lower Assembly: 101205878 Upper Assembly: 100155775 Lower Assembly: 101207115


Maximum OD in. (mm)




2 3/8 (60.33) 6P Acme Box × Pin

2.88 (73.15)

4.46 (1.36)

20,000 (1380)

80,000 (35 000)

2 7/8 (73.03) 6P Acme Box × Pin

3.625 (92.00)

3.47 (1.06)

20,000 (1380)

125,000 (56 800)



OD Seal Area

HAL8662

SAP No.

Pressure Isolation Configuration

AutoLatch™ Release Gun Connector

5-75

Isolation Sub-Assembly Gun

The isolation sub-assembly (ISA) is live well intervention technology designed to provide extreme flexibility in well completions. The ISA allows completion or recompletion of the well without killing it. The well can be producing before, during, and after the guns are deployed in or out of the well. The ISA is a lower cost alternative to other live well intervention assemblies. The ISA incorporates a threaded connection that is manually connected and disconnected.

Features • Can run VannGun® assemblies on hydraulic workovers, coiled tubing, or wireline • Can run VannGun sections to perforate a new well or add perforations to existing zones • Can run or retrieve guns without killing the well

Isolation Sub-Assembly

• Can perforate underbalanced or overbalanced

Sealing Initiator

• Low cost • Provides extreme flexibility in well completions

Sealing Area

Isolation Sub-Assembly Specifications OD Isolation Sub-Assembly with OD Ram Lock in. (mm)

Maximum OD in. (mm)




101228396

1 11/16-in. (42.86) 8P Stub Acme 2G

2 with 1 1/2 (50.8 with 38.1)

2.015 (51.18)

2.42 (0.74)

10,000 (689)

64,500 (29 250)

101222274

2 3/8 (60.33) 6P Acme 2G

2 3/4 with 2 (69.85 with 50.8)

2.765 (70.23)

2.28 (0.69)

10,000 (689)

108,000 (49 000)

101226330

2 7/8 (73.03) 6P Acme 2G

3 3/8 with 2 (85.73 with 50.8)

3.395 (86.23)

2.22 (0.68)

10,000 (689)

191,400 (86 800)

Temperature rating is determined by explosive. These ratings are guidelines only. For more information, consult your local Halliburton representative.

Sealing Initiator

Gun HAL6151

SAP No.


Isolation Sub-Assembly

5-76


Quick Torque™ Connector The Quick Torque™ connector consists of connectors that cover both ends of each gun section to enclose the assembly. The connectors have a common, self-aligning drillpipe thread that allows automatic or manual makeup. Explosive transfer occurs through a web, making the system self-contained for added safety. With these connectors, TCP gun assemblies can now be picked up by the rig equipment and properly made up using iron roughneck equipment without the need for human intervention. It simplifies the process and saves time by eliminating assembly of the components on the rig. Features • Standard NC38 thread makeup procedure • Redressable • Self-contained system increases personnel safety on the rig floor—no human intervention is needed • Once the thread protectors are removed, all subsequent steps can be automated • Efficient, automated system saves rig time • Allows venting of any built-up pressure during shipping • No exposed explosives • Q125 material, sour service > 175° F Operation

Firing Head Sub-Assembly


HAL14399

HAL14398

This system can be used on any rig with automatic or manual pipe handling equipment. It can be used with 4 5/8-in. standard or 4 5/8-in. self-orienting TCP gun systems, and a 3 3/8-in.-OD or smaller firing head.

Gun Sub-Assembly

5-77

Quick Torque™ Connector - 2 7/8-in. Guns SAP No.

Thread Connection

Tool Maximum OD in. (mm)

Maximum Operating Pressure* psi (bar)

Temperature Rating* °F (°C)

Makeup Length in. (mm)

End Connections


101635158

Box Modified API-NC26

3.14 (79.95)

22,000 (1516)

Determined by explosives and elastomers

12.5 (317)

2 7/8-in. Gun Pin

280,500 (127 232)

101634159

Pin Modified API-NC26

3.14 (79.95)

22,000 (1516)


9.3 (236)

2 7/8-in. Gun Pin

247,000 (112 354)

*Maximum Operating Pressure and Temperature Rating based on the elastomers.

Quick Torque™ Connector - 4 5/8-in. Guns SAP No.

Thread Connection

Tool Max. OD in. (mm)




End Connections


101351984

Pin Connector Assy, NC38 Pin x Acme Pin

4.75 (120.65)

20,000 (1379)


6.75 (171)

4-6 Acme Pin x Modified NC38 Pin

493,500 (223,848) Limited by 4-6 Acme Pin Thd

101352042

Firing Head Connector Assy, NC38 Pin x Double Acme Pin

4.75 (120.65)

20,000 (1379)


7.61 (193)

2 7/8-6 Acme and Pin x 4-6 Acme Pin x Modified NC38 Pin


101351885

Box Connector Assy, NC38 Box x Acme Pin

4.75 (120.65)

20,000 (1379)


23.08 (586)

Modified NC38 Box x 4-6 Acme Pin


101354907

Crossover, Standard NC38 Box x Modified NC38 Pin

4.75 (120.65)

20,000 (1379)


13.56 (344)

NC38 Box x Modified NC38 Pin

398,000 (180,530) Limited by NC38 Box

101381170

Firing Head Connector Assy, Firing Head on Bottom, NC38 Box x Double Acme Pin

4.75 (120.65)

20,000 (1379)


23.08 (586)

Modified NC38 Box x 4-6 Acme Pin x 2 7/8-6 Acme Pin



Quick Torque™ Connector - 5-in. Guns SAP No.

Thread Connection

Tool Maximum OD in. (mm)




End Connections


101514211

Box Modified API-NC38

5.0 (127)

20,000 (1379)


22.8 (579)

5-in. Gun Pin

540,600 (245 212)

101535542

Box for Centralizer Modified APINC38

5.0 (127)

20,000 (1379)


25.2 (640)

5-in. Gun Pin

540,600 (245 212)

101514214

Pin Modified API-NC38

5.0 (127)

20,000 (1379)


14.4 (365)

5-in. Gun Pin

540,600 (245 212)


5-78


Detach™ Separating Gun Connector The Detach™ separating gun connector allows operators to deploy long gun sections into the well. The guns are deployed downhole in a single trip and placed across the perforating zone supported by a gun hanger or plug. The guns are fired when desired and then, will automatically separate, which allows them to be retrieved in manageable sections or left in the hole. The Detach separating gun connector is ideal for use in monobore wells with rathole length restrictions and in rigless completions.

Operation

Rathole Length Restriction

• Can deploy entire gun assembly to cover the zone of interest in a single trip and retrieve in manageable gun sections without killing the well

In this application, insufficient rathole length causes the uppermost gun modules to remain adjacent to the perforated interval after they are fired where they may interfere with production from the well. With the Detach separating gun connector, gun sections can be removed from the perforated interval without having to kill the well.

When the firing head detonates the detonating cord initiator, the explosives train continues through the tool and detonates two shaped charges that punch holes in the vent sub. At this point, wellbore pressure is allowed to enter the assembly and move the mandrel lock piston upward, allowing the retaining dogs to move inward, releasing the stinger, and allowing the gun sections to separate. Advantages

• Guns can be retrieved or left at bottom of the hole • Allows perforating in either underbalanced or overbalanced conditions over the entire interval

HAL11525

Rigless Completion HAL12070

On wells where the completions are installed with wireline or coiled tubing, the Detach separating gun connector or modular gun system is the preferred method for perforating. No rig is required—saving both time and money.

Detach™ Separating Gun Connector

Detach™ Separating Gun Connector Specifications SAP No.

Upper Thread Size and Type in. (mm)

Lower Thread Size and Type in. (mm)

Maximum OD in. (mm)

Minimum ID




Burst Pressure


101363724

2 3/8 (60.450) 6P Acme Pin

2 3/8 (60.450) 6P Acme Box

2.75 (69.850)

N/A

2.86 (0.87)

1,000 (69)

80,000 (36 300)*

N/A

20,000 (1379)

101286871

2 7/8 (73.03) 6P Acme Box × Pin

2 7/8 (73.03) 6P Acme Box

3.38 (85.85)

N/A

2.74 (0.83)

1,000 (69)

110,000 (49 800)

N/A

20,000 (1379)

Temperature rating is determined by explosive. *Verification testing


5-79

EZ Pass™ Gun Hanger The EZ Pass™ gun hanger is designed to be run in conjunction with Halliburton’s Modular Gun System. This advanced design includes slips that stay retracted within the slip housing until the tool is set. After the perforating event, the slips will return to the running position and the tool auto releases.

If the gun hanger is deployed and positioned similar to a wireline-set permanent or sump packer, the same power charge-type setting tools are used to set the hanger. After the setting tool is removed from the wellbore, the guns may be deployed as individual modules or as a complete assembly and are stacked on top of the hanger.

If desired, the hanger can be fished with a standard pulling tool and retrieved from the well.

A releasing tool is needed to release the hanger and may be run on the bottom of the perforating assembly. When activated, the releasing tool fires a shaped charge and breaches the top of the hanger. This process allows the gun weight to be transferred to the inner mandrel, placing the hanger in the releasing position and forcing the slips away from the casing.

Features • Running and setting procedures are similar to common bridge plugs and sump packers—uses standard setting equipment • Can be set in larger ID after running through restrictions • Retrievable and redressable • May be configured to auto-release or stay set after gun detonation • Can be deployed on wireline, tubing, or coiled tubing

The EZ Pass gun hanger is designed with a 2.75 fishing neck and can be fished with a standard pulling tool. The slips will retract into the ID of the tool and helps allow it to be retrieved through a wellbore restriction.

• One size sets in multiple casing ranges Operation

If the gun hanger is run attached to the perforating assembly, it must be actuated using pressure. The assembly would be run in, positioned, and then pressure would be applied to the wellbore to set the tool. No explosive components would be necessary for this operation.

5-80

HAL12794

The EZ Pass gun hanger can be run independently or attached to the gun system.

EZ Pass™ Gun Hanger


EZ Pass™ Gun Hanger Specifications Casing Size and SAP No.

Casing Weights* lb

Range of Casing IDs* in. (cm)

Tool Maximum OD (With Slips Retracted) in. (cm)






Overall Length (Maximum) ft (mm)

Maximum Gun Weight lb (kg)

Weight lb (kg)

4 1/2 101320360

9.5 - 15.1

4.09 - 3.826 (10.4 - 9.72)

3.50 (8.89)

18,000** (1241)

500 (34.5)

400 (204.4)

74,000 (33 600)

18,000 (1241)

5.1 (1.55)

30,000 (13 600)

116 (52.6)

5 1/2 101315538

20 / 23 / 26

4.778 - 4.548 (12.14 - 11.55)

4.125 (10.5)

20,000** (1450)

500 (34.5)

400 (204.4)

74,000 (33 600)

20,000 (1450)

5.1 (1.55)

30,000 (13 600)

165 (74.8)

7 101321131

29 / 32 / 35

6.184 - 6.004 (15.70 - 15.25)

5.375 (13.65)

20,000** (1450)

500 (34.5)

400 (204.4)

74,000 (33 600)

20,000 (1450)

5.1 (1.55)

30,000 (13 600)

180 (81.7)

*Recommended **Maximum Operating Pressure based on hydrostatic pressure and applied gun weight. The EZ Pass™ hanger does not have minimum ID or Burst Pressure requirements. NOTE: The EZ Pass gun hanger is designed with specific features to enhance its retrievability; however, due to the uncertainty of the wellbore conditions created by the perforating event, the retrieval of this tool cannot be assured.


5-81

Automatic-Release Gun Hanger—Rotational Set

Features With the ARGH: • No tubing is required between the guns and packer • No wireline work is required to drop the assembly • No restrictions are left in the casing below the packer • The maximum desired underbalanced pressure can be used • Production tubing can be run and tested independently from other tools • The ARGH and guns are run on the workstring • The risk of presetting the packer is reduced • In BigBore™ monobore completions, the production tubing and permanent packer are installed before running the ARGH perforating assembly • Remedial work can be performed without pulling production equipment (such as setting bridge plugs, adding perforations, running coiled tubing, etc.) • Lower gun-firing pressures can be used since all production equipment is pressure-tested before the guns are installed in the well (no need to exceed previous test pressures)

5-82

Operation The ARGH is made up on the bottom of the perforating assembly. A righthand release on/off tool is made up on the top of the bottomhole assembly (BHA). After the BHA is correlated on depth, the operator picks up the string, turns it to the right, and slacks off weight on the ARGH. The ARGH should be set at this point.

Primacord

Shaped Charges

With weight still on the BHA, the operator continues to turn the workstring to the right to release the on/off tool. As the guns are detonated, the explosive train is continued to the ARGH. Two shaped charges are detonated into a sealed fluid chamber. This action eliminates the support to the slip assembly. The ARGH and perforating assembly are then released automatically and fall to the bottom.

Silicone Fluid Chamber

Slip Assembly

HAL10516

For high volume testing and production, the automatic-release gun hanger (ARGH) allows perforating and testing of a zone without imposing downhole restrictions. The perforating assembly can be positioned and retained adjacent to the desired interval. The drillpipe or tubing is then removed. After all surface equipment is installed, the guns are detonated and then released automatically into the bottom of the well.

Auto-Release Gun Hanger Rotational Set


Automatic-Release Gun Hanger—Rotational Set Specifications Casing OD in. (mm)

Casing Range lb/ft (kg/m)

Maximum OD in. (mm)

Length ft (m)

Minimum Tensile Rating lb (kg)

Minimum BHA Weight lb (kg)


3 1/2 (88.9)

5.7-10.2 (8.48-15.18)

2.75 (69.85)

3.33 (1.02)

25,000 (11 300)

150 (68)

12,300 (5580)

4 1/2 (114.3)

9.5-13.5 (14.14-20.09)

3.75 (95.25)

4.88 (1.49)

85,000 (38 500)

300 (136)

40,000 (18 140)

5 (127)

11.5-18 (17.11-26.78)

3.75 (95.25)

4.88 (1.49)

85,000 (38 500)

300 (136)

40,000 (18 140)

5 1/2 (139.7)

13-26 (19.34-38.69)

4.5 (114.3)

5.92 (1.80)

120,000 (54 400)

500 (227)

40,000 (18 140)

7 (177.8)

17-38 (25.3-56.54)

5.5 (123.2)

6.04 (1.84)

120,000 (54 400)

600 (272)

40,000 (18 140)

7 5/8 (193.7)

20-39 (29.76-58.03)

5.5 (123.2)

6.04 (1.84)

120,000 (54 400)

600 (272)

40,000 (18 140)

9 5/8 (244.5)

29.3-53.5 (43.6-79.61)

8.0 (203.2)

7.08 (2.16)

120,000 (54 400)

600 (272)

40,000 (18 140)


5-83

Automatic-Release Gun Hanger—Automatic-J Mandrel For high volume testing and production, the automatic-release gun hanger (ARGH) allows perforating and testing of a zone without imposing downhole restrictions. The perforating assembly can be positioned and retained adjacent to the desired interval. The drillpipe or tubing is then removed. After all surface equipment is installed, the guns are detonated and then released automatically into the bottom of the well.

• The automatic-J ARGH and guns are run on wireline, slickline, coiled tubing, or the workstring

Features

• Lower gun-firing pressures can be used since all production equipment is pressure-tested before the guns are installed in the well (no need to exceed previous test pressures)

With the ARGH: • No tubing is required between the guns and packer • No wireline work is required to drop the assembly • No restrictions are left in the casing below the packer • The maximum desired underbalanced pressure can be used

• Remedial work can be performed without pulling production equipment (such as setting bridge plugs, adding perforations, running coiled tubing, etc.)

Silicone Fluid Chamber

Slip Cone

Operation The automatic-J mandrel can be run on wireline, slickline, coiled tubing, or the workstring. Rotation is not required to set the automatic-J gun hanger. Upward and downward manipulation either sets or un-sets the hanger. As the guns are detonated, the explosive train is continued to the ARGH. Two shaped charges are detonated into a sealed fluid chamber. This action eliminates the support to the slip assembly. The ARGH and perforating assembly are then released automatically and fall to the bottom.

Automatic-J Mandrel Primacord

Slip Assembly

HAL10542

• Production tubing can be run and tested independently from other tools

• In BigBore™ monobore completions, the production tubing and permanent packer are installed before running the ARGH perforating assembly

Time-Delay Firer Crossover

Automatic-Release Gun Hanger (ARGH) Automatic-J Mandrel

5-84


Automatic-J Mandrel Specifications Casing OD in. (mm)

Casing Range lb/ft (kg/m)

Maximum OD in. (mm)

Length ft (m)



Minimum BHA Weight lb (kg)


2 7/8 (73.1)

2 7/8 6.4-6.50 (9.52-9.67)

2.25 (57.2)

4.49-4.87 (1.349-1.47)

20,000 (1379)

25,000 (11 300)

150 (68)

9,000 (4050)

3 1/2 (88.9)

3 1/2 5.75-10.2 (8.56-15.18)

2.75 (73.0)

4.87-5.28 (1.47-1.59)

N/A

25,000 (11 300)

150 (68)

12,300 (5580)

4 (101.6)

4 14.40 (21.43)

2.75 (73.0)

4.87-5.28 (1.47-1.59)

N/A

25,000 (11 300)

150 (68)

12,300 (5580)

3 1/2 (88.9) Slimhole

3 1/2 9.2-12.95 (13.69-19.27)

2.50 (63.5)

53.79-58.47 (16.40-17.82)

20,000 (1379)

25,000 (11 340)

150 (68)

20,000 (9072)

4 1/2 (114.3)

4 1/2 9.5-13.5 (14.14-20.09)

3.75 (95.25)

7.95-9.28 (2.40-2.80)

20,000 (1379)

85,000 (38 500)

300 (136)

40,000 (18 140)

5 (127)

5 15.0-18.0 (22.32-26.78)

3.75 (95.25)

7.95-9.28 (2.40-2.80)

20,000 (1379)

85,000 (38 500)

300 (136)

40,000 (18 140)

4 1/2 (114.3) Slimhole

4 1/2 15.1-16.9 (22.46-25.15)

3.50 (88.9)

58.34-67.29 (17.78-20.51)

N/A

25,000 (11 340)

200 (91)

20,000 (9072)

5 1/2 (139.7)

5 1/2 15.50-23 (23.06-34.22)

4.50 (114.3)

9.31-10.29 (2.80-3.10)

N/A

120,000 (54 400)

500 (227)

40,000 (18 140)

7 (177.8)

7 20-38 (29.76-56.54)

5.5 (123.2)

9.26-10.44 (2.79-3.14)

N/A

120,000 (54 400)

600 (272)

40,000 (18 140)

7 5/8 (193.7)

7 5/8 24-39 (35.71-58.03)

5.5 (123.2)

9.26-10.44 (2.79-3.14)

N/A

120,000 (54 400)

600 (272)

40,000 (18 140)

9 5/8 (244.5)

9 5/8 29.3-53.5 (43.6-79.61)

8.0 (203.2)

7.08 (2.16)

N/A

120,000 (54 400)

600 (272)

40,000 (18 140)

10 3/4 (273.05)

10 3/4 60.7 - 71.10 (90.31 - 105.78)

9.17 (233)

9.8 (299)

N/A

160,300 (72 700)

600 (272)

250,000 (113 400)

*As total gun weight increases, the maximum operating pressure decreases. Temperature rating is determined by explosives. These ratings are guidelines only. For more information, consult your local Halliburton representative.


5-85

Explosive Transfer Swivel Sub The explosive transfer swivel sub allows two sections of guns to rotate independently of one another. This independent rotation is important on long strings of guns in horizontal wells when they must be oriented in a specific direction. It is easier to orient several short sections of guns, rather than one long section. Features • Useful in horizontal wells when shots need to be oriented in a specific direction to the wellbore • Bi-directional, allowing firing from either direction Operation

HAL10513

This swivel sub can be run as a connector between two guns to allow them to rotate independently without breaking the explosive train. In other words, this sub passes on the explosive transfer to the next gun.

Explosive Transfer Swivel Sub Assembly

Explosive Transfer Swivel Sub Specifications SAP No.


Maximum OD in. (mm)




Maximum Operating Tensile Load* lb (kg)

101271529

2 3/8 (60.33) 6P Acme Box × Pin

2.75 (69.85)

1.13 (0.344)

20,000 (1379)

108,000 (48 988)

32,000 (14 515)

101271553

2 7/8 (73.03) 6P Acme Box × Pin

3.375 (85.73)

1.13 (0.344)

20,000 (1379)

190,000 (86 183)

40,000 (18 144)

101271546

4.00 (101.60) 6P Acme Box × Pin

4.625 (117.47)

1.16 (0.353)

20,000 (1379)

332,000 (150 593)

60,000 (27 216)

101284187

4.420 (112.27) 6P Acme Box × Pin

5.125 (130.18)

1.13 (0.344)

20,000 (1379)

416,000 (188 694)

60,000 (27 216)

101278821

5 1/8 (130.18) 6P Acme Box × Pin

5.750 (146.05)

1.16 (0.353)

20,000 (1379)

410,000 (185 973)

60,000 (27 216)

*Maximum operating tensile load is the point at which the ball bearing race will start to deform, and the tool will not function as designed. Temperature rating is determined by explosive.

5-86


Shearable Safety Sub The shearable safety sub is designed to provide a gap in the explosive train, which could be severed at surface with the shear rams. The most common application is in the use of live well intervention.

• Uses standard explosives

The shearable safety sub provides two levels of defense against wellbore pressures. First, it provides a sub with a smooth profile that is utilized by closing the sealing rams to control pressure when the gun connection is made up or broken out. Secondly, if the well conditions become dangerous and the shear rams need to be activated, it provides an area in the gun assembly that does not contain explosives and can be safely severed by the shear rams.

• Can be sheared independently of the guns firing

• Contains standard 3 3/8-in. gun connections above and below • Can be run with tubing, coiled tubing, wireline, and modular applications

• Can be redressed at minimal cost This tool has been successfully sheared during testing using the following: • Shaffer shear 7 1/16-in. 10k safety head • Piston diameter of 14 in. (153 in.²) • Sheared at 2,000 psi • Force required to shear tool = (153 in.²) (2,000 psi) = 306,000 lb

Features • Continues the explosive train without use of continuous explosives • Isolates pressure from below

HAL15454

• Allows a smooth sealing area for the pipe rams to seal against

Shearable Safety Sub

Shearable Safety Sub Specifications SAP No.

Thread Size and Type

Maximum OD in. (mm)

Minimum ID





Weight lb (kg)

101245799

2 7/8-in. Acme Box x Pin

3.375 (85.73)

N/A

2.50 (0.76)

20,000 (1380)

N/A

200,000 (90 700)

54.4 (24.6)

Temperature rating is determined by explosive.


5-87

Roller Tandem Assembly Roller tandem assemblies are used to reduce the friction between the perforating guns and the casing. In some cases, the frictional drag can be reduced by as much as 90%. Applications • Running guns on coiled tubing in horizontal and highly deviated wells • Dropping the guns into the rathole in highly deviated wells

HAL10567

• Can be deployed in conjunction with the modular gun system

Roller Tandem Assembly

Roller Tandem Assembly Specifications

5-88

SAP No.

Size in. (mm)

Effective OD in. (mm)

No. of Rollers

Roller Phasing



120021632

2 3/4 (69.85)

3.06 (77.72)

6 (2 rows of 3)

60°

140,000 (63 503)

6.97 (177.04)

100155770

3 3/8 (85.72)

3.76 (95.50)

8 (2 rows of 4)

45°

246,000 (111 584)

7.70 (195.58)

100155771

4 5/8 (117.47)

5.63 (143.00)

8 (2 rows of 4)

45°

414,000 (187 787)

9.25 (234.95)

101313551

7 (177.80)

8.20 (208.28)

8 (2 rows of 4)

45°

444,000 (201 395)

15.52 (394.21)


Centralizer Tandem In certain types of TCP operations, it is desirable to centralize the guns and other tools in the casing. Halliburton has designed a full range of centralizers to meet this requirement for all gun sizes. The centralizers are designed to minimize the possibility of “hanging up” while running or pulling the guns and to maximize the flow area around the centralizers.

Centralizer

Application Two of the primary applications for the centralizers are:

2.

When perforating with big hole charges, it is recommended to centralize the guns to ensure that the exit holes in the casing will all be of a consistent size. If the guns are not centralized, the size of the exit holes will vary according to the clearance from the gun to the casing. This can cause problems with sand control operations. In modular gun completions, it is necessary to centralize the gun modules to obtain a reliable explosive transfer between modules.

Contact your Halliburton representative for a list of available centralizers.


Guns

Centralizer

HAL15986

1.

Centralizer Tandem

5-89

Emergency Release Assembly The emergency release assembly was designed to run in conjunction with the automatic-release gun hanger assembly. When deploying the gun hanger on tubing or drill pipe, the emergency release is run between the gun hanger and guns to serve as a weak point in case the hanger gets stuck while running in the hole. Pulling or jarring on the pipe will cause the emergency release assembly to shear, allowing the retrieval of the guns and tubing from the well.

HAL15987

When deploying the gun hanger on wireline, the rope socket typically acts as the weak point.

Emergency Release Assembly

Emergency Release Assembly Specifications

5-90

SAP No.

OD Size in. (mm)

No. Shear Screws

Temperature Rating


101201127

3 3/8 (85.73)

8 steel shear screws rated at 5,600 lb per screw

Determined by explosives

25,000 (1724)


Annular Pressure-Control Line Vent The annular pressure-control line (APF-C) vent is a device that isolates the tubing from annulus fluid or pressure. The vent is actuated by rathole pressure after the perforating assembly has been detonated. It then provides a flowpath for the formation fluid into the tubing string. Features • Ideal for highly deviated or horizontal wells • Requires minimal pressure to operate • Eliminates nitrogen displacement or swabbing the tubing string to achieve desired underbalance Operation

HAL15441

The APF-C vent is run directly on top of the APF-C firing head. When the perforating assembly is detonated, gun pressure shifts an actuating piston into a power piston. This shift opens the flow ports to the tubing.

Annular Pressure-Control Line (APF-C) Vent

Annular Pressure-Control Line (APF-C) Vent Specifications SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)


Flow Area in.2 (cm2)






120038049


3.38 (85.85)

Nonfull-bore

[email protected] (25.4)

2.63 (16.97)

2.37 (0.72)

20,000 (1380)

150,000 (68 000)

22,000 (1515)

22,000 (1515)

101016565


3.88 (98.55)

Nonfull-bore

[email protected] (25.4)

3.93 (25.34)

2.43 (0.74)

20,000 (1380)

170,000 (77 000)

15,000 (1035)

15,000 (1035)



5-91

Annular Pressure-Control Line Swivel Sub When run in conjunction with the annular pressure-control line (APF-C) firing head, the APF-C swivel sub provides a swivel point between the guns and packer when it is desired to have the guns rotate freely as when orienting shots in a deviated well. Features • Compatible with APF-C firing head and control line • Can be run anywhere between the packer and the firing head • Transmits pressure through the control line while rotating Operation

HAL10539

The APF-C swivel is made up in the string between the packer and the firing head. A section of control line is made up from the packer to the top of the swivel. A second section of control line is made up from the bottom of the swivel to the APF-C firing head. Annulus pressure is transmitted from the packer, through the swivel to the firing head.

APF-C Swivel Sub

Annular Pressure-Control Line (APF-C) Swivel Sub Specifications SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)


Operating Load Limit Rating lb (kg)




101230619

2 7/8 EU 8rd Box × Pin

5.13 (130.30)

2.0 (50.8)

200,000 (90 718)

36,000 (16 329)

NA*

NA*

1.3 (0.39)

*The APF-C swivel sub is not designed to operate with differential pressure.

5-92


Annular Pressure-Control Line Tubing Release The 2 7/8-in. annular pressure-control line tubing release assembly (APF-C TR) provides a mechanical method of releasing the APF-C firing head and VannGun® assembly from the tubing string. Features • Releasing the gun assembly opens the tubing for other tools such as production logging, testing, and treating • Low cost method to release gun assembly • Utilizes off-the-shelf shifting tools • No time limit on dropping the gun assembly • Leaves perforations uncovered and helps eliminate flow restriction Operation

HAL10589

The APF-C TR is run between the APF-C firing head and the 7- or 9 5/8-in. annulus pressure transfer reservoir (APTR). The control line for the APF-C is attached to the control line housing, which transfers the pressure through the APF-C TR and out the finger sub to a second control line. The second control line transfers the pressure down to the APF-C firing head. Releasing can be accomplished by the use of a standard Halliburton or Garret shifting tool.

APF-C Tubing Release (APF-C TR)

Annular Pressure Control Line Tubing Release (APF-C TR) Specifications SAP No.

Upper Thread Size and Type

Lower Thread Size and Type


Maximum OD in. (mm)

Minimum ID in. (mm)




87921

2 7/8 (73.03) EUE 8 Rd Box

2 7/8 (73.03) EUE 8 Rd Pin

2.24 (0.68)

4.62 (117.35)

Latch Sizes – 1.88 (47.75), 2.125 (53.98), or 2.25 (57.15)

120,000 (54 431)

12,000 (827)

11,000 (758)


5-93

Bar Pressure Vent The bar pressure vent (BPV) is designed to achieve a differential pressure between the formation and tubing string. This tool helps to safely allow a differential pressure in wells with existing open perforations or in unperforated wells. The BPV is an internal sliding-sleeve tool actuated by pressure in the tubing. It is run between the packer and the guns. Features • Offers an inexpensive way to create the necessary underbalance • Allows the hole to be totally contained at the wellhead before the surge

Operation The BPV consists of a ported housing and a sliding sleeve. The sliding sleeve is isolated from the tubing pressure by a break plug with a hollow center. The BPV is activated when the detonating bar is dropped through the tubing and shears the hollow break plug. This action allows the pressure in the tubing to force the sleeve upward, uncovering the ports. A lock ring locks the sleeve open. The detonating bar continues downward to strike the firing head. If the vent must be opened before dropping the detonating bar, dropping a special tube will open the vent and not fire the guns. When the bar is dropped, it will pass through the tube and fire the guns.

• Allows the sleeve to lock in place once the port is opened • Can be run with any packer

HAL10565

• Does not rely on tubing manipulation (Hydrostatic pressure in the tubing is the only force required)

Bar Pressure Vent (BPV)

Bar Pressure Vent (BPV) Specifications Flow Area in.2 (cm2)



4 @ 1.0 (25.40)

1.77 (11.40)

1.30 (0.40)

20,000 (1380)

1,000 (69)

8,000 (550)

140,000 (63 400)

24,000 (1655)

20,000 (1380)

1.90 (48.26)

4 @ 1.0 (25.40)

3.14 (20.27)

1.30 (0.40)

15,000 (1035)

1,000 (69)

8,000 (550)

146,000 (66 200)

18,000 (1240)

22,000 (1515)

3.88 (98.55)

2.25 (57.15)

4 @ 1.13 (28.70)

3.98 (25.65)

1.40 (0.43)

15,000 (1035)

1,000 (69)

8,000 (550)

160,000 (72 500)

19,000 (1310)

17,000 (1170)

5.0 (127.0)

2.75 (69.85)

4 @ 1.75 (44.45)

5.94 (38.32)

1.57 (0.48)

15,000 (1035)

1,000 (69)

8,000 (550)

400,000 (181 400)

22,000 (1515)

18,000 (1240)

SAP No.


Maximum Minimum No. and ID OD ID of Ports in. (mm) in. (mm) in. (mm)

101201951

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.06 (77.72)

1.50 (38.10)

100155788

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.63 (92.20)

100010328

2 7/8 (73.03) EUE 8 Rd Box × Pin

100155789

3 1/2 (88.90) EUE 8 Rd Box × Pin

Minimum Maximum Operating Differential Pressure Pressure psi (bar) psi (bar)


Burst Collapse Pressure Pressure psi (bar) psi (bar)


5-94


Below-Packer Vent Device The below-packer vent device (BPVD) was developed for use with the annulus-pressure crossover assembly (APCA). Surface pressure applied to the annulus is transmitted through the APCA to a closed chamber below the BPVD and above a pressure-responsive firing head. The BPVD can be set to work before or after the perforating assembly is detonated. Features • Does not require tubing hydrostatic pressure to operate • Can operate in highly deviated wells • Can be used in wells with low formation pressure • Eliminates nitrogen requirements • Helps allow maximum underbalance • Is compatible with several types of firing heads • Can provide reliable and accurate pressure response Operation

HAL15451

HAL15450

To open the BPVD, a predetermined annulus pressure is transmitted through the APCA to below the BPVD. This pressure then ruptures a disk in the lower housing of the BPVD. An actuating piston then forces the venting sleeve away from the production ports. This action establishes communication with the tubing string.

Below-Packer Vent

Below-Packer Vent Device (BPVD)

Below-Packer Vent Device (BPVD) Specifications SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)








100155787

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.38 (85.85)

Nonfull-bore

2.32 (0.71)

4 @ 1.0 (25.4)

15,000 (1035)

1,000 (69)

150,000 (68 000)

25,000 (1725)

22,000 (1515)

100014176

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.88 (98.55)

Nonfull-bore

2.26 (0.69)

5 @ 1.0 (25.4)

15,000 (1035)

1,000 (69)

170,000 (77 000)

25,000 (1725)

25,000 (1725)



5-95

Maximum Differential Bar Vent The maximum differential bar vent (MDBV) assembly is run between the perforating guns and the packer. After the packer is set, the opening of the vent creates communication between the tubing and the rathole. The vent is opened by breaking the plug inside the tool and allowing the sleeve to uncover the ports. Running the MDBV allows the operator to run the tubing in the well with no hydrostatic pressure in the tubing. Features • Operates with a minimum amount of fluid in the tubing • Helps allow maximum differential pressure when perforating in lowpressure formations

Operation The maximum differential bar vent is held closed by a chamber of silicone fluid, which keeps a spring compressed. When the silicone fluid is released from the chamber, the spring extends and opens the vent. Once the break plug is broken, the silicone fluid drains into the tubing. The MDBV will open with up to 1,000 psi (68.95 bar) in the tubing regardless of rathole pressure. If there is more than 1,000 psi (68.95 bar) in the tubing, and there is uncertainty about the rathole pressure, consider the bar pressure vent instead of the MDBV.

• Does not depend on tubing hydrostatic pressure to operate • Assisted mechanically by an operating spring to help ensure full and complete opening

HAL15445

If the vent must be opened before dropping the detonating bar, dropping a special tube will open the vent and not fire the guns. When the bar is dropped, it will pass through the tube and fire the guns.

• Can be used in wells with open perforations to achieve an underbalance when guns are fired to add new perforations

Maximum Differential Bar Vent

Maximum Differential Bar Vent (MDBV) Specifications SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)


Flow Area of Ports in.2 (cm2)


Temperature Rating (Limited by Silicone Fluid) °F (°C)




100005291

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.36 (92.20)

2.0 (50.80)

5 @ 1.0 (25.40)

3.92 (25.29)

2.29 (0.70)

350 (176)

221,000 (100 200)

19,500 (1345)

16,500 (1135)

100005294

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.88 (98.55)

2.2 (57.15)

4 @ 1.13 (28.70)

4.01 (27.87)

2.39 (0.73)

350 (176)

231,000 (104 700)

19,000 (1310)

13,000 (895)

100156853

3 1/2 (88.9) EUE 8 Rd Box × Pin

4.50 (114.30)

2.7 (69.85)

4 @ 1.75 (44.45)

9.58 (61.81)

2.75 (0.84)

350 (176)

245,000 (111 000)

14,000 (965)

14,000 (965)


5-96


Pressure-Operated Vent The pressure-operated vent (POV) is designed to achieve a differential pressure between the formation and tubing string and to provide a way to open the vent and test the packer before the guns are fired. When the guns have been positioned and the packer has been set, the predetermined amount of fluid is added to the tubing. Adding the fluid into the tubing causes the POV to open and creates the proper pressure differential before firing. Nitrogen may also be used with or in place of the fluids to obtain the necessary hydrostatic pressure in the tubing. Features • Allows the vent to be opened without the guns being fired • Allows the packer to be tested before the guns are fired

• Can be run with mechanical or pressure-actuated firing heads • Useful in highly deviated wells • Compatible with other packers Operation The POV consists of a ported housing, a sliding sleeve, and a set of shear pins. The sleeve is held in the closed position by a variable number of shear pins. The pins are isolated from annular pressure and are only exposed to the tubing hydrostatic. The POV will open when the proper amount of hydrostatic pressure is applied to the shear pins. The amount of hydrostatic it takes to open the POV depends on how many shear pins are installed in the tool. When the pins shear, the hydrostatic pressure forces the sleeve upward, which uncovers the flow ports. The sleeve is then locked into the open position.

HAL10538

• Fills tubing automatically when run with Vann™ circulating valve

Pressure-Operated Vent (POV)

Pressure-Operated Vent (POV) Specifications SAP No.

Total Thread Size Maximum Minimum No. and ID and Type OD ID of Ports Flow Area 2 in. (mm) in. (mm) in. (mm) in. (mm) in. (cm2)






Burst Collapse Pressure Pressure psi (bar) psi (bar)

101297298

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.06 (77.72)

1.50 (38.10)

4 @ 1.0 (25.40)

1.77 (11.40)

1.30 (0.40)

20,000 (1380)

1,000 (69)

8,000 (550)

140,000 (63 400)

24,000 (1655)

20,000 (1380)

100014177

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.63 (92.20)

1.90 (48.26)

4 @ 1.0 (25.40)

3.14 (20.27)

1.30 (0.40)

15,000 (1035)

1,000 (69)

8,000 (550)

146,000 (66 200)

18,000 (1240)

22,000 (1515)

100014178

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.88 (98.55)

2.25 (57.15)

4 @ 1.13 (28.70)

3.98 (25.65)

1.40 (0.43)

15,000 (1035)

1,000 (69)

8,000 (550)

160,000 (72 500)

19,000 (1310)

17,000 (1170)

100014179

3 1/2 (88.90) EUE 8 Rd Box × Pin

5.0 (127.0)

2.75 (69.85)

4 @ 1.75 (44.45)

5.94 (38.32)

1.57 (0.48)

15,000 (1035)

1,000 (69)

8,000 (550)

400,000 (181 400)

22,000 (1515)

18,000 (1240)



5-97

Vann™ Circulating Valve The Vann™ circulating valve (VCV) is designed to be used as a fill-up valve or as a circulating valve for displacing well fluids before setting a packer. After the fluid is displaced, the operator applies pressure to the tubing or annulus to rupture a disk and close the VCV. Features • Can be used as a circulating and shutoff valve • Often run with other venting or production devices • Economical and reusable

The rupture disk is available for different pressure ratings as needed. The amount of hydrostatic pressure required to actuate the VCV depends on the rating of the rupture disk. Once the disk ruptures, the hydrostatic pressure enters the lower air chamber through the ruptured disk, forcing the sliding sleeve upward to cover the flow ports. Operating pressure can be pump-pressure applied after the VCV is at the bottom of the well or applied by hydrostatic pressure when the tool is run in the hole.

Operation

HAL15447

The VCV consists of a ported housing, a sliding sleeve, and a rupture disk, which must be ordered separately. The sliding sleeve, which has two air chambers, is open while the tool is run in the hole.

Vann™ Circulating Valve (VCV)

Vann™ Circulating Valve (VCV) Specifications Makeup Length ft (m)






3.14 (20.26)

1.96 (0.60)

15,000 (1035)

1,000 (69)

225,000 (102 000)

22,000 (1515)

18,000 (1250)

4.71 (30.39)

3.25 (0.99)

15,000 (1035)

1,000 (69)

392,000 (177 700)

20,000 (1380)

18,000 (1250)

No. and ID Flow Area of Ports of Ports in. (mm) in.2 (cm2)

SAP No.


Maximum OD in. (mm)

Minimum ID in. (mm)

101015372

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.38 (85.85)

1.875 (47.62)

4 @ 1.0 (25.4)

120038456

2 7/8 (73.03) EUE 8 Rd Box × Pin*

4.65 (188.11)

2.12 (53.85)

6 @ 1.0 (25.4)

*Optional connections are 2 7/8-IF and 3 1/2-IF. These ratings are guidelines only. For more information, consult your local Halliburton representative.

5-98


Automatic Release The automatic release (AR) allows the perforating guns to drop immediately after firing. Features • Can be used with most mechanical and pressure-actuated firing heads • Allows for immediate release of the guns • Leaves the tubing fully open after the guns are released • Eliminates the need to run wireline to shift the guns • Reduces the chance of the gun’s sticking because of debris Operation

HAL10512

The AR allows for dropping the perforating guns after they are fired. The guns may be fired either mechanically or by pressure. The releasing device is actuated by the pressure generated outside the perforating guns upon detonation, so the guns are released as soon as they fire.

Automatic Release (AR)

Automatic Release (AR) Assemblies List SAP No.

Description

100005225

2 3/4-in. Auto Release with Mechanical Firing Head

100005226

2 3/4-in. Auto Release with Mechanical Firing Head Model II-D

100005233


100005234


100155754

3 3/8-in. Auto Release with Mechanical Firing Head Model III-D

100005235

3 3/8 in. Auto Release with 2 1/2-in. TDF

100014158

3 3/8-in. Auto Release-High Pressure with 2 1/2-in. TDF

100010045

3 3/8-in. Auto Release-High Pressure with Mechanical Firing Head

101313281

3 3/8-in. Auto Release Firer with 2 1/2 in. TDF (3 1/2 NK3SB)

100005236


100156106


101205564

3 1/2-in. Auto Release Firer, Low Pressure with Model II-D

101294470

3 1/2-in. Auto Release Firer with 2 1/2 in. TDF

101313282

3 1/2-in. Auto Release Firer with Model II-D

100155752


101294471


101213155

4 1/2-in. Auto Release Firer Low Pressure with Model II-D

101357916



5-99

Automatic Release (AR) Assemblies List SAP No.

Description

101313025

5 1/2-in. Auto Release Firer with Model II-D

101310170

5 1/2-in. Auto Release Firer with Model II-D or III-D

101313059


101357918


Automatic Release (AR) Specifications SAP No.


Maximum OD in. (mm)

ID After Release in. (mm)






100005225

2 3/8 (60.33) EUE 8 Rd

2.88 (73.15)

2.125 (53.98)

2.06 (0.63)

20,000 (1380)

1,500 (103)

15,000 (1035)

49,500 (22 400)

100005226

2 3/8 (60.33) EUE 8 Rd

2.88 (73.15)

2.125 (53.98)

2.06 (0.63)

20,000 (1380)

1,500 (103)

15,000 (1035)

49,500 (22 400)

100005233

2 7/8 (73.03) EUE 8 Rd

3.38 (85.85)

2.72 (69.09)

2.23 (0.68)

20,000 (1380)

1,500 (103)

10,000 (690)

68,000 (30 800)

100005234

2 7/8 (73.03) EUE 8 Rd

3.38 (85.85)

2.72 (69.09)

2.23 (0.68)

20,000 (1380)

1,500 (103)

10,000 (690)

68,000 (30 800)

100005235

2 7/8 (73.03) EUE 8 Rd

3.38 (85.85)

2.72 (69.09)

2.23 (0.68)

20,000 (1380)

1,500 (103)

10,000 (690)

68,000 (30 800)

100155754

2 7/8 (73.03) EUE 8 Rd

3.38 (85.85)

2.72 (69.09)

2.23 (0.68)

20,000 (1380)

1,500 (103)

10,000 (690)

68,000 (30 800)

100014158

2 7/8 (73.03) EUE 8 Rd

3.38 (85.85)

2.52 (64.186)

2.23 (0.68)

20,000 (1380)

500 (34)

17,000 (1170)

68,000 (30 800)

100010045

2 7/8 (73.03) EUE 8 Rd

3.38 (85.85)

2.52 (64.186)

2.23 (0.68)

20,000 (1380)

500 (34)

17,000 (1170)

68,000 (30 800)

100005236

3 1/2 (88.90) EUE 8 Rd

3.78 (96.01)

2.99 (75.95)

2.23 (0.68)

20,000 (1380)

1,500 (103)

10,000 (690)

68,000 (30 800)

100156106

3 1/2 (88.90) EUE 8 Rd

3.78 (96.01)

2.99 (75.95)

2.23 (0.68)

20,000 (1380)

1,500 (103)

10,000 (690)

68,000 (30 800)

100155752

4 1/2 (114.30) OD Box

4.5 (114.30)

3.67 (93.22)

2.23 (0.68)

20,000 (1380)

1,500 (103)

9,500 (655)

115,000 (52 100)

101357916

4 1/2 (114.30) OD Box

4.92 (126)

3.76 (96)

2.39 (.728)

13,000 (896)

7000 (483)

6000 (414)

87,200 (39 553)

101294470

3 1/2 (88.90) EUE 8 Rd

3.78 (96.01)

3.00 (76.2)

1.74 (0.53)

20,000 (1380)

7000 (483)

7500 (517)

53,300 (24 100)

101313059

5 1/2 (139.7) TS-3SB Pin

5.81 (148)

4.703 (119)

1.83 (0.56)

17,800 (1227)

4000 (276)

4700 (324)

106,100 (48 100)

101357918

5 1/2 (139.7) VAM Box

5.957 (151)

4.70 (119)

2.39 (0.73)

13,000 (896)

7000 (483)

4000 (276)

106,100 (48 100)

101313281

3 1/2 (88.90) NK3SB Box

101205564

3 1/2 (88.90) EUE 8 Rd

101313282

3 1/2 (88.90) NK3SB Box

100155752

4 1/2 (114.30) OD Blank

101294471

4 1/2 (114.30) OD Blank

101213155

4 1/2 (114.30) CS Hydril Box

101313025

5 1/2 (139.7) OD Blank

5-100

Contact Halliburton TCP Representative


Mechanical Tubing Release The mechanical tubing release (MTR) provides operators with the option of keeping or releasing the VannGun® assembly from the tubing string. The MTR is usually run above the firing head and below the production ports below the packer. A standard shifting tool is used to operate the release mechanism in the MTR. Features • Frees the tubing for other tools and operations such as logging, production testing, and treating • Provides a low-cost way to release the gun assembly • Uses standard off-the-shelf shifting tools • Does not have a time limit on dropping the gun assembly • Leaves perforations uncovered to eliminate flow restrictions Operation The MTR consists of three main components: the upper housing, a lower finger release sub, and a latch. The latch retains the finger release sub in the housing. To operate the MTR, the user must do the following: Select the proper shifting tool and run it into the hole on slickline through the MTR.

2.

Pick back up to engage the latch and lightly jar the latch four or five times.

3.

Go back down to verify the release of the VannGun assembly.

HAL15435

1.

Mechanical Tubing Release (MTR)

Mechanical Tubing Release (MTR) Specifications SAP No. (w/o Latch)


Maximum OD in. (mm)

Minimum ID (Latch Size) in. (mm)





111,500 (50 576)

12,000 (825)

10,000 (690)

1.50 (0.46)

1.50 (38.10) 100005286

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.06 (77.22)

1.63 (41.40) 1.81 (45.97) 1.88 (760)


5-101

Mechanical Tubing Release (MTR) Specifications Thread Size and Type in. (mm)

SAP No. (w/o Latch)

Maximum OD in. (mm)

Minimum ID (Latch Size) in. (mm)





111,500 (50 576)

12,000 (825)

11,000 (760)

1.63 (0.50)

111,500 (50 576)

11,000 (760)

10,000 (690)

1.88 (0.57)

1.88 (47.75) 100005281

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.38 (85.85)

2.13 (53.98) 2.25 (57.15) 2.25 (57.15)

100005284

3 1/2 (88.9) EUE 8 Rd Box × Pin

3.95 (100.33)

101236790

5 (127) 15 lb (6.8 kg) New Vam Box × Pin

5.59 (142.01)

3.69 (93.68)

111,500 (50 576)

12,000 (825)

11,000 (760)

3.60 (1.10)

101435633

5 1/2-17.00 Vam Top HC Box X Pin Threads, 13 Chrome

6.50 (165)

4.313 (110)

168,000 (76 200)

6,800 (469)

5,000 (345)

4.7 (1.4)

101398862

4 1/2-12.6 Vam Top Threads, 13 Chrome

5.50 (140)

3.562 (90)

107,000 (48,500)

6,300 (434)

6,000 (414)

4.1 (1.25)

101399826

5 1/2-15.5 Vam Top Threads, 13 Chrome

6.50 (165)

4.313 (110)

168,000 (76,200)

6,400 (441)

4,000 (276)

4.8 (1.46)

101327124

4 1/2-12.6 Vamace Box X Pin, 13 Chrome

5.50 (140)

3.562 (90)

107,000 (48,500)

6,300 (434)

6,000 (414)

4.1 (1.25)

2.75 (69.85)

Mechanical Tubing Release (MTR) Shifting Tool and Key Number Latch Size in. (mm)

Tool No. SAP No.

Key No. SAP No.

Key Maximum Exp. OD in. (mm)

Key Minimum OD in. (mm)

1.50 (38.10)

42 BO 245 101059081

42 B 818 101282505

1.64 (41.65)

1.49 (37.85)

1.625 (41.28)

42 BO 121 12005796

42 B 80 101059269

1.89 (48.006)

1.62 (41.148)

42 BO 117 101059064

42 B 37 101059122

2.076 (52.73)

1.75 (44.45)

42 BO 237 101059079

42 B 681 101059193

2.156 (54.76)

1.69 (42.93)

42 BO 116 100008775

42 B 153 101059090

2.108 (53.569)

1.84 (46.74)

42 BO 117 101059064

42 B 37 101059122

2.076 (52.73)

1.750 (44.45)

42 BO 237 101059079

42 B 681 101059193

2.156 (54.76)

1.69 (42.93)

2.25 (57.15)

42 BO 118 100008776

42 B 287 101059109

2.592 (65.837)

2.156 (54.762)

2.125 (53.98)

42 BO 159 101015719

42 B 387 101059133

2.49 (63.25)

1.97 (50.04)

2.75 (69.85)

42 BO 146 100009659

42 B 349 101059118

3.156 (80.16)

2.718 (69.037)

3.69 (93.73)

42 BO 238 101010057

42 B 707 101059204

4.15 (105.41)

3.67 (93.218)

3.562 (90)

101399752

101399753

4.313 (110)

101399109

101399113

1.81 (45.97)

1.88 (47.75)


5-102


Pressure-Actuated Tubing Release The pressure-actuated tubing release (PATR) is used to separate the guns from the toolstring when mechanical or slickline devices are not desirable. When separated, the guns drop off of the production tubing. Once the guns drop away, other tools and operations have no restrictions through the end of the tubing. In fact, the housing attached to the string has a greater ID than the tubing. Features • Leaves the tubing string fully open • Ideal for use in remote areas where wireline is expensive or unavailable • Ideal for situations where wireline can cause a safety hazard • Provides access to the wellbore for production logging tools • Especially suited for releasing guns prior to stimulation treatments Operation

HAL15442

Tubing pressure is applied to shear the retaining pins in the latch. Once the latch has been shifted, the finger release sub with the sleeve releases from the housing and drops the perforating assembly into the rathole.

HAL10531

The PATR consists of four main components: an upper housing, lower finger release sub, inner sleeve, and retaining latch. The PATR is pressure-balanced until the standing valve is dropped into the inner sleeve.

Standing Valve

Pressure-Actuated Tubing Release (PATR)

Pressure-Actuated Tubing Release (PATR) Specifications SAP No.


Maximum OD in. (mm)

Minimum ID Before Release in. (mm)

Minimum ID After Release in. (mm)

Standing Valve OD in. (mm)





100156751

2 3/8 (60.33) EUE 8 Rd Box × Pin

3.38 (85.85)

1.63 (41.40)

2.31 (58.67)

1.76 (44.70)

1.73 (0.53)

90,000 (40 800)

10,000 (670)

9,000 (620)

100156744

2 7/8 (73.03) EUE 8 Rd Box × Pin

3.75 (95.25)

1.812 (46.02)

2.828 (71.83)

1.86 (47.24)

1.72 (0.52)

120,000 (54 400)

10,000 (670)

10,000 (670)

101015385

3 1/2 (88.9) EUE 8 Rd Box × Pin

4.19 (106.43)

1.812 (46.02)

3.5 (88.90)

1.86 (47.24)

1.71 (0.52)

130,000 (58 900)

10,000 (670)

10,000 (670)



5-103

DPU® Downhole Power Unit The DPU® downhole power unit firing head is an electromechanical device that is designed to produce a linear force that activates a pressure-assisted firing device. The pressure-assisted device fires the perforating guns. Before the DPU firing head was used to activate the pressure-assisted firing device, this type of perforating gun activation was run on tubing. The pressure-assisted firing device was previously activated by dropping a device from the surface. The DPU firing head is run on slickline.

Fish Neck Pressure Temperature Switch Firing Head PC Board

For the DPU firing head to begin activation, several parameters must be present.

®

DPU Downhole Power Unit

• Pressure setting: The DPU firing head has a surfaceselected downhole pressure setting that must be met. Any time the well pressure at the DPU firing head drops below the selected pressure setting, the DPU firing head activation sequence is stopped

DPU® Power Rod

Push Guide

• Downhole Temperature: The DPU firing head requires a precise surface-selected downhole temperature. Any time the well temperature drops below the selected temperature setting, the DPU firing head activation sequence is stopped

Model III Firing Head

• Tool Movement: The DPU firing head has an accelerometer that detects tool movement. If the accelerometer detects motion, the other operating parameters are inactive

DPU Power Rod Push Guide

• Surface-Selected Timer: The DPU firing head has a surface-selected timer that is activated if the three previous parameters are present

The 3.66 OD DPU and 2.50-in. DPU firing head can be converted to run either the Model II-D or the Model III-D pressure-assisted firing heads.

5-104

HAL15988

HAL15990

If these four parameters are present, the DPU firing head is activated and the rod begins to stroke out. Rod travel takes approximately 20 minutes before contracting the pressureassisted firing device. When the DPU firing head rod contacts the pressure-assisted firing device, a pin is sheared and perforating is activated. After initial activation, the DPU runs for 25 minutes and then turns off.

Model III Firing Head

Adapter to Guns

Adapter to Guns

DPU® Downhole Power Unit

Conversion Kits for DPU® Downhole Power Unit Assembly No.

SAP No.

Maximum OD in. (mm)

146DFH20

00050531

3.66 (93.96)

146DFH11

00050462

2.50 (64.50)


SmartETD® Advanced Electronic Triggering Device The SmartETD® tool is an advanced electronic triggering device that provides an accurate, safe, and reliable method to run and fire downhole explosive tools using slickline. With its built-in sensor and memory capabilities, it can record and store downhole temperature and pressure data that can be used by the slickline specialists to program firing parameters. The SmartETD tool requires four parameters to be met prior to firing. These are motion, time (preset), pressure (preset), and temperature (preset). The timing sequence begins when the tool is exposed to pressure. After the tool stops, any motion resets the electronic timer. After the SmartETD timer has remained motionless for a specific period of time and has simultaneously encountered the preset temperature and pressure windows, it initiates the firing sequence. The SmartETD tool can log memory settings for pressure and temperature readings up to 12k data sets.

SmartETD® Specifications Features 101038328 SAP No.

146ETD14 Optional No-Blow No-Drop Assembly

Diameter in. (mm)

1.690 (42.93)

Length in. (mm)

60 (1524)

Max. Temperature °F (°C)

300 (149)

Max. Pressure psi (bar)

15,000 (103.42)

No-Blow, No Drop Assembly

Top Shock/Centralizer Quick Lock Assembly

®

Smart ETD Tool

Control Parameters Pressure

yes (programmable)

Temperature

yes (programmable)

Time

yes (programmable)

Motion

yes

Tension

no

Resist Detonation Capability

yes

HES RED® Capability

yes

HV Shooting Module Adapter Selectable Mechanical Pressure Switch Shock Absorber

Memory Logging Pressure

yes

Temperature

yes

No. of Points (reading)

12k data sets

Detonator Sub/Explosives as required with STD 1 3/8-in. GO™ Connection

The SmartETD tool will fire the Halliburton rig environment RED® detonator, as well as API RP-67-compliant devices. It is also capable of resisting detonation. HAL15398

VannGun® Assembly

SmartETD® Tool


5-105

Y-Block Assembly The Y-block assembly is used in dual completions and single selective completions to attach or hang guns from the long string. In single selective completions, this installation is run either for selectively shooting and testing two zones or for production when the application requires the option of producing two zones separately through one tubing string.

Retrievable Packer

In dual completions, the assembly allows for the elimination of the tail pipe between the dual packer and the gun.

Sliding-Side Door®

The Y-block assembly is available as a ported or non-ported assembly. The ported Y-block allows guns to be fired upon applying pressure to the long string. In the non-ported assembly, there is no communication between the long string and the short string. Non-Ported

Y-Block

VannGun® Assembly

Ported Time-Delay Firer

HAL10578

Hydraulic Packer

Nipple

Y-block assemblies are custom-made according to the casing ID, the tubing size and type, and the gun size. Consult your local Halliburton representative for ordering information.

Vent Tubing Release

Mechanical Firing Head

HAL8139

VannGun Assembly

Time-Delay Firer Y-Block Assembly

5-106


Gun Guides Gun guides were developed by Halliburton to maintain the proper orientation of guns attached to the short string in a dual completion. The gun orientation must be maintained so that the charges shoot away from the long string. Gun guides are also used with Y-blocks in dual-string and single-string completions.

Dual Hydraulic Set Packer

There are two types of gun guides. The delta-shaped or dual gun guide can be used when the casing ID is the same from top to bottom. If the casing at the top of the well is larger, then the wraparound guide must be used. The wraparound type may also be used in the wellbores with the same ID top to bottom.

Balanced Isolation Tool

Guides are available for most of the smaller size guns (3 3/8 in. or 85.73 mm and smaller) that are typically run on the short string side of a dual completion.

Gun Guide

VannGun® Assemblies

VannGun Assemblies Gun Guide VannGun Assemblies

HAL10577

Time-Delay Firing Head

Permanent or Retrievable Packer

Dual Completion with Wraparound Gun Guide

Tubing Release

HAL15395

Mechanical Firing Head VannGun Assemblies Time-Delay Firing Head

HAL6190

Dual Completion with Gun Guides Dual Completion with Dual Gun Guide


5-107

Hydraulic Metering Release Tool for the Single Trip System (STPP™-GH) Tool The hydraulic metering release tool is one component of the single trip system that allows us to perforate and frac-pack a zone of interest in a single trip.

Plug

Numerous safety and economic benefits accompany this capability. These benefits become even more profound as well parameters become more severe. The ever-present goal is to reduce completion CAPEX and maximize net present value. Features • Save rig time with reduced pipe trips for faster completions

Floating Piston

• Minimize fluid loss and formation damage

Metering Section

• Minimize associated well control risks • Perforate under- or overbalanced Silicone Fluid

• Perform the sand control option most suitable for your well (FP, HRWF, GP) • Complete deep, hot zones where fluid loss pills are not effective

Finger Release

Stinger/Fishneck

HAL15780

Shear Screws

Hydraulic Metering Release Tool

5-108


Hydraulic Metering Release Assembly (Low Temperature) Upper Thread Size and Type


Overall Length in. (cm)

Maximum OD in. (cm)

Effective OD* in. (cm)



Maximum Slack Off Weight on Tool lb (kg)

Minimum Slack Off Weight on Tool lb (kg)

Redressable

Weight lb (kg)

200 (93.33)

97,700 (44 315)

30,000 (13 607)

13,600 (6168)

Yes

156.46 (70.96)

4.5 (11.43) 2 7/8 EU-RD

N/A

45.47 (115.49)

4.5 (11.43)

5.5 (13.97) 7.5 (19.05)

*Effective OD of the tool is dictated by the OD of the skirt to be used. **Maximum weight on gun hanger = gun weight + slackoff weight on hydraulic release tool. ***The tool is assembled with four shear screws of 3,400 lb each.

Hydraulic Metering Release Assembly (High Temperature) Upper Thread Size and Type


Overall Length in. (cm)

Maximum OD in. (cm)

Effective OD* in. (cm)



Maximum Slack off Weight on Tool lb (kg)

Minimum Slackoff Weight on Tool lb (kg)

Redressable

Weight lb (kg)

200-350 (93.33-148.88)

97,700 (44 315)

30,000 (13 607)

13,600 (6168)

Yes

156.46 (70.96)

4.5 (11.43) 2 7/8 EU-RD

N/A

45.47 (115.49)

4.5 (11.43)

5.5 (13.97) 7.5 (19.05)

*Effective OD of the tool is dictated by the OD of the skirt to be used. **Maximum weight on gun hanger = gun weight + slackoff weight on hydraulic release tool. ***The tool is assembled with four shear screws of 3,400 lb each.


5-109

Fast Gauge Recorder The fast gauge recorder is a downhole gauge that records important pressure and temperature data in high-pressure, severe shock/vibration environments. This gauge is typically used with StimGun™* assemblies or StimTube™* tools. The pressure profile collected is used to verify proper propellant burn as well as determine the fracturing response of the formation by analyzing post-job data with PulsFrac™** software. The data the fast gauge recorder collects can be used to determine whether or not the job was executed properly, to validate computer models, and to make initial determinations of rock properties. The data can also be used to estimate fracture gradients.

Each gauge includes a shock mitigator which isolates the gauge from the tool, reducing shock and vibration (up to a factor of 10) that occurs when the gun ignites. Use of the shock mitigator lengthens the life of the recorder, battery, and sensors. A special application of the 1 11/16-in. (42.86 mm) OD gauge is its use as a “drop bar” to fire a propellant or perforating gun. The gauge can be used with firing pin and fishneck attachments as the drop bar to trigger a gun firing head. It can be left there as long as necessary to collect pressure flow data. With this feature, the customer can retrieve pressure data from the gun and also determine if the gun actually fired.

HAL15464

The fast gauge recorder can perform within the rigors of perforating applications by withstanding shock loads of 100,000 g. The tool collects and records 115,000 data points per second to give exceptionally accurate and reliable information.

The programmable multi-speed feature allows flexibility in collecting pressure, acceleration, and vibration data at various sampling speeds and time intervals. The gauge starts sampling at a slow speed and when a pressure pulse or acceleration/vibration event occurs, the gauge automatically switches to a high sampling speed, then back to an intermediate speed, and finally back to a slow sampling speed. The process can be repeated until the memory is full.

Fast Gauge Recorder *StimTube and StimGun are trademarks of Marathon Oil Company. **PulsFrac is a trademark of John F. Schatz Research and Consulting, Inc.

5-110


Features •

Measures tool movement and acceleration/vibration up to ±50,000 g

Records pressure, acceleration, vibration, and temperature

•

Current and internal/battery voltage readouts to verify proper gauge operation

Programmable low, intermediate, and high speeds and time intervals

•

Internal temperature and battery data

•

Selectable sampling rates up to 115,000 data points per second

•

Shock-hardened design

•

High sampling speed

• • •

Can be used as drop bar pressure gauge

•

Computer programming and data readout

•

Auto stop/start recording modes

•

Internal microprocessor control

•

Includes shock mitigator

•

Automatic sensor testing and balancing

•

Up to 1,048,756 data points of memory

•

Selectable pressure, temperature, and acceleration/ vibration ranges

•

Uses low-cost standard AA alkaline or lithium batteries

Fast Gauge Recorder Specifications Gauge Dimensions

Maximum Acceleration and Vibration

Current Drain

Computer/ Communications

Software

Sensor Frequency Response

Power Requirements

1 11/16 in. OD × 50 in. (22 lb)

± 50,000 g

500 uA sleeping 100 mA sampling

750 MHz or greater PC, with standard RS-232

Windows 98*

0 to 10,000 Hz

6 to 12 volts, AA alkaline or lithium cells

*Windows 2000 or NT is recommended.

Sampling Rate

Temperature Range °F (°C)

Pressure Range psi (bar)

Data Resolution

Memory Capacity

115,000 points/second down to one sample every 10 seconds

-40 to 248 (-40 to 120)

35,000 (2413) peak 15,000 (1034) continuous

12 bits @ 115,000 data points/second

1,048,576 data points


5-111

Gamma Perforator Logging Tool The gamma perforator is a ruggedized depth correlation tool designed specifically for operation with explosive equipment, such as perforating guns, packers and plugs, and coring guns. The tool can operate in liquid or gas-filled, openhole or cased hole wells. The gamma perforator is available in two sizes: 3.375-in. and 1.687-in. version. The gamma perforator is not intended to provide a calibrated gamma measurement. No borehole corrections are performed in the algorithms, and calibration procedures are only used to ensure that the tool is working properly before and after jobs.

Features • Offers three configurations: – Normal perforating and plug setting – Stand-alone gamma/CCL-correlation – Side wall coring • High resistance minimizes accidental firing risks • Slimhole version allows perforating operations to be performed without the need to pull tubing from the well

The tool has a built-in shock absorber system and does not require an external shock sub. In addition, the electronic components are covered with silicon potting to help dampen the shock wave that impacts components. All sub-assemblies required for perforating with different connections must be ordered individually.

Gamma Perforator Logging Tool Specifications Tool Length

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

GPLT

5.03 (1.5)

3.375 (85.7)

20,000 (137.9)

350 (176.7)

82 (37.2)

GPST

6.23 (1.9)

1.69 (42.9)

18,000 (124.1)

350 (176.7)

35 (15.9)

5-112


Detonators Capsule RED® Detonators

Features • Does not use primary explosives • Redundant electrical components for enhanced safety • Ceramic firing capacitors for enhanced reliability • Surface-mount circuit technology for ruggedness • Metal housing for radio frequency shielding • High-output explosive load and flyer plate for enhanced reliable detonation transfer • Dual sealing methods at top of detonator • Patented sealing for detonating cord interface Specifications • No-fire voltage level: 120 VDC • Firing voltage: 155 to 190 VDC (nominal 175 VDC) • Recommended firing method: “Dump firing.” Deliver 250 VDC to the firing head • Recommended firing polarity: positive or negative DC

• Requirements for radio silence waivers: – Transmitters with power less than 1 watt = no exclusion area – Handheld RF transmitters (cell phones and walkietalkies) operation— minimum distance radius from explosive workplace = no minimum distance restriction

– Output pellet = 500 mg HMX • Environmental rating: 375°F at 15,000 psi for one hour • UN shipping classification: 1.4S

– All other RF sources (land or offshore, mobile or fixed) operation—minimum distance radius from explosive workplace = no minimum distance restriction – Offshore workboats (or other 1-MHz, 1,000 watt or above transmitters) operation— minimum distance radius from explosive workplace = no minimum distance restriction – Stray voltage measurement, electric welding operation, or electrical cathodic protection systems = operation acceptable if stray voltage is less than 2 V • Bleed-off time with power removed: 5 sec • Semi-conductor bridge (SCB) resistance: 2 ohms • No-fire DC power dissipation (stand-alone SCB without circuit): 5 watts minimum • Energetic materials: – Ignition pyrotechnic mix = 50 mg THKP


– Transition column = 400 mg HMX

HAL9251

The capsule RED® detonator is an advanced electro-explosive device designed for use with capsule perforating guns and other explosive devices where a pressure-resistant detonator is required. The design features of the capsule RED detonator provides significantly improved safety characteristics over conventional resistorized devices and allows wellsite activities to continue uninterrupted while perforating.

Capsule RED® Detonator

5-113

RED® GO™-Style Thermal Igniter

Features • Mates with top subs and adapters for industry standard setting tools • Redundant electrical components for enhanced safety • Multiple ceramic firing capacitors for reliability • Surface-mount circuit technology for ruggedness • Thermally conductive semiconductor bridge for stray power dissipation • Metal housing for radio frequency shielding

– Handheld RF transmitters (cell phones and walkietalkies) operation— minimum distance radius from explosive workplace = no minimum distance restriction – All other RF sources (land or offshore, mobile or fixed) operation—minimum distance radius from explosive workplace = no minimum distance restriction – Offshore workboats (or other 1-MHz, 1,000 watt or above transmitters) operation— minimum distance radius from explosive workplace = no minimum distance restriction – Stray voltage measurement, electric welding operation, or electrical cathodic protection systems = operation acceptable if stray voltage is less than 2 V

• Thin aluminum end-closure for low debris characteristics

• Bleed-off time with power removed: 5 sec

Specifications • No-fire voltage level: 120 VDC

• SCB resistance: 2 ohms

• Firing voltage: 155 to 190 VDC (nominal 175 VDC)

• SCB no-fire power dissipation: 5 watts minimum – Ignition pyrotechnic mix = 150 mg THKP pressed in SCB header

• Recommended firing polarity: positive or negative DC

– Main load = .15 gm FFFG black powder and .75 gm THKP loose powders

– Transmitters with power less than 1 watt = no exclusion area

5-114

RED® GO™-Style Thermal Igniter

• Energetic materials:

• Recommended firing method: “Dump firing.” Deliver 250 VDC to the firing head

• Requirements for radio silence waivers:

HAL11756

The RED® igniter is an advanced electro-explosive device used to initiate gas-generating power charges inside oilfield setting tools. The design features of the RED igniter provide significantly improved safety characteristics over conventional resistorized devices and allow many wellsite activities to continue uninterrupted while using power setting tools.

• Temperature rating: 375°F for one hour • UN shipping classification: 1.4G


Block RED® Detonators The block RED® detonator is an advanced electro-explosive device used to initiate perforating guns. The design features of the block RED detonator provide significantly improved safety characteristics over conventional resistorized devices and allow wellsite activities to continue uninterrupted while perforating.

• Energetic materials:

Features • Does not use primary explosives

• UN shipping classification: 1.4S

– Ignition pyrotechnic mix = 50 mg THKP – Transition column = 400 mg HMX – Output pellet = 500 mg HMX • Temperature rating: 375°F for one hour

• Redundant electrical components for enhanced safety • Ceramic firing capacitors for enhanced reliability • Surface-mount circuit technology for ruggedness • Metal housing for radio frequency shielding • High-output explosive load and flyer plate for enhanced reliable detonation transfer • Fluid-disabled to prevent gun damage in the event of a seal failure Specifications • No-fire voltage level: 120 VDC • Firing voltage: 155 to 190 VDC (nominal 175 VDC) • Recommended firing method: “Dump firing.” Deliver 250 VDC to the firing head • Recommended firing polarity: positive or negative DC • Requirements for radio silence waivers:

– All other RF sources (land or offshore, mobile or fixed) operation—minimum distance radius from explosive workplace = no minimum distance restriction – Offshore workboats (or other 1-MHz, 1,000 watt or above transmitters) operation—minimum distance radius from explosive workplace = no minimum distance restriction – Stray voltage measurement, electric welding operation, or electrical cathodic protection systems = operation acceptable if stray voltage is less than 2 V

HAL11412

– Handheld RF transmitters (cell phones and walkie-talkies) operation—minimum distance radius from explosive workplace = no minimum distance restriction

Block RED® Detonator

• Bleed-off time with power removed: 5 sec • SCB resistance: 2 ohms • SCB no-fire power dissipation: 5 watts minimum


5-115

Top Fire RED® Detonators The top fire RED® detonator is an advanced electroexplosive device used to initiate perforating guns, jet cutters, and severing tools. The design features of the top fire RED detonator provide significantly improved safety characteristics over conventional resistorized devices and allow wellsite activities to continue uninterrupted while perforating.

• SCB no-fire power dissipation: 5 watts minimum

Features • Does not use primary explosives

• UN shipping classification: 1.4S

• Energetic materials: – Ignition pyrotechnic mix = 50 mg THKP – Transition column = 400 mg HMX – Output pellet = 500 mg HMX • Temperature rating: 375°F for one hour

• Redundant electrical components for enhanced safety • Ceramic firing capacitors for reliability • Surface-mount circuit technology for ruggedness • Thermally conductive semi-conductor bridge for stray power dissipation • Metal housing for radio frequency shielding • High-output explosive load and flyer plate assure reliable detonation transfer Specifications • No-fire voltage level: 120 VDC • Firing voltage: 155 to 190 VDC (nominal 175 VDC) • Recommended firing method: “Dump firing.” Deliver 250 VDC to the firing head • Recommended firing polarity: positive or negative DC • Requirements for radio silence waivers: – Handheld RF transmitters (cell phones and walkie-talkies) operation—minimum distance radius from explosive workplace = no minimum distance restriction – All other RF sources (land or offshore, mobile or fixed) operation—minimum distance radius from explosive workplace = no minimum distance restriction

– Stray voltage measurement, electric welding operation, or electrical cathodic protection systems = operation acceptable if stray voltage is less than 2 V

HAL11413

– Offshore workboats (or other 1-MHz, 1,000 watt or above transmitters) operation—minimum distance radius from explosive workplace = no minimum distance restriction

Top Fire RED® Style Detonator

• Bleed-off time with power removed: 5 sec • SCB resistance: 2 ohms

5-116


Dynamic Modeling Dynamic modeling is used to understand perforation performance, tubing movement, shock loading, and wellbore pressure response during well intervention.

The ability to understand dynamic behavior is critical for Halliburton to deliver world-class solutions to its customers.

PerfPro® Process PerfPro® Process– Predicting In-Situ Charge Performance Casing Gun Test Specimen

Water Steel Form

HAL15333

28-Day Concrete

API Section 1 Concrete Target

HAL15393

Halliburton's PerfPro® charge performance calculations for penetration are based on proprietary models derived from theoretical and experimental studies carried out at Jet Research Center (JRC), a Halliburton Company. API RP-19B defines the procedure for evaluating gun system performance at surface conditions in unstressed concrete targets. A fully loaded gun system is perforated in actual casing surrounded by concrete, and the target penetration, casing entrance hole, and burr height are recorded. Halliburton's PerfPro program transforms API RP-19B Section I surface test data to downhole conditions by correcting for the formation compressive strength and effective stress. The associated downhole charge performance takes into account the gun positioning, casing grade, wellbore fluid density, and well condition.

PerfPro® Charge Performance Calculations


5-117

The primary objective of the Halliburton PerfPro® process is to optimize gun selection and job execution to deliver the highest productivity index or lowest skin factor. Therefore, after charge performance values are calculated, the PerfPro program makes a productivity index and skin factor assessment. The PerfPro process accounts for skin factors due to perforation, drilling damage, partial penetration, nonDarcy flow, and well deviation. A fully three-dimensional

(3D) flow model is utilized, as described by Ansah et al. 2001, to characterize the skin component due to perforation geometry. Input well parameters and calculated charge performance values are linked to an artificial neural network, trained by the 3D finite element model, to generate the perforation skin component. The productivity index and total skin factor are corrected, utilizing analytical calculations for well inclination, partial penetration effect, non-Darcy flow, and drilling damage effects.

CHARGE PERFORMANCE REPORT

General Data Reservoir fluid type Borehole Diameter Porosity Permeability Formation Compressive Strength Drilling Damage Radius

Oil 12.25 24.0 1191.0 3891.0

in % md psi

Mid-Perforation Depth Reservoir Pressure Reservoir Temperature Completion Fluid Type Completion Fluid Density

3250.0 1464.0 112.0 Diesel 6.83

3.0

in

Lithology

Sandstone

ft - TVD psi °F lb/gal

Completion Data Casing Description Outer Diameter Inner Diameter Grade Weight

1 9.63 8.68 N-80 47.0

in in

PRODUCTIVITY REPORT

lb/ft

Completion Data

Perforator Information Charge Name

Charge Type Charge Loading, gm Phasing, deg Shot Density, spg Gun Position Avg Formation Penetration, in Avg Entrance Hole Dia*, in API 5th Edition Section I Data Total Target Penetration, in Entrance Hole Diameter, in

Gun 1 7" MILLENNIU M DP 39.0 45.0 12 Eccentered 40.68 0.36

Gun 2 4" MILLENNIU M SDP 39.0 60.0 5 Eccentered 43.22 0.29

Gun 3 4-1/2" MILLENNIU M SDP 22.7 30.0 12 Eccentered 23.78 0.28

43.3 0.36

52.0 0.37

26.8 0.38

Reservoir Fluid Type Drainage Radius Pseudo-Skin due to Well Deviation

Oil 1500.0 -0.697

Distance To Top Perf Interval Skin due to Partial Penetration

0.0 0.0

ft

1191.0 0.2 1.1 4.36

md

ft

Well Deviation @ Perfs Net Sand Thickness Perforated Total Length

56.2 27.0 27.0

deg ft ft

Reservoir Pressure Reservoir Temperature Porosity API Gravity

1464.0 112.0 24.0 32.6

psi °F % °API

Reservoir Data Permeability Anisotropic Ratio, kV/kH Formation Volume Factor Formation Fluid Viscosity

bbl/stb cp

Perforator Information Charge Name

Gun Position Shot Phasing, deg Shot Density, spf Avg Formation Penetration, in Avg Entrance Hole Dia, in Underbalance Condition, psi

Gun 1 7" MILLENNIU M Eccentered 45.0 12 40.68 0.36 -350.0

Gun 2 4" MILLENNIU M Eccentered 60.0 5 43.22 0.29 -350.0

Gun 3 4-1/2" MILLENNIU M Eccentered 30.0 12 23.78 0.28 -500.0

Productivity Analysis Gun No. 1 Gun No. 2 Gun No. 3

5-118

Total Skin -0.666 -0.158 0.319

Perforation Skin 0.031 0.539 1.016

Productivity Index, STB/day/psi 7.2 6.682 6.261


Total Pressure Drop Vs Flow Rate

1600

Total Pressure Drop (psi)

1400 1200 1000 800 600 400 200 0

2000

HAL15390

0

4000 Gun No.1

6000 Gun No.2

8000

10000

Gun No.3

PerfPro® Graph Example

Pl and Total Skin Vs Gun

0.0

HAL15389

6.2

Gun 1

Gun 2 Gun Number

Gun 3

Total Skin

1.0

7.2

-1.0

PI Total Skin

PerfPro® Graph Example


5-119

Near-Wellbore Stimulation and PulsFrac™ Software In many formations, the remaining reservoir pressure or underbalance is insufficient to effectively clean the perforations as suggested by King et al. (1985) and others. In other cases, where formation competence is questionable and the risk of sticking perforating assemblies is greater, sufficient underbalance pressure is not possible, aid in lowering treating pressures is needed, or bypassing near-wellbore damage is needed, then near-wellbore stimulation could be a possible perforating solution. To address the perforation damage in these cases, some (Handren et al. 1993, Pettijohn and Couet, 1994; Snider and Oriold, 1996) have suggested near-wellbore stimulation using extreme overbalanced (EOB) perforating and propellant assisted perforating. Nearwellbore stimulation provides perforation breakdown in preparation for other stimulation methods, and therefore, eliminates the need for conventional perforation breakdown methods.

Near-wellbore stimulation can be achieved using energized fluids, propellants, or a combination of both, and all can be properly designed using the PulsFrac™* dynamic pressure modeling software. The PulsFrac software allows a job simulation to be performed to determine anticipated peak pressures, injection rates, injection volumes, and theoretical fracture lengths.

Wellhead Isolation Tool

Nitrogen

EOB - Energized Fluid Stimulation EOB techniques involve pressuring the wellbore with compressible gases above relatively small volumes of fluid. The gases have a high level of stored energy. Upon expansion at the instant of gun detonation, the gases are used to fracture the formation and divert fluids to all intervals. The high flow rate through relatively narrow fractures in the formation is believed to enhance near-well conductivity by extending the fractures past any drilling formation damage.

300 ft of Fluid Radioactive Collar

Packer

Tubing

Pressure-Operated Venture Firing Head

Bauxite Proppant Carrier

HAL15314

VannGun® Assembly

Typical Extreme Overbalanced (EOB) Perforating Assembly

5-120


Propellant Stimulation Propellant stimulation can be provided during the perforating event with propellant-assisted perforating. Propellant-assisted perforating using the StimGun™ assembly, patented by Marathon Oil Company, combines solid propellant technology with conventional perforating. The StimGun assembly may be utilized for either EOB or conventional underbalanced perforating. The hardware utilized for either system remains the same aside from added protection by using centralizer rings to protect the brittle propellant material. The propellant sleeve in the StimGun assembly simply slides over the perforation scalloped carrier and is held in position on the gun with the centralizer rings.

The propellant material is potassium perchlorate, an oxidizer that burns rapidly, creating carbon dioxide gas. As the shaped charges detonate, the propellant is ignited by extreme heat from the gun system. As it burns, the propellant generates carbon dioxide gas at high peak pressures typically well above the formation fracture gradient. The StimGun assembly is an effective method for mild stimulation (fractures on order of 2 to 9 ft) for treating nearwellbore problems.

RA Marker

Safety Joint

Retrievable Packer

Propellant stimulation can also occur using solid propellant conveyed in protective carriers. This type of propellant can virtually be unlimited in length by simply interconnecting the carriers to place across existing perforations, slotted liner, or in openhole. The propellant is ignited using a sealed ignition system, and similar to the StimGun assembly once the propellant is ignited it will generate carbon dioxide at high peak pressure, allowing for adequate stimulation of the desired formation interval. As with all near-wellbore stimulation techniques, PulsFrac™ software aids in proper job design and provides estimated peak pressures, injection rates, and volumes to ensure successful propellant stimulation.

Fill Disk

Firing Head Centralizer

Fast Gauge Recorder

HAL15977

Building upon the success of EOB perforating, Marathon Oil Company incorporated proppant carriers into the perforation assembly to introduce proppants into the flow path as the gun detonates. The POWR*PERF™ process, patented by Marathon Oil Company, further enhances productivity by scouring the perforations to leave some residual conductivity on the fracture plane. Most EOB perforating jobs are designed with a minimum pressure level of 1.4 psi/ft of true vertical depth. For optimum results, it is suggested to utilize the highest possible pressure level without compromising wellbore integrity or operation safety.

StimGun™ Assembly


5-121

Near-Wellbore Stimulation Increasing conductivity past near-wellbore damage is critical in maximizing a well’s producibility. Halliburton provides multiple solutions suitable for various stimulation scenarios depending upon the well's restriction, completion methods, and reservoir characteristics.

Radioactive Marker

StimGun™* Assembly

Safety Joint

The StimGun™ assembly is a process that combines perforating and perforation breakdown with propellant in a single tool and operation. The StimGun assembly has a propellant sleeve over a conventional Halliburton VannGun® perforating gun assembly. When the guns are detonated, the propellant sleeve is ignited, instantly producing a burst of high-pressure CO2 gas. This gas enters the perforations, breaks through any damage around the perforation tunnel, and creates short fractures near the wellbore. As the gas pressure in the wellbore dissipates, the gas in the formation surges back into the wellbore carrying with it damaging fines. The StimGun assembly has been used with great success in conventional underbalanced perforating to obtain the benefits of both extreme overbalance from propellants and the surging effect from maximum underbalance.

Retrievable Packer

Fill Disk

Features

Firing Head

• Improved production or injectivity with greater uniformity in the perforation breakdown

Centralizer

• Improved connectivity to the undamaged reservoir matrix by extending fractures past damage induced by either drilling or completion practices • Improved conventional underbalanced perforating by combining benefits of extreme overbalance in one operation

Fast Gauge Recorder

• Excellent pre-hydraulic fracture treatment assists in keeping perforations open and minimizes tortuosity effects, resulting in lower breakdown pressures and horsepower requirements on location *StimGun is a trademark of Marathon Oil Company and is licensed to Halliburton by Marathon.


HAL15417

• Stimulation of near-wellbore on zones that cannot be treated conventionally with acid or hydraulic fracturing due to undesirable production from nearby gas cap or water contact

StimGun™ Assembly

5-127

Operation

HAL5941

The StimGun™ assembly consists of a cylindrical sleeve of gas-generating propellant-potassium perchlorate that slides in place over the outside of a conventional hollow steel carrier perforating gun. The StimGun assembly can be conveyed on either wireline, coiled tubing, or in a conventional perforation configuration. StimGun sleeves are similar to PVC pipe and must be protected and positioned on the gun with an oversized retaining collar that is secured to the gun scallop. Additional sleeve protection is achieved through centralization of the gun sections at the tandems.

The StimGun™ tool can be run on Halliburton tubingconveyed or wireline equipment.

5-128


StimGun™ Assembly Specifications Gun Size in.

Sleeve SAP No.

Sleeve OD in. (mm)

Sleeve ID in. (mm)

Minimum Centralizer OD* in. (mm)

Propellant Mass** lb/ft (kg/m)

2 1/2

58179

3.11 (78.99)

2.50 (63.50)

3.50 (88.90)

2.01 (2.99)

2 3/4

58190

3.36 (85.34)

2.75 (69.85)

3.76 (95.50)

2.01 (2.99)

3 1/8

58193

3.72 (94.48)

3.21 (81.53)

4.13 (104.90)

2.33 (3.46)

3 3/8

58195

4.02 (102.10)

3.38 (85.85)

4.40 (111.76)

2.67 (3.98)

4

58196

4.71 (119.63)

4.05 (102.87)

5.09 (129.28)

3.68 (5.47)

4 5/8

57514

5.21 (132.33)

4.72 (119.88)

5.63 (143.00)

3.33 (4.96)

5 1/8

101240496

5.81 (147.63)

5.175 (131.44)

6.18 (156.97)

3.99 (5.94)

5 3/4

215347

6.45 (163.83)

5.75 (146.05)

6.95 (176.53)

4.68 (6.97)

7

58159

7.88 (200.15)

7.09 (180.08)

8.25 (209.55)

7.01 (10.43)

StimGun™ sleeves are manufactured in standard 3 ft (0.91 m) lengths and are rated for a service temperature of 350°F (177°C). The sleeves are non-reactive to most commonly used oilfield fluids, including acids. *The StimGun sleeve is an oxidizer that is bonded with a resin or plastic, making it quite brittle; therefore, it is required that the perforating gun be centralized to this minimum OD to provide protection when the assembly is in the wellbore. **CO2 gas generated from a propellant burn is estimated at 7.06 scf per kg of material at standard conditions.

Retaining Collar Assembly Specifications SAP No.

Gun Size in.

OD in. (mm)

ID in. (mm)

Sleeve OD in. (mm)

Minimum Centralizer OD in. (mm)

Flow Area through Collar in.2 (mm2)

101233588

2 1/2

3.38 (85.85)

2.56 (65.02)

3.11 (78.99)

3.51 (89.15)

1.10 (709.67)

101233598

2 3/4

3.63 (92.20)

2.81 (71.37)

3.36 (85.34)

3.76 (95.50)

1.15 (741.93)

101233215

3 1/8

4.02 (102.10)

3.18 (80.77)

3.72 (94.48)

4.13 (104.90)

1.21 (780.64)

101240387

3 3/8 12 spf

4.27 (108.45)

3.43 (87.12)

4.02 (102.10)

4.40 (111.76)

1.71 (1103.22)

101222271

3 3/8

4.27 (108.45)

3.43 (87.12)

4.02 (102.10)

4.40 (111.76)

1.71 (1103.22)

101233163

4

4.96 (125.98)

4.06 (103.12)

4.71 (119.63)

5.09 (129.28)

2.00 (1290.32)

101227396

4 5/8

5.50 (139.70)

4.69 (119.12)

5.21 (132.33)

5.63 (143.00)

2.00 (1290.32)

101239368

5 1/8

6.05 (153.67)

5.19 (131.82)

5.81 (147.32)

6.18 (156.97)

2.21 (1425.80)

101303748

5 3/4

6.70 (170.18)

5.82 (147.82)

6.45 (163.83)

6.95 (176.53)

2.70 (1741.93)

101292913

7

8.15 (207.01)

7.07 (179.57)

7.88 (200.15)

8.25 (209.55)

3.75 (2419.35)



5-129

Propellent Stimulation Tool Assembly The stimulation tool assembly is a process that uses the same solid propellant technology employed by the StimGun™ assembly to stimulate existing perforations, slotted liners, or openhole sections when it is not desirable to add perforations. The stimulation assembly is assembled with propellant and standard detonating cord to provide the ignition system. When the detonating cord is ignited, the solid propellant breaks up into many smaller pieces, allowing it to burn very rapidly and producing CO2 gas. This gas enters the perforations, breaking through any damage around the perforation tunnel, creating short fractures near the wellbore. As the gas pressure in the wellbore dissipates, the gas in the formation surges back into the wellbore, carrying with it damaging fines. Stimulation assembly jobs are designed using Halliburton’s PulsFrac™ simulator, which assists in achieving consistent results without compromising safety or wellbore integrity. Operation The stimulation assembly consists of a solid stick of gasgenerating propellant-potassium perchlorate with detonating cord run through it. The assembly can be conveyed on either wireline, coiled tubing, or threaded pipe. Standard perforating safety, arming, and firing procedures are used. The industry standard detonating cord provides consistent, reliable, and instantaneous ignition over the entire length of the stimulation assembly.

HAL22575

When deployed on coiled tubing or threaded pipe, the stimulation assembly is run inside a vented hollow steel carrier.

Stimulation Assembly

5-130


Features • Improved production or injectivity with greater uniformity in the perforation breakdown • Improved connectivity to the undamaged reservoir matrix by extending fractures past damage induced by either drilling or completion practices • Stimulation of near-wellbore on zones that cannot be treated conventionally with acid or hydraulic fracturing due to undesirable production from nearby gas cap or water contact

• Excellent pre-hydraulic fracture treatment assists in keeping perforations open and minimizes tortuosity effects resulting in lower breakdown pressures and horsepower requirements on location • Selective stimulation of long openhole horizontal sections This assembly is currently available in 2 7/8 OD ported carriers. Contact TCP technology for more information.

Stimulation Tool Assembly Specifications SAP No.

Tool Size in.

Upper Thread Size and Type




Maximum OD in. (mm)

Temperature Rating1 °F (°C)

Pressure Rating1 psi (bar)

Tensile Rating2 lb (kg)

Redressable

Weight (No Explosives) lb (kg)

101566827

2 7/8

2 7/8 Gun Pin

2 7/8 Gun Box

26.25 (8.0)

25.98 (7.92)

2.88 (73.2)

300 (149)

8500 (578)

110,800 (50 250)

Yes

249 (113)

1 Based 2

on control line collapse rating 2 7/8 gun box at top sub


5-131

POWR*PERFSM* Perforation/Stimulation Process POWR*PERFSM perforation/ stimulation process is a completion process that uses proven extreme overbalance perforating techniques. This method is coupled with the release of an erosive agent at the moment of VannGun® detonation to clean and scour near-wellbore damage and enhance conductivity of fractures created by extreme overbalance perforating.

The fluid “spear” is driven ahead of the expanding nitrogen gas into the formation at velocities that can exceed 140 bbl/min. The bauxite material is ejected into the fluid stream at the moment of detonation by specially designed shaped charges. The combination of fluid and bauxite serves to fracture, erode, and scour all of the perforations, and to further enhance the fractures created by extreme overbalance perforating.

Features • Overcomes skin damage in low pressure, high permeability wells

*POWR*PERF is a service mark/trademark of Marathon Oil Company and licensed by Halliburton.

• Can be a useful pre-frac evaluation tool • Applicable to both new wells and wells with nearby water or gas

Retrievable Packer

• Compatible with all casing sizes and tubulars Operation

5-132

KV-II Firing Head

Proppant Carrier

VannGun® Assembly HAL15314

The POWR*PERF tool is run as a normal part of the completion assembly. A non-damaging fluid is added to the tubing to serve as a medium for carrying the bauxite into the formation. After the assembly has been positioned across the producing zone, the tubing is energized with nitrogen gas to create a pressure gradient of no less than 1.4 psi/ft (31 bar/m). A model KV-II firing head, which has been pre-set to function at the desired bottomhole pressure, detonates the VannGun assembly and opens flow ports to allow the fluid and nitrogen to rush toward the formation.

POWR*PERFSM Perforation/Stimulation Process


PerfStim™* Process The PerfStim™ process uses an extreme overbalanced condition to simultaneously perforate and stimulate a well. The process not only produces cleaner perforations in lowpressure formations, it also initiates fractures in the formation, reducing stimulation costs. Features • Gets production flowing quickly • Saves rig time • Helps develop negative skin factors • Gives an early evaluation of a well’s potential • Uses less horsepower than full scale stimulations Operation In the PerfStim process, an extreme overbalanced condition is created—pressure gradients of at least 1.4 psi/ft (31 bar/m).

Packer

When the perforating gun fires, the pressure drives a fluid “spear” into the perforation at velocities exceeding 3,000 ft/sec (900 m/sec) and at rates that can exceed 140 bbl/min. Crushed zone damage is removed and small fractures are created—improving initial production and treatment results. Firing Head

*The PerfStim process is licensed to Halliburton by Oryx Energy Company. PerfStim is a trademark of Oryx Energy Company.

HAL15387

VannGun® Assembly

Halliburton’s VannSystem® toolstring is used in typical PerfStim™ procedures. The tubing conveyed system helps to allow for the highest possible bottomhole pressures. A small volume (usually no more than a 300-ft column) of nondamaging fluid is placed above the gun, then pressured with nitrogen. If needed, a liquid can be bullheaded on top of the nitrogen column. The VannGun® perforating assembly can remain attached to the toolstring or dropped into the rathole after the guns have been fired.


5-133

Oriented Perforating

G-Force® Precision Oriented Perforating System Historically, oriented perforating was attempted via external orienting devices and weights (external to the gun and exposed to the casing environment). In the externally oriented systems, there is added friction created by the guns moving axially down the casing wall, which can significantly work against the orienting mechanism. In addition, doglegs and other discontinuities during the deployment can cause loss of orientation. It was conceived that if the rotating device could be taken inside the protective environment of the carrier, adverse factors that can significantly decrease the ability to orient the guns in a desired direction could be overcome, if not completely eliminated. Halliburton's G-Force® system is comprised of an internal orienting charge tube assembly and gun carrier, which allows perforating in any direction irrespective of the gun's position relative to the casing.

Features • Able to go through restrictions not possible with older systems • Since the orienting mechanism of the internal orienting system is contained within the gun carrier, the fundamental orienting design is unaffected by potential restrictions in the completion string • Able to run through tubing and orient in casing • No need for fin tandems, eccentric tandems, and swivel subs • Increased orientation accuracy: the operating range will be for wells of 25° deviation and greater. For deviated wells, the accuracy range is ± 5° • Compatible with live well intervention systems such as the AutoLatch™ connector, ratchet connector, and the modular gun system • Gun assemblies can be centralized in the casing • Can be deployed on coiled tubing, wireline, slickline, or jointed pipe • No external weight bars required means no gaps between loaded sections and no lost shots

HAL12019

The benefits of sand prevention or improved stimulation performance can be enjoyed using any of Halliburton's leading oriented perforation technologies. Halliburton oriented perforating solutions can be deployed using a wide range of conveyance methods providing reliable world-class results.

G-Force® System

5-134


3.375-in. G-Force® System Specifications SAP No.


Gun OD in. (mm)

Length ft (m)

Maximum Shot Density

Shot Phasing

Perforation Planes

Vertical Shot Spacing in. (mm)

Maximum Diameter after Detonation in. (mm)

Distance from Top End of Gun to First Shot in. (mm)

101300078

2 7/8 (73.03) 6P Acme

3.375 (85.73)

22 (6.7)

4 spf (13 spm)

180°

2

2.8 (71.12)

3.42 (86.87)

8.50 (215.90)

SAP No.

Tensile Load lb (kg)


Tandem Tensile Load lb (kg)

Survival Test Medium

101300078

238,000 (107 954)

25,000 (1725)

355,000 (161 025)

Fluid

4.625-in. G-Force® System Specifications SAP No.


Gun OD in. (mm)

Length ft (m)


Shot Phasing

Perforation Planes

Vertical Shot Spacing in. (mm)

Maximum Diameter after Detonation in. (mm)

Distance from Top End of Gun to First Shot in. (mm)

101305067

4.00 6P Acme (101.60 Acme)

4.625 (117.48)

22 (6.7)

4 spf (13 spm)

180°

2

2.8 (71.12)

4.69 (118.87)

8.50 (215.90)

SAP No.

Tensile Load lb (kg)


Tandem Tensile Load lb (kg)

Survival Test Medium

101305067

403,000 (182 783)

20,000 (1378.95)

563,000 (255 372)

Fluid

G-Force® System Specifications SAP No.

Gun OD in.

Length ft


Shot Phasing

Perforation Planes

Maximum Shots per Gun

Distance to First Shot in.

Charge

101450833

4 5/8

16.00

4 spf

10°-350°

2

52

7.94

101466192 - 39g DP HMX

101498446

4 5/8

22.00

4 spf

0°-180°

2

76

9.94

101210636 - 39g Millennium™

101435773

4 5/8

22.00

4 spf

0°

1

75

8.60

101210636 - 39g Millennium

101426443

4 5/8

22.00

4 spf

10°-350°

2

75

8.60


101390900

4 5/8

22.00

4 spf

0°-180°

2

75

8.60


101294752

3 3/8

4.83

4 spf

10°-350°

2

14

9.50


101640605

3 3/8

4.83

4 spf

180°

1

14

9.50


101515354

3 3/8

22.00

4 spf

0°-180°

2

72

9.25

101371884 - 25g Super DP

101407434

3 3/8

22.00

4 spf

0°-180°

2

72

9.25


101406739

3 3/8

22.00

4 spf

0°

1

72

9.25


101295030

3 3/8

2.00

4 spf

0° OR 180°

1 or 2

2

10.00


101630791

2 7/8

16.00

4 spf

10°-350°

2

56

7.74

101571815 - 11.1g G-Force® HMX

101621606

2 7/8

4.00

4 spf

0° OR 180°

1 or 2

12

7.62

101571815 - 11.1g G-Force HMX

101600677

2 7/8

22.00

4 spf

10°-350°

2

78

7.62

101571815 - 11.1g G-Force HMX

101563379

2 7/8

22.00

4 spf

0° OR 180°

1 or 2

78

7.62

101571815 - 11.1g G-Force HMX


5-135

Oriented Perforating with Modular Guns There are several methods available for orienting perforating guns in horizontal and highly deviated wells, such as the G-Force® system. In vertical wells it can be more difficult to orient perforations in a particular direction. One proven method is the oriented Modular Gun System.

Lug Stinger

HAL24405

To accomplish this, a standard auto-J gun hanger is used in conjunction with specially modified skirts and stingers for the modular guns. The stingers are made with locating lugs, and the skirts are modified to locate on the lugs. The gun hanger is run in the well and set on wireline using normal procedures. A gyro steering tool is then run to determine the direction of the locating lug on the gun hanger stinger. The skirts and stingers on the remaining gun modules are then adjusted accordingly so that when they are landed, the shots will be oriented to the desired direction.

Modified Skirt

HAL24406

This system has been used successfully in standard applications when perforating for production, and in special applications such as shooting from a relief well into a well that is blowing out.

Gun Hanger with Modifications

5-136

Modular Gun with Modifications

HAL24403

HAL24407

HAL24404

Modified Stinger

Modified Skirt and Stinger Assembly


Finned Orienting Tandem As perforating guns are run into the well, and transition from a vertical to deviated position occurs, the fin will orient to the high side of the wellbore. The finned tandem works on the principle of gravity whereby the weight of the perforating guns rotates towards the lowest side of the wellbore and is aided by the additional standoff from the casing wall created by the connected fin. Features • Built with an adjustable ring, which makes it possible to orient the shots in the casing to a predetermined direction • Tensile strength of finned tandem equivalent to the standard gun connectors • Available for most gun sizes HAL 2440

9

• Cost effective perforation orientation solution

Finned Orienting Tandem


5-137

Eccentric Orienting Tandem For several years, Halliburton successfully ran oriented perforating jobs using a fin welded to a gun connection every 30 ft in conjunction with swivel assemblies.

The eccentric tandem works on the same principle as the fins. As the guns are run into the well, and transition from a vertical to deviated position occurs, the natural tendency is for the fin to orient to the high side of the wellbore. The eccentric tandem works on the same principle. The eccentric tandems allows for a greater degree of accuracy with an overall smaller profile. Features

HAL15456

Now, a second method for orienting perforations referred to as eccentric subs has been developed. The eccentric sub is run in place of the finned tandem still in conjunction with a swivel assembly.

Eccentric Orienting Tandem

Eccentric subs allow perforating guns to be oriented in situations where the fin system is not ideal due to restrictions in the casing, fishing concerns, welding concerns, etc. Several tests and wells have been perforated using this new technique in the North Sea area and the Gulf of Mexico. • Built with an adjustable ring, which makes it possible to orient the shots in the casing to a predetermined direction • Tensile strength of the eccentric sub equivalent to the standard gun connectors • Available for most gun sizes • Eliminates the use of welded fins on the connectors

5-138


Special Applications Modular Gun System Through a special arrangement of perforating equipment, Halliburton’s modular gun system permits the optimum number of guns to be removed via slickline or electric line so larger intervals can be perforated simultaneously. In fact, the modular gun system is so innovative, Halliburton has patented* this unique system, proving once again our commitment to bring the latest technology to the wellsite.

Retrievable Firing Head (Wireline Conveyed) Wireline

Running Tool

The modular gun system is run by Halliburton perforating specialists who know the equipment, know your well, and know the best techniques to fit your particular application. And of course, the modular gun system is backed by Halliburton’s worldwide network of technical support, reliable equipment, and innovative performance—all of which are ready to go wherever and whenever needed.

Stinger Skirt

Features • Ideal for monobore completions

Stinger

• With the modular gun system, you are able to stack an optimum number of guns downhole for perforating the maximum interval

Centralizer

• Several features make the modular gun system your best choice for perforating under a wide range of conditions The guns are retrievable or can be left at the bottom of the hole

–

The system allows perforating in either underbalanced or overbalanced conditions over the entire interval

–

Wide range of gun sizes (2- to 7-in. OD) permits deployment over a wide range of casing, from 3 1/2 to 9 5/8 in.

• No rig is required—the system is ideal for rigless completions

Auto-Release Gun Hanger HAL6093

–

Modular Gun System Configuration

*US Patent Number 5,366,014

• The modular gun system can be deployed via coiled tubing, electric wireline, or slickline, as well as with conventional tubing or drillstring • The modular gun system allows a zone to be perforated and tested with no downhole restrictions below or above the packer • Proven VannSystem® guns and firing heads are used in the modular gun system


5-139

The modular gun system allows operators to deploy multiple gun sections to perforate long intervals. The gun modules are deployed downhole individually and stacked on each other at the perforating zone until the appropriate length is achieved with the lowermost gun module being supported by the gun hanger. This method avoids any gun length restrictions caused by the lubricator. The auto-release gun hanger positions the perforating assembly and allows it to remain adjacent to the desired interval. The guns are fired, via a pressure-actuated firing head, and are then, automatically released to the bottom of the hole where they can later be retrieved or left in the hole.

HAL15458

The Modular Gun System Process

Stinger Assembly

The modular gun system is ideal for use in wells with rathole length restrictions and rigless completions. Rathole Length Restriction In this application, insufficient rathole length causes the uppermost gun modules to remain adjacent to the perforated interval after they are fired—where they may interfere with production from the well. The modular gun system allows the guns to be retrieved in sections without having to kill the well.

On wells where the completions are installed with wireline or coiled tubing, the modular gun system is the preferred method for perforating. No rig is required, saving both time and money.

HAL15457

Rigless Completion

Skirt Assembly

5-140


Select Fire™ Systems The Select Fire™ system offers flexibility in perforating, testing, and evaluating multiple zones in one trip. The Select Fire system saves rig time and tool charges to help multiply profits.

Air Chamber

VannGun® Assembly

Features • Perforating and testing several individual zones — one at a time • Selecting the order zones are perforated

TDF Firing Head

• Customizing gun configurations for various applications • Available for all VannGun® assemblies 2-in. and larger • Helps develop essential information about the reservoir — potentially saving hundreds of thousands of dollars

Pressure Isolation Sub

• Saves rig time and tool charges to help multiply profits

Sealed Initiator Before Firing

A I R C H A M B E R

Select Fire™ Sub When gun #1 fires, the explosives train is continued to the Select Fire™ Sub, which fires a shaped charge downward.

VannGun® Assembly

HAL10537

Pressure may now enter into the air chamber. (Note: the isolation sub is used to prevent pressure from going upward from the Select Fire Sub). P R E S S U R E

HAL10586

Air Chamber

Select Fire™ Tubing Conveyed Perforating System

Select Fire™ Sub Operation


5-141

Coiled Tubing Conveyed Perforating Conveying perforating guns to the zone of interest with coiled tubing has been effectively used for many years in a variety of applications. Benefits include faster run-in times when compared to conventional methods. And the guns can be detonated either with wireline or a pressure-activated firing head. Some of the applications include:

Coiled Tubing Connector

Back Pressure Valve Hydraulic Disconnect Swivel

• Perforating in Underbalanced Conditions Underbalanced conditions occur when hydrostatic pressure in the well is lower than formation pressure. Perforation under these conditions allows increased flow from the formation, which helps clean the perforations and helps reduce nearwellbore damage

Circulating Valve Crossover

• Horizontal Well Perforating Coiled tubing conveyed perforating could be deployed in horizontal portions of the well where conventional methods of perforating are impractical or impossible

5-142

Centralizer

Back Pressure Valve

Battery Housing

Hydraulic Disconnect

Memory Controller

Pressure Relief Ports* Coiled Tubing and Firing Head Crossover Firing Head with Circulating Ports

Pressure

• Coiled Tubing Used as the Production String The coiled tubing that conveys the perforating guns can also be used as the production tubing after well completion

Casing Collar Locator (CCL)

Roller Centralizer

Correlation Tool Stack

HAL15400

Gamma/Ray Temperature

HAL15399

Special features include an automaticrelease gun hanger, which allows the coiled tubing to detach from the perforating guns before they are fired, avoiding damage to the coiled tubing. A modular gun system is also available in which the perforating guns are loaded at the surface, deployed downhole individually, and stacked at the perforating zone. This method helps eliminate any gun length restrictions caused by the lubricator.

Coiled Tubing Connector

Swivel

3 3/8-in.-6TTP Scalloped Guns

Perforating Gun String *Pressure relief ports are added to the BHA for coiled tubing perforating jobs to help eliminate the possibility of a pressure increase due to thermal expansion in a closed chamber.


DrillGun™ Perforating Systems Halliburton has developed the DrillGun™ assembly to be a drillable perforating system that provides reliable, quality performance while lowering overall wellsite costs by: • Eliminating the high costs associated with wireline services • Eliminating the need to switch to a mud system for workovers The DrillGun perforating system is a new method that combines rugged, reliable Halliburton perforating components with the versatility of drillable materials. It is this type of innovative design that has made Halliburton the leader in perforating charge performance and delivery systems. Now, with the DrillGun perforating system, you have a drillable, disposable system that helps save you two of the most valuable commodities at the wellsite—time and money.

The drillable perforating system is ideal for: • Single-trip perforating, packer placement, and cementing on tubing • Cementing and perforating in underbalanced conditions • Plug-to-abandon operations • Workover cementing with clear fluids • Plugback set on wireline • Limited entry drill stem testing Components of the drillable perforating system include: • Aluminum perforating gun • High-performance, perforating charges • Halliburton’s industry-proven EZ Drill® SVB packer

HAL12056

Components of the drillable perforating system are the drillpipe conveyed to the zone of interest; thereby eliminating mobilization or demobilization charges normally associated with wireline units. And, since no mud system is needed, clear fluids can remain in place for workover operations. Once in place, the firing head is actuated by pressure applied through the tubing. After perforating, the gun can be drilled out with conventional drilling methods.

DrillGun™ Assembly


5-143

DrillGun™ Perforating System - Quick, Economical Solution For Perforating In Unusual Conditions. Savings on Rig Time

Block Squeeze Application

Plug-to-Abandon

Operator's challenge—Carrizo Oil & Gas, Inc. needed to perform a squeeze job on a South Texas well. The customer had already switched to a lighter drilling fluid and did not want the high cost of changing to a mud system. As a result, the well would have to be perforated underbalanced.

Operator's challenge—An operator working in the Permian Basin had to perform three block squeezes in a 7 5/8 in. liner from 14,400 ft to 14,800 ft. A primary cement job had not been possible, so instead of cement behind the casing, there was 15.5 ppg drilling mud. The well fluid was 10 ppg brine water. However, it would not be necessary to change the well fluid to 15.5 ppg drilling mud to cement.

Operator's challenge—To plug a well before abandoning it, an operator in Chambers County, Texas needed to perforate six zones.

Halliburton's solution—To meet this challenge, Halliburton recommended its DrillGun system. Economic value created—As a result, Carrizo was able to perform the squeeze job without having to replace the lighter drilling fluid with an expensive mud system. This procedure saved rig time and the expense of a fluid change for a total economic value to the customer of $20,000.

Halliburton's solution— Halliburton logged the first DrillGun system on depth, perforated and performed the cement job at 4,230 psi underbalanced. For the next two DrillGun system runs, we tagged the first retainer and located it on depth to perform the squeeze. Economic value created—The three aluminum perforating guns added only one hour each to the drill-out time. The customer estimates that this procedure saved $52,000.

Halliburton's solution—Halliburton recommended using its DrillGun rather than employing electric-line perforators which would normally be selected for the project. The first DrillGun system was started in the well on Sunday evening and was set the next day at a depth of 13,050 ft. The bottom zone was then squeezed. After the procedure was completed, the setting assembly was pulled out of the hole. It went back in with the second stage, and the job was performed at 8,590 ft. The next day, the final four jobs were run at 5,500 ft, 2,615 ft, 500 ft, and 350 ft, respectively. Economic value created—All six stages were completed in 2 1/2 days. If electric-line perforators had been used, the total job would have taken up to six days. By using the Halliburton DrillGun system, the operator saved four days of rig-associated costs, consultants, and fluid standby time. An additional savings was realized by using the perforating DrillGun system instead of more expensive electric-line charges. The resulting estimated economic value to the customer is $24,200.

DrillGun™ Assembly Specifications SAP No.


Maximum OD in. (mm)




Maximum Overall Length ft (m)

101288693 Aluminum

2 7/8 (73.03) EUE 8 Rd

4.00 (101.6)

15,000 (1020)

3,500 (241)

300 (148.9)*

4.40 (1.341)

101288692 Aluminum

2 7/8 (73.03) EUE 8 Rd

7.00 (177.8)

12,000 (816)

3,500 (241)

300 (148.9)*

4.40 (1.341)

101292015 Composite

2 7/8 (73.03) EUE 8 Rd

3.625 (92.1)

15,000 (1020)

3,500 (241)

300 (148.9)*

3.95 (1.204)

*For use in wells above 300°F (148.89°C), consult a Halliburton representative.

5-144


Setting Tools for the Auto-Release Gun Hanger Running and Retrieving Tools The running and retrieving tools for the modular gun system and the auto-release gun hanger gives customers flexibility in the conveyance of these tools in the well. There are four basic running tools that have been run with these systems: explosive set, jar down, hydraulic, and rotational set. Most of the tools are for wireline and slickline deployment of the systems. The on/off tool requires rotation to operate and is limited to tubing conveyed applications. All of these tools are reusable with a minimal amount of redressing. Application The running and retrieving tools are used for setting gun hangers in position, running modules, and retrieving modules. The tools break down into four categories: explosive set, jar down and jar up, hydraulic, and rotational set. There are many tools that can be used with the modular system. This manual has been written for the tools specially designed for the modular gun system or those recognized as a usable tool. • Explosive set –Adapter kit for Baker #10 setting tool –Adapter kit for Baker #20 setting tool • Jar down –Otis® SB and RB shear release and running tool –Camco JDC and JUC • Hydraulic –Hydraulic JDC running and retrieving tool • Rotational set

HAL15778

–Right hand release on/off tool

Running Tool Assembly Modular 3.12 in. OD for Baker #20 Setting Tool


5-145

5-146


Downhole Video Services Equipment providing real-time videos of actual oil production into wellbores through perforations, and the resulting flow up production tubulars, enhance the ability to characterize fluid inflow on a perforation-specific basis. The visually intuitive nature of downhole video data results in greatly increased effectiveness of conformance technology treatments, leading to increased oil and gas production and decreased water production. Greater knowledge of the type of fluid being produced from each perforation substantially reduces the risk of inadvertently shutting off oil or gas production with misplaced treatments. Features A downhole video survey allows observation of the integrity of the casing or tubing to find holes, cracks, or corroded areas and fluid entry or exit points. Also, it can detect scale or bacteria buildup, which can impede the flow of hydrocarbons out of the wellbore and reduce the ID of the wellbore tubulars and plug slotted liners, gravel pack screens, or perforations. Downhole video can help the operator detect and identify phase entry, fluid flow, and sand or particulate matter entry into the wellbore. The video survey can detect the entry of sand and particulate matter from individual perforations. Conventional flowmeasurement tools often cannot detect such subtle changes in fluid activity. Oil bubbling into the wellbore does not disrupt the surrounding well fluids. The oil remains in bubbles and migrates to the high side of the well, causing

some of the oil to bypass conventional logging tools. Video surveying clearly identifies the oil-producing perforations. A downhole video survey documents the amount of gas and oil being produced at each point in a producing interval. Conventional flowmeters directly measure the average flow rate of a column of fluid. The downhole video survey does not directly measure absolute flow rates but is used to quantify relative flow rates along the production intervals. Downhole video surveys can visually confirm the initial analysis of conformance problems and determine if the prescribed treatment can solve the problem. If the initial analysis was incorrect, the visual information can be used to modify the treatment schedule to prevent costly but ineffective treatment procedures. Downhole video can monitor well and reservoir treatments in real-time during the treatment process. For example, downhole video surveys run during a frac job can verify that the frac proppant entered the intended fracture areas. The downhole video is limited by fluid clarity, the operational limits of the camera and system, and extremely high flow rates. After the completion of a treatment, a downhole video survey can show whether the treatment successfully treated the problem area. Video confirmation of the job results also allows operators to learn more about the effectiveness of the treatment to continually improve the treatment process.

Downhole Video Services Specifications Cable Tension Limits lb (kg) Max Deployment Depth ft (m)

Camera Assembly OD in. (mm)



at Camera Cable Head

at Surface

14,000 (4267)

1.687 (42.8)

10,000 (69)

225 (107)

500 (226.8)

1,200 (544.3)

Downhole Video

6-1

Downhole Video

Downhole Video

Hawkeye™ Camera System The Hawkeye™ camera system allows operators to view conditions inside oil and gas wells without the need for a special coaxial or fiber-optic cable. Video images (frames) are transmitted to the surface every 1.7 seconds over standard electric line logging cable. Complete redundancy for all mission critical components is provided along with rugged shipping containers for complete transportability. The camera requires a transparent medium in the area to be filmed for meaningful results. Obtaining the correct clarity of fluid at the viewing zone is often the most challenging aspect of performing this service.

annotate the recorded tape with text entered from an optional laptop computer or video typewriter is provided • The system comes equipped with two downhole tools, two surface power supply/receivers, and two video monitors. This provides complete backup for the image producing and display equipment • The system is provided in three rugged shipping containers with internal padding designed for the standard components plus some additional room for cables and miscellaneous equipment

Features • The Hawkeye system can be run from any logging cable with less than 250 ohms total loop resistance and up to 1.5 micro farads of total capacitance. This allows downhole video service to be offered as the system is completely transportable to any location without the need for special cable or logging units • The ability to measure depth and superimpose it on the video image along with time, date, and internal tool temperature is provided. In addition, the ability to

HAL11281

The camera is used as a diagnostic tool to detect all types of fluid and solids entry into the borehole, to inspect pipe for corrosion, mechanical integrity, and correct production/ perforation verification. Additionally it may be used to aid fishing operations.

This image shows cut up casing that has fallen onto a trash cap for a casing shoe.

Hawkeye™ Camera System Specifications

6-2

Length ft (m)

Diameter in. (mm)



Weight lb (kg)

8.5 (2.6)

1.69 (42.9)

10,000 (69.0)

250 (121.1)

31 (14.1)

Downhole Video

Fiber-Optic Camera System The fiber-optic system allows operators to view conditions inside oil and gas wells. Video images (frames) are transmitted to the surface at a rate of 30 frames every second over a specialty 0.25-in. diameter logging cable with a fiberoptic cable at its center. Complete redundancy for all mission critical components is provided along with rugged shipping containers for complete transportability. The camera requires a transparent medium in the area to be filmed for meaningful results. Obtaining the correct clarity of fluid at the viewing zone is often the most challenging aspect of performing this service. The camera is used as a diagnostic tool to detect all types of fluid and solids entry into the borehole, and to inspect pipe for corrosion, mechanical integrity, and correct production/ perforation verification. Additionally, it may be used to aid fishing operations. The fiber-optic system differentiates itself from other video camera tools by having the highest video data rate and is better than any other products available for detecting flow due to gas entry.

Features • A 1.6875-in. backlight camera is used to provide unobstructed, wide viewing angle, and clearly defined images. A 10,000 psi pressure rating and operation at temperatures up to 250°F are standard • The ability to measure depth and superimpose it on the video image along with time, date, and internal tool temperature is provided. In addition, the system has the ability to annotate the recorded tape with text entered from an optional laptop computer or video typewriter • The system comes equipped with two downhole tools, two surface power supply/receivers, and two video monitors. This provides complete backup for the image producing and display equipment • The system is provided in three rugged shipping containers with internal padding designed for the standard components plus some additional room for cables and miscellaneous equipment • The fiber optic system’s resolution is 550 × 350 lines vs. the 317 × 262 lines of the Hawkeye™ system. As a result, the fiber-optic system has better picture resolution and provides pictures virtually in real time. By comparison, the Hawkeye system is more akin to a slo-scan security camera

Fiber-Optic Camera System Specifications Length ft (m)

Diameter in. (mm)



Weight lb (kg)

9.5 (2.9)

1.69 (42.9)

10,000 (69.0)

250 (121.1)

35 (15.9)

Downhole Video

6-3

EyeDeal™ Camera System Pictures are said to be worth a thousand words—and they become even more powerful when they are transmitted from wellbores miles beneath the Earth’s surface. Halliburton’s EyeDeal™ camera system opens new windows to the downhole world with high-resolution images that eliminate the guesswork from a range of diagnostic tests and troubleshooting operations.

The EyeDeal camera system can be deployed in two ways: • Fiber-optic configuration – When attached to the fiberoptic system, the EyeDeal camera system can operate to a depth of 14,000 ft and can sustain pressures of 10,000 psi and temperatures of 250°F. In this configuration, the EyeDeal camera system offers a continuous-feed image with an excellent screen resolution of 550 × 350

HAL18526

HA L18 523

HAL18527

• Hawkeye™ system configuration – When attached to the Hawkeye system, the EyeDeal camera system uses existing logging cables to transmit high-quality images (screen resolution: 317 × 262) at the rate of one frame every 1.7 seconds. The Hawkeye system provides full remote camera operation and control, and its advantages include deeper operation and the ability to perform flawlessly in corrosive fluids

Fiber Optic Configuration: Side View, Real Time

HAL18528

Fiber Optic Configuration: Down View, Real Time

Hawkeye™ Configuration: Snapshots, Every 1.7 Seconds

HAL18525

HAL18524

Downhole Camera View

6-4

Applications of the EyeDeal camera system include quality assurance inspection, gas entry, water entry, fishing operations, casing and perforation inspection, and general problem identification. Sideview camera with view angle that is closer and almost dead-on to the camera lens

The technology incorporated in the fiber-optic and Hawkeye systems allows operators to toggle between downview and sideview images. The sideview lens records images perpendicular to the borehole wall and gives a true 360° view. This is especially useful in large-diameter wellbores (from 16 to 30 in.) where traditional downview cameras offer only a limited field of vision. The EyeDeal camera system can be toggled between downview and sideview images, giving operators the valuable advantage of being able to isolate and study an area of interest.

Downhole Video

HAL18528

HAL18527

HAL18526

EyeDeal™ Camera System Examples

Suspect Latch Found OK, DV

Damaged Flow Tube, DV

HAL18531

HAL18530

HAL18529

Latch Issues Due to Debris, SV

Fishing Operation 1 of 3


HAL18534

HAL18533

HAL18532


Perfs After Cleanout, DV

Perfs Before Cleanout, DV

5.5-in. Lubricator

EyeDeal™ Camera System Specifications: Sideview and Downview Combination Length ft (in.)

Diameter in. (mm)



Weight lb (kg)

9.75 (117)

1.937 (49.2)

10,000 (69)

250 (121.1)

36 (16.3)

Downview Camera Specifications Length ft (mm)

Diameter in. (mm)



Weight lb (kg)

8.5 (2.6)

1.687 (42.9)

10,000 (69)

250 (121.1)

31 (14.1)

Downhole Video

6-5

6-6

Downhole Video

Slickline Service Equipment

Slickline Service Equipment and Services The high quality of Halliburton’s slickline services depends upon the capabilities of its service tools and equipment; therefore, we are committed to designing and manufacturing the most sophisticated tools in the industry. Our success in this endeavor, along with highly trained and experienced personnel, has allowed us to remain the leader of the slickline service industry. Through our decades of experience and global presence, Halliburton has continued to offer the industry the most complete line of slickline service equipment, tools, and services.


7-1

Subsurface Service Tools Slickline Service Tools Otis® designed and manufactured slickline service tools have been the benchmark for the industry and are a requirement for all toolboxes worldwide. Known for dependable performance and low maintenance costs, these service tools can help reduce your total operating costs. As the original equipment manufacturer (OEM), Halliburton continues to provide high-quality slickline service tools.

Wireline Socket

Stem

Slickline Toolstring HAL8501

Wireline Toolstring A wireline toolstring is attached to the wireline to furnish the mechanical force necessary for setting, pulling, or servicing subsurface equipment under pressure without killing the well. Toolstrings are available in various ODs and component lengths designed to be compatible with various tubing sizes.

Otis® Rope Socket

Otis Rope Sockets Otis rope sockets provide a means for connecting the wireline to the toolstring. The wireline is tied around a disc or dart in the socket to achieve a firm connection. Otis Stems Otis stems are used as weight to overcome stuffing-box packing friction and well pressure on the cross-sectional area of the wireline. The stem can also transmit force either upward or downward to set or retrieve subsurface controls. Size and weight of the stem are determined by the impact force required and the size of the subsurface control to be run or pulled. For normal conditions, 5 ft of 1 1/2-in. OD stem is made up by combining 2-, 3-, or 5-ft (0.61, 0.91, 1.22 m) lengths of standard stem. For high-pressure applications when additional weight is needed, lead or mallory-filled stems are available.

Jars

Running or Pulling Tool

Typical String of Wireline Tools

7-2

HAL8502

HAL8500

Knuckle Joint

Otis® Stem


Otis Jars Otis jars are available in mechanical and hydraulic types. With a set of mechanical jars below the stem, the weight of the jars and stem can be used to jar up or down by pulling and releasing the wireline. A Halliburton wireline specialist can easily feel the jars and manipulate the wireline. Hydraulic jars are designed to provide jarring action in wells in which it is difficult to obtain good jarring action with mechanical jars. Hydraulic jars, which allow an upward impact only, are usually run just above the regular mechanical jars. They require careful maintenance for maximum use in the toolstring. Jar operation is monitored by a weight indicator.

Otis® Knuckle Joint

HAL8504

Otis Knuckle Joints Otis knuckle joints have a special ball and socket design, allowing angular movement between the jars and the running or pulling tool to help align them with the tubing. Knuckle joints are important if the tubing is corkscrewed and when wireline work is done in a directional hole. In these conditions, joints are used at every connection in the toolstring. Where stem and jars will not align or move freely, tool operation may be impossible; however, the knuckle joint inhibits the wireline tools from hanging up.

HAL8503

Otis® Accelerators Otis® accelerators are used with and just above hydraulic jars for shallow, weighty jarring. Accelerators help maintain constant pull as the hydraulic jars begin to open. The accelerator inhibits pulling the wireline out of the wireline socket at these shallow depths.

Otis® Blind Box

Otis B Blind Box Otis B blind box serves as the impact point when downward jarring operations are required.

Standard Wireline Toolstring 3/4 (19.05)

5/8 in. - 11 UNC

0.750 (19.05)

1 (25.40)

5/8 in. - 11 UNC

1.000 (25.40)

1 1/4 (31.75)

15/16 in. - 10 UNS

1.188 (30.18)

1 1/2 (38.10)

15/16 in. - 10 UNS

1.375 (34.93)

1 7/8 (47.63)

1 1/16 in. - 10 UNS

1.750 (44.45)

2 (50.80)

1 1/16 in. - 10 UNS

1.750 (44.45)

2 1/2 (63.50)

1 1/16 in. - 10 UNS

2.313 (58.75)

*Other thread connections available


Otis® Mechanical Jar

Otis® Hydraulic Jar

HAL8507

Fishneck OD in. (mm)

HAL8506

Thread Connection*

HAL8505

Normal Tool OD in. (mm)

Otis® Accelerator

7-3

Slickline Detent Jars The Halliburton detent jar is a mechanically operated jar that is run on slickline or wireline to deliver an impact through the toolstring when the release setting is overcome by tension. This jar has adjustable stroke and release settings that are predetermined on the surface prior to running the jar. The detent jar can be run with accelerator, weight bar, and link-type or Spang jars for delivering an optimum impact load for releasing a stuck object or operating a downhole tool. The detent jar is re-settable downhole by slacking weight at the jar to a collapsed mode. The jar can be tripped and reset rapidly and multiple times downhole. There are no seals in the detent jar, so bottomhole temperature or pressure has minimal effect on the jar operation. Sometimes in deep and deviated wells, the line tension on the weight indicator at the surface is not the same line tension at the rope socket. Modeling the slickline job with Cerberus™ will provide calculated rope socket line tensions.

Detent Jars Size in. (mm)

Standard Release lb (kg)

High Release lb (kg)

Stroke in. (mm)

Length in. (mm)

Tensile lb (kg)

1.500 (38.10)

up to 900 (up to 408)

750 to 2,100 (340 to 953)

8 to 14 (203.2 to 355.6)

52 (1320.8)

37,500 (17 010)

1.875 (47.63)

up to 1,400 (up to 635)

1,300 to 3,500 (590 to 1588)

8 to 14 (203.2 to 355.6)

53 (1346.2)

62,000 (28 123)

2.250 (57.15)

up to 3,100 (up to 1406)

1,250 to 5,000 (567 to 2268)

8 to 14 (203.2 to 355.6)

50 (1270)

76,000 lb (34 473)

Slickline Detent Jar

7-4


Otis® Quick Connect Toolstring Connection Before its extensive field history, the Otis® quick connect was thoroughly tested in both the engineering laboratory and the Halliburton test well in Carrollton, Texas. During the design proving phase, a 1 1/2-in. (38.1 cm) Otis quick connect was jarred through 50,000 cycles at impact loads of 9,000 to 10,000 lb (4082.33 to 4535.92 kg) in both directions. Tensile testing on the tool after jarring revealed the Otis quick connect had retained full strength throughout the operation. Now Halliburton toolstring components and wireline service tools are available with integral Otis quick connects. Features • Spacing of load-bearing shoulders will not allow coupling to connect until full engagement of all shoulders are in place • Self-washing feature minimizes sand buildup in the locking mechanism • Designed for manual operation; no special tools required • Otis quick connect design ensures proper toolstring makeup • Reliable disconnect, even in sandy environment • Safe assembly/disassembly on location


HAL11444

Mechanical Wireline Jar

HAL11443

HAL11442

• Faster turnaround on location minimizes job time

Wireline Quick Connect Stem

Knuckle Joint Quick Connect

7-5

Auxiliary Tools For Use with Slickline Toolstring

HAL8508

HAL8509

Otis® Gauge Cutter and Swaging Tools It is important to run a gauge cutter before running subsurface controls to: (1) determine if the flow control will pass freely through the tubing and (2) to locate the top of the landing nipple or restriction if any are in the tubing. The gauge cutter knife (larger than OD of the control) is designed to cut away paraffin, scale, and other debris in the tubing. Mashed spots in the tubing and large obstructions may be removed with the swaging tool. These tools are available in sizes for all tubing IDs. Otis Impression Tool Otis® impression tool is a lead-filled cylinder with a pin through the leaded section to secure it to the body of the tool. It is used during a fishing operation to ascertain the shape or size of the top of the fish and to indicate the type of tool necessary for the next operation.

Otis® Swaging Tool

Otis® Gauge Cutter

Otis Tubing Broach Otis tubing broach is made up of three major parts: (1) mandrel, (2) nut, and (3) a set of three spools. Spools are tapered and used to cut burrs in the tubing ID caused by perforation, rust, bent tubing, etc. A small OD spool is run first followed by the next larger size, followed by a spool corresponding to the original ID of the tubing. Broach assemblies are run on wireline.

Otis® Impression Tool

7-6

Otis® Tubing Broach

HAL8512

HAL8511

HAL8510

Otis M Magnetic Fishing Tool Otis M magnetic fishing tool is designed to remove small particles of ferrous metals from the top of tools in the well.

Otis® M Magnetic Fishing Tool


Otis® G Fishing Socket Otis® G fishing socket was designed primarily to extract prongs with fishing necks from Halliburton subsurface equipment, such as the Otis PS plug choke.

HAL8513

Otis Go-Devil Otis go-devil is a slotted stem with a fishing neck. Should the tool become stuck, the go-devil can be attached to the slickline via a small strip of metal pinned in the slot to keep the wireline from coming out. The go-devil is dropped from surface and will slide down the wire until it hits a restriction or the top of the rope socket. The go-devil will cut the slickline at that point, allowing the slickline to be retrieved. Its use is usually limited to fishing operations where the wireline socket is inaccessible and the line must be cut. Otis go-devils designed to cut the wireline at the wireline socket are also available.

HAL8514

Otis P Wireline Grab Otis P wireline grab is a fishing tool designed to extract broken wireline or cable from the tubing or casing.

Expandable Wirefinder The expandable wirefinder is designed to locate wireline lost below a tubing restriction (such as a TRSV). The expandable wirefinder is held retracted in a sleeve which is run, located, and preferably latched in the restriction in the tubing. The wirefinder is then sheared out of the sleeve allowing it to expand to the ID of the tubing. Once the lost wireline is found and deformed, the wirefinder can be returned to its running sleeve and retracted for retrieval. A wireline grab is then run to latch and retrieve the lost wireline.

Otis® G Fishing Socket

Otis® P Wireline Grab

Run-in Position

Otis® Go-Devil


HAL14025

HAL8515

Wirefinder Position

Otis® Expandable Wirefinder

7-7

Running Tools

7-8

Otis MR Running Tools Otis MR running tools are used to run Otis XNS and RNS soft set bomb hangers. This running tool is designed to carry weight exceeding the 140-lb (63.50 kg) weight limit of hydraulic running tools because no preset force needs to be overcome.

Otis® RXN Running Tool

HAL8517

The lugs of the running tool hold the fish neck of the bomb hanger during the running of the bombs. The lugs are held in the expanded position by the core in the fully down position. When the bomb hanger locks into the nipple profile, the lock moves upward, pushing the core up by means of the core extension. Once the core is pushed up, the lock-out lug can then be pushed into the core recess by the leaf spring, thus locking the core in the up position. In the up position, the core no longer holds the lugs out and the running tool is disengaged from the hanger. The bomb hanger and pressure gauges are left suspended in the well.

HAL8519

Otis® X® or R® Running Tool

Otis® SAFETYSET® Running Tool

HAL14029

Otis SAFETYSET® Running Tools Otis SAFETYSET® running tools are used to set Halliburton surfacecontrolled, wireline-retrievable safety valves on Otis RP and RQ lock mandrels. Two independent conditions must exist in sequence before the running tool will release the valve and lock. First, the SCSSV must be pressured open to activate the running tool. Second, only when the locking sleeve is moved upward into its locked position will the running tool release. A running tool retrieved to the surface without the lock and valve indicates a

Otis UP Running Tool An Otis UP running tool is also available for running SAFETYSET lock mandrels and subsurface safety valves, which utilize staggered sealbores. The UP running tool is entirely mechanical and does not require control line pressure to activate.

HAL8516

Otis RXN Running Tools Otis RXN running tools set Otis X, XN, R, RN, RPT®, and RQ lock mandrels in their respective landing nipples. This tool is generally used for installing wireline-retrievable subsurface valves in the uppermost landing nipple in staggered bore nipples such as RPT. With this tool, the lock mandrel may be run with the keys in the control or locating positions. The lock mandrel keys or no-go serve to locate the nipple rather than the dogs on the running tool. When a non-no-go lock is being run, the keys must be run in the locating position and the lock must be set in the first nipple in the bore of that lock size. The tool gives a positive indication when the lock is fully set.

functional valve securely locked in the landing nipple.

HAL8518

Otis® X® and R® Running Tools Otis® X® and R® running tools are used to set Otis X, XN®, R, RN®, and RQ lock mandrels in their respective Otis landing nipples. These tools are designed with locator dogs, serving to locate the proper landing nipple and positioning the lock mandrel before locating and locking. By selecting the position of the running tool, the lock mandrel keys may be placed in the locating or retracted position.

Otis® MR Running Tool

Otis® UP Running Tool


Pulling Tools Fishing Neck

External Fishing Necks Otis S pulling tools are designed for jobs in which extensive upward jarring is required to pull a bottomhole control. This tool is designed to pull any subsurface equipment with an external fishing neck. The core is manufactured in various lengths and may be changed in the field to accommodate the fishing necks of various controls. These are referred to as SS, SB, or SJ. The tool is designed to shear and release by downward jarring. With this feature, the tool may also be used as a running tool to run collar stops, pack-off anchor stops, and various other Halliburton tools.

Core Nut Fishing Neck Shear Pin Cylinder Spring Spring Retainer Dog Spring Dog Retainer Cylinder

Otis® GU Shear Up Adapter

HAL8522

Dogs Core

Otis® GS Pulling Tool Shear Down

Otis® GR Pulling Tool Shear Up

Otis R pulling tools are designed for jobs in which extensive downward jarring is required. Tools use upward jarring to release when necessary. Dogs in the R pulling tool engage the fishing neck of the device to allow it to shear with upward jarring. The R pulling tool can be modified as follows:

• Otis RS pulling tool (R body with S core) pulls Halliburton S mandrel assemblies

HAL8523

• Otis RJ pulling tool (R body with J core) pulls all controls that do not have full relative motion

HAL8544

• Otis RB pulling tool (R body with a B core) pulls Otis B, C, and W lock mandrel assemblies and mandrel assemblies with full relative motion

Note: When used as a running tool, the core must be long enough to allow for upward travel after shearing the pin before the skirt is stopped by the Otis® S Pulling Tool equipment being run. It is this action that permits complete release of the running tool.


Dowel Pin

HAL8521

Otis GR pulling tools are used during wireline operations to unlock and pull a variety of subsurface controls with internal fishing necks, including: Otis D bridge plugs, Otis X® and R® lock mandrels, Otis D mandrels, and Otis D collar stops. Designed to shear with a jarring up action, this pulling tool is used during routine wireline operations on controls when shear-down is not possible. The Otis GR pulling tool is assembled by incorporating an Otis GS pulling tool with an Otis GU shear-up adapter.

Shear Pin

Shear Pin

HAL8520

Internal Fishing Necks Otis® GS pulling tools are used during wireline operations to unlock and pull a variety of subsurface controls with internal fishing necks, such as an Otis G pack-off assembly. Designed to shear with a jarring down action, this pulling tool is used where excessive jarring upward is necessary to retrieve subsurface flow controls. In the running position, the dogs are designed to seat and lock in the internal recess of the mandrel being retrieved. If the device cannot be retrieved by upward jarring, the GS pulling tool can be released by jarring down which shears the pin to allow the pulling tool and toolstring to be removed from the well. With this tool being a shear-down-to-release, it can be used in many cases as a running tool for certain devices.

Otis® R® Wireline Pulling Tool

7-9

Plugs For Wells Without Landing Nipples Monolock® Plug The Halliburton Monolock® plug is designed to be set anywhere in a given size of tubing, casing, or liner. The Monolock plug differs from a conventional lock mandrel because it does not require either a profile or sealbore in the tubing string and is retained in its set position by slips rather than keys. The Monolock plug may be used in association with the Halliburton full bore nipple system or any other selective or nipple and lock system. The plug is set and retrieved with Halliburton’s DPU® running and retrieving tools, which can be run on slickline, braided line, or coiled tubing. When used for plugging applications, the plug is designed to withstand differential pressure of up to 10,000 psi (690 bar) from either direction.

• Belleville spring energy storage system provides positive sealing during pressure reversals • Can be installed and retrieved through restrictions • Run and retrieved on same DPU unit • Run on slickline, braided line, or coiled tubing • Element located above slips, preventing any debris accumulation around slip area • Equalizing feature provided in standard assembly • Barrel-slip design provides maximum slip engagement while minimizing tubing deformation Benefits • Can be set anywhere in tubing, casing, or liner • Quick running and retrieval

• As a retrievable bridge plug placed anywhere in the tubing string • Can be adapted to install BHP gauges and other flow control devices • Plug tubing below hanger for well repairs Features • Pressure ratings up to 10,000 psi (690 bar) • Requires no landing receptacle • Seals against pipe ID • Slip-type anchor system • Element is retracted during retrieval

• Use of slickline rather than conductor line lowers installation and retrieval costs • Redressable in field, reducing downtime • Because element returns to original shape, assembly can be recovered back through restrictions • Slip configuration ensures centralized setting of the lock even in high-angle or horizontal wells • Provides same reliability as production packers • Slip design minimizes tubing deformation HAL10466

Applications

Monolock® Plug

7-10


Test Tools Otis® selective test tools are used to test tubing, locate leaks, or set hydraulic-set packers. Designed to hold pressure from above, selective test tools may be set in compatible Otis X®, XN®, R®, or RN® landing nipples in the tubing string. With the keys retracted, the tool is run to a point below the desired nipple. Pulling up through the nipple releases the locking keys to set the tool with downward motion. Pressure from above may then be applied. Features • Designed for high working pressure

Otis Non-Selective Test Tools Otis non-selective test tools are designed to test the tubing string, set hydraulic packers, and protect lower zones when circulating through a Sliding Side-Door® circulating device or producing a zone above the lowermost zone. Designed to hold pressure from above only by employing the use of a drop valve equalizing assembly, the non-selective test tools land in no-go landing nipples with compatible packing bores. When landed in the landing nipple, pressure from above is sealed by the drop, seal ring, and v-packing. In order to retrieve by wireline, the drop is moved off seat with a pulling tool. This equalizes the pressure across the test tool, allowing it to be retrieved.

HAL8524

• Located in the lowest nipples first, these tools are then moved up the tubing and set in sequential nipples until a leak is not detected, thus reducing wireline trips

Otis® Non-Selective Test Tool

Features • Ease of running, setting, and retrieving • No-go OD on bottom of tool for positive location in landing nipple • May be pumped into the well

HAL8525

• Designed for high-pressure ratings

Otis® Selective Test Tool


7-11

Positioning Tools Otis® BO Selective Positioning Tools Otis® BO selective positioning tools are used to move the inner sleeve to its open or closed position in Sliding Side-Door® circulating devices.

Note: The Otis B selective positioning tool is not to be used for shifting Otis XXO or RRO surface-controlled safety valve nipples. For these nipples, use the Otis XL or RL shifting tool. The positioning tool engages the recess in the upper (or lower) end of the inner sleeve to permit the sleeve to be shifted by a jarring action. The tool is designed to release itself only after the sleeve reaches its fully open or closed position. This automatic-releasing feature incorporates a releasing profile on the key itself that acts to compress the key spring and release the positioning tool. A shear pin is an added feature designed to release the tool in the event well conditions make it impossible to shift the sleeve. A set of positive keys is available for this tool to permit upward movement of the inner sleeve of one among several Sliding Side-Door circulating devices in one wellbore. These keys do not have a releasing profile. The positioning tool pin must be sheared to release.

This positioning tool is designed with dogs that serve to locate the proper Sliding Side-Door circulating device and release the spring-loaded keys to engage the profile in the inner sleeve. The tool is designed to release itself only after the sleeve reaches the full-down position. This automaticrelease feature incorporates a releasing profile on the key that acts to compress the key spring and release the positioning tool. The tool can then be raised to the next Sliding Side-Door circulating device to position its sleeve down or return to the surface.

7-12

HAL8527

Otis BO selective positioning tools are designed to selectively position Sliding Side-Door inner sleeves only to the down position. These tools are designed so that one sleeve can be shifted to the down position at any level in the tubing string without shifting any other sleeve.

HAL8526

Note: The Otis BO selective positioning tool will not pass through position number 1 of Otis S landing nipples.

Otis® BO Selective Positioning Tool

Otis® BP Selective Positioning Tool


Tubing Perforators and Bailers Otis® A tubing perforators are mechanically operated and can be used with slickline (under pressure) to perforate both standard and heavyweight tubing. Applications • To provide access to casing annulus to circulate or kill a well

well pressure until the bailer is retrieved. For large pieces of junk, a flapper bottom and junk basket are available.

Note: The internal chamber pressure should always be bled off through the bailer release valve before the bailer bottom is broken off at surface.

• To bring in additional productive zones • To permit production through tail pipe that has been plugged and cannot be opened by regular methods Features • No explosives used, minimizing the possibility of perforating the casing • Safety-release mechanism designed to permit removing perforator without perforating • Greater tubing penetration • Perforator designed to retract the punch and release automatically after perforating

Otis® A Tubing Perforator

Otis® M Sand Pump Bailer

HAL8532

HAL8531

Otis M sand pump bailers may be used to remove a sand bridge if one is encountered during normal wireline operations. The sand bailer consists of a piston encased in an outer cylinder. By working the wireline in the same manner as used to set certain subsurface controls (lightly jarring up and down), the bailer acts to pull sand into the cylinder to remove the sand bridge. An assortment of bailer bottoms is available:

HAL8530

• Service performed by Halliburton-trained personnel

Otis® B Hydrostatic Bailer

• Flat bottom for soft, easy-to-bail sand • Chisel bottom for hard-packed sand • Flapper bottom for bailing metal particles that are too large to pass the ball and seat Otis B hydrostatic bailers are designed for use when the substance to be bailed cannot be removed by a pump-type bailer. This is sometimes the case when small metallic particles become lodged on top of the locking mandrel dogs of a subsurface flow control. The Otis B hydrostatic bailer is sealed at the surface and run into the tubing bore with the internal bailer chamber at atmospheric pressure. When the bailer reaches the object to be bailed, a few downward strokes of the wireline jars act to shear a small sealing disc and admit the well pressure and/or hydrostatic head (as well as the junk) into the bailer cylinder. A ball check valve acts to contain the junk in addition to the


7-13

Slickline Skid Units and Trucks components to make both specialized and standard operations more productive. For more detailed information, please contact your local Halliburton representative.

HAL22811

HAL22810

Halliburton designs and manufactures top quality skid-base units for offshore operations and trucks for land operations. The units are known worldwide for their user-focused design, providing the right mix of operator-friendly

HAL22809

HAL22808

HAL22812

T800 Slickline Crane Truck

Offshore Three-Piece Skid Unit

7-14

Slickline Container Unit

Stainless Steel Skid Unit


Surface Service Equipment Halliburton’s wellhead pressure control equipment provides for a safe and highly productive service operation. Unmatched equipment quality backed by available extensive training and maintenance instruction has made

Halliburton the industry’s premier provider of this type of equipment and services. For more detailed information, please contact your local Halliburton representative.

HAL22753

Options: • Slickline Grease Head • Liquid Chamber • Lubricator Control (Purge) Valve Hydraulic Stuffing Box (16-in. Sheave) Quick Union Upper Lubricator Section Quick Union

Slickline Grease Head

Middle Lubricator Section HAL22754

Lubricator Pick Up Clamp Quick Union

Liquid Chamber

Option: • Pump-In Sub

Quick Union

HAL22755

Lower Lubricator Section

Options: • Wireline Valve Dual (Manual or Hydraulic) • Wireline Valve Triple (Manual or Hydraulic)

Dual Wireline Valve (Manual or Hydraulic)

HAL22757

HAL22756

Wireline Valve Single (Manual or Hydraulic)

Options: • Lubricator Safety Valve • Pin End Assembly

Triple Wireline Valve (Manual or Hydraulic) Flanged Tree Connection


7-15

Advanced® Slickline Services Highly developed measurement and innovative downhole tools provide low-cost slickline solutions for well interventions. Halliburton Advanced® slickline services let you set and retrieve packers, plugs, and monobore flow controls, and perforate, cut casing, and tubing–all with depth accuracy comparable to electric line with the efficiency of slickline. Halliburton’s innovative slickline technology produces depth measurements so accurate you can now use slickline procedures for many services traditionally reserved for electric line operations. Procedure for procedure, when compared to electric line, Halliburton's new slickline technology substantially lowers your total cost.

Correlate to the Original Log to Identify Collar Locations Halliburton's exclusive slickline collar locator further enhances data accuracy. As it passes a tubing or casing collar, it increases line tension. The tension spikes are recorded in real time on the permanent job log so the operator always knows the precise tool location in relation to the tubing or casing collars. Set Packers and Plugs Without Explosives The remarkable Halliburton DPU® downhole power unit eliminates the need to use explosive charges to set packers and plugs. The slow controlled force provided by an electromechanical powertrain improves setting performance for downhole equipment, such as packers, where improved element compression and a more uniform slip set are obtained.

Key developments make this revolutionary advance in slickline utility possible: • An advanced measurement system that makes slickline depth readings comparable to electric line depth readings • A slickline collar locator that pinpoints tubing or casing collars • A downhole power unit that eliminates the need for explosives to set packers and plugs • An electronic triggering device that fires perforating and cutting charges • A data/job logger that produces real-time slickline collar logs or customer job summary • A wire inspection device that detects abnormalities in slickline to facilitate wire management and reduce premature failures Unprecedented Slickline Accuracy Halliburton's Advanced Measurement System (AMS) uses microprocessor technology to take the guesswork out of slickline depth measurements. Yes, we still count wheel turns. But, the processor not only counts wheel turns, it also instantly and continuously adjusts for the effect of ambient temperature on counter wheel size and for tension-caused line stretch measured with an electronic load sensor. Depth, tension, and line speed are logged and a hard copy printed in real time, guiding the operator and providing a permanent job record.

7-16


JobTrak® Data Logger

LineTrak® Inspection Device

Advanced® Slickline Service Unit

Advanced Measuring System (AMS)

Memory Production Logging • CCL/Gamma Ray • Pressure • Temperature • Capacitance Water Holdup • Filled Density (Differential Pressure) • Fullbore Spinner and Continuous

CollarTrak® Slickline Collar Locator

SmartETD® System

DPU® Downhole Power Unit Perforating Gun

Monolock® Plug

Packer

Perforator

Bridge Plug Advanced® Slickline Service Tools


7-17

Perforating and Cutting Services Performed with Slickline The Halliburton electronic triggering device employs slickline to run and fire perforating and cutting charges when explosives are a requirement. The triggering device also can be used to fire explosive-activated tools used to set plugs and packers. The device's redundant safety system prevents premature firing. Produce a Permanent Job Record Data recorded through the job logger can either be a printed hardcopy or stored to floppy disc as a permanent well file. The data can also be merged with data from downhole memory tool surveys to produce API quality production well logs for diagnostic or flow analysis. Even More Built in Reliability Halliburton's new wire inspection device and wire management software has prevented fishing trips and has greatly reduced lost production time caused by slickline failure. The device can be used for periodic electronic inspection to detect line abnormalities.

The state-of-the-art Advanced® slickline service system offered by Halliburton provides the most efficient means for precise depth correlation, setting plugs and packers, perforating, and producing high quality memory production logs. Advanced® Slickline Service System This system provides services traditionally performed by e-line services, but with slickline. Save With Halliburton Advanced Slickline Services You can substantially save on your electric line costs for comparable services with Halliburton's Advanced slickline technology. And the Halliburton wire inspection device in conjunction with wire management software can cut the costs of traditional slickline services by significantly reducing the potential for line breaks.

The wire management software tracks wire usage and provides a permanent record of each line's job history, when utilizing AMS. The software provides a basis for predicting wire failures due to normal, job-related stresses, and exposure to hostile well environments.

7-18


DPU® Downhole Power Unit Halliburton’s DPU® downhole power unit is an electromechanical downhole electric power supply device that produces a linear force for setting packers using downhole electric power. The tool is self-contained with a battery unit and an electrical timer to start the setting operation. The unit consists of three functioning sections: the pressure sensing actuator, the power source, and the linear drive section.

Shifts: • Sliding Side-Door® circulation/production devices • Internal control valves • Releasing mechanisms/sleeves

The slickline version of the DPU unit uses batteries to provide the energy to the motor and timing circuits. An electric line version without the timer, circuits, and batteries is also available.

Note: Both slickline and e-line DPU units include conversion kits to allow the use of existing Baker setting adapter kits. The DPU unit and attached subsurface device are run into the well on slickline or braided line. The timer initiates the operation. The setting motion is gradual and controlled (about 0.7 in./min) allowing the sealing element to conform against the casing/tubing wall and the slips to fully engage. The controlled setting motion allows the sealing element to be fully compressed. Once the setting force is reached, the DPU unit shears loose from the subsurface device and is free for removal from the well. The DPU unit is designed to help set and allow for dependable operation of downhole flow control devices, reduce well completion costs, and improve safety at the wellsite. Applications Sets and Retrieves: • Packers • Bridge plugs • Whipstocks • Monolock® devices Sets: • Cement retainers • Sump packers • HE3® retrievable bridge plugs

HAL14000

• Subsea tree plugs

DPU® Downhole Power Unit

• BB wireline-retrievable packers Perforates: • Tubing • Casing


7-19

Features • Equipped with a timer/accelerometer/pressure actuation system to ensure tool setting at the proper time and depth • Batteries for self-contained operation • Slickline, e-line, or coiled tubing operation • Sets and retrieves tools with optimal setting force • Reduced cost for setting packers and bridge plugs using traditional electric line • Non-explosive operation improves safety • Eliminates need for electric wireline • Dependable operation • Positive setting of slips and elements • Optimized operating speed

7-20


Slickline DPU® System Specifications Max OD in. (mm)

Max Shear Force lbf (N)

Voltage

Amps

Max Temperature °F (°C)

Max Pressure psi (bar)

Max Effective Stroke in. (mm)

1.70 (43.2)

15,000 (66 720)

27

2

300 (148)

15,000 (1034.5)

9 (229)

2.51 (63.75)

30,000 (133 440)

36

4

300 (148)

15,000 (1034.5)

8.5 (216)

50,000 (222 400)

30

5

250 (121)

10,000 (689.4)

36 (914)

60,000 (266 880)

48

2

329 (165)

10,000 (689.4)

8.75 (222)

3.59 (91.19)

E-Line DPU System Specifications Max OD in. (mm)

Max Shear Force lbf (N)

Voltage

Amps

Max Temperature °F (°C)

Max Pressure psi (bar)

Max Effective Stroke in. (mm)

1.70 (43.2)

15,000 (66 720)

50

0.6

400 (204)

15,000 (1034.5)

9 (229)

2.51 (63.75)

30,000 (133 440)

115

0.6

400 (204)

15,000 (1034.5)

8.5 (216)

3.81 (96.77)

60,000 (266 880)

200

0.75

400 (204)

20,000 (1378)

8.75 (222)


7-21

DPU® Tubing Punch The DPU® tubing punch can help cut your costs for perforating the tubing. Coupled with the Monolock® plugging device, the DPU tubing punch provides an effective and dependable solution for well (kill) workover operations. Features • Can reduce the cost for perforating tubing • Reduces rig time by minimizing misruns with other mechanical perforators • No extensive jarring to achieve a hole • Eliminates the need for electric wireline and an explosive soft shot perforating service. The DPU tubing punch can be run on slickline, braided line, or coiled tubing. This means it offers the economy of slickline and the versatility to meet operational requirements • Improves safety with its non-explosive operation by eliminating transportation and handling of explosives and by not requiring explosive-trained personnel • Offers proven, dependable operation of the punch HAL23161

• Equipped with a timer/accelerometer/pressure actuation system for precise control

HAL23160

7-22


CollarTrak® Slickline Collar Locator The Halliburton CollarTrak® slickline collar locator consists of a standard electric line collar locator, an electronic subassembly, and a magnet/drag sub-assembly. When the collar locator senses a tubing or casing collar, it signals the electronic sub-assembly, which instantaneously activates magnets in the magnet/drag assembly. The magnets increase frictional engagement to the pipe wall, creating a brief but significant increase in line tension. Halliburton's advanced measurement system detects the tension increase and sends the data signals to the data/job logger, which records it as a well-defined spike on the log. The advanced measurement system automatically and continuously compensates for line stretch, assuring log accuracy.

HAL8887

The tool, which is powered by alkaline batteries, locates collars in up to 13 chrome pipe and in flush-joint tubing.

CollarTrak® Slickline Collar Locator

Slickline Collar Locator (SLCL) (with Power Pack) Specifications Size in. (mm)

Tubing or Casing Size in.

Max OD Magnets Collapsed in. (mm)

Max OD Magnets Expanded in. (mm)

2.50 (64) 3.66 (93) 1.69 (43)

3 1/241/2 5 1/27 5/8 2 3/82 7/8

2.50 (64) 3.66 (93) 1.69 (43)

3.85 (98) 5.50 (140) 3.06 (77)

Optional Larger Magnet Housing

Max OD Larger Max OD Larger Max Max Magnet Housing Magnet Housing Operating Operating Collapsed Expanded Pressure Temp. in. (mm) in. (mm) psi °F

No

N/A

N/A

15,000

300

Yes

5.70 (145)

7.50 (191)

10,000

250

No

N/A

N/A

15,000

300

Overall Length in. (mm)

Power Source

Top Connection

Bottom Tool Connection

95.3 (2.421) 69.8 (1.773) 34.12 (.86)

“AA” size Batteries “C” size Batteries “AA” size Batteries

1 5/16-in. 10UNS pin 1 1/16 in. 10UNS pin 1 5/16 in. 10UNS pin

1 5/16-in. 10UNS box 1 1/16 10UNS box 15/16 in. 10UNS box

All sizes are alloy material and have three magnets.


7-23

Electronic Depth Measurement System

Halliburton Job Logger

JOB ENDED ( DATE: May, 02 1995

TIME: 15:04:39 )

MAXIMUM ( DEPTH: 1352.5 m TENSION :

123 DNs LINE SPEED : 238.8 m/min

) COMMENTS : TOOL BOX SAFETY MEETING RIH FLOWING DUMMY AT 1353M. RIH FLOWING SURVEY MAKE 5 MIN STOP 250M 423M 453M 746M 766M 984M 1104M 1152M 1172M 1282M 1302 1343M 15MIN STOP CASSING PRESS 4000KPA

Data/Job Logger (Portable)

6000

Slickline Service Unit

Combination Depth Counter and Line Tension Sensors (Input to Electronic Depth Measurement System) Slickline Collar Locator Slickline Collar Log

6100

Downhole Power Unit Casing Collar Location

HAL8356

Bridge Plug or packer

7-24

6200 Line Speed


Advanced Measurement System (AMS) The electronic advanced measurement system (AMS) measures tension and depth, compensates for wire stretch and temperature effects on the measuring wheel, and reports a corrected depth reading. This model of the AMS system is designed to be mounted inside a wireline operator cabin. Other features also help improve the quality of a service job. A differential load indicator indicates small changes in pickup weight. Digital displays can be switched between English and metric measurements at any time. The approaching surface alarm warns the operator as the tools near the surface. The excessive tension function works with the hydraulic system to limit the maximum line tension to an adjustable preset value. The system allows the operator to input a “rig-up angle” for accurate line tension readings. When used with a Halliburton two-wheel counter with a “universal” measuring wheel, the AMS gives accurate depth readings for any size wire, in English or metric, without changing wheels.

Standard Mounted Equipment • Automatic depth adjustment • Line tension adjustment • Depth offset adjustment • Ambient temperature correction • Analog line tension display • Analog differential line tension display • Digital line tension display • Digital line depth display • Digital line speed display • RS-232 serial port output for corrected depth, line speed, line tension, units of measurement, and time

This model has digital and analog displays with switch input controls and RS-232 output for data acquisition with a laptop computer.

HAL8890

Panel AMS will not work with IS (Class 1 Division 2) counter. This system requires an electronic strain gauge load sensor and an optical encoder.

Advanced Measurement System


7-25

Electronic Advanced Measurement System (Portable) This portable model has a flat screen display, keypad functional inputs, and extended RAM for data storage. A RS-232 serial port is provided for real-time data retrieval.

• Depth offset adjustment

This system requires an electronic strain gauge, load sensor, and an optical encoder. The portable unit is available for standard and hazardous Class I Division 2 operation.

• Analog differential analog line tension display

Standard Portable Model Equipment

• Digital line speed display

• Automatic depth adjustment

• RS-232 serial port output for corrected depth, line speed, line tension, units of measurement, and time

• Line tension adjustment

• Ambient temperature correction for counter wheel • Analog line tension display • Digital line tension display • Digital line depth display

Integrated AMS™ Advanced Measurement System

7-26


SmartETD® System The Halliburton SmartETD® system is an advanced electronic triggering device that provides an accurate, safe, and reliable method to run and fire downhole explosive tools using slickline. With its built-in sensor and memory capabilities, it can record and store downhole temperature and pressure data that can be used by the slickline specialists to program firing parameters.

No-Blow, No Drop Assembly

The SmartETD tool requires four parameters to be met prior to firing. These are time, motion, pressure, and temperature. The timing sequence begins when the tool is exposed to pressure. After the tool stops, any motion resets the electronic timer. After the SmartETD timer has remained motionless for a specific period of time and has simultaneously encountered the preset temperature and pressure windows, it initiates the firing sequence.

Top Shock/Centralizer Quick Lock Assembly

The SmartETD tool will fire the Halliburton RED® rig environment detonator, as well as API RP-67-compliant devices.

HV Shooting Module

SmartETD® Tool

Adapter Selectable Mechanical Pressure Switch Shock Absorber

Detonator Sub/Explosives as required with STD 1 3/8-in. GO™ Connection

®

HAL15398

VannGun Assembly

SmartETD® System


7-27

JobTrak® Data Job Logger Standard Mounted Equipment • Temperature rating: -10° to 110°F • Power supply: 12-30 VDC or 110-240 VAC • Maximum line speed: 3,000 ft/min (914 m/min) • Maximum line tension: 5,000 lb (2267 kg) • Plot units per hour settings: 4 in./hr or 8 in./hr (10 cm/hr or 20 cm/hr)

HAL8322

The JobTrak® data job logger is used with the Halliburton advanced measurement system to produce summary logs that provide a real-time plot of depth, line speed, and line tension. The data logger consists of a portable computer and thermal printer packaged in a heavy-duty carrying case. It is connected to the AMS system through a RS-232 port, and the computer is programmed to convert the AMS data to graphical form. The data logger can be powered using 12 to 30 volts DC or 110 to 240 volts AC.

JobTrak® Data Job Logger

7-28


Memory Production Logging (MPL) Service Halliburton’s memory production logging service provides solutions to production problems with accurate flow profiles and downhole diagnostics. Logging data is stored in downhole memory and played back on location after the tools are retrieved from the well. MPL can be used in producing and injecting wells with single- or multi-phase flow regimes. Features • Economical in hostile environments – Using slickline minimizes the risk in CO2, H2S, or high-pressure environments. Slickline wellhead pressure control equipment simplifies rig up and operates safely and efficiently in demanding conditions • Proven in horizontal applications – MPL is deployable on coiled tubing for highly deviated or horizontal wells

• Helicopter portable – MPL can be run with existing slickline equipment, avoiding the cost of mobilizing a logging unit • Proven reliability and resolution of electric line tools – MPL string uses the same sensors as the standard electric line tools to deliver the same accuracy and highresolution data • Exclusive depth indicators ensure depth accuracy – AMS advanced slickline depth measurement system or slickline collar locator provides accurate depth control for the MPL string, eliminating misruns and saving valuable rig time • Tool strings customized to meet well requirements – All services can be run with a 1 second sample rate, allowing approximately 18 hours of logging time. Sample rates as high as 0.2 seconds can be selected for increased data density and higher resolution

HAL964

HAL965

• Reduced rig space requirements – Small footprint and low weight make MPL ideal for small production platforms and mono-pod completions. MPL also requires less surface equipment and crane height than electric line services

This memory production log was obtained for an operator looking to cut high water production in a formation with a three-phase downhole flow regime. The MPL service captures logging data on a memory recorder. The data is equal to data obtained with electric line services.


Computing center analysis of the MPL data reveals that the bottom set of perforations is producing mostly water and only 2% of the total oil production and 6% of the gas. Remedial work to plug off the bottom zone should decrease water production and reduce water disposal costs without greatly affecting hydrocarbon production.

7-29

Memory Production Logging Service Battery and Memory Recorder

Max. Tool OD in. (mm)

Tool Length in. (m)

Battery Housing

1.687 (43)

18 (0.46)

Memory Tool

1.68 (43)

19.5 (0.50)

Quartz Pressure

1.68 (43)

12.1 (0.31)


1.687 (43)

18.5 (0.47)

Gamma Ray

1.687 (43)

26.6 (0.68)

Capacitance Water Holdup

1.687 (43)

26.2 (0.67)

Temperature

1.687 (43)

11.5 (0.29)

Fluid Density Differential Pressure

1.687 (43)

47 (1.19)

Caged Fullbore

1.687 (43)

34.1 (0.87)

Continuous

1.687 (43)

24 (0.61)

Roller Centralizer

1.687 (43)

23 (0.58)

Knuckle Joint

1.687 (43)

6.1 (0.15)

Tool Description

Quartz Pressure

Services


Gamma Ray

Roller Centralizer Spinners

Accessories

Fluid Density Differential Pressure

All tools are rated to 350°F (177°C) and 15,000 psi (103 400 kPa)

Capacitance Water Holdup

Roller Centralizer

Temperature

HAL966

Caged Fullbore Spinner

7-30


LineTrak® Slickline Inspection Device and Wire Management Program The Halliburton LineTrak® slickline inspection device spots problems that simply would be impossible for even a veteran slickline technician to detect. The device is used to provide continuous inspection of the entire line —not just selected areas and provides inspection of both in-service lines as well as new lines as it is spooled.

Wire Management Program In addition to periodic inspections for line abnormalities, a permanent record of each line’s job history, when utilizing Halliburton’s AMS advanced measurement system and the JobTrak® data logger, provide a basis for predicting line failures due to normal job-related stresses and exposure to hostile well environments. Wire inspections have become an integral component of Halliburton’s extensive Wire Management Program—a program designed to prevent on-the-job failures.

The LineTrak slickline inspection device spots problems before they cause downhole line failure. The following are examples of problems detected by the LineTrak device.

This 0.021-in. deep crack (100x magnification) was detected in a nickel alloy wire with 1,850 cycles.

Damage on left was detected at 462 ft and on right at 368 ft (arrow points to pit on wire) on a nickel alloy wire.

Abrasion damage on this cobalt alloy wire was detected before it could cause wire separation.


7-31

During inspection, the slickline travels through a coil matched to its size. A high-frequency, low-power alternating current running through the coil produces an alternating magnetic field which generates an electric current, or eddy current, in the slickline. Any changes or discontinuities in the slickline’s conductivity affects the eddy current, changing the coil’s impedance. The inspection device detects the impedance change. Pass-fail criteria are based on notched reference wires. Impedance changes that exceed the established limits identify line sections that require more detailed inspection or cause a line to be taken out of service.

Generator/Indicator

Discontinuities

Magnetic Field

Coil

Slickline

Direction of Movement AC

Inspection System Using Self-Comparison Differential Coils

Although the LineTrak® inspection device cannot guarantee you will never have another parted line, it can minimize the chances of a line failure causing a fishing job in your well. Wire Management Program Features • Proprietary software developed from extensive empirical cycle fatigue test data and field testing • Utility application in AMS system • Extends wireline life • Minimizes premature line failure • User friendly interface • Tracks wire usage and length • Provides graph of used life of line

7-32

Wire Management Program


Deepwater Riserless Subsea Light Well Intervention System The Halliburton deepwater riserless subsea light well intervention system offers complete well intervention solutions.

• System can be operated from a more cost-effective intervention DP vessel • Ideal intervention method on deepwater wells • Increases subsea well availability • Reduced chance of damage resident pipelines and structures

Features • Reduced well intervention costs on subsea wells • No workover riser during operation

Deepwater Riserless Intervention System


7-33

7-34


Mobilization

Mobilization LOGIQ™ Logging Truck LOGIQ™ logging trucks are an evolution in onshore logging technology. The trucks are designed to operate all of the new evolution tools at well depths of up to 27,000 ft in single drum (open-hole) or dual drum (open and cased-hole) configuration. The latest state-of-the-art technology and engineering design make the truck and computer system a platform that can be upgraded as technology evolves.

• Power Distribution Panel

Logging Cabin Features

• Curbside Tool Racks (with airbags)

– Power type – 110V and 220V sockets – Direct Lights – 110V and 12V direct lights – Floodlights – 110V, 500W quartz – Air Conditioners – four DuoTherm; 13,500 BTU/ 5,600 BTU heating for each – Intercom – 3M Model D-15 – Top – four, 2-in. diameter tools, maximum length 92 in. (233.7 cm)

• Exterior – Material – 1/8-in. aluminum

– Middle, Lower – holds two, 4-in. diameter tools, maximum length 98 in. (249 cm)

– Construction – welded aluminum – Insulation – 2-in. urethane foam

• Roadside Tool Racks (with airbags)

– Entrance(s) – single door

– Top – four, 2-in. diameter tools, maximum length 88 in. (223.5 cm)

• Interior

– Middle, Lower – holds two, 4-in. diameter tools, maximum length 136 in. (345.4 cm)

– Material – brushed anodized aluminum skin – Console – winch operator console for depth panel, engine, and generator panel

• Underbelly Tool Rack – Holds four, 5-in. diameter tools and two, 4-in. diameter tools; maximum length 22 ft (6.7 m) with pneumatic tool retainers

– Window – one large sliding window facing reel and frame assembly

LOGIQ™ Logging Truck

Truck Chassis and Engine Specifications Make/Model

Height

Width

Length

Wheel Base

Cab to Axle

Engine Model

Horsepower

Fuel Tanks

Kenworth T-800 6X4

13 ft, 2 in. (4.01 m)

7 ft, 11 in. (2.41 m)

38 ft, 4 in. (11.68 m)

24 ft, 6 in. (8.86 m)

16 ft (4.87 m)

Caterpillar Cat-13

380 hp at 2100 RPM

Two 24.5-in. diameter aluminum, cap: 110 and 50 USG

Mobilization

8-1

Winch Specifications • Two-speed transmission, speeds from 55,000 ft/hour down to 360 ft/hour with an enhanced low speed option down to 50 ft per hour. • Single speed transmission cased-hole drum with speeds up to 52,000 ft/hour and down to 360 ft/hour with an enhanced slow speed option down to 50 ft/hour

• Large drum capable of holding 25,500 of 0.490-in. heptacable slammer cable or 28,500 ft of 0.472-in. heptacable slammer. Small drum capable of holding 22,500 ft of 5/16 single conductor cable or 28,500 ft of 7/32 single conductor cable. • Satellite dish and communications optional

• Rexroth AA4VG pumps and AA6V motors with electronic controls

8-2

Mobilization

LOGIQ™ Modular Skid Unit The LOGIQ™ DNV 2.7.1 certified logging skids are an evolution in offshore logging technology. The three-piece modular skids are designed to operate the most complex logging jobs in the harshest offshore and land environments. The three-module design allows for the three modules to operate together or separate changing the footprint of the skid to better match the space available.

Setup times are greatly reduced because of the slewing mechanism of the winch module and service multiple wells as well. It will run all of the new evolution tools at well depths of up to 27,000 ft, in single drum (open-hole) or dual drum (open and cased-hole) configuration. The latest state-of-theart technology and engineering design make the skid and computer system a platform that can be upgraded as technology evolves.

LOGIQ™ Modular Skid Unit

Mobilization

8-3

Cabin Module The cabin module unit can be transported as a single DNV 2.7.1 certified lift. The unit has entry doors on both sides, and cooling and heating is provided by four units. The exterior material is 3/16-in. aluminum with 2.0-in. urethane foam walls. The cabin is ergonomically designed and holds a single or double LOGIQ™ logging system. The control panel includes all functions, such as: gauges for power pack, winch controls, generator controls, start/stop, pump controls, and an integrated touch screen depth panel.

Cabin Module

Cabin Module Specifications

8-4

Length in. (m)

Height in. (m)

Width in. (m)

Weight lb (kg)

136 (3.45)

113 (2.87)

96 (2.44)

11,350 (5148)

Mobilization

Winch Module The winch module unit can be transported as a single DNV 2.7.1 certified lift. It has interchangeable reels for open-hole and cased-hole purposes. Both have maximum slew rate angles of up to ± 12°. The open-hole reel has a two-speed direct drive transmission. Speeds vary from 55,000 ft/hour down to 360 ft/hour with an enhanced low speed option down to 50 ft/hour. The cased-hole reel has a single speed direct drive transmission with speeds up to 52,000 ft/hour and down to 360 ft/hour with an enhanced slow speed option down to 50 ft/hour. It also features a Rexroth 90 cc pump and 80 cc motors with electronic controls. The unit includes a large drum capable of holding 25,500 ft of 0.490-in. heptacable slammer cable or 28,500 ft of 0.472-in. heptacable slammer. The small drum is capable of holding 22,500 ft of 5/16 single conductor cable or 28,500 ft of 7/32 single conductor cable.

Winch Module

Satellite dish and communications optional

Winch Module Specifications

Mobilization

Length in. (m)

Height in. (m)

Width in. (m)

Weight lb (kg)

Certification

72 (1.83)

113 (2.87)

96 (2.44)

25,200 (11 455)

DNV 2.7.1 / EN12079 certified

8-5

Power Pack The power pack unit can be transported as a single DNV 2.7.1 certified lift. Its main component is the Caterpillar 3126 EURO-3 engine with 230 hp. It runs the hydraulic pumps for the winch and 30 kW hydraulic generator and other auxiliary hydraulic controls. All electrical and hydraulic connections are quick change so set up time is minimal. All service access points are easy to reach. The power pack unit has an enclosed pollution drip pan with easy access drain plugs. It also includes air-start with standard rig air connections.

Power Pack Module

Power Pack Module Specifications

8-6

Length in. (m)

Height in. (m)

Width in. (m)

Weight lb (kg)

60 (1.52)

113 (2.87)

96 (2.44)

7,150 (3250)

Mobilization

Mnemonics

Mnemonics Mnemonic:

Refers to the Curve Mnemonic - LIS / DLIS

Unit:

Refers to the Engineering Units—LIS Eng / Metric; DLIS Eng / Metric

Tool:

Refers to the logging tool for the curve.

Description:

Described the recorded Curve Serv_Name: Refers to the General Service (combined tools)

Type_Data:

Refers to the Data format classification and processing status RES = Result curve INP = Processed Input data TEL = Telemetry with some processing applied

This is a generalized listing of current supported tools and is not intended to include older tools, software versions or data systems. Dual detector tools may utilize either N or 1 to distinguish Near detector and F or 2 to distinguish Far detector.

Mnemonics

9-1

Wireline and Perforating Services Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

ACRT - ARRAY COMP TRUE RES HRM2

RT RESISTIVITY MAP - TWO FOOT

HRM2

RES

ACRT - ARRAY COMP TRUE RES RMAN

RIGHT MANDREL

RMAN

RES

ACRT - ARRAY COMP TRUE RES RF90

OHMM

OHMM

90 IN RADIAL RESISTIVITY 4FT

RF90

ohm.m

ohm.m

RES


OHMM

OHMM


RF60

ohm.m

ohm.m

RES


OHMM

OHMM


RF30

ohm.m

ohm.m

RES


OHMM

OHMM


RF20

ohm.m

ohm.m

RES


OHMM

OHMM


RF10

ohm.m

ohm.m

RES


OHMM

OHMM

6 IN RADIAL RESISTIVITY 4 FT

RF06

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES LSO

LEFT STANDOFF

LSO

RES

ACRT - ARRAY COMP TRUE RES LMAN

LEFT MANDREL

LMAN

RES

ACRT - ARRAY COMP TRUE RES CO60

MMHO

MMHO

ACRT - ARRAY COMP TRUE RES HRM4 ACRT - ARRAY COMP TRUE RES RO20

OHMM

OHMM

ACRT - ARRAY COMP TRUE RES HRM1 ACRT - ARRAY COMP TRUE RES ECC ACRT - ARRAY COMP TRUE RES D2

60 IN RADIAL CONDUCTIVITY 1FT

CO60

RT RESISTIVITY MAP - FOUR FOOT

HRM4


RO20

RT RESISTIVITY MAP - ONE FOOT

HRM1

0.001/ohm

0.001/ohm

ohm.m

ohm.m

RES RES RES RES

ECCENTRICITY

ECC

OUTER RADIAL DEPTH OF INVASION

D2

in

IN

MM

INNER RADIAL DEPTH OF INVASION

D1

in

mm

RES

MM

RADIAL DEPTH OF INVASION

DI

in

mm

RES RES

IN

IN

ACRT - ARRAY COMP TRUE RES D1

IN

ACRT - ARRAY COMP TRUE RES DI

IN

RES RES

ACRT - ARRAY COMP TRUE RES CT90

MMHO

MMHO


CT90

0.001/ohm

0.001/ohm


MMHO

MMHO


CT06

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CT20

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CT10

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CO90

0.001/ohm

0.001/ohm

RES

INCLINATION

INCL

OHMM

OHMM


RT60

ohm.m

ohm.m

TEMPERATURE FEEDPIPE - CALC

TMPF

ACRT - ARRAY COMP TRUE RES INCL ACRT - ARRAY COMP TRUE RES RT60 ACRT - ARRAY COMP TRUE RES TMPF

RES RES RES

ACRT - ARRAY COMP TRUE RES SED6

MMHO

MMHO

SKIN EFFECT CORRECTIONS D6

SED6

0.001/ohm

0.001/ohm

ACRT - ARRAY COMP TRUE RES SEU5

MMHO

MMHO

SKIN EFFECT CORRECTIONS U5

SEU5

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


SED4

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


SED3

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


SED2

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


SED1

0.001/ohm

0.001/ohm

RES

ACRT - ARRAY COMP TRUE RES SMUD

OHMM

OHMM

MUD RESISTIVITY - CALCULATED

SMUD

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES RMUD

OHMM

OHMM

MUD RESISTIVITY

RMUD

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES RXO/RT

OHMM

OHMM

UNIVADED ZONE RESISTIVITY

RXO/RT

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES RO06

OHMM

OHMM


RO06

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES RT90

OHMM

OHMM


RT90

ohm.m

ohm.m

RES


OHMM

OHMM


RO10

ohm.m

ohm.m

RES


OHMM

OHMM


RT30

ohm.m

ohm.m

RES


OHMM

OHMM


RT20

ohm.m

ohm.m

RES


OHMM

OHMM


RT10

ohm.m

ohm.m

RES


OHMM

OHMM


RT06

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES RT

OHMM

OHMM

TRUE RESISTIVITY UNIVADED ZONE

RT

ohm.m

ohm.m

RES

RIGHT STANDOFF

RSO

ACRT - ARRAY COMP TRUE RES RSO

9-2

RES

RES

Mnemonics

LISU_ eng

LISU_ met

Description


OHMM

OHMM


RO90

ohm.m

ohm.m

RES


OHMM

OHMM


RO60

ohm.m

ohm.m

RES


OHMM

OHMM


RO30

ohm.m

ohm.m

RES


MMHO

MMHO


CT30

0.001/ohm

0.001/ohm

RES

Serv_Name

LIS Mnem

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data

ACRT - ARRAY COMP TRUE RES RXO

OHMM

OHMM

UNIVADED ZONE RESISTIVITY

RXO

ohm.m

ohm.m

RES

ACRT - ARRAY COMP TRUE RES BCD4

MMHO

MMHO

BOREHOLE CORRECTIONS D4

BCD4

0.001/ohm

0.001/ohm

RES RES


MMHO

MMHO


CT60

0.001/ohm

0.001/ohm


MMHO

MMHO


CO06

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


BCD1

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


BCD3

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


BCD6

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


BCD5

0.001/ohm

0.001/ohm

RES

ACRT - ARRAY COMP TRUE RES CALU

IN

IN

CAL DIAMETER USED

CALU

in

IN

RES

ACRT - ARRAY COMP TRUE RES CDIA

IN

IN

CALCULATED DIAMETER

CDIA

in

IN

RES RES

ACRT - ARRAY COMP TRUE RES CF10

MMHO

MMHO


CF10

0.001/ohm

0.001/ohm


MMHO

MMHO


CF20

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CO10

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CF06

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CF60

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CF90

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


BCD2

0.001/ohm

0.001/ohm

RES

ACCELEROMETER Z

ACCZ


MMHO

MMHO


CO20

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CF30

0.001/ohm

0.001/ohm

RES


MMHO

MMHO


CO30

0.001/ohm

0.001/ohm

RES

ACRT - ARRAY COMP TRUE RES ACCZ

RES

BCDT/BSAT/BCS/CBL - BH COMP ARRAY SONIC

TT22

TT_T2R2

TT22

INP


ALPH

ALPHA

ALPHA

INP


TT2

US

US

FAR TRAVEL TIME

TT2

uS

uS

RES


DT2

US/F

US/M

DELTA - TIME TRANSMITTER 2

DT2

uS/ft

US/M

RES


TT12

UPPER XMTR TRAVEL TIME TT_T1R2

TT12

INP


TT11

UPPER XMTR TRAVEL TIME TT_T1R1

TT11

INP


TT21

TT_T2R1

TT21

INP


AMPL

DB

DB

AMPLITUDE

AMPL

dB

dB

RES


AMP

MV

MV

CBL - PIPE AMPLITUDE

AMP

mv

mv

RES


DT1

US/F

US/M

DELTA - TIME TRANSMITTER 1

DT1

uS/ft

US/M

RES


FRMC

TOOL FRAME COUNT

FRMC


TT

US/F

US/M

CBL - PIPE TRAVEL TIME

TT

uS/ft

US/M

RES


TT1

US

US

NEAR TRAVEL TIME

TT1

uS

uS

RES


WFFW

WAVEFORM - ALL

WFFW

INP


ITTT

INTEGRATED TRAVEL TIME TOTAL

ITTT

RES


WMSG

WAVEFORM - MSG

WMSG

INP

Mnemonics

RES

9-3

Serv_Name

LIS Mnem

BCDT/BSAT/BCS/CBL - BH COMP ARRAY SONIC BCDT/BSAT/BCS/CBL - BH COMP ARRAY SONIC BCDT/BSAT/BCS/CBL - BH COMP ARRAY SONIC

DT


LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

BI

CBL - BOND INDEX

BI

RES

ITT

INTEGRATED TRAVEL TIME MARK

ITT

RES

DELTA TIME COMPRESSIVE

DT

DTRC

DELTA T AT RECEIVER

DT_RCV

INP


DTUN

DELTA T UNFILTERED

DT_UNF

INP


DTXM

DELTA T AT TRANSMITTER

DT_XMT

INP


ERR

ERROR

ERROR

INP


FNOI

FAR RECEIVER NOISE

FNOISE

INP


GFAR

FAR RECEIVER GAIN

GAIN_F

INP


MSGR

MSG RECEIVER

MSGRCV

INP


GNEA

NEAR RECEIVER GAIN

GAIN_N

INP


SPHI

SONIC POROSITY

SPHI


MSGG

MSG GAIN

MSGGAI

INP


NNOI

NEAR RECEIVER NOISE

NNOISE

INP


PKCD

PICK CODE

PKCODE

INP


QDT

DELTA TIME QUALITY

QDT

RES


SDT2

US/F

US/M

DELTA T (2 FOOT)

SDT2

uS/ft

US/M

BHPT - BORE HOLE PROP TOOL

FLWT

LBS/G

K/M3

FLUID WEIGHT

FLWT

LBS/G

Kg/m3

RES


DTEM

DEGF

DEGC

DIFFERENTIAL TEMPERATURE

DTEM

degF

degC

RES


DPRS

PSIA

KPA

DIFFERENTIAL PRESSURE

DPRS

PSIA

Kpa

RES


PRES

PSIA

KPA

BOREHOLE PRESSURE

BHPRES

PSIA

Kpa

RES


PXIT

DEGF

DEGC

PRESSURE XDCR INTERNAL TEMP

PXIT

degF

degC

RES


PTMP

DEGF

DEGC

PROBE INTERNAL TEMP

PTMP

degF

degC

RES


RES

OHM-M

OHM-M

BOREHOLE RESISTIVITY

BHRES

OHM-M

OHM-M

RES


TEMP

DEGF

DEGC

BOREHOLE TEMPERATURE

BHTEMP

degF

degC

RES

US/F

DECP

US/M

DECP

uS/ft

100 pu

US/M

100 pu

RES

RES

RES

CALIPER - 2 ARM

AHVT

FT3

M3

ANNULAR VOLUME TOTAL

AHVT

ft3

m3

RES

CALIPER - 2 ARM

BHV

FT3

M3

BORE HOLE VOLUME MARK

BHV

ft3

m3

RES RES

CALIPER - 2 ARM

BHVT

FT3

M3

BOREHOLE VOLUME TOTAL

BHVT

ft3

m3

CALIPER - 2 ARM

CALI

IN

MM

CALIPER

CALI

in

mm

RES

CALIPER - 2 ARM

DCAL

IN

MM

DIFFERENTIAL CALIPER

DCAL

in

mm

RES RES

CALIPER - 2 ARM

AHV

FT3

M3

ANNULAR VOLUME MARK

AHV

ft3

m3

CAST-V - CIRCUM ACOU SCAN

AM32

IN

MM

CALIPER 32

AM32

in

mm

RES


AM31

IN

MM

CALIPER 31

AM31

in

mm

RES


AM30

IN

MM

CALIPER 30

AM30

in

mm

RES


AM29

IN

MM

CALIPER 29

AM29

in

mm

RES


AM28

IN

MM

CALIPER 28

AM28

in

mm

RES


AM27

IN

MM

CALIPER 27

AM27

in

mm

RES


AM33

IN

MM

CALIPER 33

AM33

in

mm

RES


AM25

IN

MM

CALIPER 25

AM25

in

mm

RES


AM38

IN

MM

CALIPER 38

AM38

in

mm

RES


AM26

IN

MM

CALIPER 26

AM26

in

mm

RES

9-4

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


AM34

IN

MM

CALIPER 34

AM34

in

mm

RES


AM35

IN

MM

CALIPER 35

AM35

in

mm

RES


AM24

IN

MM

CALIPER 24

AM24

in

mm

RES


AM37

IN

MM

CALIPER 37

AM37

in

mm

RES


AM20

IN

MM

CALIPER 20

AM20

in

mm

RES


AM39

IN

MM

CALIPER 39

AM39

in

mm

RES


AM40

IN

MM

CALIPER 40

AM40

in

mm


AMMN

CAST AMPLITUDE - MINIMUM

AMMN

RES


AMMX

CAST AMPLITUDE - MAXIMUM

AMMX

RES


AMP

CAST AMPLITUDE SCAN

AMP

RES


AVAM

AVERAGE AMPLITUDE

AVAM


AM36

CALIPER 36

AM36

IN

MM

RES

INP in

mm

RES


AM12

IN

MM

CALIPER 12

AM12

in

mm

RES


AM01

IN

MM

CALIPER 01

AM01

in

mm

RES


AM02

IN

MM

CALIPER 02

AM02

in

mm

RES


AM03

IN

MM

CALIPER 03

AM03

in

mm

RES


AM04

IN

MM

CALIPER 04

AM04

in

mm

RES


AM05

IN

MM

CALIPER 05

AM05

in

mm

RES


AM06

IN

MM

CALIPER 06

AM06

in

mm

RES


AM07

IN

MM

CALIPER 07

AM07

in

mm

RES


AM08

IN

MM

CALIPER 08

AM08

in

mm

RES


AM09

IN

MM

CALIPER 09

AM09

in

mm

RES


AM22

IN

MM

CALIPER 22

AM22

in

mm

RES


AM11

IN

MM

CALIPER 11

AM11

in

mm

RES


AM23

IN

MM

CALIPER 23

AM23

in

mm

RES


AM13

IN

MM

CALIPER 13

AM13

in

mm

RES


AM14

IN

MM

CALIPER 14

AM14

in

mm

RES


AM15

IN

MM

CALIPER 15

AM15

in

mm

RES


AM16

IN

MM

CALIPER 16

AM16

in

mm

RES


AM17

IN

MM

CALIPER 17

AM17

in

mm

RES


AM18

IN

MM

CALIPER 18

AM18

in

mm

RES


AM19

IN

MM

CALIPER 19

AM19

in

mm

RES


AVOD


AM21

IN

MM

RES


AM10

IN

MM


THKP


MXID

IN

MM

MAXIMUM INSIDE DIAMETER

MXID

in

mm


MXIR

IN

MM

MAXIMUM INSIDE RADIUS

MXIR

in

mm

RES


MXTK

IN

MM

MAXIMUM THICKNESS

MXTK

in

mm

RES

AVERAGE CASING OD

AVOD

CALIPER 21

AM21

in

mm

RES

CALIPER 10

AM10

in

mm

THICKNESS PLOT

THKP

RES RES RES


MXZ

MAXIMUM IMPEDENCE

MXZ

RES


NBS

NUMBER OF MISSED SHOTS

NBS

RES


OVAL

OVALITY

OVAL

RES


PAMP

PEAK AMPLITUDE

PAMP

RES


RADI

IN

MM

CAST RADIUS SCAN

RADI

in

mm


RAMN

IN

MM

CAST MINIMUM RADIUS

RAMN

in

mm

RES


RAMX

INCH

INCH

CAST MAXIMUM RADIUS

RAMX

in

INCH

RES


AVID

IN

MM

AVERAGE INSIDE DIAMETER

AVID

in

mm

RES


THET

DIRECTION FROM HIGH SIDE

THETA


MNTK

MINIMUM THICKNESS

MNTK

in

mm

RES

Mnemonics

IN

MM

RES

RES

9-5

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data

.1 ms

.1ms

.1 ms

.1ms

RES


TT

CAST TRANSIT TIME

TT


VOL1

IMPEDENCE VOLUME 1

VOL1

RES


VOL2

IMPEDENCE VOLUME 2

VOL2

RES


VOL3

IMPEDENCE VOLUME 3

VOL3

RES


VOL4

IMPEDENCE VOLUME 4

VOL4

RES


VOL5

IMPEDENCE VOLUME 5

VOL5

RES


XO

X COORDINATE FROM CENTER

XO

RES


YO

Y COORDINATE FROM CENTER

YO

RES


ZMUD

IMPEDENCE OF BOREHOLE FLUID

ZMUD

RES


ZP

IMPEDENCE PLOT

ZP

RES


SEQ

SCAN SEQUENCE

SEQ

TEL


GAS

GAS FLAG

GAS


AVIR

IN

MM

AVERAGE INSIDE RADIUS

AVIR

in

mm


AVTK

IN

MM

AVERAGE THICKNESS

AVTK

in

mm


AVZ

AVERAGE IMPEDENCE

AVZ


BSI

BAD SHOT INDEX

BSI


DIAV

IN

MM

CAST AVERAGE DIAMETER

DIAV

in

mm

RES


DIMN

IN

MM

CAST MINIMUM DIAMETER

DIMN

in

mm

RES

IN

MM

in

mm

RES

RES RES RES RES RES


DIMX

CAST MAXIMUM DIAMETER

DIMX


DVTH

DEVIATION OF THICKNESS

DVTK

RES


DVZ

DEVIATION OF IMPEDENCE

DVZ

RES


ECTY


MSPD

REV

ECCENTRICITY

ECTY

XDUCER REVOLUTIONS / SEC

MSPD

REV


FTT

US/FT


MNZ

FLUID TRAVEL TIME

FTT

uS/ft

US/M

MINIMUM IMPEDENCE

MNZ


HIGD

IN

MM

HIGH SCALE FOR DISTANCE

HIGHD

in

mm


HIGT

RES

IN

MM

HIGH SCALE FOR THICKNESS

HIGHT

in

mm

RES


HRAD


IDP

IN

MM

HOLE RADIUS

HRAD

in

mm

INNER DIAMETER PLOT

IDP

US/M

RES INP RES RES

RES RES


IRP

INNER RADIUS PLOT

IRP


LOWD

IN

MM

LOW SCALE FOR DISTANCE

LOWD

in

mm

RES


LOWT

IN

MM

LOW SCALE FOR THICKNESS

LOWT

in

mm

RES


MDWT

GMCC

MUD WEIGHT GM/CC

MUDWT

GMCC


MNID

IN

MM

MINIMUM INSIDE DIAMETER

MNID

in

mm

RES


MNIR

IN

MM

MINIMUM INSIDE RADIUS

MNIR

in

mm

RES

MUDCELL WAVE NUMB SAMPLES

MCNS

KHZ

KHZ

MEASURED KHZ

FREQ

1000 Hz

1000 Hz

RES


MCNS


FREQ

RES

RES

RES


LWAV

LONG WAVEFORM

LWAV

RES


MZP

CALCULTED MUD IMPEDANCE

MZP

RES


MNCS

MINIMUM COMPRESSIVE STRENGTH

MNCS

RES


MFTT

MUDCELL FTT REFLECTION

MFTT

RES


MDN

MUDCELL DENSITY

MDN

RES


MCSQ

MUDCELL SEQUENCE NUMBER

MCSQ

RES


AVCS

AVERAGE COMPRESSIVE STRENGTH

AVCS

RES


CSP

COMPRESSIVE STRENGTH IMAGE

CSP

RES


AVRA

AVERAGE RADIUS

AVRA

INP


LSTO

START TIME LONG WAVEFORM

LSTO

RES


RB

RELATIVE BEARING

RB

RES


LWNS

LONG WAVEFORM NUMB. SAMPLES

LWNS

RES

9-6

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


LWSQ

LONG WAVEFORM SEQUENCE NUMBER

LWSQ

RES


LWNS

LONG WAVEFORM NUMB. SAMPLES

LWNS

RES


MAMP

MUDCELL PEAK AMPLITUDE

MAMP

RES


MATN

CALCULATED MUD ATTENUATION

MATN

RES


MCAL

CALIBRATED MUDCELL OFFSET

MCAL

RES


MCF

CALCULATED MUDCELL FREQUENCY

MCF

RES


FSRA

FIRST SHOT RAW AMPLITUDE

FSRA

RES


RWAV

FAST CAST TRANSDUCER WAVEFORM

RWAV

RES


SMRT

SAMPLE RATE

SMRT

RES


RBRF

TOOL REFERENCE ANGLE

RBRF

RES


MNZD

MINIMUM DIFFERENTIAL IMPEDANCE

MNZD

RES

CCL - CASING COLLAR LOCATOR

CCL

CASING COLLAR LOCATOR

CCL

RES

CSNG - COMP SPECT GAMMA

HBAR

BARITE CORR FACTOR - RUN AVG

HBAR

RES


MINU

URANIUM - MIN ERROR

MINU

RES


MINT

THORIUM - MIN ERROR

MINT

RES


MINK

POTASSIUM - MIN ERROR

MINK

RES


MAXU

URANIUM - MAX ERROR

MAXU

RES


MAXT

THORIUM - MAX ERROR

MAXT

RES


MAXK

POTASSIUM - MAX ERROR

MAXK

RES


LSPC

LOW ENERGY SPECTRUM

LSPC

RES


HBHK

BORHOLE POTASSIUM - RUN AVG

HBHK

RES


ERTO

ERROR GAMMA RAY TOTAL

ERTO

RES


ERTC

ERROR GAMMA RAY KT

ERTC

RES


EHBK

BOREHOLE K CONCENTRATION ERROR

EHBK

RES


CVBF

COMPUTED BARITE FACTOR

CVBF

RES


CRDF

RESOLUTION DEGRADE FACTOR

CRDF

RES


CGCF

SPECTRAL GAIN CORR FACTOR

CGCF

RES


CASR

CSNG CASING RATIO

CASR

RES


HSPC

HIGH ENERGY SPECTRUM

HSPC

RES


STAB

CSNG STABILIZER

STAB

INP


LITR

LITHOLOGY RATIO

LITR

RES


LSPD

LINE SPEED

LSPEED

INP


NAVG

TPU INTERVALS PER DEPTH INTERv

NUMAVG


NOIS

CPS

CPS

SPECTRAL NOISE

NOIS

1.0/S

1.0/S


POTA

%

%

POTASSIUM

POTA

%

%


SPEH

CSNG HIGH ENERGY SPECTRUM SUM

SPEH

INP


SPEL

CSNG LOW ENERGY SPECTRUM SUM

SPEL

INP


AMER

AMERICIUM COUNTS

AMER

INP


SRCF

SOURCE FACTOR

SRCF

RES

GAMMA THORIUM

GRTH

SWITCH POSITION

SW_POS

THORIUM

THOR

RES


GRTH SWPO


THOR


TKRT

CSNG RATIO THORIUM POTASSIUM

TKRT

RES


TOID

CSNG TOOL ID

TOOLID

INP


TOTF

CSNG TOTAL SPECTRA COUNTER

TOTFRM

INP


TURT

CSNG RATIO THORIUM URANIUM

TURT

RES


UKRT


URAN


SRAT

PPM

PPM

GAPI

RES


Mnemonics

GAPI

RES

PPM

PPM

CSNG RATIO URANIUM POTASSIUM

UKRT

URANIUM

URAN

SELECTED RATIO

SRAT

gAPI

gAPI

RES

ppm

ppm

RES

INP

RES ppm

ppm

RES RES

9-7

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


FRMI

FRAMES PER DEPTH INCRAMENT

FRMINC


CCL

CSNG CCL INPUT

CCL

RES INP


CSPC

CSNG DISPLAY SPECTRUM

CSPC

RES


CTIM

ACCUMULATION TIME

C_TIME

TEL


DERR

CSNG FRAME DATA ERROR

DATERR

INP


ERPO

%

%

ERROR POTASSIUM

ERPO

%

%

RES


ERTH

PPM

PPM

ERROR THORIUM

ERTH

ppm

ppm

RES


ERUR

PPM

PPM

ERROR URANIUM

ERUR

ppm

ppm

RES


FAVG

AVERAGE FRAME TIME

FRMAVG


GRUR

GAMMA URANIUM

GRUR

gAPI

gAPI


FRCT

CSNG SPECTRAL FRAME COUNTER

FRMCNT

GAPI

GAPI

RES RES TEL


GRTO

GAPI

GAPI

TOTAL GAMMA (150 KEV - 3 MEV)

GRTO

gAPI

gAPI

RES


FTIM

MSEC

MSEC

FRAME TIME

FTIME

MSEC

MSEC

RES


GKCL

GAPI

GAPI

GAMMMA KCL

GKCL

gAPI

gAPI

RES


GKUT

GAPI

GAPI

GAMMA KUT

GKUT

gAPI

gAPI

RES


GRHI

GAPI

GAPI

OBSERVED GAMMA (500KEV - 3MEV)

GRHI

gAPI

gAPI

RES


GRK

GAPI

GAPI

GAMMA POTASSIUM

GRK

gAPI

gAPI

RES


GRKC

GAPI

GAPI

GAMMMA KCL CORRECTED

GRKC

gAPI

gAPI

RES RES


GRKT

GAPI

GAPI

GAMMA KT

GRKT

gAPI

gAPI


AMCR

CPS

CPS

AMERICIUM COUNTS

AMCR

1.0/S

1.0/S


FERR

FIT ERROR

FERR

RES RES


BORQ

BORQ

BORQ

RES


MNGR

MIN GAMMA RAY TOTAL ERROR

MNGR

RES


MNHB

MIN BH POTASSIUM RUN AVG

MNHB

RES


MNKT

MIN GAMMA RAY KT ERROR

MNKT

RES


MXBK

MAX BH K CONCENT ERROR

MXBK

RES


MXGR

MAX GAMMA RAY TOTAL

MXGR

RES


MXHB

MAX BH POTASSIUM RUN AVG

MXHB

RES


MXKT

MAX GAMMA RAY KT ERROR

MKKT

RES


MNBK

MIN BH K CONCENT ERROR

MNBK

DH TENSION

DLOD

LB

KG

DOWNHOLE TENSION (HDTD)

DLOD

lbm

Kg

RES

RES

DH TENSION

TEM2

DEGF

DEGC

BOREHOLE TEMPERATURE

TEM2

degF

degC

RES

DH TENSION

PLOC

DEG

DEG

PAD LOCATOR (HDTD)

PLOC

deg

deg

RES

DLLT- DUAL LATERLOG

LLS

OHMM

OHMM

LATEROLOG SHALLOW RESISTIVITY

LLS

ohm.m

ohm.m

RES

DLLT- DUAL LATERLOG

CLLD

MMHO

MS-M

LATEROLOG DEEP CONDUCTIVITY

CLLD

0.001/ohm

mS.m

RES

DLLT- DUAL LATERLOG

DI

IN

IN

DIAMETER OF INVASION

DI

RES

DLLT- DUAL LATERLOG

LLDC

OHMM

OHMM

LLD CORRECTED

LLDC

RES

DLLT- DUAL LATERLOG

LLSC

OHMM

OHMM

LLS CORRECTED

LLSC

RES

DLLT- DUAL LATERLOG

RT

OHMM

OHMM

TRUE RESISTIVITY

RT

RES

DLLT- DUAL LATERLOG

RX0

OHMM

OHMM

FLUSHED ZONE RESISTIVITY

RX0

DLLT- DUAL LATERLOG

LLD

OHMM

OHMM

LATEROLOG DEEP RESISTIVITY

LLD

ohm.m

ohm.m

RES

DSN/DSEN - DUAL SPACE NEUTRON

NPRS

DECP

DECP

HDSN PRESSURE POROSITY CORR

NPRS

100 pu

100 pu

RES


MCOR

DECP

DECP

DSEN MUD POROSITY CORRECTION

MCOR

100 pu

100 pu

RES


NPHS

DECP

DECP

NEUTRON POROSITY SANDSTONE

NPHS

100 pu

100 pu

RES


NBHC

DECP

DECP

HDSN BOREHOLE POROSITY CORR

NBHC

100 pu

100 pu

RES


NBHL

DECP

DECP

HDSN BAD HOLE POROSITY CORR

NBHL

100 pu

100 pu

RES

9-8

RES

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


NCSG

DECP

DECP

HDSN CASING POROSITY CORR

NCSG

100 pu

100 pu

RES


NDNU

CPS

CPS

HOSTILE DSN NEAR COUNTS UNFILT

NDNU

1.0/S

1.0/S

RES


ADPE

DECP

DECP

DSEN AIR DOLO POROSITY EVR

ADPE

100 pu

100 pu

RES


NDSE

DSNE NEAR SPACED COUNTS

NDSE


NDSN

CPS

CPS

DSN NEAR COUNTS

NDSN

1.0/S

1.0/S

RES


RNDS

COUNTS

COUNTS

RAW DSN II NEAR COUNTS

NDSN

COUNTS

COUNTS

TEL


NPSO

DECP

DECP

HDSN STANDOFF POROSITY CORR

NPSO

100 pu

100 pu

RES


FDSN

CPS

CPS

DSN FAR COUNTS

FDSN

1.0/S

1.0/S

RES


NRAT

C/C

C/C

DSN (NDSN/FDSN) RATIO

NRAT

C/C

C/C

RES


ENPH

DECP

DECP

DSEN LIQUID POROSITY

ENPH

100 pu

100 pu

RES


NTMP

DECP

DECP

HDSN TEMPERATURE POROSITY CORR

NTMP

100 pu

100 pu

RES


NTOT

DECP

DECP

HDSN TOTAL POROSITY CORR

NTOT

100 pu

100 pu

RES


RFDS

COUNTS

COUNTS

RAW DSN II FAR COUNTS

FDSN

COUNTS

COUNTS

TEL


NLIM

DECP

DECP

NEUTRON PHI LIME MATRIX

NLIM

100 pu

100 pu

RES


NPHD

DECP

DECP

NEUTRON POROSITY DOLOMITE

NPHD

100 pu

100 pu

RES


ENDS

CPS

CPS

DSN NEAR COUNTS - EVR

ENDSN

1.0/S

1.0/S

RES


EAPH

DECP

DECP

DSEN AIR POROSITY

EAPH

100 pu

100 pu

RES


LDPE

DECP

DECP

DSEN LIQUID DOLO POROSITY EVR

LDPE

100 pu

100 pu

RES


LLP

DECP

DECP

DSEN LIQUID LIME POROSITY

LLP

100 pu

100 pu

RES


LLPE

DECP

DECP

DSEN LIQUID LIME POROSITY EVR

LLPE

100 pu

100 pu

RES


LSP

DECP

DECP

DSEN LIQUID SAND POROSITY

LSP

100 pu

100 pu

RES


LSPE

DECP

DECP

DSEN LIQUID SAND POROSITY EVR

LSPE

100 pu

100 pu

RES


LPHI

DECP

DECP

DSEN LIQUID POROSITY

LPHI

100 pu

100 pu

RES


EMPH

DECP

DECP

MEAN OF NEAR/FAR AIR POROSTIY

EMPH

100 pu

100 pu

RES


ELPH

DECP

DECP

DSEN AIR POROSITY LONG

ELPH

100 pu

100 pu

RES


ENRA

C/C

C/C

DSN (NDSN/FDSN) RATIO - EVR

ENRAT

C/C

C/C

RES


EFDS

CPS

CPS

DSN FAR COUNTS - EVR

EFDSN

1.0/S

1.0/S

RES


FDSE

DSEN FAR SPACED COUNTS

FDSE


ASPE

DECP

DECP

DSEN AIR SAND POROSITY EVR

ASPE

100 pu

100 pu

RES


NPHI

DECP

DECP

NEUTRON POROSITY

NPHI

100 pu

100 pu

RES


ENLI

DECP

DECP

NEUTRON PHI LIME MATRIX - EVR

ENLIM

100 pu

100 pu

RES


ALPE

DECP

DECP

DSEN AIR LIME POROSITY EVR

ALPE

100 pu

100 pu

RES


ENPD

DECP

DECP

NEUTRON POROSITY DOLOMITE EVR

ENPHD

100 pu

100 pu

RES

Mnemonics

TEL

TEL

9-9

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


LDP

DECP

DECP

DSEN LIQUID DOLO POROSITY

LDP

100 pu

100 pu

RES


ENPS

DECP

DECP

NEUTRON POROSITY SAND EVR

ENPHS

100 pu

100 pu

RES


ETCO

EVR TOTAL CORRECTION

ETCOR


FDNU

HOSTILE DSN FAR COUNTS UNFILT

FDNU

CPS

CPS

RES 1.0/S

1.0/S

RES

EMI - ELECT MICRO IMAGING

ACYU

G

G

ACCELEROMETER Y UNFILTERED

ACYU

G

G

INP


EDD2

OHMM

OHMM

PAD #2 RESISTIVITY (FAST)

EDD2

ohm.m

ohm.m

RES


CALA

IN

MM

EMI AVERAGE CALIPER

CALA

in

mm

RES


DCAL

IN

MM

EMI DIFFERENTIAL CALIPER

DCAL

in

mm

RES


DEVI

DEG

DEG

DRIFT ANGLE

DEVI

deg

deg

RES


DMAX

IN

MM

EMI MAXIMUM CALIPER PAIR

DMAX

in

mm

RES


DMIN

IN

MM

EMI MINIMUM CALIPER PAIR

DMIN

in

mm

RES


DXT2

08.3MS

08.3MS

Z ACCELEROMETER (FAST) TIME

DXT2

8.3 mS

8.3 mS

RES


ACCZ

G

G

ACCELEROMETER Z-AXIS

ACCZ

G

G

RES


EDD1

OHMM

OHMM


EDD1

ohm.m

ohm.m

RES


CAL4

IN

MM

EMI CALIPER ARM #4 (DIAMETER)

CAL4

in

mm

RES


EDD3

OHMM

OHMM


EDD3

ohm.m

ohm.m

RES


EDD4

OHMM

OHMM


EDD4

ohm.m

ohm.m

RES


EDD5

OHMM

OHMM


EDD5

ohm.m

ohm.m

RES


EDD6

OHMM

OHMM


EDD6

ohm.m

ohm.m


EMIM

EMI TOOL MODE

EMIM

RES INP


EMMR

VOLT

VOLT

REAL PART PHASOR VOLTAGE

EMMR

V

V

INP


DXTM

08.3MS

08.3MS

Z ACCELEROMETER (FAST) TIME

DXTM

8.3 mS

8.3 mS

RES


BHVT

FT3

M3


BHVT

ft3

m3

RES


ACCX

G

G

ACCELEROMETER X-AXIS

ACCX

G

G

RES


ACCY

G

G

ACCELEROMETER Y-AXIS

ACCY

G

G

RES


ACXU

G

G

ACCELEROMETER X UNFILTERED

ACXU

G

G

INP


ACZU

G

G

ACCELEROMETER Z UNFILTERED

ACZU

G

G

INP


AHV

FT3

M3

ANNULAR HOLE VOLUME MARK

AHV

ft3

m3

RES


AHVT

FT3

M3

ANNULAR HOLE VOLUME TOTAL

AHVT

ft3

m3

RES


CAL6

IN

MM


CAL6

in

mm

RES


BHV

FT3

M3

BOREHOLE VOLUME MARK

BHV

ft3

m3

RES


CAL5

IN

MM


CAL5

in

mm

RES RES


C14

IN

MM

EMI CALIPER PAIR 1-4

C14

in

mm


C25

IN

MM


C25

in

mm

RES


C36

IN

MM


C36

in

mm

RES RES


CAL1

IN

MM


CAL1

in

mm


CAL2

IN

MM


CAL2

in

mm

RES


CAL3

IN

MM


CAL3

in

mm

RES

ACCELEROMETER SUM OF SQUARES

ACCQ

DEG

DEG

PAD #1 AZIMUTH

AZI1

deg

deg

RES


ACCQ


AZI1

RES


MAGZ

MAGNETOMETER Z-AXIS

MAGZ


P4B1

OHMM

OHMM

PAD #4 RESISTIVITY

P4B1

ohm.m

ohm.m

RES RES


ITMP

DEGF

DEGC

INTERNAL TEMPERATURE

ITMP

degF

degC

RES

DEG

DEG

deg

deg

RES


LOWS

LOW SIDE OF HOLE

LOSIDE


MAGQ

MAGNETOMETER SUM OF SQUARES

MAGQ

RES


MAGX

MAGNETOMETER X-AXIS

MAGX

RES


F6B1

SED PAD #6, PROFILE 1 (FAST)

F6B1

RES

9-10

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


MAGY

MAGNETOMETER Y-AXIS

MAGY


F5B1


F5B1

RES RES


MGXU

MAGNETOMETER X UNFILTERED

MGXU

INP


MGYU

MAGNETOMETER Y UNFILTERED

MGYU

INP


MGZU

MAGNETOMETER Z UNFILTERED

MGZU

INP


P1B1

OHMM

OHMM

PAD #1 RESISTIVITY

P1B1

ohm.m

ohm.m

RES


P2B1

OHMM

OHMM

PAD #2 RESISTIVITY

P2B1

ohm.m

ohm.m

RES


RB

DEG

DEG

PAD #1 ROTATION

RB

deg

deg

RES


RAD6

IN

MM

EMI CALIPER ARM #6 (RADIUS)

RAD6

in

mm

RES


ERD4

OHMM

OHMM

PAD #4 RESISTIVITY FAST UNDELY

ERD4

ohm.m

ohm.m


BTOT

TOAL MAGNETIC FIELD - NAV TOOL

BTOT

RES RES


GTOT

TOAL GRAVITY FIELD - NAV TOOL

GTOT

RES


HDIA

MEASURED HOLE DIAMETER

HDIA

RES


TLFC


ERD1

OHMM


HAZI

DEG


ERD3

OHMM

TOOL FACE DIRECTION

TLFC


ERD1

ohm.m

ohm.m

DEG

DRIFT AZIMUTH

HAZI

deg

deg

RES

OHMM


ERD3

ohm.m

ohm.m

RES

OHMM

RES RES


P5B1

OHMM

OHMM

PAD #5 RESISTIVITY

P5B1

ohm.m

ohm.m

RES


ERD5

OHMM

OHMM


ERD5

ohm.m

ohm.m

RES


ERD6

OHMM

OHMM


ERD6

ohm.m

ohm.m


F1B1


F1B1

RES RES


F2B1


F2B1

RES


F3B1


F3B1

RES


F4B1


F4B1


ERD2

OHMM

OHMM


ERD2

ohm.m

ohm.m

RES

RES


RAD5

IN

MM


RAD5

in

mm

RES


RHOC

OHMM

OHMM

BHC CORR. RESISTIVITY

RHOC

ohm.m

ohm.m

RES


TEMP

DEGC

DEGC

NAVIGATION TEMPERATURE

TEMP

degC

degC

RES


ZAC2

G

G

Z ACCELEROMETER (FAST)

ZAC2

G

G

RES


ZACC

G

G


ZACC

G

G

RES


P3B1

OHMM

OHMM

PAD #3 RESISTIVITY

P3B1

ohm.m

ohm.m

RES


EMMX

VOLT

VOLT

IMAGINARY PART PHASOR VOLTAGE

EMMX

V

V

INP


RHOA

OHMM

OHMM

AVERAGE RESISTIVITY

RHOA

ohm.m

ohm.m

RES


RAD4

IN

MM


RAD4

in

mm

RES


RAD3

IN

MM


RAD3

in

mm

RES


RAD2

IN

MM


RAD2

in

mm

RES


PRES

EMI PAD FORCE

PRES


PDDV

V

V

EMI RELATIVE PAD VOLTAGE

PDDV

V

V

RES RES


PADS

NESW

NESW

VIEW BUTTONS IMAGE (N-E-S-W-N)

PADS

NESW

NESW

RES


PAD6

PAD #6 - FAST DATA ARRAY

PAD6


PAD5


PAD5

INP


PAD4


PAD4

INP


P6B1


PAD1


RAD1


PAD2


PAD3

FCMT - FORM COMP MONITOR

RGR1


ACCZ

Mnemonics

OHMM

IN

CPS

OHMM

MM

CPS

PAD #6 RESISTIVITY

P6B1


PAD1


RAD1


PAD2


PAD3

RAW GAMMA RAY 1

RGR1

ACCELEROMETER

ACCZ

INP

ohm.m

ohm.m

RES INP

in

mm

RES INP INP

1.0/S

1.0/S

RES RES

9-11

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


CCL

CCL FOR CORRELATION

CCL

RES


CCL1

RAW COLLAR LOCATOR 1

CCL1

RES


CCL2


TEMP

DEGF

DEGC

RAW COLLAR LOCATOR 2

CCL2

INTERNAL TOOL TEMPERATURE

TEMP

RES degF

degC

RES


GR

API

API

GAMMA RAY

GR

gAPI

gAPI

RES


RGR3

CPS

CPS

RAW GAMMA RAY 3

RGR3

1.0/S

1.0/S

RES


RGR2

CPS

CPS

RAW GAMMA RAY 2

RGR2

1.0/S

1.0/S

RES


DXTM

CPS

CPS

ACCELEROMETER TIME

DXTM

1.0/S

1.0/S

RES


RGR4

CPS

CPS

RAW GAMMA RAY 4

RGR4

1.0/S

1.0/S

RES

FIAC - FOUR INDEP ARM CALIPER

SO3

IN

MM

STAND OFF ARM 3

STAND3

in

mm

RES


SO4

IN

MM

STAND OFF ARM 4

STAND4

in

mm

RES


SO2

IN

MM

STAND OFF ARM 2

STAND2

in

mm

RES


SO1

IN

MM

STAND OFF ARM 1

STAND1

in

mm

RES


CALA

IN

MM

AVERAGE CALIPER (C1+C2)/2

CALA

in

mm

RES


CAL4

IN

MM

CALIPER 4

CAL4

in

mm

RES


CAL2

IN

MM

CALIPER 2

CAL2

in

mm

RES


CAL1

IN

MM

CALIPER 1

CAL1

in

mm

RES


C24

IN

MM

FOUR ARM CALIPER ARMS 2 & 4

C24

in

mm

RES


C13

IN

MM

FOUR ARM CALIPER ARMS 1 & 3

C13

in

mm

RES


CAL3

IN

MM

CALIPER 3

CAL3

in

mm

RES

FWST - FULL WAVE SONIC

AMPL

DB

DB

AMPLITUDE

AMPL

dB

dB


ITT

INTEGRATED TRAVEL TIME MARK

ITT

RES RES


GFAR

FAR RECEIVER GAIN

GAIN_F

INP


FNOI

FAR RECEIVER NOISE

FNOISE

INP


ERR

ERROR

ERROR

INP


DTXM

DELTA T AT TRANSMITTER

DT_XMT

INP


DTUN

DELTA T UNFILTERED

DT_UNF

INP


ALPH

ALPHA

ALPHA

INP


DT


ALPH

US/F

US/M

DELTA TIME COMPRESSIVE

DT

ALPHA

ALPHA

uS/ft

US/M

INP

RES


MSGR

MSG RECEIVER

MSGRCV

INP


ITTT

INTEGRATED TRAVEL TIME TOTAL

ITTT

RES


DTRC

DELTA T AT RECEIVER

DT_RCV


TT1

NEAR TRAVEL TIME

TT1

US

US

INP uS

uS

RES


NNOI

NEAR RECEIVER NOISE

NNOISE

INP


WFMS

FWST MSG WAVEFORM

WFMSG

INP


WFFW

MONOPOLE WF; ONE OF TWO WF'S.

WFMT

TEL


GNEA

NEAR RECEIVER GAIN

GAIN_N

INP


TT2

US

US

FAR TRAVEL TIME

TT2

uS

uS

RES


SPHI

DECP

DECP

SONIC POROSITY

SPHI

100 pu

100 pu

RES


SDT2

US/F

US/M

DELTA T (2 FOOT)

SDT2

uS/ft

US/M


QDT

DELTA TIME QUALITY

QDT

RES RES


PKCD

PICK CODE

PKCODE

INP


WFFW

HFWS FULL WAVE WAVEFORMS

WFFW

INP

9-12

Mnemonics

LIS Mnem

LISU_ eng

LISU_ met

GTET-GAMMA TELEMETRY

ACCZ

G

G


EGR

Serv_Name


INCL


GR

HDIL - HOSTILE DUAL IND RES

ILM

DEG

OHMM

DEG

OHMM

Mnem

DLISU_ Eng

DLISU_ Met


ACCZ

G

G

GAMMA RAY - EVR

EGR

Description

INCLINATION

INCL

GAMMA RAY

GR

INDUCTION MEDIUM RESISTIVITY

Type_ Data RES RES

deg

deg

RES

ILM

ohm.m

ohm.m

RES

RES


SP

MV

MV

SP

SP

mV

mV

RES


ILD

OHMM

OHMM

INDUCTION DEEP RESISTIVITY

ILD

ohm.m

ohm.m

RES

MMHO

MS-M

DEEP INDUCTION CONDUCTIVITY

CILD

0.001/ohm

mS.m

RES


CILD

HFDT - HI FREQ DIELECTRIC TOOL

FE23

DIFF DIELECTRIC CONST 12 17 CM

FE23

RES


FE13


FE13

RES


FE12


FE12

RES


FDB3

DB

DB

AMPLITUDE 17 CM RECEIVER

FDB3

dB

dB

RES


FDB2

DB

DB


FDB2

dB

dB

RES


FDB1

DB

DB


FDB1

dB

dB

RES


FD23

DB

DB

DIFF AMPLITUDE 12 17 CM RCVR

FD23

dB

dB

RES


FET2

DIELECTRIC CONSTANT 12 CM

FET2


FD13


FD13


FET3

DIELECTRIC CONST 17 CM

FET3

RES


FET1

DIELECTRIC CONSTANT 8 CM

FET1

RES


MP1V

MINUS .1 VOLT

MP1V

TEL


FTPL

HFDT TRAVEL TIME

FTPL


GR16

GROUND 16

GR16

TEL


GR64

GROUND 64

GR64

TEL


GRD1

GROUND 1

GRD1

TEL


GRD4

GROUND 4

GRD4

TEL


HSTA

HFDT TOOL STATUS

HSTA

TEL


IMLA

MICROLOG LATERAL

IMLA

TEL


IMNO

MICROLOG NORMAL

IMNO

TEL


ITEM

RAW TEMPERATURE

ITEM

TEL


ITMP

HFDT TEMPERATURE

TEMP

INP


FETR

TRANS. DIELECTRIC R

FETR

RES


M8V

MINUS 8. VOLT

M8V

TEL


FRPY

HFDT REFELECTED POWER Y

FRPY

TEL


MP5V

MINUS .5 VOLT

MP5V

TEL


P2V

POSITIVE 2 VOLT

P2V

TEL

Mnemonics

DB

NS/M

DB

NS/M

RES dB

NS/M

dB

NS/M

RES

RES

9-13

Serv_Name

LIS Mnem

HFDT - HI FREQ DIELECTRIC TOOL HFDT - HI FREQ DIELECTRIC TOOL

LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

P8V

POSITIVE 8 VOLT

P8V

TEL

PP1V

POSITIVE .1 VOLT

PP1V

TEL


PP5V

POSITIVE .5 VOLT

PP5V

TEL


RACZ

HFDT Z-ACCELEROMETER RAW

RACZ

TEL


RAD1

CALIPER 1

RAD1

TEL


RAD2

CALIPER 2

RAD2

TEL


TEM2

DSTU TEMPERATURE (F)

DSTEMP

TEL


TPL

HFDT TRAVEL TIME - LO RES

FTPL25


ZACC

ACCZ CALIBRATED INPUT FAST

ZACC

INP


M2V

MINUS 2. VOLT

M2V

TEL


FR1Y

HFDT REC. #1 Y COMPONENT

FR1Y

TEL


FPH1

PHASE 8 CM RECEIVER

FPH1


FIPY

HFDT INCIDENT POWER Y

FIPY


FP12

DEGREE

DEGREE

DIFF PHASE 8 12CM RECEIVER

FP12

deg

deg

RES


FP13

DEGREE

DEGREE


FP13

deg

deg

RES


FP23

DEGREE

DEGREE


FP23

deg

deg

RES


FPH2

DEGREE

DEGREE

PHASE 12 CM RECEIVER

FPH2

deg

deg

RES


FPHX

DECP

DECP

HFDT POROSITY

FPHX

100 pu

100 pu

RES


FPHY

HFDT QUALITY

FPHY


FR1

OHMM

OHMM

RESISTIVITY 8 CM

FR1

ohm.m

ohm.m

RES


FR12

OHMM

OHMM

DIFF RESISTIVITY 8 12 CM

FR12

ohm.m

ohm.m

RES


FR13

OHMM

OHMM

DIFF RESISTIVITY 8 17CM

FR13

ohm.m

ohm.m

RES


FT25

NS/M

NS/M

HFDT TRAVEL TIME - LO RES

FTPL25

NS/M

NS/M

RES


FR1X

HFDT REC. #1 X COMPONENT

FR1X


FRTR

OHMM

OHMM

TRANS. RESISTIVITY

FRTR

ohm.m

ohm.m

RES


FR2

OHMM

OHMM

RESISTIVITY 12 CM

FR2

ohm.m

ohm.m

RES


FR23

OHMM

OHMM

DIFF RESISTIVITY 12 17CM

FR23

ohm.m

ohm.m

RES


FR2G

HFDT REC. #2 GAIN

FR2G

TEL


FR2X


FR2X

TEL


FR2Y


FR2Y

TEL


FR3

RESISTIVITY 17 CM

FR3


FR3G

HFDT REC. #3 GAIN

FR3G

TEL


FR3X


FR3X

TEL

9-14

NS/M

DEGREE

OHMM

NS/M

DEGREE

OHMM

NS/M

deg

NS/M

deg

RES

RES TEL

RES

TEL

ohm.m

ohm.m

RES

Mnemonics

Serv_Name

LIS Mnem

HFDT - HI FREQ DIELECTRIC TOOL HFDT - HI FREQ DIELECTRIC TOOL

LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

FR3Y


FR3Y

TEL

FRPX

HFDT REFELECTED POWER X

FRPX

TEL


FIPX

HFDT INCIDENT POWER X

FIPX

TEL


FR1G

HFDT REC. #1 GAIN

FR1G

TEL


AG1

AUX GROUND 1

AG1

TEL


FPH3

DEGREE

DEGREE

PHASE 17 CM RECEIVER

FPH3

deg

deg

RES


AC

DB/M

DB/M

ATTENUATION CORRECTED - LO RES

FAC25

DB/M

DB/M

RES


FD12

DB

DB


FD12

dB

dB

RES


AG16

AUX GROUND 16

AG16

TEL


AG4

AUX GROUND 4

AG4

TEL


AG64

AUX GROUND 64

AG64

TEL


DXTM

08.3MS

08.3MS

HFDT Z-ACCELEROMETER TIME BASE

DXTM

8.3 mS

8.3 mS

INP


FA25

DB/M

DB/M

ATTENUATION CORRECTED - LO RES

FAC25

DB/M

DB/M

RES


FAC

DB/M

DB/M

ATTENUATION CORRECTED

FAC

dB/m

dB/m

RES

HRAI/HRI - HIGH RES ARRAY IND

HF06

OHMM

OHMM

HRAI 60 IN RAD RESIST 4FT

HF06

ohm.m

ohm.m

RES


HMR

HRI MEDIUM RAW R

HMR


HMCN

MMHO

MS-M

HRI MEDIUM CONDUCTIVITY

HMCN

0.001/ohm

mS.m

RES


HMC1

MMHO

MS-M

HRI MEDIUM CONDUCTIVITY 1FT

HMC1

0.001/ohm

mS.m

RES


HF12

OHMM

OHMM


HF12

ohm.m

ohm.m

RES


HF09

OHMM

OHMM


HF09

ohm.m

ohm.m

RES


HMR1

OHMM

OHMM

HRI MEDIUM RESISTIVITY 1FT

HMR1

ohm.m

ohm.m

RES


HF03

OHMM

OHMM


HF03

ohm.m

ohm.m

RES


HF02

OHMM

OHMM


HF02

ohm.m

ohm.m

RES


HF01

OHMM

OHMM


HF01

ohm.m

ohm.m

RES


HMRS

OHMM

OHMM

HRI MEDIUM RESISTIVITY

HMRS

ohm.m

ohm.m

RES


HDRS

OHMM

OHMM

HRI DEEP RESISTIVITY

HDRS

ohm.m

ohm.m

RES


HO09

OHMM

OHMM


HO09

ohm.m

ohm.m

RES


HDR1

OHMM

OHMM

HRI DEEP RESISTIVITY 1FT

HDR1

ohm.m

ohm.m

RES


HDR

HRI DEEP RAW R

HDR

RES


HDX

HRI DEEP RAW X

HDX

RES


HO24

HRI DEEP RES 1FT 24 INCH I

HO24


HRM1

HRI MAP - ONE FOOT

HRM1

RES


HRFX

XMTR REF 32KHz X SIGNAL

X32KRF

INP

Mnemonics

OHMM

OHMM

RES

ohm.m

ohm.m

RES

9-15

Serv_Name

LIS Mnem

LISU_ eng


HRFR


HO90

OHMM


HO60


LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

XMTR REF 32KHz R SIGNAL

R32KRF

OHMM


HO90

ohm.m

ohm.m

RES

OHMM

OHMM


HO60

ohm.m

ohm.m

RES

HO03

OHMM

OHMM


HO03

ohm.m

ohm.m

RES


HO30

OHMM

OHMM


HO30

ohm.m

ohm.m

RES


HMX

HRI MEDIUM RAW X

HMX


HO12

OHMM

OHMM


HO12

ohm.m

ohm.m

RES


HD3R

MMHO

MMHO

LOWER 54" RCVR 32KHz R SIGNAL

HD3R

0.001/ohm

0.001/ohm

INP


HO06

OHMM

OHMM


HO06

ohm.m

ohm.m

RES


HDCN

MMHO

MS-M

HRI DEEP CONDUCTIVITY

HDCN

0.001/ohm

mS.m

RES


HO02

OHMM

OHMM


HO02

ohm.m

ohm.m

RES


HO01

OHMM

OHMM


HO01

ohm.m

ohm.m

RES


HO40

OHMM

OHMM


HO40

ohm.m

ohm.m

RES


DSE2

MMHO

MMHO


DSE2

0.001/ohm

0.001/ohm

RES


DT18

OHMM

OHMM

AVG DECON 18" 2FT

DT18

ohm.m

ohm.m

RES


DSE9

MMHO

MMHO


DSE9

0.001/ohm

0.001/ohm

RES


DSE8

MMHO

MMHO


DSE8

0.001/ohm

0.001/ohm

RES


DSE7

MMHO

MMHO


DSE7

0.001/ohm

0.001/ohm

RES


DSE6

MMHO

MMHO


DSE6

0.001/ohm

0.001/ohm

RES


DSE5

MMHO

MMHO


DSE5

0.001/ohm

0.001/ohm

RES


HD4R

MMHO

MMHO


HD4R

0.001/ohm

0.001/ohm

INP


DSE3

MMHO

MMHO


DSE3

0.001/ohm

0.001/ohm

RES


DT54

OHMM

OHMM

AVG DECON 54" 2FT

DT54

ohm.m

ohm.m

RES


DSE1

MMHO

MMHO


DSE1

0.001/ohm

0.001/ohm

RES


DSE0

MMHO

MMHO


DSE0

0.001/ohm

0.001/ohm

RES


DRCO

MMHO

MMHO

HRI DEEP R CORRECTION

DRCO

0.001/ohm

0.001/ohm

RES


DQZE

MMHO

MMHO

HRI DEEP QUALITY ZERO

DQZER

0.001/ohm

0.001/ohm

INP


DQU9

MMHO

MMHO

QUALITY U1

DQU9

0.001/ohm

0.001/ohm

RES


DQU8

MMHO

MMHO

QUALITY U2

DQU8

0.001/ohm

0.001/ohm

RES


DSE4

MMHO

MMHO


DSE4

0.001/ohm

0.001/ohm

RES


HD1R

MMHO

MMHO

LOWER 78" RVCR 32KHz R SIGNAL

HD1R

0.001/ohm

0.001/ohm

INP


ZM

DFL MEASURE Z

ZM


HD6R


HD6R

9-16

MMHO

MMHO

INP

RES

RES 0.001/ohm

0.001/ohm

INP

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng


HRM2


HD3X

MMHO


HT12


LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

HRI MAP - TWO FOOT

HRM2

MMHO

LOWER 54" RCVR 32KHz X SIGNAL

HD3X

0.001/ohm

0.001/ohm

INP

OHMM

OHMM


HT12

ohm.m

ohm.m

RES

HD2X

MMHO

MMHO


HD2X

0.001/ohm

0.001/ohm

INP


DT30

OHMM

OHMM

AVG DECON 30" 2FT

DT30

ohm.m

ohm.m

RES


HD1X

MMHO

MMHO


HD1X

0.001/ohm

0.001/ohm

INP


DT42

OHMM

OHMM

AVG DECON 42" 2FT

DT42

ohm.m

ohm.m

RES


ECC

ECCENTRICITY

ECC

RES


DZM

DFL MEASURE DELTA Z

DZM

RES


DZB

DFL BUCK DELTA Z

DZB

RES


DXCO

MMHO

MMHO

HRI DEEP X CORRECTION

DXCO

0.001/ohm

0.001/ohm

RES


DT78

OHMM

OHMM

AVG DECON 78" 2FT

DT78

ohm.m

ohm.m

RES


DT69

OHMM

OHMM

AVG DECON 69" 2FT

DT69

ohm.m

ohm.m

RES


HDC1

MMHO

MS-M

HRI DEEP CONDUCTIVITY 1FT

HDC1

0.001/ohm

mS.m

RES


HD2R

MMHO

MMHO


HD2R

0.001/ohm

0.001/ohm

INP


LSO

LEFT STANDOFF

LSO


LD4R

MMHO

MMHO

LOWER 42" RCVR 8 KHz R SIGNAL

LD4R

0.001/ohm

0.001/ohm

INP


LD4X

MMHO

MMHO

LOWER 42" RCVR 8 KHz X SIGNAL

LD4X

0.001/ohm

0.001/ohm

INP


LD6R

MMHO

MMHO


LD6R

0.001/ohm

0.001/ohm

INP


LD6X

MMHO

MMHO


LD6X

0.001/ohm

0.001/ohm

INP


LMAN

LEFT MANDREL

LMAN


HT06


HT06


LRFX

XMTR REF 8 KHz X SIGNAL

X8KREF


LD2X

MMHO

MMHO


LD2X

0.001/ohm

0.001/ohm

INP


LU1R

MMHO

MMHO

UPPER 78" RCVR 8 KHz R SIGNAL

LU1R

0.001/ohm

0.001/ohm

INP


LU1X

MMHO

MMHO

UPPER 78" RCVR 8 HKz X SIGNAL

LU1X

0.001/ohm

0.001/ohm

INP


LU2R

MMHO

MMHO


LU2R

0.001/ohm

0.001/ohm

INP


LU2X

MMHO

MMHO

UPPER 69" RCVR 8 KHz X SIGNAL

LU2X

0.001/ohm

0.001/ohm

INP


LU3R

MMHO

MMHO


LU3R

0.001/ohm

0.001/ohm

INP


LU3X

MMHO

MMHO


LU3X

0.001/ohm

0.001/ohm

INP


LRFR

XMTR REF 8 KHz R SIGNAL

R8KREF


HD4X

MMHO

MMHO


HD4X

0.001/ohm

0.001/ohm

INP


HU1X

MMHO

MMHO

UPPER 78" RCVR 32KHz X SIGNAL

HU1X

0.001/ohm

0.001/ohm

INP

Mnemonics

OHMM

OHMM

RES

RES

RES ohm.m

ohm.m

RES INP

INP

9-17

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


HU2R

MMHO

MMHO

UPPER 69" RCVR 32KHz R SIGNAL

HU2R

0.001/ohm

0.001/ohm

INP


HU2X

MMHO

MMHO


HU2X

0.001/ohm

0.001/ohm

INP


HU3R

MMHO

MMHO


HU3R

0.001/ohm

0.001/ohm

INP


HU3X

MMHO

MMHO


HU3X

0.001/ohm

0.001/ohm

INP


HU4R

MMHO

MMHO


HU4R

0.001/ohm

0.001/ohm

INP


LD3X

MMHO

MMHO


LD3X

0.001/ohm

0.001/ohm

INP


HU5R

MMHO

MMHO


HU5R

0.001/ohm

0.001/ohm

INP


LD3R

MMHO

MMHO


LD3R

0.001/ohm

0.001/ohm

INP


HU5X

MMHO

MMHO


HU5X

0.001/ohm

0.001/ohm

INP


DQU7

MMHO

MMHO

QUALITY U3

DQU7

0.001/ohm

0.001/ohm

RES


LD1R

MMHO

MMHO


LD1R

0.001/ohm

0.001/ohm

INP


LD1X

MMHO

MMHO


LD1X

0.001/ohm

0.001/ohm

INP


LD2R

MMHO

MMHO


LD2R

0.001/ohm

0.001/ohm

INP


LU5R

MMHO

MMHO


LU5R

0.001/ohm

0.001/ohm

INP


HU4X

MMHO

MMHO


HU4X

0.001/ohm

0.001/ohm

INP


HT60

OHMM

OHMM

HRI DEEP RES. 2FT RES 60INCH I

HT60

ohm.m

ohm.m

RES


LU4R

MMHO

MMHO


LU4R

0.001/ohm

0.001/ohm

INP


VRES

IN

IN

HRI VERTICAL RESOLUTION

VRES

IN

IN

RES


VRES

FT

FT

RESOLUTION OF VAR CURVES

VRES

ft

ft

RES


XFRA

HRI DEEP X FRACTION

XFRAC

RES


XHRF

XMTR REF 32KHz X DELAYED

XHRF

INP


ZB

DFL BUCK Z

ZB

RES


STEM

DEGF

DEGC

HRI SONDE TEMPERATURE

STEM

degF

degC

RES


HT90

OHMM

OHMM


HT90

ohm.m

ohm.m

RES


SP

MV

MV

ANALOG SPONTANEOUS POTENTIAL

SP

mV

mV

INP


HT40

OHMM

OHMM


HT40

ohm.m

ohm.m

RES


HT30

OHMM

OHMM


HT30

ohm.m

ohm.m

RES


HT24

OHMM

OHMM


HT24

ohm.m

ohm.m

RES


HT09

OHMM

OHMM


HT09

ohm.m

ohm.m

RES


HT03

OHMM

OHMM


HT03

ohm.m

ohm.m

RES


HT02

OHMM

OHMM


HT02

ohm.m

ohm.m

RES


HU1R

MMHO

MMHO


HU1R

0.001/ohm

0.001/ohm

INP


RMUD

OHMM

OHMM

MUD RESISTIVITY

RMUD

ohm.m

ohm.m

RES

9-18

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


HT01

OHMM

OHMM


HT01

ohm.m

ohm.m

RES


LU5X

MMHO

MMHO


LU5X

0.001/ohm

0.001/ohm

INP


MQCA

MMHO

MMHO

HRI MEDIUM QUALITY CAL

MQCAL

0.001/ohm

0.001/ohm

INP


MQZE

MMHO

MMHO

HRI MEDIUM QUALITY ZERO

MQZER

0.001/ohm

0.001/ohm

INP


MRCO

MMHO

MMHO

HRI MEDIUM R CORRECTION

MRCO

0.001/ohm

0.001/ohm

RES


MXCO

MMHO

MMHO

HRI MEDIUM X CORRECTION

MXCO

0.001/ohm

0.001/ohm

RES


TMPF

DEGF

DEGC

FEEDPIPE TEMP CALCULATED

TMPF

degF

degC

RES


RMAN

RIGHT MANDREL

RMAN


LU4X


LU4X


RSO

RIGHT STANDOFF

RSO


RT

OHMM

OHMM

UNINVADED ZONE RESISTIVITY

RT

ohm.m

ohm.m

RES


RX0

OHMM

OHMM

INVADED ZONE RESISTIVITY

RX0

ohm.m

ohm.m

RES


RXRT

RXO OVER RT

RXRT

RES


RXRT

RXO OVER RT

RXRT

RES


SP

SPONTANEOUS POTENTIAL

SP


RHRF

XMTR REF 32KHz R DELAYED

RHRF


DBH2


DBH2


DDRY

HRI DECONVOLED DEEP RY

DDRY


CT03

MMHO

MMHO

HRAI 30 IN RADIAL COND 2FT

CT03

0.001/ohm

0.001/ohm

RES


CT06

MMHO

MMHO


CT06

0.001/ohm

0.001/ohm

RES


CT09

MMHO

MMHO


CT09

0.001/ohm

0.001/ohm

RES


CT12

MMHO

MMHO


CT12

0.001/ohm

0.001/ohm

RES


D1

IN

MM

INNER RADIAL DEPTH OF INVASION

D1

in

mm

RES


D2

IN

IN

OUTTER RADIAL DPTH OF INVASION

D2

in

IN

RES


CT01

MMHO

MMHO


CT01

0.001/ohm

0.001/ohm

RES


DBH1

MMHO

MMHO


DBH1

0.001/ohm

0.001/ohm

RES


CO12

MMHO

MMHO


CO12

0.001/ohm

0.001/ohm

RES


DBH3

MMHO

MMHO


DBH3

0.001/ohm

0.001/ohm

RES


DBH4

MMHO

MMHO

BOREHOLE CORRECTIONS U5

DBH4

0.001/ohm

0.001/ohm

RES


DBH5

MMHO

MMHO


DBH5

0.001/ohm

0.001/ohm

RES


DBH6

MMHO

MMHO


DBH6

0.001/ohm

0.001/ohm

RES


DBH7

MMHO

MMHO


DBH7

0.001/ohm

0.001/ohm

RES


DBH8

MMHO

MMHO


DBH8

0.001/ohm

0.001/ohm

RES

Mnemonics

MMHO

MV

MMHO

MMHO

MV

MMHO

RES 0.001/ohm

0.001/ohm

INP RES

mV

mV

RES INP

0.001/ohm

0.001/ohm

RES RES

9-19

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


DBH9

MMHO

MMHO


DBH9

0.001/ohm

0.001/ohm

RES


HD6X

MMHO

MMHO


HD6X

0.001/ohm

0.001/ohm

INP


DBH0

MMHO

MMHO


DBH0

0.001/ohm

0.001/ohm

RES


CF06

MMHO

MMHO


CF06

0.001/ohm

0.001/ohm

RES


BH30

MMHO

MMHO

BOREHOLE CORRECTIONS 30"

BH30

0.001/ohm

0.001/ohm

RES


BH42

MMHO

MMHO


BH42

0.001/ohm

0.001/ohm

RES


BH54

MMHO

MMHO


BH54

0.001/ohm

0.001/ohm

RES


BH69

MMHO

MMHO


BH69

0.001/ohm

0.001/ohm

RES


BH78

MMHO

MMHO


BH78

0.001/ohm

0.001/ohm

RES


CALC

IN

IN

CALC DIAMETER

CALC

in

IN

RES


CF01

MMHO

MMHO


CF01

0.001/ohm

0.001/ohm

RES


CT02

MMHO

MMHO


CT02

0.001/ohm

0.001/ohm

RES


CF03

MMHO

MMHO


CF03

0.001/ohm

0.001/ohm

RES


DDX

HRI DECONVOLED DEEP X

DDX


CF09

MMHO

MMHO


CF09

0.001/ohm

0.001/ohm

RES


CF12

MMHO

MMHO


CF12

0.001/ohm

0.001/ohm

RES


CO01

MMHO

MMHO


CO01

0.001/ohm

0.001/ohm

RES


CO01

MMHO

MMHO


CO01

0.001/ohm

0.001/ohm

RES


CO02

MMHO

MMHO


CO02

0.001/ohm

0.001/ohm

RES


CO03

MMHO

MMHO


CO03

0.001/ohm

0.001/ohm

RES


CO06

MMHO

MMHO


CO06

0.001/ohm

0.001/ohm

RES


CO09

MMHO

MMHO


CO09

0.001/ohm

0.001/ohm

RES


CF02

MMHO

MMHO


CF02

0.001/ohm

0.001/ohm

RES


DO69

OHMM

OHMM

AVG DECON 69" 1FT

DO69

ohm.m

ohm.m

RES


DDRX

HRI DECONVOLED DEEP RX

DDRX


DLS4

OHMM

OHMM

SYMMETRIZED 8K S42"

DLS4

ohm.m

ohm.m

RES


DLU5

OHMM

OHMM

VERT DECON 8K UPPER 30"

DLU5

ohm.m

ohm.m

RES


DMR

HRI DECONVOLED MEDIUM R

DMR

RES


DMY

HRI DECONVOLED MEDIUM Y

DMY

RES


DO18

OHMM

OHMM

AVG DECON 18" 1FT

DO18

ohm.m

ohm.m

RES


DO30

OHMM

OHMM

AVG DECON 30" 1FT

DO30

ohm.m

ohm.m

RES


DLS2

OHMM

OHMM

SYMMETRIZED 8K S69"

DLS2

ohm.m

ohm.m

RES


DO54

OHMM

OHMM

AVG DECON 54" 1FT

DO54

ohm.m

ohm.m

RES

9-20

RES

RES

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


DLS1

OHMM

OHMM

SYMMETRIZED 8K S78"

DLS1

ohm.m

ohm.m

RES


DO78

OHMM

OHMM

AVG DECON 78" 1FT

DO78

ohm.m

ohm.m

RES


DQCA

HRI DEEP QUALITY CAL

DQCAL


DQU0

MMHO

MMHO

QUALITY D1

DQU0

0.001/ohm

0.001/ohm

RES


DQU1

MMHO

MMHO

QUALITY D2

DQU1

0.001/ohm

0.001/ohm

RES


DQU2

MMHO

MMHO

QUALITY D3

DQU2

0.001/ohm

0.001/ohm

RES


DQU3

MMHO

MMHO

QUALITY D4

DQU3

0.001/ohm

0.001/ohm

RES


DQU4

MMHO

MMHO

QUALITY U5

DQU4

0.001/ohm

0.001/ohm

RES


DQU5

MMHO

MMHO

QUALITY D6

DQU5

0.001/ohm

0.001/ohm

RES


DO42

OHMM

OHMM

AVG DECON 42" 1FT

DO42

ohm.m

ohm.m

RES


DFLF

OHMM

OHMM

DIGITALLY FOCUSED LATEROLOG FL

DFLF

ohm.m

ohm.m

RES


DDY

HRI DECONVOLED DEEP Y

DDY


DF18

OHMM

OHMM

AVG DECON 18" 4FT

DF18

ohm.m

ohm.m

RES


DF30

OHMM

OHMM

AVG DECON 30" 4FT

DF30

ohm.m

ohm.m

RES


DF42

OHMM

OHMM

AVG DECON 42" 4FT

DF42

ohm.m

ohm.m

RES


DF54

OHMM

OHMM

AVG DECON 54" 4FT

DF54

ohm.m

ohm.m

RES


DF69

OHMM

OHMM

AVG DECON 69" 4FT

DF69

ohm.m

ohm.m

RES


DQU6

MMHO

MMHO

QUALITY U4

DQU6

0.001/ohm

0.001/ohm

RES


DLS3

OHMM

OHMM

SYMMETRIZED 8K S54"

DLS3

ohm.m

ohm.m

RES


DFL

OHMM

OHMM

DIGITALLY FOCUSED LATEROLOG

DFL

ohm.m

ohm.m

RES


BH18

MMHO

MMHO


BH18

0.001/ohm

0.001/ohm

RES


DHD6

OHMM

OHMM

VERT DECON 32K LOWER 18"

DHD6

ohm.m

ohm.m

RES


DHS1

OHMM

OHMM

SYMMETRIZED 32K S78"

DHS1

ohm.m

ohm.m

RES


DHS2

OHMM

OHMM


DHS2

ohm.m

ohm.m

RES


DHS3

OHMM

OHMM


DHS3

ohm.m

ohm.m

RES


DHS4

OHMM

OHMM


DHS4

ohm.m

ohm.m

RES


DHU5

OHMM

OHMM

VERT DECON 32K UPPER 30"

DHU5

ohm.m

ohm.m

RES


DI

IN

IN

RADIAL DEPTH OF INVASION

DI

IN

IN

RES


DLD6

OHMM

OHMM

VERT DECON 8K LOWER 18"

DLD6

ohm.m

ohm.m

RES


DF78

OHMM

OHMM

AVG DECON 78" 4FT

DF78

ohm.m

ohm.m

RES

INP

RES

HSN - SHORT NORMAL RES

SGRU

OHMM

OHMM

UNFILTERED NORMAL RESISTIVITY

SGRU

ohm.m

ohm.m

RES


SGRD

OHMM

OHMM

SHORT NORMAL RESISTIVITY

SGRD

ohm.m

ohm.m

RES


RXRT

RXO OVER RT

RXRT

ICT - SIX INDEP ARM CALIPER

SO1

STAND OFF ARM 1

STAND1

in

mm

RES

Mnemonics

IN

MM

RES

9-21

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


RAD6

IN

MM

RADIUS CALIPER ARM # 6

RAD6

in

mm

RES


RAD5

IN

MM


RAD5

in

mm

RES RES


RAD4

IN

MM


RAD4

in

mm


RAD3

IN

MM


RAD3

in

mm

RES


RAD2

IN

MM


RAD2

in

mm

RES


RAD1

IN

MM


RAD1

in

mm

RES


SO6

IN

MM

STAND OFF ARM 6

STAND6

in

mm

RES


SO5

IN

MM

STAND OFF ARM 5

STAND5

in

mm

RES


SO4

IN

MM

STAND OFF ARM 4

STAND4

in

mm

RES


HAZI

DEG

DEG

DRIFT AZIMUTH

HAZI

deg

deg

RES


SO2

IN

MM

STAND OFF ARM 2

STAND2

in

mm

RES


CAL6

IN

MM

ICT CALIPER ARM #6

CAL6

in

mm

RES


CALA

IN

MM

ICT AVERAGE CALIPER

CALA

in

mm

RES RES


CAL5

IN

MM

ICT CALIPER ARM #5

CAL5

in

mm


CAL3

IN

MM

ICT CALIPER ARM #3

CAL3

in

mm

RES


CAL2

IN

MM

ICT CALIPER ARM #2

CAL2

in

mm

RES


CAL1

IN

MM

ICT CALIPER ARM #1

CAL1

in

mm

RES


C36

IN

MM

ICT CALIPER PAIR 3-6

C36

in

mm

RES


C25

IN

MM


C25

in

mm

RES


C14

IN

MM


C14

in

mm

RES


SO3

IN

MM

STAND OFF ARM 3

STAND3

in

mm

RES RES


CAL4

IN

MM

ICT CALIPER ARM #4

CAL4

in

mm


HAZI

DEG

DEG

DRIFT AZIMUTH

HAZI

deg

deg

RES


DEVI

DEG

DEG

DRIFT ANGLE

DEVI

deg

deg

RES


DEVI

DEG

DEG

DRIFT ANGLE

DEVI

deg

deg

RES


DCAL

IN

MM

DIFFERENTIAL CLAIPER

DCAL

in

mm

RES


HDIA

IN

MM

MEASURED HOLE DIAMETER

HDIA

in

mm

RES

DEG

DEG

RELEATIVE BEARNING

RB

deg

deg

RES

CALIPER PAD FORCE

PRES


RB


PRES


DMIN

IN

MM

MINIMUM CALIPER PAIR

DMIN

in

mm

RES


DMAX

IN

MM

MAXIMUM CALIPER PAIR

DMAX

in

mm

RES

IDT - INSITE DIRECTIONAL TOOL

RB

DEG

DEG

RELATIVE BEARING

RB

deg

deg

RES


MAGD

MAGNETIC DIP FOR DIRECT TOOL

MAGD

RES


MAGZ

MAGNETOMETER Z-AXIS

MAGZ

RES


MAGY

MAGNETOMETER Y-AXIS

MAGY

RES


MAGX

MAGNETOMETER X-AXIS

MAGX

RES


TLFC

TOOL FACE DIRECTION

TLFC

RES


GTOT

TOAL GRAVITY FIELD - NAV TOOL

GTOT

RES


BTOT

TOAL MAGNETIC FIELD - NAV TOOL

BTOT

RES


AZI1

DEG

DEG

PAD 1 AZIMUTH

AZI1

deg

deg

RES


ACCZ

G

G


ACCZ

G

G

RES


ACCQ

G

G

ACCELEROMETER QUALITY

ACCQ

G

G

RES


ACCX

G

G


ACCX

G

G

RES

9-22

RES

Mnemonics

Serv_Name

LIS Mnem


MTMP


ACCY


MAGQ

MACT - MULTI-ARM CALIPER

LISU_ eng

LISU_ met

Description

Mnem

MAGNET TEMPERATURE

MTMP


ACCY

G

G

CALCULATED MAGNETIC FIELD

MAGQ

CALA

IN

MM

AVERAGE CALIPER


MXID

IN

MM


MNID

IN


RMWL

IN

MRIL - MAGNETIC RESONANCE IMAGE

PC3

PU


PC2


DLISU_ Eng

DLISU_ Met

Type_ Data RES

G

G

CALA

in

mm

RES

CASING MAXIMUM ID

MXID

in

mm

RES

MM

CASING MINIMUM ID

MNID

in

mm

RES

MM

REMAINING WALL THICKNESS

RMWL

in

mm

RES

PU

Bin Sums 1-3 for display

PC3

pu

pu

RES

PU

PU


PC2

pu

pu

RES

PC4

PU

PU


PC4

pu

pu

RES


PC5

PU

PU


PC5

pu

pu

RES


PC1

PU

PU


PC1

pu

pu

RES


P9

PU

PU

BIN 9 Porosity

P9

pu

pu

INP


P7

PU

PU

BIN 7 Porosity

P7

pu

pu

INP


P6

PU

PU

BIN 6 Porosity

P6

pu

pu

INP


TPW

TOTAL POROSITY Distribution

TPW


P5

PU

PU

BIN 5 Porosity

P5

pu

pu

INP


PC6

PU

PU


PC6

pu

pu

RES


SEQN

Sequence Number

SEQN


P8

PU

PU

BIN 8 Porosity

P8

pu

pu

INP


PC7

PU

PU


PC7

pu

pu

RES


PC8

PU

PU


PC8

pu

pu

RES


PC9

PU

PU


PC9

pu

pu

RES


PC10

PU

PU


PC10

pu

pu

RES


PC11

PU

PU


PC11

pu

pu

RES


PC12

PU

PU


PC12

pu

pu

RES


PC13

PU

PU


PC13

pu

pu

RES


WTME

MRIL WAIT TIEM

WTME

INP


PERM

Computed Permiability

PERM

INP


RDSP

Raw Echos for Display

RDSP

INP


STAT

DATA STATUS

STAT

INP


T2W

MSEC

MSEC

T2 Distribution Waveform

T2W

MSEC

MSEC

RES


TPHI

DECP

DECP

MRIL FULL POROSITY

TPHI

100 pu

100 pu

RES


PHA

Corrected Echo Phases

PHAS

Mnemonics

RES RES

RES

INP

INP

9-23

Serv_Name

LIS Mnem


FRQ3


P4

MRIL - MAGNETIC RESONANCE IMAGE MRIL - MAGNETIC RESONANCE IMAGE

LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

MRIL FREQUENCY 3

FRQ3

BIN 4 Porosity

P4

FRQ4

MRIL FREQUENCY 4

FRQ4

INP

ACTN

MRIL ACTIVATION NAME

ACTN

INP


TE

MRIL ECHO SPACING

TE

INP


FRQ2

MRIL FREQUENCY 2

FRQ2

INP


FRQ1

MRIL FREQUENCY 1

FRQ1

INP


FRQ0

MRIL FREQUENCY 0

FRQ0

INP


ANT

DEG

DEG

ANTENNA TEMPERATURE

ANT

deg

deg

INP


B1

MG

MG

B1 SENSOR

B1

MG

MG

INP


B1MD

MG

MG

B1 ADJUSTED for TEMPERATURE

B1MOD

MG

MG

INP


CHI

CHI from analysis

CHI

INP


DIH

DIAM of INVESTIGATION HYDROGEN

DIH

RES


ECHO

Corrected Echo Amplitudes

ECHO

INP


GAIN

MRIL GAIN

GAIN

INP


MBVI

MRIL Bound Volume

MBVI


MDPT

DATA DEPTH

MDPT


MPHI

PU

PU

MRIL EFFECTIVE POROSITY

MPHI

pu

pu

INP


P1

PU

PU

BIN 1 Porosity

P1

pu

pu

INP


P10

PU

PU

BIN 10 Porosity

P10

pu

pu

INP


P11

PU

PU

BIN 11 Porosity

P11

pu

pu

INP


P3

PU

PU

BIN 3 Porosity

P3

pu

pu

INP


P12

PU

PU

BIN 12 Porosity

P12

pu

pu

INP


P2

PU

PU

BIN 2 Porosity

P2

pu

pu

INP


P13

PU

PU

BIN 13 Porosity

P13

pu

pu

INP


DIS

DIAM of INVESTIGATION SODIUM

DIS

PU

PU

PU

PU

INP pu

pu

pu

pu

INP

INP INP

RES

MSFL/ML - MICRO RES

MNOR

OHMM

OHMM

MICROLOG NORMAL

MNOR

ohm.m

ohm.m

MSFL/ML - MICRO RES

MSFL

OHMM

OHMM

MSFL (FRXO)

MSFL

ohm.m

ohm.m

MSFL/ML - MICRO RES

RXRT

RXO OVER RT

RXRT

RES RES RES

MSFL/ML - MICRO RES

MSFU

OHMM

OHMM

MSFL UNFILTERED

MSFLUF

ohm.m

ohm.m

RES

MSFL/ML - MICRO RES

MINV

OHMM

OHMM

MICROLOG LATERAL (INVERSE)

MINV

ohm.m

ohm.m

RES

PL TOOLS - PRODUCTION

FCCW

RPS

RPS

FLOW (CONTINUOUS) CW

FCCW

RPS

RPS

RES


DPRS

PSI

KPA


DPRS

psi

Kpa

RES


DPRS

PSI

KPA


DPRS

psi

Kpa

RES


DTEM

DEGF

DEGC


DTEM

degF

degC

RES


DTEM

DEGF

DEGC


DTMP

degF

degC

RES

9-24

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data RES


FBCC

RPS

RPS

FLOW (FULL BORE) CCW

FBCC

RPS

RPS


FCCC

RPS

RPS

FLOW (CONTINUOUS) CCW

FCCC

RPS

RPS

RES


FCON

RPS

RPS

AVERAGE FLOW (CONTINUOUS)

FCON

RPS

RPS

RES


FDC

CPS

CPS

1.0/S

1.0/S


FDDP


FDEN

G/CC


FICC

RPS


FINL


FICW

PL TOOLS - PRODUCTION PL TOOLS - PRODUCTION

FLUID DENSITY COUNTS

FDC


FDDP

K/M3

FLUID DENSITY

FDEN

G/CC

Kg/m3

RES

RPS

FLOW (INLINE) CCW

FICC

RPS

RPS

RES

RPS

RPS

AVERAGE FLOW (INLINE)

FLOWI

RPS

RPS

RES

RPS

RPS

FLOW (INLINE) CW

FICW

RPS

RPS

RES

FBCW

RPS

RPS

FLOW (FULL BORE) CW

FBCW

RPS

RPS

RES

CP4

INDEX

INDEX

SENSOR 4 CAPACITANCE INDEX

CP4

INDEX

INDEX

RES


CALX

SQIN

SQIN


CHMA


TEMP


CP1


FLFB

RPS


CP11

INDEX


CP12

INDEX


CP10

INDEX


CP3

INDEX MV

DEGF

CROSS SECTION AREA

CALX

HORIZONTAL IMAGE MAP

CHMAP

TEMPERATURE

TEMP


CP1

RPS

AVERAGE FLOW (FULL BORE)

INDEX

DEGC

RES RES

RES RES

degF

degC

RES

FLOWFB

RPS

RPS

RES


CP11

INDEX

INDEX

RES

INDEX


CP12

INDEX

INDEX

RES

INDEX


CP10

INDEX

INDEX

RES

INDEX


CP3

INDEX

INDEX

RES

MV

DIFFERENTIAL MILLIVOLTS

DIFFMV

mV

mV

RES


CP5


CP6

INDEX

INDEX

RES RES

RES


DIMV


CP5


CP6

INDEX


CP7

INDEX

INDEX


CP7

INDEX

INDEX


CP8

INDEX

INDEX


CP8

INDEX

INDEX

RES


CP9

INDEX

INDEX


CP9

INDEX

INDEX

RES

INDEX

RES


CRMA

RADIAL IMAGE MAP

CRMAP


CSDL

F/M

M/M

CABLE SPEED - DELAYED

CSDL

ft/m

m/min

RES INP


CP2

INDEX

INDEX


CP2

INDEX

INDEX

RES


YTWA

TURB

TURB

WATER HOLDUP - TURBULENT FLOW

YTWAT

TURB

TURB

RES


RHOG

GM/CC

KG/M3

GAS DENSITY

RHOG

GM/CC

KG/M3

RES


YGHT

%

%

GAS HOLDUP

YGHT

%

%

RES


YGHU

%

%

GAS HOLDUP - UNLIMITED

YGHU

%

%

RES


YGHZ

%

%

GAS HOLDUP - PVT UNCORRECTED

YGHZ

%

%

RES


YOD

%

%

OIL HOLDUP FDR TOOL

YOD

%

%


YGAS

GAS HOLDUP

YGAS


YOIL


TEMP

DEGF

DEGC

OIL HOLDUP

YOIL

TEMPERATURE

TEMP

RES RES RES

degF

degC

RES


YWAT

WATER HOLDUP

YWAT


YWAT

LAMNR

LAMNR

WATER HOLDUP - LAMINAR FLOW

YWAT

LAMNR

LAMNR

RES


YWD

%

%

WATER HOLDUP FDR TOOL

YWD

%

%

RES


YWH

%

%

WATER HOLDUP

YWH

%

%


CAL1

INCH

CALIPER ARM 1

CAL1

in


CAL2

INCH

CALIPER ARM 2

CAL2

in


YOH

%

%

OIL HOLDUP

YOH

%

%


HYDR

CPS

CPS

CENTER SAMPLE HYDROMETER CPS

HYDR

1.0/S

1.0/S


FTMP

FDD SENSOR TEMPERATURE

FTMP


GHCC

CPS

CPS

GHT DEAD TIME & DECAY CORR CPS

GHTCC

1.0/S

1.0/S

RES


GHTC

CPS

CPS

GHT DEAD TIME ONLY CORR CPS

GHTC

1.0/S

1.0/S

RES

Mnemonics

RES

RES RES RES RES RES RES

9-25

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


GR

API

API

GAMMA RAY

GR

gAPI

gAPI

RES


GRCO

API

API

GAMMA RAY CORRECTED

GRCO

gAPI

gAPI

RES


YGD

%

%

GAS HOLDUP FDR TOOL

YGD

%

%

RES


GRS

API

API

GAMMA RAY (SONDEX)

GRS

gAPI

gAPI

RES


FREF

FREQUENCY REFERENCE

FREF


IDER

ID OUT OF TOLERANCE WARNING

IDWARN


ITMP

F

C


INTMP

ft

C

RES


PRBU

PSI

KG/M3

PRESSURE BUILDUP

PRBU

psi

KG/M3

RES

TEL RES


PRES

PSI

KPA

PRESSURE

PRES

psi

Kpa

RES


PRES

PSIA

KPA

ABSOLUTE PRESSURE

PRES

PSIA

Kpa

RES


SIT

DEGF

DEGC

degF

degC

RES


TEMP


GRCS

gAPI

gAPI

PSGT - PULSE SPECT GAMMA

STUN

API

API

SENSOR TEMPERATURE

SIT


TEMP

GAMMA RAY CORRECTED (SONDEX)

GRCS

CO STATISTICAL UNCERTAINTY

STUN

RES RES

INP RES


YCA

CALCIUM YIELD CAPTURE

YCA


SPC2

PSGT CAPTURE 2 SPECTRUM

SPC2

INP


SPBK

PSGT BACKGROUND SPECTRUM

SPBK

INP INP


SPC1

PSGT CAPTURE 1 SPECTRUM

SPC1


SPEN

PSGT INELASTIC SPECTRUM

SPEN

INP


SWPO

PSGT TOOL MODE

SWPOS

INP


TCCR

TOTAL COUNTS CAPTURE

TCCR

RES


TMD1

TMD GATE 1 UNFILTERED

TMD1

RES RES


TMD2


TMD2


TMD3


TMD3

RES


TMD4


TMD4

RES


TMD5


TMD5

RES


SIC

SULPHUR INDICATOR_C

SIC

RES


TMDS

TMD SIGMA

TMDS


SIAI

CU

CU

SILICON_ACT_INDICATOR SIAI

SIAI

cu

CU

RES

RES

RES


YCL

CHLORINE YIELD CAPTURE

YCL


YFE

IRON YIELD CAPTURE

YFE

RES


YH

HYDROGEN YIELD CAPTURE

YH

RES


YIC

CARBON YIELD INELASTIC

YIC

RES


YICA

CALCIUM YIELD INELASTIC

YICA

RES


YIO

OXYGEN YIELD CAPTURE

YIO

RES


YISI

SILICON YIELD INELASTIC

YISI

RES


YK

POTASSIUM YIELD CAPTURE

YK

RES


YS

SULPHUR YIELD CAPTURE

YS

RES


YSI

SILICON YIELD CAPTURE

YSI

RES


YTI

TITANIUM YIELD CAPTURE

YTI

RES


ZOFF

ZERO OFFSET PSGT.SHOP CAL S-2

ZOFF

RES


TMD6


TMD6

RES


FTR

SPECTRAL FIT ERROR

FTR

RES


CLIC

CHLORINE INDICATOR_C

CLIC

RES


COIR

INELASTIC CO RATIO

COIR

RES


COYR

CO YIELD RATIO INELASTIC

COYR

RES


CRAT


CTIM


DTMP

9-26

MSEC

MSEC

COMPTON RATIO (OAI/OBI)

CRAT

ACCUMULATION TIME MILLISECONDS

C_TIME

DETECTOR TEMPERATURE

DTMP

RES MSEC

MSEC

RES RES

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


F110

%

%

PSGT 110 VOLT

F110

%

%

RES


F17V

%

%

PSGT 17V LOAD

F17V

%

%

RES


F2KV

%

%

PSGT 2K VOLT LOAD

F2KV

%

%

RES


F50V

%

%

PSGT 50 V LOAD

F50V

%

%

RES


FEIC

IRON INDICATOR_C

FEIC

RES


SIIC

SILICON INDICATOR_C

SIIC

RES


FREP

PSGT REPLENISHER

FREP


LIRI

%

%

INELASTIC LITHOLOGY INDEX

LIRI

%

%

RES RES


RIC

INELASTIC CAPTURE RATIO

RIC

RES


PSST

PSGT TOOL STATE

PSGST

INP


PSPC

PSGT DISPLAY SPECTRUM

PSPC

RES


OBI

OXYGEN BACKGROUND INDICATOR

OBI

RES RES


FERC

IRON RATIO CAPTURE

FERC


LIYR

LITH YIELD RATIO INEL

LIYR

RES


CAIC

CALCIUM INDICATOR_C

CAIC

RES RES


KIC

POTASSIUM INDICATOR_C

KIC


ITCR

INELASTIC TOTAL

ITCR

RES


IDER

PSGT ID ERROR

IDERR

INP


HPLI

CAPTURE HYDROGEN PEAK

HPLI

RES


HIC

HYDROGEN INDICATOR_C

HIC

RES RES


GOUT

GENERATOR OUTPUT

GOUT


OAI

OXYGEN ACTIVATION INDICATOR

OAI

RES

RDT - RESERVOIR DESC TOOL

C11

CURVE 11

C11

INP


P1TE

DEGF

DEGC

PROBE 1 TEMPERATURE

P1TEMP

degF

degC

INP


PTHO

PSI

KPA

PRESSURE THOUSANDS

PTHO

psi

Kpa

RES


PTEN

PSI

KPA

PRESSURE TENS

PTEN

psi

Kpa

RES


PRES

PSI

KPA

TOTAL PRESSURE

PRES

psi

Kpa

RES


PRAT

CC/S

CC/S

FPS PUMP MEASURED RATE

PRATE

0.1 L/S

0.1 L/S

INP


POTE

DEGF

DEGC

FPS OUTLET TEMPERATURE

OUTTMP

degF

degC

INP


PONE

PSI

KPA

RDT PRESSURE ONES

PONE

psi

Kpa

RES


PITE

DEGF

DEGC

FPS INLET TEMPERATURE

INTMP

degF

degC

INP


PHUN

PSI

KPA

PRESSURE HUNDREDS

PHUN

psi

Kpa

RES


PHST

PSI

KPA

RDT HYDROSTATIC PRESSURE

PHST

psi

Kpa

RES


PHFL

PSI

KPA

RDT HYDRAULIC PRESSURE

PHFL

psi

Kpa

RES


PHDS

PSI

KPA

PRESSURE HUNDREDTHS

PHDS

psi

Kpa

RES


HPRS

PSI

KPA

FPS HYDRALIC PRESSURE

SYPRES

psi

Kpa

INP


P2PS

PSI

PSI

PROBE 2 PRESSURE

P2PRES

PSI

PSI

INP


PTTE

DEGF

DEGC

PRETEST TEMPERATURE

PTTEMP

degF

degC

INP


P1PS

PSI

PSI

PROBE 1 PRESSURE

P1PRES

PSI

PSI

INP


OPTR

CC/S

CC/S

FPS OPTIMUM PUMP RATE

OPTR

CC/S

CC/S

INP


OPTR

CC/S

CC/S

FPS OPTIMUM PUMP RATE

OPTR

CC/S

CC/S

INP


OFFS

OFFSET

OFFSET

TEL


NOIS

NOISE

NOISE

TEL


MTEM

DEGF

DEGC

MAGNET TEMPERATURE

TEMP2

degF

degC

TEL


MSPD

RPM

RPM

Motor Speed

MOTSPD

RPM

RPM

INP


MRAT

CC/S

CC/S

PRETEST MEASURED RATE

MRATE

0.1 L/S

0.1 L/S

INP


HTMP

DEGF

DEGC

HPS HYDRAULIC TEMPERATURE

HYTEMP

degF

degC

INP


HTMP

HPS HYDRAULIC TEMPERATURE

HYTEMP

INP


HSVA

SOLENOID VALVE A

HPSSVA

TEL

Mnemonics

9-27

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description


HPRS

PSI

KPA

HPS HYDRALIC PRESSURE

HYPRES

psi

Kpa

INP


P2TE

DEGF

DEGC

PROBE 2 TEMPERATURE

P2TEMP

degF

degC

INP


SVB

PPS Solenoid Valve B

PPSSVB


RHOG

GM/CC

GM/CC

GAS DENSITY - EST.

RHOG

gm/cc

gm/cc

INP

CURVE 1

C1

KV/KH

KV/KH

ANISOTROPY

ANISO

Kv/Kh

Kv/Kh

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data

TEL


C1


ANSO

INP


VISC

VISCOCITY

VISC

INP TEL

INP


V50

50 VOLT DC

V50


V30

30 VOLT DC

V30

TEL


V200

200 VOLT DC

V200

TEL


UTLV

SURFACE UTILITY VOLTAGE

UTLVLT

TEL


UTLC

SURFACE UTILITY CURRENT

UTLCUR

TEL


SVG

PPS Solenoid Valve G

PPSSVG

TEL


SVF

PPS Solenoid Valve F

PPSSVF

TEL


SVE


PTHS


SVC


PTPS


SVA

PPS Solenoid Valve A

PPSSVA

TEL


SPIK

ECHO SPIKING INDICATOR

SPIKE

INP


SMOB

SHPERICAL MOBILITY

MPTHS

INP


SEQ

SEQUENCE NUMBER

SEQ


SDEP

SFT SET DEPTH

SDEP


RING

RINGING

RING


RHOF

GM/CC

GM/CC

FLUID DENSITY

RHOF

gm/cc

gm/cc


QTMP

DEGF

DEGC

QUARTZ GAUGE TEMPERATURE

QGTEMP

degF

degC


PWRF

HIGH POWER FACTOR

PWRFAC

PPS Solenoid Valve E

PPSSVE

PSI

KPA

PRESSURE TENTHS

PTHS

PPS Solenoid Valve C

PPSSVC

PSI

PSI

PRETEST PRESSURE

PTPRES

FT

M

TEL psi

Kpa

RES

PSI

PSI

INP

TEL

TEL ft

m

RES TEL INP INP TEL


PVOL

CC

CC

PRETEST VOLUME

PTVOL

0.01 L

0.01 L


PTTH

PSI

KPA

PRESSURE TEN THOUSANDS

PTTH

psi

Kpa

INP RES


QPRS

PSI

KPA

QUARTZ GAUGE PRESSURE

QGPRES

psi

Kpa

INP


SVD

PPS Solenoid Valve D

PPSSVD

TEL


C14

CURVE 14

C14

INP


C29

CURVE 29

C29

INP


C28

CURVE 28

C28

INP


C27

CURVE 27

C27

INP


C26

CURVE 26

C26

INP


C25

CURVE 25

C25

INP


C24

CURVE 24

C24

INP


C23

CURVE 23

C23

INP


C22

CURVE 22

C22

INP


C21

CURVE 21

C21

INP


C20

CURVE 20

C20

INP INP


C2

CURVE 2

C2


C19

CURVE 19

C19

INP


C3

CURVE 3

C3

INP INP


C16

CURVE 16

C16


C17

CURVE 17

C17

INP


C13

CURVE 13

C13

INP


C12

CURVE 12

C12

INP

9-28

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data

PSI

PSI

PSI

PSI

INP


FPRE

FORMATION PRESSURE

FPRE


C10

CURVE 10

C10

INP


BINS

Bins 1-32

BINS

INP


BBLP


B1

PSI

KPA

BUBBLE POINT

BBLPNT

B1 SENSOR

B1

psi

Kpa

INP INP


AUXV

SURFACE AUX VOLTAGE

AUXVLT

TEL


AUXC

SURFACE AUX CURRENT

AUXCUR

TEL


ATIM

ASCII ELAPSED TIME

A_TIME

RES


HMOB

HORIZONTAL MOBILITY

MPTHH

INP


RELC

Relative Capacitance

RELCAP

TEL


C18

CURVE 18

C18

INP


FIDV


HLOS

V

V

FLUID ID VOLTS(Volts)

FLVOLT

HPS LOW OIL SWITCH

HPSLOS

V

V

INP

INP


HI

HYDROGEN INDEX

HI

INP


C15

CURVE 15

C15

INP


C30

CURVE 30

C30

INP


GEOM

GEOMETRIC MEAN

GEOMM

INP


GAIN


FTEM

DEGF

DEGC

GAIN

GAIN

FLUID TEMPERATURE

TEMP1

INP degF

degC

TEL


FREQ

FREQUENCY

FREQ

TEL


FMSR

FPS MOTOR START RELAY

FPSMSR

TEL


FLPH

DEG

DEG

FLUID ID PHASE

FLPHI

DEG

deg

INP


FIDI

MA

MA

FLUID ID CURRENT (mA)

FLAMP

mA

mA

INP


EVNT


ERES

OHMM

OHMM

ohm.m

ohm.m

INP

PTA EVENT STRING

EVENT

ESTIMATED RESISTIVITY

ERES

INP


ECHN

Echo Noise

ECHONS

TEL


C8

CURVE 8

C8

INP


C31

CURVE 31

C31

INP


C32

CURVE 32

C32

INP


C4

CURVE 4

C4

INP


FLTC

FAULT CURRENT

FLTCUR

TEL


DIEL

DIELECTRIC CAPACITANCE

DIELCP

TEL


C6

CURVE 6

C6

INP INP


C7

CURVE 7

C7


C5

CURVE 5

C5

INP


C9

CURVE 9

C9

INP


CPRS

COMPRESSIBLITY

CMPRSS


CPV

CVS FLUID PURGE VALVE

CVSFPV

TEL


CV1

CVS Chamber Valve 1

CVSCV1

TEL


CV2

CVS Chamber Valve 2

CVSCV2

TEL

RMT-ELITE - RESERV MON TOOL

OAIN

OXYGEN ACT INDICATOR NEAR

OAI1

RES


OAIF

OXYGEN ACT INDICATOR FAR

OAI2

RES


RCAP

RATIO TOTAL CAPTURE

RCAP

RES


OBIN

OXYGEN BKG INDICATOR NEAR

OBI1

RES


o194

OIN CHANNEL 194

OIN194

RES


oi68

OIN CHANNEL 68

OIN68

RES

Mnemonics

1/PSI

1/PSI

1/PSI

1/PSI

INP

9-29

Serv_Name

LIS Mnem

RMT-ELITE - RESERV MON TOOL RMT-ELITE - RESERV MON TOOL

LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

o114

OIN CHANNEL 114

OIN114

RES

OBIF

OXYGEN BKG INDICATOR FAR

OBI2

RES


RNFC

RATIO NEAR INEL TO NEAR COUNTS

RICN

RES


SIAF

SILICON ACT INDICATOR FAR

SIA2

RES


SIIN

SILICON INDICATOR NEAR

SIIC1

RES


SIIF

SILICON INDICATOR FAR

SIIC2

RES


NTIM

ACCUMULATION TIME NEAR

TIME_N

RES


LMOD

LOGGING MODE

LMODE

PAR


SICF

SULPHUR INDICATOR FAR

SIC2

RES


SICN

SULPHUR INDICATOR NEAR

SIC1

RES


SIAN

SILICON ACT INDICATOR NEAR

SIA1

RES


NGAI

NEAR GAIN

NGAIN

RES


LIY1

LITH YIELD RAT INEL NEAR

LIYR1

RES


LIY2

LITH YIELD RAT INEL FAR

LIYR2

RES


YSI1

SILICON YIELD CAPT. NEAR

YSI1

RES


STUF

STATISTIC UNCERTAINTY FAR

STUN2

RES


NBAC

NEAR BACKGROUND SPECTRUM

NBACK

INP


NCAC

NEAR CAPTURE SPECTRUM CORR

NCAPAC

INP


NBAK

NEAR BACKGROUND SPECTRUM

NBACK

INP


NFEC

NEAR IRON CHANNEL

NFECH

RES


NSPT

NEAR SPECTRA SUM

NSPT

RES


NGAO

NEAR GAIN OK

NGAOK

RES


NHCH

NEAR HYDROGEN CHANNEL

NHCH

RES


NINC

NEAR INELASTIC SPECTRUM CORR

NINELC

INP


NINE

NEAR INELASTIC SPECTRUM

NINEL

INP


NOFO

NEAR OFFSET OK

NOFOK

RES


NOFS

NEAR OFFSET

NOFST

RES


NCAP

NEAR CAPTURE SPECTRUM

NCAP

INP


YMG2

MAGNESIUM YIELD CAPT. FAR

YMG2

RES


YIC2

CALCIUM YIELD INEL FAR

YICA2

RES


YIO1

OXYGEN YIELD INEL NEAR

YIO1

RES


YIO2

OXYGEN YIELD INEL FAR

YIO2

RES


YIS1

SILICON YIELD INEL NEAR

YISI1

RES

9-30

Mnemonics

Serv_Name

LIS Mnem


LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

YIS2

SILICON YIELD INEL FAR

YISI2

RES

YK1

POTASSIUM YIELD CAPT. NEAR

YK1

RES


YS1

SULPHUR YIELD CAPT. NEAR

YS1

RES


YMG1

MAGNESIUM YIELD CAPT. NEAR

YMG1

RES


YH1

HYDROGEN YIELD CAPT. NEAR

YH1

RES


YS2

SULPHUR YIELD CAPT. FAR

YS2

RES


YSI2

SILICON YIELD CAPT. FAR

YSI2

RES


YTI1

TITANIUM YIELD CAPT. NEAR

YTI1

RES


YTI2

TITANIUM YIELD CAPT. FAR

YTI2

RES


LIRN

LITH INDEX INEL NEAR

LIRI1

RES


FGAI

FAR GAIN

FGAIN

RES


YK2

POTASSIUM YIELD CAPT. FAR

YK2

RES


YCA2

CALCIUM YIELD CAPT. FAR

YCA2

RES


TCCF

TOTAL COUNTS FAR

TCCR2

RES


TCCN

TOTAL COUNTS NEAR

TCCR1

RES


TNGC

NEAR SPACED GATES CORR

TNGTC

INP


TNGT

NEAR SPACED GATES

TNGT

INP


TNGT

NEAR SPACED GATES

TNGT

INP


YC1

CARBON YIELD INEL NEAR

YIC1

RES


YIC1

CALCIUM YIELD INEL NEAR

YICA1

RES


YCA1

CALCIUM YIELD CAPT. NEAR

YCA1

RES


YH2

HYDROGEN YIELD CAPT. FAR

YH2

RES


YCL1

CHLORINE YIELD CAPT. NEAR

YCL1

RES


YCL2

CHLORINE YIELD CAPT. FAR

YCL2

RES


YEX1

EXTRA YIELD CAPT. NEAR

YEX1

RES


YEX2

EXTRA YIELD CAPT. FAR

YEX2

RES


YFE1

IRON YIELD CAPT. NEAR

YFE1

RES


YFE2

IRON YIELD CAPT. FAR

YFE2

RES


STUN

STATISTIC UNCERTAINTY NEAR

STUN1

RES


YC2

CARBON YIELD INEL FAR

YIC2

RES


ERIN

RATIO NEAR/ FAR INELASTIC EVR

ERIN

RES


FEIN

IRON INDICATOR NEAR

FEIC1

RES


CRAF

COMPTON RATIO FAR

CRAT2

RES

Mnemonics

9-31

Serv_Name

LIS Mnem


LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

CRAN

COMPTON RATIO NEAR

CRAT1

RES

EFCA

FAR COUNTRATE EVR

EFCA

RES


EFSI

FAR INELASTIC COUNTS EVR

EFSI

RES


ENCA

NEAR COUNTRATE EVR

ENCA

RES


COYF

C0 YIELD RAT INEL FAR

COYR2

RES


ERIC

RATIO FAR INEL/FAR COUNTS EVR

ERIC

RES


COIN

CO RATIO INELASTIC NEAR

COIR1

RES


ERNF

RATIO NEAR / FAR - EVR

ERNF

RES


ESGI

CU

CU

FAR FORMATION SIGMA EVR

ESGF

RES


ESGN

CU

CU

NEAR FORMATION SIGMA EVR

ESGN

RES


FBAC

FAR BACKGROUND SPECTRUM

FBACK

INP


FCAP

FAR CAPTURE SPECTRUM

FCAP

INP


FCPC

FAR CAPTURE SPECTRUM CORR

FCAPAC

INP


FEIF

IRON INDICATOR FAR

FEIC2

RES


ENSI

NEAR INELASTIC COUNTS EVR

ENSI

RES


AFTN

NEAR FORMATION AMPLITUDE

AFTN

RES


1780

SILICON CHANNEL

E1780

RES


2220

HYDROGEN CHANNEL

E2220

RES


3730

CALCIUM CHANNEL

E3730

RES


4440

CARBON CHANNEL

E4440

RES


6100

OXYGEN CHANNEL

E6100

RES


7140

OXYGEN FIRST ESCAPE CHANNEL

E7140

RES


COYN

C0 YIELD RAT INEL NEAR

COYR1

RES


AFTF

FAR FORMATION AMPLITUDE

AFTF

RES


CFT1

CAPTURE FIT ERROR NEAR

CFTR1

RES


FHCH

FAR HYDROGEN CHANNEL

FHCH

RES


CAIN

CALCIUM INDICATOR NEAR

CAIC1

RES


LIRF

LITH INDEX INEL FAR

LIRI2

RES


CFT2

CAPTURE FIT ERROR FAR

CFTR2

RES


CLIF

CHLORINE INDICATOR FAR

CLIC2

RES


CLIN

CHLORINE INDICATOR NEAR

CLIC1

RES


COIF

CO RATIO INELASTIC FAR

COIR2

RES


7650

IRON CHANNEL

E7650

RES

9-32

Mnemonics

Serv_Name

LIS Mnem


LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

IR10

LOG RATIO TOTAL INELASTIC

IRIN10

RES

HPLN

HYDROGEN PEAK NEAR

HPLI1

RES


IFT2

INELASTIC FIT ERROR FAR

IFTR2

RES


FERF

IRON PEAK FAR

FERC2

RES


INC2

INCA FAR

INCA2

RES


INC2

INCA FAR

INCA2

RES


INX1

INOXY NEAR

INOX1

RES


HPLF

HYDROGEN PEAK FAR

HPLI2

RES


IONI

ION CURRENT

IONI


IFT1

INELASTIC FIT ERROR NEAR

IFTR1

RES


IRIN

RATIO TOTAL INELASTIC

IRIN

RES


ITCF

INELASTIC TOTAL COUNTS FAR

ITCR2

RES


ITCN

INELASTIC TOTAL COUNTS NEAR

ITCR1

RES


KAT1

KATO NEAR

KATO1

RES


KAT2

KATO FAR

KATO2

RES


CAIF

CALCIUM INDICATOR FAR

CAIC2

RES


INX2

INOXY FAR

INOX2

RES


FINC

FAR INELASTIC SPECTRUM CORR

FINELC

INP


FERN

IRON PEAK NEAR

FERC1

RES


FFEC

FAR IRON CHANNEL

FFECH

RES


KICN

POTASSIUM INDICATOR NEAR

KIC1

RES


INC1

INCA NEAR

INCA1

RES


KICF

POTASSIUM INDICATOR FAR

KIC2

RES


HICN

HYDROGEN INDICATOR NEAR

HIC1

RES


FINE

FAR INELASTIC SPECTRUM

FINEL

INP


FOFO

FAR OFFSET OK

FOFOK

RES


FOFS

FAR OFFSET

FOFST

RES


FSPT

FAR SPECTRA SUM

FSPT

RES


FTIM

ACCUMULATION TIME FAR

TIME_F

RES


FTMP

INTERNAL FLASK TEMPERATURE

FTMP


FTRF

SPECTRAL FIT ERROR FAR

FTR2

RES


FTRN

SPECTRAL FIT ERROR NEAR

FTR1

RES


HICF

HYDROGEN INDICATOR FAR

HIC2

RES

Mnemonics

MA

DEGF

MA

DEGC

MA

degF

MA

degC

INP

RES

9-33

Serv_Name

LIS Mnem


FGAO

SDDT/NAV - DIRECTIONAL

AZI1


MAGQ


TEMP

LISU_ eng

LISU_ met

Description FAR GAIN OK

FGAOK

DEG

DEG

PAD 1 AZIMUTH

AZI1


MAGQ

DEGC

DEGC


TEMP

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data

deg

deg

RES

degC

degC

RES

RES

RES


RBX

DEG

DEG

AUXILIARY ROTATION

RBX

deg

deg

RES


RB

DEG

DEG

RELATIVE BEARING

RB

deg

deg

RES


MAGZ

MAGNETOMETER Z-AXIS

MAGZ

RES


MAGX

MAGNETOMETER X-AXIS

MAGX

RES


AX

G

G


AX

G

G


HAZI

DEG

DEG

DRIFT / HOLE AZIMUTH

HAZI

deg

deg

RES


MAGY

MAGNETOMETER Y-AXIS

MAGY


ACCQ


ACCQ


AY

G

G


AY

G

G

RES


AZ

G

G


AZ

G

G

RES

RES RES RES


AZI1

DEG

DEG

REFERENCED AZIMUTH

AZI1

deg

deg

RES


AZIX

DEG

DEG

AUXILIARY AZIMUTH

AZIX

deg

deg

RES RES


DEVI

DEG

DEG

DRIFT ANGLE

DEVI

deg

deg


DXTM

MS

MS

Z-ACCELEROMETER, TIME BASE

DXTM

mS

mS

INP

SDL - SPECTRAL DENSITY

NAB

CPS

CPS

NEAR ABOVE

NAB

1.0/S

1.0/S

TEL


NHV

V

V

NEAR HIGH VOLTAGE

NHV

V

V

INP


NLU

CPS

CPS

NEAR LITHOLOGY UNFILTERED

NLIU

1.0/S

1.0/S

TEL


NLO

CPS

CPS

NEAR CESIUM LOW

NLO

1.0/S

1.0/S

TEL


NLIU

CPS

CPS

NEAR LITHOLOGY UNFILTERED

NLIU

1.0/S

1.0/S

INP


NLI

CPS

CPS

NEAR LITHOLOGY

NLI

1.0/S

1.0/S

TEL


NPK

CPS

CPS

NEAR PEAK

NPK

1.0/S

1.0/S

TEL


NHI

CPS

CPS

NEAR CESIUM HI

NHI

1.0/S

1.0/S

TEL


NDE

CPS

CPS

NEAR DENSITY

NDE

1.0/S

1.0/S

TEL


NVA

CPS

CPS

NEAR VALLEY

NVA

1.0/S

1.0/S

TEL


NBA

CPS

CPS

NEAR BARITE

NBA

1.0/S

1.0/S

TEL


QF

FAR QUALITY

QF


M5AN

V

V

MINUS 5 VOLTS ANALOG

MI5AN

V

V

INP


M15V

V

V

MINUS 15 VOLTS

MI15V

V

V


LDWC

HSDL LS DENSITY WINDOW COUNTS

LDENWD


NBAU


QS

CPS

CPS

RES

INP RES

NEAR BARITE UNFILTERED

NBAU

SDL QUALITY SHORT

QS

1.0/S

1.0/S

RES

TEL


SPWC

HSDL SS PEAK WINDOW COUNTS

SPEKWD

RES


SLWC

HSDL SS LITH. WINDOW COUNTS

SLITWD

RES

HSDL SS DENSITY WINDOW COUNTS

SDENW D

RES


SDWC


SDSO

IN

MM

SDL STANDOFF

SDSO

in

mm


SDC1

INCH

MM

SDL PAD CALIPER

CALIP

in

mm


SBWC

HSDL SS BARITE WINDOW COUNTS

SBARWD

RES TEL RES


PRTM

C

C

PRE-REG. TEMPERATURE

PRTMP

C

C

INP


REF5

V

V

5 VOLT REFERENCE

REF5

V

V

INP


P15V

VOLT

VOLT

PLUS 15 VOLTS

P15

V

V

TEL


QN

NEAR QUALITY

QN


QL

SDL QUALITY LONG

QL

RES


PTMP

PAD TEMPERATURE

PTMP

TEL


LBWC

HSDL LS BARITE WINOW COUNTS

LBARWD

RES

9-34

RES

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


PE

PHOTO-ELECTRIC FACTOR

PE


P5AN

V

V

Plus 5 Volts Analog

PL5AN

V

V

RES INP


RHOB

G/C3

K/M3

BULK DENSITY

RHOB

g/cm3

Kg/m3

RES


DLIM

DECP

DECP

DENSITY POROSITY, LIMESTONE

DLIM

100 pu

100 pu

RES


EDLI

DECP

DECP

DENSITY POROSITY LIME, EVR

EDLI

100 pu

100 pu

RES RES


EDCT

G/CC

K/M3

EVR DENSITY CORRECTION TOTAL

EDCT

GM/CC

KG/M3


EDCP

G/CC

K/M3

EVR DENSITY CORRECTION POS.

EDCP

GM/CC

KG/M3

RES


EDCN

G/CC

K/M3

EVR DENSITY CORRECTION NEG.

EDCN

GM/CC

KG/M3

RES


DRHO

G/C3

K/M3

DENSITY CORRECTION

DRHO

g/cm3

Kg/m3

RES


DPHS

DECP

DECP

DENSITY POROSITY, SANDSTONE

DPHS

100 pu

100 pu

RES

EVR MINIMUM FILTERING

EDMF

DECP

DECP

DENSITY POROSITY, DOLOMITE

DPHD

100 pu

100 pu

RES


EDMF


DPHD

RES


DPE

PE CORRECTION

DPE

RES


DCOM

DENSITY CORRECTION MINUS

DCOR_M

RES

DCB 10 Volt Reference

DCB10

DENSITY CORRECTION PLUS

CORP


DC10


CORP

V

V

V

V

V

V

INP RES


5VD

5 Volt

5VD


CORM

DENSITY CORRECTION MINUS

CORM

V

V

INP RES


ITMP

INSTRUMENT TEMPERATURE

ITMP

TEL


PROU

V

V

Pre Reg OUT

PROUT

V

V

INP


DPHI

DECP

DECP

DENSITY POROSITY

DPHI

100 pu

100 pu

RES


FDE

CPS

CPS

FAR DENSITY

FDE

1.0/S

1.0/S


DCOP

DENSITY CORRECTION PLUS

DCOR_P

TEL RES


EDPD

DECP

DECP

DENSITY POROSITY DOLO, EVR

EDPD

100 pu

100 pu

RES


FPK

CPS

CPS

FAR PEAK

FPK

1.0/S

1.0/S

TEL


FLO

CPS

CPS

FAR CESIUM LOW

FLO

1.0/S

1.0/S

TEL


FLI

CPS

CPS

FAR LITHOLOGY

FLI

1.0/S

1.0/S

TEL


FHI

CPS

CPS

FAR CESIUM HIGH

FHI

1.0/S

1.0/S

TEL


FVA

CPS

CPS

FAR VALLEY

FVA

1.0/S

1.0/S

TEL


FBA

CPS

CPS

FAR BARITE

FBA

1.0/S

1.0/S

TEL


EDPS

DECP

DECP

DENSITY POROSITY SAND, EVR

EDPS

100 pu

100 pu

RES


EDPH

DECP

DECP

DENSITY POROSITY, EVR

EDPH

100 pu

100 pu

RES


FHV

V

V

FAR HIGH VOLTAGE

FHV

V

V

INP


EDPL

DECP

DECP

EVR DENSITY LIME POROSITY

EDPL

100 pu

100 pu

RES


FAB

CPS

CPS

FAR ABOVE

FAB

1.0/S

1.0/S

TEL

EVR PE - MIN FILT

EMPE

G/CC

KG/M3

EVR BULK DENSITY - MIN FILT

EMRH

G/CC

KG/M3


EMPE


EMRH

RES


EPE

PE EVR

EPE

RES


EPMF

EVR PE MINIMUM FILTERING

EPMF

RES

RES


ERHO

G/CC

KG/M3

BULK DENSITY - EVR PROCESSED

ERHO

G/CC

KG/M3

RES

SED - SIX ELECT DIPMETER

PDD2

OHMM

OHMM

SED PAD #2 RESISTIVITY (FAST)

PDD2

ohm.m

ohm.m

RES


MAGZ

MAGNETOMETER Z-AXIS

MAGZ


MAGY

MAGNETOMETER Y-AXIS

MAGY


P2B1

OHMM

OHMM

SED PAD #2, RESISTIVITY

P2B1

ohm.m

ohm.m

RES


P3B1

OHMM

OHMM


P3B1

ohm.m

ohm.m

RES

RES RES


P4B1

OHMM

OHMM


P4B1

ohm.m

ohm.m

RES


P5B1

OHMM

OHMM


P5B1

ohm.m

ohm.m

RES


P6B1

OHMM

OHMM


P6B1

ohm.m

ohm.m

RES


PDD1

OHMM

OHMM


PDD1

ohm.m

ohm.m

RES

Mnemonics

9-35

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


P1B1

OHMM

OHMM

SED PAD #1 RESISTIVITY

P1B1

ohm.m

ohm.m

RES


PDD3

OHMM

OHMM


PDD3

ohm.m

ohm.m

RES


PDD4

OHMM

OHMM


PDD4

ohm.m

ohm.m

RES


PDD5

OHMM

OHMM


PDD5

ohm.m

ohm.m

RES


PDD6

OHMM

OHMM


PDD6

ohm.m

ohm.m

RES


PDDV

V

V

SED PAD VOLTAGE

PDDV

V

V

RES

SED PAD FORCE

PRES

PAD #1 ROTATION

RB

deg

deg

RES

G

G


PRES


RB

DEG

DEG


ZACC

G

G


MAGX


F2B1


TEMP

DEGC

DEGC


CAL3

IN

MM

RES

SED Z ACCELEROMETER (FAST)

ZACC

MAGNETOMETER X-AXIS

MAGX

RES


F2B1


TEMP

degC

degC

RES

SED CALIPER ARM #3 (RADIUS X2)

CAL3

in

mm

RES RES

RES RES


ACCX

G

G


ACCX

G

G


ACCY

G

G


ACCY

G

G


F4B1


F4B1


MAGQ


MAGQ


C14

IN

MM

SED CALIPER PAIR 1-4

C14

in

mm

RES


C25

IN

MM


C25

in

mm

RES

RES RES RES


C36

IN

MM


C36

in

mm

RES


CAL2

IN

MM


CAL2

in

mm

RES


CAL4

IN

MM


CAL4

in

mm

RES


CAL5

IN

MM


CAL5

in

mm

RES

IN

MM

in

mm


CAL6


F5B1


CAL6


F5B1

RES RES


DEVI

DEG

DEG

DRIFT ANGLE

DEVI

deg

deg


DMAX

IN

MM

SED MAXIMUM CALIPER PAIR

DMAX

in

mm

RES


DMIN

IN

MM

SED MINIMUM CALIPER PAIR

DMIN

in

mm

RES


DXTM

08.3MS

08.3MS

SED Z-ACCELEROMETER, TIME BASE

DXTM

8.3 mS

8.3 mS

INP


F1B1


F1B1

RES


F3B1


F3B1

RES


CALA

IN

MM

SED AVERAGE CALIPER

CALA

in

mm

RES


CAL1

IN

MM


CAL1

in

mm

RES

DEG

DEG

deg

deg


HAZI


F6B1

DRIFT AZIMUTH

HAZI


F6B1

RES

RES RES

SFT - SEQ FORM TESTER

STTF

DEGF

DEGF

SFT TRANSDUCER TEMPERATURE

STTF

degF

degF


STTC

DEG C

DEG C

SFT TRANSDUCER TEMP

STTC

DEG C

DEG C


SSI

SAMPLE SHUTIN LOGICAL

SSI

RES RES RES


SITF

DEGF

DEGF

SFT INSTRUMENT TEMPERATURE

SITF

degF

degF

RES


SITC

DEGC

DEGC

SFT INSTRUMENT TEMPERATURE

SITC

degC

degC

RES


SDEP

FT

M

SFT SET DEPTH

SDEP

ft

m

RES


RPRE

PSI

KPA

STRAIN GAUGE PRESSURE

RPRE

psi

Kpa

RES


SAMP

CC

CC

PRETEST VOLUME

SAMP

0.01 L

0.01 L

RES


TENS

LB

KG

LINE TENSION (SURFACE)

TENS

lbm

Kg

RES

HSFT Event

HSFE

PSI

KPA

SFT SAMPLE DRAWDOWN

SDD

psi

Kpa

RES


HSFE


SDD

RES


TLPS

TOOL POSITION

TLPS


TMIN

MN

MN

TEST TIME MINUTES

TMIN

min

min

RES


TPT

MN

MN

PRETEST TIME

TPT

min

min

RES

9-36

RES

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data RES


TSAM

MN

MN

SFT SAMPLE TIME

TSAM

min

min


TSEC

S

S

SECONDS INTO TEST

TSEC

S

S

RES


TSI

MN

MN

SHUTIN TIME

TSI

min

min

RES


TTMP

DEGF

DEGF

HSFT TRANSDUCER TEMPERATURE

TTMP

degF

degF

RES


STRA

PSI

KPA

STRAIN PRESSURE

STRA

psi

Kpa

RES


HYDP

PSI

KPA

HSFT HYDRAULIC PRESSURE

HYDP

psi

Kpa

RES


HTF

PSI

KPA

HONER BUILD UP DITS

HTF

psi

Kpa

RES


PTTH

PSI

KPA

PRESSURE TEN THOUSANDS

PTTH

psi

Kpa

RES


PROD

PSI

KPA

DRAW DOWN PRESSURE

PROD

psi

Kpa

RES


DMV

V

V

SFT DOWNHOLE MOTOR VOLTAGE

DMV

V

V

RES


KHOR

MD

MD

HORNER PERMEABILITY

KHOR

mD

mD

RES


PTHS

PSI

KPA

PRESSURE TENTHS

PTHS

psi

Kpa


ATXT

ASCII ACTION EVENTS

A_TEXT


ATIM


DIV

V

V

ASCII ELAPSED TIME

A_TIME

SFT INSTRUMENT VOLTAGE

DIV

RES RES RES

V

V

RES


FTHU

PSI

KPA

STRAIN PRESSURE HUNDREDS

FTHU

psi

Kpa

RES


FTON

PSI

KPA

STRAIN PRESSURE ONES

FTON

psi

Kpa

RES


FTTE

PSI

KPA

STRAIN PRESSURE TENS

FTTE

psi

Kpa

RES


FTTH

PSI

KPA

STRAIN PRESSURE THOUSANDS

FTTH

psi

Kpa

RES

HORNER TIME (DIMENSIONLESS)

HORT

MD

MD

DRAWDOWN PERMEABILITY

KD

mD

mD

RES


HORT


KD

RES


PBUP

PSI

KPA

SFT PRETEST BUILDUP

PBUP

psi

Kpa

RES


PRDD

PSI

KPA

DRAW DOWN PRESSURE

PRDD

psi

Kpa

RES


PTHO

PSI

KPA

PRESSURE THOUSANDS

PTHO

psi

Kpa

RES


PHDS

PSI

KPA

PRESSURE HUNDREDTHS

PHDS

psi

Kpa

RES


PSBU

PSI

KPA

SAMPLE BUILDUP

PSBU

psi

Kpa

RES


PTEN

PSI

KPA

PRESSURE TENS

PTEN

psi

Kpa

RES


PRES

PSI

KPA

TOTAL PRESSURE

PRES

psi

Kpa

RES


PPSI

PSI

KPA

SFT PREVIOUS SHUT-IN PRESSURE

PPSI

psi

Kpa

RES


PPSI

PSI

KPA

SFT PREVIOUS SHUT-IN PRESSURE

PPSI

psi

Kpa

RES


PONE

PSI

KPA

SFT PRESSURE ONES

PONE

psi

Kpa

RES


PHUN

PSI

KPA

PRESSURE HUNDREDS

PHUN

psi

Kpa

RES


PHST

PSI

KPA

SFT HYDROSTATIC PRESSURE

PHST

psi

Kpa

RES


PHFL

PSI

KPA

SFT HYDRAULIC PRESSURE

PHFL

psi

Kpa

RES

TMD-L - THERMAL MULTIGATE DECAY

RICL

ALOG10(RINC)

RINCL

RES


NSG6

NEAR GATE 6 CNTS UNFILTERED

NSG6

RES


QW

WATER FLOW RATE

QW

RES


RIN

RATIO NEAR TO FAR INELASTIC

RIN

RES


PHIT

POROSITY FROM NEAR/FAR RATIO

PHIT

RES


OBI

OXYGEN BACKGROUND

OBI

RES


OB66

OB66

OB66

RES


RINC

RATIO N NET INEL TO F NET INEL

RINC

RES


OAI

OXYGEN ACTIVATION

OAI

RES


RICF

RATIO FAR TO FAR COUNTS

RICF

RES

Mnemonics

9-37

Serv_Name

LIS Mnem

TMD-L - THERMAL MULTIGATE DECAY TMD-L - THERMAL MULTIGATE DECAY

LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

O194

OA194

OA194

RES

O114

OA114

OA114

RES


NTMD

NEAR COUNTRATE

NTMD

RES


NSG3


NSG3

RES


NSGI

NEAR GATE I

NSGI

RES


NSG5


NSG5

RES


NSG4


NSG4

RES


RINL

Log(RIN)

RINL

RES


SGIN

INTRINSIC FORMATION SIGMA

SGIN


NSG2


NSG2

RES


NSG1

NEAR GATE 1CNTS UNFILTERED

NSG1

RES


NSIN

NEAR INELASTIC COUNTS

NSIN


SGNU

NEAR SIGMA STATISTIC

SGNU

RES


NSBU

NEAR BACKGROUND UNFILTERED

NSBU

RES


INOX

OXYGEN VALUE

INOX

RES


YSI

YIELD SILICATE

YSI

RES


YFE

YIELD IRON

YFE

RES


YCA

YIELD CARBONATE

YCA

RES


Y4

YIELD EXTRA

Y4

RES


WBUF

Work Space Buffer

WBUF

RES


TNGT

NEAR SPACED UNFILTERED

TNGT

INP


TNA

TOTAL NEAR ACTIVATION

TNA

RES


TFGT

FAR SPACED GATES

TFGT

INP


SGFN

NEAR FORMATION SIGMA

SGFN


TFA

TOTAL FAR ACTIVATION

TFA

RES


ROA

RATIO OXYGEN ACTIVATION

ROA

RES


SGFU

FAR SIGMA STATISTIC

SGFU

RES


SGFM

CU

CU

CORRECTED FORMATION SIGMA

SGFM

cu

CU

RES


SGFF

CU

CU

FAR FORMATION SIGMA

SGFF

cu

CU

RES


SGBN

CU

CU

NEAR BOREHOLE SIGMA

SGBN

cu

CU

RES


SGBF

CU

CU

FAR BOREHOLE SIGMA

SGBF

cu

CU

RES


RTMD

RATIO NEAR TO FAR COUNTRATE

RTMD

RES


RTBF

RATIO NEAR BORE TO FORM AMP

RTBF

RES

9-38

CU

CU

CU

CU

CU

CU

cu

cu

cu

CU

CU

CU

RES

RES

RES

Mnemonics

Serv_Name

LIS Mnem


LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

ROAT

RATIO OXYGEN ACTIVATION TOTAL

ROAT

RES

ROAS

RATIO OXY ACTIVATION SPECTRAL

ROAS

RES


ROAG

RATIO OXYGEN ACTIVATION GAMMA

ROAG

RES


TFGT

FAR SPACED UNFILTERED

TFGT

INP


E510

E510

E510

RES


FACT

FAT ACTIVATION SPECTRUM

FACT

INP


ESGN

CU

CU

EVR SIGMA NEAR

ESGN

cu

CU

RES


ESGF

CU

CU

EVR SIGMA FORMATION FAR

ESGF

cu

CU

RES


ESFM

CU

CU

EVR SIGMA FORMATION CORRECTED

ESFM

cu

CU

RES


ERIN

EVR RATIO INEL COUNTS

ERIN

RES


ERIC

EVR RATIO INEL/FS COUNTS

ERIC

RES


ENTM

EVR NEAR COUNTS

ENTM

RES


EGR

NATURAL GAMMA RAY - EVR

EGR


EFTM

EVR FAR COUNTS

EFTM

RES


EFSI

EVR FAR INELASTIC COUNTS

EFSI

RES


ECRN

EVR CORR RATIO COUNT

ECRN

RES


FDX

FLOW DETECTION INDICATOR

FDX

RES


E645

OXYGEN CHANNEL - SECOND ESCAPE

E645

RES


ERAT

EVR RATIO NEAR/FAR COUNTRATE

ERAT

RES


DSIG

DELTA SIGMA FORMATION

DSIG

RES


DCSF

DIFFUSION CORRECTED SIGMA FORM

DCSF

RES


ABTF

FAR BOREHOLE AMPLITUDE

ABTF

RES


ABTN

NEAR BOREHOLE AMPLITUDE

ABTN

RES


BACK

BACKGROUND SPECTRUM

BACK

INP


BKSM

SPECTRUM SUMS

BKSM

RES


BORE

BOREHOLE SPECTRUM

BORE

INP


CRAT

COMPTON RATIO

CRAT

RES


CRNF

CORRECTED RATIO

CRNF

RES


ITMP

INTERNAL INSTRUMENT TEMPERATUR

ITMP


NSBF

NEAR BACKGROUND FILTERED

NSBF

RES


E665

IRON EDGE

E665

RES


INCA

CATION VALUE

INCA

RES


NNIN

NEAR NET INELASTIC COUNT RATE

NNIN

RES

Mnemonics

GAPI

DEGF

GAPI

DEGC

gAPI

degF

gAPI

degC

RES

RES

9-39

Serv_Name

LIS Mnem


LISU_ eng

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem

NFTR

NEAR FIT ERROR

NFTR

RES

NACT

NEAR ACTIVATION SPECTRUM

NACT

INP


KATO

RATIO CATION/OXYGEN VALUE

KATO

RES


ENSI

EVR NEAR INELASTIC COUNTS

ENSI

RES


INEL

INELASTIC SPECTRUM

INEL

INP


FFTR

FAR FIT ERROR

FFTR

RES


GRA

API

API

GAMMA RAY TMD FILTERED

GRA

gAPI

gAPI

RES


GENV

VOLTS

VOLTS

GENERATOR VOLTS

GENV

VOLTS

VOLTS

INP


FVT

FLOW VELOCITY TOTAL

FVT

RES


FVS

FLOW VELOCITY SPECTRAL

FVS

RES


FVG

FLOW VELOCITY GAMMA

FVG

RES


FV

FLOW VELOCITY

FV

RES


FTMD

FAR COUNTRATE

FTMD

RES


FSG1

FAR GATE 1 CNTS UNFILTERED

FSG1

RES


FNIN

FAR NET INELASTIC COUNT RATE

FNIN

RES


IONI

ION CURRENT

IONI


FSIN

FAR INELASTIC COUNTS

FSIN

RES


FORM

FORMATION SPECTRUM

FORM

INP


FSBU

FAR BACKGROUND UNFILTERED

FSBU

RES


FSG2


FSG2

RES


FSG3


FSG3

RES


FSG4


FSG4

RES


FSG5


FSG5

RES


FSG6


FSG6

RES


FSGI

FAR GATE I

FSGI

RES


FSBF

FAR BACKGROUND FILTERED

FSBF

RES

MA

MA

MA

MA

INP

WSTT - WAVESONIC

SBY

Y B-D PRES WAVEFORM SEMBLANCE

SBY

INP

WSTT - WAVESONIC

YSBP

Y SEMBLANCE VALUE OF PEAK

YSBP

INP

X A-C PRES WAVEFORM SEMBLANCE

SBX

SONIC POROSITY

SPHI

WSTT - WAVESONIC

SBX

WSTT - WAVESONIC

SPHI

DECP

DECP

INP 100 pu

100 pu

RES

WSTT - WAVESONIC

VPVX

VELOCITY RATIO X

VPVX

WSTT - WAVESONIC

VPVY

VELOCITY RATIO Y

VPVY

INP INP

WSTT - WAVESONIC

WVST

XACT FORMAT DATA STRUCTURE

WVST

INP

WSTT - WAVESONIC

XDT2

X DIPOLE PEAK SLOWNESS 2

XDT2

INP

WSTT - WAVESONIC

XSBP

X SEMBLANCE VALUE OF PEAK

XSBP

INP

WSTT - WAVESONIC

XSH

X DIPOLE UPPER SLOWNESS

XSH

INP

9-40

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data

WSTT - WAVESONIC

XSL

X DIPOLE LOWER SLOWNESS

XSL

INP

WSTT - WAVESONIC

YDT

Y DIPOLE PEAK SLOWNESS

YDT

INP INP

WSTT - WAVESONIC

YMUT

Y DIPOLE MUTE

YMUT

WSTT - WAVESONIC

YSH

Y DIPOLE UPPER SLOWNESS

YSH

INP

WSTT - WAVESONIC

YSL

Y DIPOLE LOWER SLOWNESS

YSL

INP INP

WSTT - WAVESONIC

XDT

X DIPOLE PEAK SLOWNESS

XDT

WSTT - WAVESONIC

SBM

MONO PRES WAVEFORM SEMBLANCE

SBM

INP

WSTT - WAVESONIC

YDT2

Y DIPOLE PEAK SLOWNESS 2

YDT2

INP

WSTT - WAVESONIC

DXRV

DIPOLE X WAVE RIGHT VALUE

DXRV

INP

WSTT - WAVESONIC

PRY

POISSON"S RATIO Y

PRY

INP

WSTT - WAVESONIC

XMUT

X DIPOLE MUTE

XMUT

INP

WSTT - WAVESONIC

DXLV

DIPOLE X WAVE LEFT VALUE

DXLV

INP

WSTT - WAVESONIC

DPSY

DIPOLE SOURCE Y STRUCTURE

DPSY

INP

WSTT - WAVESONIC

DPSX

DIPOLE SOURCE X STRUCTURE

DPSX

INP

WSTT - WAVESONIC

D2CT

DIPOLE 2 COMPRESSED WORD COUNT

D2CT

INP

WSTT - WAVESONIC

D1CT

DIPOLE 1 COMPRESSED WORD COUNT

D1CT

INP INP

WSTT - WAVESONIC

ACQN

ACQUISITION NUMBER

ACQN

WSTT - WAVESONIC

DXXW

X DIPOLE A-C #1 PRES WAVEFORM

DXXW

INP

WSTT - WAVESONIC

DYLV

DIPOLE Y LEFT VALUE

DYLV

INP

WSTT - WAVESONIC

DYRV

DIPOLE Y RIGHT VALUE

DYRV

INP

WSTT - WAVESONIC

DYYW

Y DIPOLE B-D #1 PRES WAVEFORM

DYYW

INP

WSTT - WAVESONIC

FAZI

DIRECTION OF FAST SHEAR WAVE

FAZI

INP

WSTT - WAVESONIC

MSH

MONOPOLE UPPER SLOWNESS

MSH

INP

WSTT - WAVESONIC

PNSA

% ANISOTROPY

PNSA

INP

WSTT - WAVESONIC

PRX

POISSON"S RATIO X

PRX

INP

WSTT - WAVESONIC

CONF

CONFIDENCE OF THE MEASUREMENT

CONF

INP

WSTT - WAVESONIC

MCNT

MONOPOLE COMPRESSED WORD COUNT

MCNT

INP

WSTT - WAVESONIC

MWRV

MONOPOLE WAVE RIGHT VALUE

MWRV

INP

WSTT - WAVESONIC

MSL

MONOPOLE LOWER SLOWNESS

MSL

INP

WSTT - WAVESONIC

MWV

MONOPOLE REC #1 PRES WAVEFORM

MWV

INP

WSTT - WAVESONIC

MSBP

MONO SEMBLANCE VALUE OF PEAK

MSBP

INP

WSTT - WAVESONIC

MMUT

MONOPOLE MUTE

MMUT

INP

WSTT - WAVESONIC

MIT

MIT mode

MITMOD

INP

WSTT - WAVESONIC

MDT2

MONOPOLE PEAK SLOWNESS 2

MDT2

INP

WSTT - WAVESONIC

MDT

MONOPOLE PEAK SLOWNESS

MDT

INP

WSTT - WAVESONIC

MWLV

MONOPOLE WAVE LEFT VALUE

MWLV

INP

XRMI/XROMI - EXT RANGE MICRO IMAGING

OMIS

NESW

NESW


OMIS

NESW

NESW

RES


OMI4

OHMM

OHMM

OMI #4 - FAST BUTTON ARRAY

OMI4

ohm.m

ohm.m

RES


P1B1

OHMM

OHMM

PAD #1 RESISTIVITY

P1B1

ohm.m

ohm.m

RES


OMI6

OHMM

OHMM


OMI6

ohm.m

ohm.m

RES


OMI5

OHMM

OHMM


OMI5

ohm.m

ohm.m

RES


OMI3

OHMM

OHMM


OMI3

ohm.m

ohm.m

RES


OMI2

OHMM

OHMM


OMI2

ohm.m

ohm.m

RES


OMI1

OHMM

OHMM


OMI1

ohm.m

ohm.m

RES


ITMP

DEGF

DEGC


ITMP

degF

degC

RES

Mnemonics

9-41

Serv_Name

LIS Mnem

LISU_ eng


F5B1


P2B1

OHMM


ZACC

G


F6B1


P3B1

OHMM


P4B1

XRMI/XROMI - EXT RANGE MICRO IMAGING XRMI/XROMI - EXT RANGE MICRO IMAGING

LISU_ met

DLISU_ Eng

DLISU_ Met

Type_ Data

Description

Mnem


F5B1

OHMM

PAD #2 RESISTIVITY

P2B1

ohm.m

ohm.m

RES

G


ZACC

G

G

RES


F6B1

OHMM

PAD #3 RESISTIVITY

P3B1

ohm.m

ohm.m

RES

OHMM

OHMM

PAD #4 RESISTIVITY

P4B1

ohm.m

ohm.m

RES

P5B1

OHMM

OHMM

PAD #5 RESISTIVITY

P5B1

ohm.m

ohm.m

RES

P6B1

OHMM

OHMM

PAD #6 RESISTIVITY

P6B1

ohm.m

ohm.m

RES


PADS

NESW

NESW


XPADS

NESW

NESW

RES


ROM1

ROMI #1 - FAST RAW VOLTAGE

ROMI1

INP


ROM2


ROMI2

INP


ROM3


ROMI3

INP


ROM4


ROMI4

INP


ROM5


ROMI5

INP


ROM6


ROMI6

INP


F4B1


F4B1

RES


XRAZ

XRMI AZIMUTH

EMIAZ

INP


DMIN

XRMI MINIMUM CALIPER PAIR

DMIN


XRAZ

XRMI AZIMUTH

EMIAZ


AHV

FT3

M3

ANNULAR HOLE VOLUME MARK

AHV

ft3

m3

RES


EDD1

OHMM

OHMM


EDD1

ohm.m

ohm.m

RES


C36

IN

MM

XRMI CALIPER PAIR 3-6

C36

in

mm

RES


C25

IN

MM


C25

in

mm

RES


C14

IN

MM


C14

in

mm

RES


BHVT

FT3

M3


BHVT

ft3

m3

RES


BHV

FT3

M3

BOREHOLE VOLUME MARK

BHV

ft3

m3

RES


CAL2

IN

MM

XRMI CALIPER ARM #2 (DIAMETER)

CAL2

in

mm

RES


AHVT

FT3

M3

ANNULAR HOLE VOLUME TOTAL

AHVT

ft3

m3

RES


CAL3

IN

MM


CAL3

in

mm

RES


ACZU

G

G

ACCELEROMETER Z UNFILTERED

ACZU

G

G

INP


ACYU

G

G

ACCELEROMETER Y UNFILTERED

ACYU

G

G

INP


ACXU

G

G

ACCELEROMETER X UNFILTERED

ACXU

G

G

INP


ACCZ

G

G


ACCZ

G

G

RES

9-42

IN

MM

RES

RES

in

mm

RES INP

Mnemonics

Serv_Name

LIS Mnem

LISU_ eng

LISU_ met

Description

Mnem

DLISU_ Eng

DLISU_ Met

Type_ Data


ACCY

G

G


ACCY

G

G

RES


ACCX

G

G


ACCX

G

G

RES


ACCQ


ACCQ


AZI1

DEG

DEG

PAD #1 AZIMUTH

AZI1

deg

deg

RES


DXTM

08.3MS

08.3MS

Z ACCELEROMETER (FAST) TIME-MS

DXTM

8.3 mS

8.3 mS

RES


F2B1


F2B1

RES


F1B1


F1B1

RES


EMIM

XRMI LAST TOOL COMMAND

EMIM

INP


EDD6

OHMM

OHMM


EDD6

ohm.m

ohm.m

RES


EDD5

OHMM

OHMM


EDD5

ohm.m

ohm.m

RES


EDD4

OHMM

OHMM


EDD4

ohm.m

ohm.m

RES


CAL1

IN

MM


CAL1

in

mm

RES


EDD2

OHMM

OHMM


EDD2

ohm.m

ohm.m

RES


F3B1


F3B1


DMAX

IN

MM

XRMI MAXIMUM CALIPER PAIR

DMAX

in

mm

RES


DEVI

DEG

DEG

DRIFT ANGLE

DEVI

deg

deg

RES


DCAL

IN

MM

XRMI DIFFERENTIAL CALIPER

DCAL

in

mm

RES


CALA

IN

MM

XRMI AVERAGE CALIPER

CALA

in

mm

RES


CAL6

IN

MM


CAL6

in

mm

RES


CAL5

IN

MM


CAL5

in

mm

RES


CAL4

IN

MM


CAL4

in

mm

RES


EDD3

OHMM

OHMM


EDD3

ohm.m

ohm.m

RES

Mnemonics

RES

RES

9-43

Log Header Mnemonics

9-44

Tool

LIS Mnem

LOG_HDR

LRU5

LOGGING DATA-GENERAL-RUN NO. 5

Character

LOG_HDR

LSC1

LOGGING DATA-ACOUSTIC-SCALE R 1

Character

Mnem

Description

Data_Location

LOG_HDR

LSC2


Character

LOG_HDR

LSC3


Character

LOG_HDR

LSC4


Character

LOG_HDR

LSC5


Character

LOG_HDR

LSL1

LOGGING DATA-NEUTRON-SCALE L 1

Character

LOG_HDR

LSL2


Character

LOG_HDR

LSL3


Character

LOG_HDR

LSL4


Character

LOG_HDR

LSL5


Character

LOG_HDR

LSP1

LOGGING DATA-GENERAL-SPEED 1

Character

LOG_HDR

LSP2


Character

LOG_HDR

LSP3


Character

LOG_HDR

LSP4


Character

LOG_HDR

LSP5


Character

LOG_HDR

LSR1

LOGGING DATA-NEUTRON-SCALE R 1

Character

LOG_HDR

LSR2


Character

LOG_HDR

LSR3


Character

LOG_HDR

LSR4


Character

LOG_HDR

LSR5

LOG_HDR

LSRV

LSRV


Character

NAME OF SERVICE

Character

LOG_HDR

LTO1

LOGGING DATA-GENERAL-DEPTH TO 1

Character

LOG_HDR

LTO2


Character

LOG_HDR

LTO3


Character

LOG_HDR

LTO4


Character

LOG_HDR

LTO5

LOG_HDR

LTYP

LTYP


Character

LOG TYPE

Character

LOG_HDR

LUL

LUL1

LOGGING UNIT LOCATION

Character

LOG_HDR

LUL2

LUL2

LOGGING UNIT LOCATION 2

Character

LOG_HDR

LUL3

LUL3


Character

LOG_HDR

LUL4

LUL4


Character

LOG_HDR

LUN

LUN1

LOGGING UNIT NUMBER

Character

LOG_HDR

LUN2

LUN2

LOGGING UNIT NUMBER 2

Character

LOG_HDR

LUN3

LUN3


Character

LOG_HDR

LUN4

LUN4


Character

LOG_HDR

MCS2

MCS2

MUD CAKE SAMPLE SOURCE 2

Character

LOG_HDR

MCS3

MCS3


Character

LOG_HDR

MCS4

MCS4


Character

LOG_HDR

MCSS

MCSS

MUD CAKE SAMPLE SOURCE

Character

LOG_HDR

MCST

TMC1

MUDCAKE SAMPLE TEMPERATURE

Character

LOG_HDR

MCT2

TMC2

MUDCAKE SAMPLE TEMPERATURE 2

Character

LOG_HDR

MCT3

TMC3


Character

LOG_HDR

MCT4

TMC4


Character

LOG_HDR

MFS2

MFSS2

MUD FILTRATE SAMPLE SOURCE 2

Character

LOG_HDR

MFS3

MFSS3


Character

Mnemonics

Tool

Mnemonics

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

MFS4

MFSS4


Character

LOG_HDR

MFSS

MFSS

MUD FILTRATE SAMPLE SOURCE

Character

LOG_HDR

MFST

TMF1

MUD FILTRATE SAMPLE TEMPERATURE

Character

LOG_HDR

MFT2

TMF2

MUD FILTRATE SAMPLE TEMPERATURE 2

Character

LOG_HDR

MFT3

TMF3


Character

LOG_HDR

MFT4

TMF4


Character

LOG_HDR

MRT

MRT

MAXIMUM RECORDED TEMPERATURE

Character

LOG_HDR

MRT2

MRT2

MAXIMUM RECORDED TEMPERATURE 2

Character

LOG_HDR

MRT3

MRT3


Character

LOG_HDR

MRT4

MRT4


Character

LOG_HDR

MSS

MSS

SOURCE OF MUD SAMPLE

Character

LOG_HDR

MSS2

MSS2

SOURCE OF MUD SAMPLE 2

Character

LOG_HDR

MSS3

MSS3


Character

LOG_HDR

MSS4

MSS4


Character

LOG_HDR

OS1

OS1

OTHER SERVICES LINE 1

Character

LOG_HDR

OS2

OS2


Character

LOG_HDR

OS3

OS3


Character

LOG_HDR

OS4

OS4


Character Character

LOG_HDR

OS5


LOG_HDR

OS6


Character

LOG_HDR

OTH1

RES. EQUIP DATA: OTHER 1 (OH)

Character

LOG_HDR

OTH2


Character

LOG_HDR

OTH3


Character

LOG_HDR

OTH4


Character

LOG_HDR

OTH5


Character

LOG_HDR

OTH6

LOG_HDR

PDAT

LOG_HDR

PGMV

PROGRAM VERSION

Character

LOG_HDR

PT1

RES. EQUIP DATA: PAD TYPE 1 (OH)

Character

LOG_HDR

PT2


Character

LOG_HDR

PT3


Character

LOG_HDR

PT4


Character

LOG_HDR

PT5


Character

LOG_HDR

PT6

LOG_HDR

R1

PDAT

RMK1


Character

PERMANENT DATUM

Character


Character

REMARKS LINE 1

Character

LOG_HDR

R10

REMARKS LINE 10

Character

LOG_HDR

R11

REMARKS LINE 11

Character

LOG_HDR

R12

LOG_HDR

R2

LOG_HDR

R3

RMK3

REMARKS LINE 3

Character

LOG_HDR

R4

RMK4

REMARKS LINE 4

Character

LOG_HDR

R5

REMARKS LINE 5

Character

LOG_HDR

R6

REMARKS LINE 6

Character

LOG_HDR

R7

REMARKS LINE 7

Character

LOG_HDR

R8

REMARKS LINE 8

Character

LOG_HDR

ACB

ADD. SAMPLES: RMC - BHT 1 (OH)

Character

LOG_HDR

ACB2


Character

LOG_HDR

ACT

ADD. SAMPLES: MUDCAKE TEMP. 1

Character

LOG_HDR

ACT2

ADD. SAMPLES: MUDCAKE TEMP. 2

Character

RMK2

REMARKS LINE 12

Character

REMARKS LINE 2

Character

9-45

9-46

Tool

LIS Mnem

LOG_HDR

ACX

ADD. SAMPLES: RMC BOTTOMHOLE TEMP

Character

LOG_HDR

ACX2

ADD. SAMPLES: RMC BOTTOMHOLE TEMP

Character

Mnem

Description

Data_Location

LOG_HDR

ADD

ADDITIONAL SAMPLES: DEPTH-DRILLER 1 (OH)

Character

LOG_HDR

ADD2


Character Character

LOG_HDR

ADE

ADDITIONAL SAMPLES: DENSITY 1

LOG_HDR

ADE2

ADDITIONAL SAMPLES: DENSITY 2

Character

LOG_HDR

ADFT

ADDITIONAL SAMPLES: FLUID TYPE IN HOLE 1 (OH)

Character

LOG_HDR

ADT

ADDITIONAL SAMPLES: DATE 1 (OPEN HOLE )

Character

LOG_HDR

ADT2

ADDITIONAL SAMPLES: DATE 1 (OPEN HOLE )

Character Character

LOG_HDR

AFB

ADD. SAMPLES: RMF - BHT 1 (OH)

LOG_HDR

AFB2


Character

LOG_HDR

AFL

ADDITIONAL SAMPLES: FLUID LOSS 1

Character

LOG_HDR

AFL2

ADDITIONAL SAMPLES: FLUID LOSS 2

Character

LOG_HDR

AFT

ADD. SAMPLES: MUD FILTRATE TEMP 1 (OH)

Character

LOG_HDR

AFT2


Character

LOG_HDR

AFX

ADD. SAMPLES: RMF BOTTOMHOLE TEMP 1 (OH)

Character

LOG_HDR

AFX2


Character

LOG_HDR

AMS2

ADD. SAMPLES: MUD SAMPLE TEMP 2 (OH)

Character

LOG_HDR

AMST


Character

LOG_HDR

APD

ABOVE PERMANENT DATUM

Character

LOG_HDR

APH

ADDITIONAL SAMPLES: PH 1 (OH)

Character

LOG_HDR

APH2


Character

LOG_HDR

ARB

ADD. SAMPLES: RES. OF MUD - BHT 1 (OH)

Character

LOG_HDR

ARB2


Character

LOG_HDR

ARC

ADD. SAMPLES: RES. OF MUDCAKE 1 (OH)

Character Character

APD

LOG_HDR

ARC2


LOG_HDR

ARF

ADD. SAMPLES: RES. MUD FILTRATE 1 (OH)

Character

LOG_HDR

ARF2


Character

LOG_HDR

ARM

ADD. SAMPLES: RES. OF MUD SAMPLE 1 (OH)

Character

LOG_HDR

ARM2


Character

LOG_HDR

ARX

ADD. SAMPLES: RM BOTTOMHOLE TEMP 1 (OH)

Character

LOG_HDR

ARX2


Character

LOG_HDR

ASC

ADD. SAMPLES: SOURCE RMC 1 (OH)

Character

LOG_HDR

ASC2


Character

LOG_HDR

ASF

ADD. SAMPLES: SOURCE RMF 1 (OH)

Character

LOG_HDR

ASF2


Character

LOG_HDR

ASN

ADDITIONAL SAMPLES: SAMPLE NO. 1 (OH)

Character

LOG_HDR

ASN2


Character

LOG_HDR

ASS

ADD. SAMPLES: SOURCE OF SAMPLE 1 (OH)

Character

LOG_HDR

ASS2


Character

LOG_HDR

AST2


Character

LOG_HDR

AV

ADDITIONAL SAMPLES: VISCOSITY 1 (OH)

Character

LOG_HDR

AV2

LOG_HDR

EGL

EGL

LOG_HDR

BARI

BARI

LOG_HDR

R9


Character

ELEVATION OF GROUND LEVEL

Character

BARITE CORRECTION

Character

REMARKS LINE 9

Character

DRILLING RIG

Character

LOG_HDR

RIG

LOG_HDR

RMB

RMBH1

RESISTIVITY OF MUD - BHT

Character

LOG_HDR

RMB2

RMBH2

RESISTIVITY OF MUD - BHT 2

Character

Mnemonics

Tool

Mnemonics

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

RMB3

RMBH3


Character

LOG_HDR

RMB4

RMBH4


Character

LOG_HDR

RMC2

RMC2

RESISTIVITY OF MUD CAKE SAMPLE 2

Character

LOG_HDR

RMC3

RMC3


Character

LOG_HDR

RMC4

RMC4


Character

LOG_HDR

RMCS

RMCS

RESISTIVITY OF MUD CAKE SAMPLE

Character

LOG_HDR

RMF2

RMF2

RESISTIVITY OF MUD FILTRATE SAMPLE 2

Character

LOG_HDR

RMF3

RMF3


Character

LOG_HDR

RMF4

RMF4


Character

LOG_HDR

RMFS

RMF1

RESISTIVITY OF MUD FILTRATE SAMPLE

Character

LOG_HDR

RMS

RM1

RESISTIVITY OF MUD SAMPLE

Character

LOG_HDR

RMS2

RM2

RESISTIVITY OF MUD SAMPLE 2

Character

LOG_HDR

RMS3

RM3


Character

LOG_HDR

RMS4

RM4


Character

LOG_HDR

RRN1

RES. EQUIP DATA: RUN NO 1 (OH)

Character

LOG_HDR

RRN2


Character

LOG_HDR

RRN3


Character

LOG_HDR

RRN4


Character

LOG_HDR

RRN5


Character

LOG_HDR

RRN6


Character

LOG_HDR

RUN

RUN NUMBER

Character

LOG_HDR

RUN2

RUN NUMBER 2

Character

LOG_HDR

RUN3

RUN NUMBER 3

Character Character

LOG_HDR

RUN4

RUN NUMBER 4

LOG_HDR

SDC1

RES. SCALE CHANGES: DEPTH 1 (OH)

Character

LOG_HDR

SDC2


Character

LOG_HDR

SDC3


Character

LOG_HDR

SDC4


Character

LOG_HDR

SDC5


Character

LOG_HDR

SCT1

RES. SCALE CHANGES: TYPE LOG 1 (OH)

Character

LOG_HDR

SCT2


Character

LOG_HDR

SCT3


Character

LOG_HDR

SCT4


Character

LOG_HDR

SCT5


Character

LOG_HDR

SDAT

LOG_HDR

DATLOG

DATE SECTION STARTED

Character

SDH1

RES. SCALE CHANGES: SCALE DOWN HOLE 1

Character

LOG_HDR

SDH2


Character

LOG_HDR

SDH3


Character

LOG_HDR

SDH4


Character

LOG_HDR

SDH5

LOG_HDR

SON


Character

SERVICE/TICKET ORDER NUMBER

Character

LOG_HDR

STAT

LOG_HDR

STEM

STATE

STATE

Character

STEM

SURFACE TEMP

LOG_HDR

STIM

TIMLOG

Character

TIME SECTION STARTED

Character

LOG_HDR LOG_HDR

SUH1

RES. SCALE CHANGES: SCALE UP HOLE 1 (OH)

Character

SUH2


LOG_HDR

Character

SUH3


Character

SON1

LOG_HDR

SUH4


Character

LOG_HDR

SUH5


Character

9-47

Tool

9-48

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

TCS

TCS

TIME CIRCULATION STOPPED

Character

LOG_HDR

TCS2

TCS2

TIME CIRCULATION STOPPED 2

Character

LOG_HDR

TCS3

TCS3


Character

LOG_HDR

TCS4

TCS4


Character

LOG_HDR

TDD1

TDD1

DRILLERS DEPTH 1

Character

LOG_HDR

TDD2

TDD2

DRILLERS DEPTH 2

Character

LOG_HDR

TDD3

TDD3

DRILLERS DEPTH 3

Character

LOG_HDR

TDD4

TDD4

DRILLERS DEPTH 4

Character

LOG_HDR

TDL

TDL

LOGGERS DEPTH

Character

LOG_HDR

TDL2

TDL2

LOGGERS DEPTH 2

Character

LOG_HDR

TDL3

TDL3

LOGGERS DEPTH 3

Character

LOG_HDR

TDL4

TDL4

LOGGERS DEPTH 4

Character

LOG_HDR

TLA2

TLAB2

TIME LOGGING ON BOTTOM 2

Character

LOG_HDR

TLA3

TLAB3


Character

LOG_HDR

TLA4

TLAB4


Character

LOG_HDR

TLAB

TLAB

TIME LOGGING ON BOTTOM

Character

LOG_HDR

TLI

TLI

TOP LOGGED INTERVAL

Character

LOG_HDR

TLI2

TLI2

TOP LOGGED INTERVAL 2

Character

LOG_HDR

TLI3

TLI3


Character

LOG_HDR

TLI4

TL4


Character

LOG_HDR

TN1

RES. EQUIP DATA: TOOL TYPE & NO. 1 (OH)

Character

LOG_HDR

TN2


Character

LOG_HDR

TN3


Character

LOG_HDR

TN4


Character

LOG_HDR

TN5


Character

LOG_HDR

TN6

LOG_HDR

TOOL

LOG_HDR

TPS1

RES. EQUIP DATA: TOOL POS. 1 (OH)

Character

LOG_HDR

TPS2


Character

LOG_HDR

TPS3


Character

LOG_HDR

TPS4


Character

LOG_HDR

TPS5


Character

LOG_HDR

TPS6


Character

TOOL


Character

TOOL STRING

Character

LOG_HDR

TTL1

HEADER TITLE LINE 1

Character

LOG_HDR

TTL4

HEADER TITLE LINE 4

Character

LOG_HDR

WIT2

WITN2

WITNESS 2 NAME

Character

LOG_HDR

WIT3

WITN3

WITNESS 3 NAME

Character

LOG_HDR

BASI

BASI

BASIN

Character

LOG_HDR

BHT

BHT

BOTTOMHOLE TEMPERATURE

Character

LOG_HDR

BHT2

BHT2

BOTTOMHOLE TEMPERATURE 2

Character

LOG_HDR

BHT3

BHT3


Character

LOG_HDR

BHT4

BHT4


Character

LOG_HDR

BLI

BLI1

BOTTOM LOGGED INTERVAL

Character

LOG_HDR

BLI2

BLI2

BOTTOM LOGGED INTERVAL 2

Character

LOG_HDR

BLI3

BLI3


Character

LOG_HDR

BLI4

BLI4


Character

LOG_HDR

BS1

BITDI1

BIT SIZE 1

Character

LOG_HDR

BS2

BITDI2

BIT SIZE 2

Character

LOG_HDR

BS3

BITDI3

BIT SIZE 3

Character

Mnemonics

Mnemonics

Tool

LIS Mnem

Mnem

LOG_HDR

BS4

BITDI4

BIT SIZE 4

Character

LOG_HDR

CBD1

DEDRI1

CASING BOTTOM DRILLER 1

Character

Description

Data_Location

LOG_HDR

CBD2

DEDRI2


Character

LOG_HDR

CBD3

DEDRI3


Character

LOG_HDR

CBD4

DEDRI4


Character

LOG_HDR

CBL1

DELOG1

CASING BOTTOM LOGGER 1

Character

LOG_HDR

CBL2

DELOG2


Character

LOG_HDR

CBL3

DELOG3


Character

LOG_HDR

CBL4

DELOG4


Character

LOG_HDR

CN

COMPAN

COMPANY NAME

Character

LOG_HDR

COUN

COUNTY

COUNTY

Character

LOG_HDR

CS1

CASDI1

CASING DIAMETER 1

Character

LOG_HDR

CS2

CASDI2

CASING DIAMETER 2

Character

LOG_HDR

CS3

CASDI3

CASING DIAMETER 3

Character

LOG_HDR

CS4

CASDI4

CASING DIAMETER 4

Character

LOG_HDR

CSW1

CASWE1

CASING WEIGHT 1

Character

LOG_HDR

CSW2

CASWE2

CASING WEIGHT 2

Character

LOG_HDR

CSW3

CASWE3

CASING WEIGHT 3

Character

LOG_HDR

CSW4

CASWE4

CASING WEIGHT 4

Character

LOG_HDR

CTRY

COUNTR

COUNTRY

Character

LOG_HDR

DAT2

HDATE2

LOGGING DATE 2

Character

LOG_HDR

DAT3

HDATE3

LOGGING DATE 3

Character

LOG_HDR

DAT4

HDATE4

LOGGING DATE 4

Character

LOG_HDR

DDEG

DIRECTIONAL DEPTH

Character

LOG_HDR

DDEV

DIRECTIONAL DEVIATION

Character

LOG_HDR

DFD

DFD

DRILLING FLUID DENSITY

Character Character

LOG_HDR

DFD2

DFD2

DRILLING FLUID DENSITY 2

LOG_HDR

DFD3

DFD3


Character

LOG_HDR

DFD4

DFD4


Character

LOG_HDR

DFL

DFL

DRILLING FLUID LOSS

Character

LOG_HDR

DFL2

DFL2

DRILLING FLUID LOSS 2

Character

LOG_HDR

DFL3

DFL3


Character

LOG_HDR

DFL4

DFL4


Character

LOG_HDR

DFP2

DFPH2

DRILLING FLUID PH 2

Character

LOG_HDR

DFP3

DFPH3

DRILLING FLUID PH 3

Character

LOG_HDR

DFP4

DFPH4

DRILLING FLUID PH 4

Character

LOG_HDR

DFPH

DFPH

DRILLING FLUID PH

Character

LOG_HDR

DFS

DFS

SALINITY

Character

LOG_HDR

DFT

DFT

DRILLING FLUID TYPE

Character

LOG_HDR

DFT2

DFT2

DRILLING FLUID TYPE 2

Character

LOG_HDR

DFT3

DFT3


Character

LOG_HDR

DFT4

DFT4


Character

LOG_HDR

DFV

DFV

DRILLING FLUID VISCOSITY

Character

LOG_HDR

DFV2

DFV2

DRILLING FLUID VISCOSITY 2

Character

LOG_HDR

DFV3

DFV3


Character

LOG_HDR

DFV4

DFV4


Character

DIRECTIONAL KOP

Character

DMF

DRILLING MEASURED

Character

DIRECTIONAL REMARKS

Character

LOG_HDR

DKOP

LOG_HDR

DMF

LOG_HDR

DRMK

9-49

9-50

Tool

LIS Mnem

LOG_HDR LOG_HDR LOG_HDR

Mnem

Description

Data_Location

EAER

EQUIP. DATA-ACOUSTIC-SERIAL NO.

Character

EAOD

EQUIP. DATA-ACOUSTIC-MODEL NO.

Character

ECNT

EQUIP. DATA-ACOUSTIC-NO. OF CENT

Character

LOG_HDR

EDF

ELEVATION OF DRILLING FLOOR

Character

LOG_HDR

EDIA

HIGHT3

EQUIP. DATA-DENSITY-DIAMETER

Character

LOG_HDR

EDOD

EQUIP. DATA-DENSITY-MODEL NO.

Character

LOG_HDR

EDS1

EQUIP. DATA-GAMMA-DISTANCE TO SOURCE

Character Character

LOG_HDR

EDSN

EQUIP. DATA-DENSITY-SOURCE SERIAL NO.

LOG_HDR

ELT

EQUIP. DATA-GAMMA-DETECTOR MODEL NO.

Character

LOG_HDR

EDTR

EQUIP. DATA-DENSITY-STRENGTH

Character

LOG_HDR

EDUN

EQUIP. DATA-DENSITY-RUN NO.

Character

LOG_HDR

EFWD

EQUIP. DATA-ACOUSTIC-FWDA

Character

LOG_HDR

EGMD

EQUIP. DATA-GAMMA-MODEL NO.

Character

LOG_HDR

EGRN

EQUIP. DATA-GAMMA-RUN NO.

Character

EQUIP. DATA-GAMMA-SERIAL NO.

Character

LOG_HDR

EGSN

LOG_HDR

EKB

LOG_HDR

HIGHT1

ELEVATION OF KELLY BUSHING

Character

ELGT

EQUIP. DATA-DENSITY-LOG TYPE

Character

LOG_HDR

ELN1

EQUIP. DATA-GAMMA-LENGTH

Character

LOG_HDR

EMIA

EQUIP. DATA-GAMMA-DIAMETER

Character

LOG_HDR

ENER

EQUIP. DATA-DENSITY-SERIAL NO.

Character

LOG_HDR

ENG2

ENGI2

ENGINEER 2 NAME

Character

LOG_HDR

ENG3

ENGI3

ENGINEER 3 NAME

Character

LOG_HDR

ENG4

ENGI4

ENGINEER 4 NAME

Character

LOG_HDR

ENGI

ENGI1

ENGINEER 1 NAME

Character Character

LOG_HDR

ENGT

EQUIP. DATA-NEUTRON-LOG TYPE

LOG_HDR

ENIA

EQUIP. DATA-NEUTRON-DIAMETER

Character

LOG_HDR

ENOD

EQUIP. DATA-NEUTRON-MODEL NO.

Character

LOG_HDR

EPD

LOG_HDR

EQLA

EPD

ELEVATATION OF PERMANENT DATUM

Character

EQUIP. DATA-ACOUSTIC-LSA

Character Character

LOG_HDR

ERUN

EQUIP. DATA-ACOUSTIC-RUN NO.

LOG_HDR

ESAT

EQUIP. DATA-DENSITY-SOURCE TYPE

Character

LOG_HDR

ESER

EQUIP. DATA-NEUTRON-SERIAL NO.

Character

LOG_HDR

ESPC

EQUIP. DATA-ACOUSTIC-SPACING

Character

LOG_HDR

ESRT

EQUIP. DATA-NEUTRON-SOURCE TYPE

Character

LOG_HDR

ESSN

EQUIP. DATA-NEUTRON-SOURCE SERIAL NO.

Character

LOG_HDR

ESTR

EQUIP. DATA-NEUTRON-STRENGTH

Character

LOG_HDR

ETP1

EQUIP. DATA-GAMMA-TYPE

Character

EQUIP. DATA-NEUTRON-RUN NO.

Character

LOG_HDR

EURN

LOG_HDR

FL1

LOC1

FIELD LOCATION LINE 1

Character

LOG_HDR

FN

FIELD

FIELD NAME

Character

LOG_HDR

HDAT

HDAT

LOG_HDR

HDRT

LOG_HDR

LAT

LOG_HDR

LCC

LAT

DATUM

Character

HEADER TYPE

Character

LATITUDE

Character

LOGGING COMPANY_CODE

Character Character

LOG_HDR

LCL1

LOGGING DATA-GAMMA-SCALE L 1

LOG_HDR

LCL2


Character

LOG_HDR

LCL3


Character

LOG_HDR

LCL4


Character

LOG_HDR

LCL5


Character

Mnemonics

Mnemonics

Tool

LIS Mnem


Mnem

Description

Data_Location

LCR1

LOGGING DATA-GAMMA-SCALE R 1

Character

LCR2


Character

LCR3


Character

LOG_HDR

LCR4


Character

LOG_HDR

LCR5


Character

LOG_HDR

LDAT

LOGGING DATE

Character

LOG_HDR

LDL1

LOGGING DATA-DENSITY-SCALE L 1

Character

LOG_HDR

LDL2


Character

LDAT

LOG_HDR

LDL3


Character

LOG_HDR

LDL4


Character

LOG_HDR

LDL5


Character

LOG_HDR

LDR1

LOGGING DATA-DENSITY-SCALE R 1

Character

LOG_HDR

LDR2


Character

LOG_HDR

LDR3


Character

LOG_HDR

LDR4


Character

LOG_HDR

LDR5


Character

LOG_HDR

LDX1

LOGGING DATA-DENSITY-MATRIX 1

Character

LOG_HDR

LDX2


Character

LOG_HDR

LDX3


Character

LOG_HDR

LDX4


Character

LOG_HDR

LDX5


Character

LOG_HDR

LFR1

LOGGING DATA-GENERAL-DEPTH FROM 1

Character

LOG_HDR

LFR2


Character

LOG_HDR

LFR3


Character

LOG_HDR

LFR4


Character

LOG_HDR

LFR5


Character

LOG_HDR

LGC1

LOGGING DATA-ACOUSTIC-SCALE L 1

Character

LOG_HDR

LGC2


Character

LOG_HDR

LGC3


Character

LOG_HDR

LGC4


Character

LOG_HDR

LGC5

LOG_HDR

LMF


Character

LOG MEASURED FROM

Character

LOG_HDR LOG_HDR

LMT1

LOGGING DATA-ACOUSTIC-MATRIX 1

Character

LMT2


LOG_HDR

Character

LMT3


Character

LMF

LOG_HDR

LMT4


Character

LOG_HDR

LMT5


Character Character

LOG_HDR

LMX1

LOGGING DATA-NEUTRON-MATRIX 1

LOG_HDR

LMX2


Character

LOG_HDR

LMX3


Character

LOG_HDR

LMX4


Character

LOG_HDR

LMX5


Character

LOG_HDR

LNAM

LNAM

Character

LOG_HDR

LONG

LONGITUDE

Character

LOG_HDR

LRU1


Character

LOG_HDR

LRU2


Character

LOG_HDR

LRU3


Character


Character

WITNESS 4 NAME

Character

LOG_HDR

LRU4

LOG_HDR

WIT4

XLONG

WITN4

9-51

Tool

9-52

LIS Mnem

Mnem

Description

Data_Location Character

LOG_HDR

WITN

WITN1

WITNESS 1 NAME

LOG_HDR

WN

NAMWEL

WELL NAME

Character

LOG_HDR

X

X

X COORDINATE

Character

LOG_HDR

XTP

MAX. REC TEMP. @ 1 (OPEN HOLE)

Character

LOG_HDR

XTP2


Character

LOG_HDR

XTP3


Character

LOG_HDR

XTP4

LOG_HDR

Y

Y


Character

Y COORDINATE

Character

LOG_HDR

SON

ORDER-NUMBER

String

LOG_HDR

RUN

RUN-NUMBER

String

LOG_HDR

WN

WELL-NAME

String

LOG_HDR

FN

FIELD-NAME

String

LOG_HDR

LCC

PRODUCER-CODE

String

LOG_HDR

CN

COMPANY

String

LOG_HDR

ACB


String

LOG_HDR

ACB2


String

LOG_HDR

ACT

ADD. SAMPLES: MUDCAKE TEMP. 1 (OH)

String

LOG_HDR

ACT2

ADD. SAMPLES: MUDCAKE TEMP. 2 (OH)

String

LOG_HDR

ACX

ADD. SAMPLES: RMC OTTOMHOLE TEMP 1 (OH)

String

LOG_HDR

ACX2

ADD. SAMPLES: RMC OTTOMHOLE TEMP 2 (OH)

String

LOG_HDR

ADD


String

LOG_HDR

ADD2


String

LOG_HDR

ADE

ADDITIONAL SAMPLES: DENSITY 1 (OH)

String

LOG_HDR

ADE2

ADDITIONAL SAMPLES: DENSITY 2 (OH)

String

LOG_HDR

ADFT

ADDI. SAMPLES: FLUID TYPE IN HOLE 1 (OH)

String

LOG_HDR

ADT

ADDITIONAL SAMPLES: DATE 1 (OPEN HOLE)

String

LOG_HDR

ADT2

ADDITIONAL SAMPLES: DATE 2 (OPEN HOLE)

String

LOG_HDR

AFB


String

LOG_HDR

AFB2


String

LOG_HDR

AFL

ADDITIONAL SAMPLES: FLUID LOSS 1 (OH)

String

LOG_HDR

AFL2

ADDITIONAL SAMPLES: FLUID LOSS 2 (OH)

String

LOG_HDR

AFT

ADD. SAMPLES: MUD FILTRATE TEMP. 1 (OH)

String

LOG_HDR

AFT2


String

LOG_HDR

AFX


String

LOG_HDR

AFX2


String

LOG_HDR

AMS2


String

LOG_HDR

AMST


String

LOG_HDR

APD

ABOVE PERMANENT DATUM

String

LOG_HDR

APH


String

LOG_HDR

APH2


String

LOG_HDR

ARB


String

LOG_HDR

ARB2


String

LOG_HDR

ARC


String

LOG_HDR

ARC2


String

LOG_HDR

ARF


String

LOG_HDR

ARF2


String

LOG_HDR

AR,


String

LOG_HDR

ARM2


String

LOG_HDR

ARX


String

Mnemonics

Tool

Mnemonics

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

ARX2


String

LOG_HDR

ASC


String

LOG_HDR

ASC2


String

LOG_HDR

ASF


String

LOG_HDR

ASF2


String

LOG_HDR

ASN


String

LOG_HDR

ASN2


String

LOG_HDR

ASS


String

LOG_HDR

ASS2


String

LOG_HDR

AST2


String

LOG_HDR

AV


String

LOG_HDR

AV2


String

ELEVATION OF GROUND LEVEL

String

LOG_HDR

EGL

LOG_HDR

BARI

EGL

BARITE CORRECTION

String

LOG_HDR

BASI

BASIN

String

LOG_HDR

BHT

BOTTOMHOLE TEMPERATURE

String

LOG_HDR

BHT2


String

LOG_HDR

BHT3


String

LOG_HDR

BHT4


String

LOG_HDR

BLI

BOTTOM LOGGED INTERVAL

String

LOG_HDR

BLI2


String

LOG_HDR

BLI3


String

LOG_HDR

BLI4


String

LOG_HDR

BS1

BIT SIZE 1

String

LOG_HDR

BS2

BIT SIZE 2

String

LOG_HDR

BS3

BIT SIZE 3

String

LOG_HDR

BS4

BIT SIZE 4

String

LOG_HDR

CBD1


String

LOG_HDR

CBD2


String

LOG_HDR

CBD3


String

LOG_HDR

CBD4


String

LOG_HDR

CBL1


String

LOG_HDR

CBL2


String

LOG_HDR

CBL3


String

LOG_HDR

CBL4


String

LOG_HDR

CN

COMPANY NAME

String

LOG_HDR

COUN

COUNTY

String

LOG_HDR

CS1

CASING DIAMETER 1

String

LOG_HDR

CS2

CASING DIAMETER 2

String

LOG_HDR

CS3

CASING DIAMETER 3

String

LOG_HDR

CS4

CASING DIAMETER 4

String String

LOG_HDR

CSW1

CASING WEIGHT 1

LOG_HDR

CSW2

CASING WEIGHT 2

String

LOG_HDR

CSW3

CASING WEIGHT 3

String

LOG_HDR

CSW4

CASING WEIGHT 4

String

LOG_HDR

CTRY

COUNTRY

String

LOG_HDR

DAT2

LOGGING DATE 2

String

LOG_HDR

DAT3

LOGGING DATE 3

String

LOG_HDR

DAT4

LOGGING DATE 4

String

9-53

9-54

Tool

LIS Mnem


Mnem

Description

Data_Location

DDEG

DIRECTIONAL DEPTH

String

DDEV

DIRECTIONAL DEVIATION

String

DFD

DRILLING FLUID DENSITY

String

LOG_HDR

DFD2


String

LOG_HDR

DFD3


String

LOG_HDR

DFD4


String

LOG_HDR

DFL

DRILLING FLUID LOSS

String

LOG_HDR

DFL2


String

LOG_HDR

DFL3


String

LOG_HDR

DFL4


String

LOG_HDR

DFP2

DRILLING FLUID PH 2

String

LOG_HDR

DPF3

DRILLING FLUID PH 3

String

LOG_HDR

DFP4

DRILLING FLUID PH 4

String

LOG_HDR

DFPH

DRILLING FLUID PH

String

LOG_HDR

DFS

SALINITY

String

LOG_HDR

DFT

DRILLING FLUID TYPE

String

LOG_HDR

DFT2


String

LOG_HDR

DFT3


String

LOG_HDR

DFT4


String

LOG_HDR

DFV

DRILLING FLUID VISCOSITY

String

LOG_HDR

DFV2


String

LOG_HDR

DFV3


String

LOG_HDR

DFV4


String

LOG_HDR

DKOP

DIRECTIONAL KOP

String

LOG_HDR

DMF

DRILLING MEASURED FROM

String

LOG_HDR

DRMK

DIRECTIONAL REMARKS

String

LOG_HDR

EAER

EQUIP. DATA-ACOUSTIC-SERIAL NO.

String

LOG_HDR

EAOD

EQUIP. DATA-ACOUSTIC-MODEL NO.

String

LOG_HDR

ECNT

EQUIP. DATA-ACOUSTIC-NO. OF CENT

String

LOG_HDR

EDF

ELEVATION OF DRILLING FLOOR

String

LOG_HDR

EDIA

EQUIP. DATA-DENSITY-DIAMETER

String

LOG_HDR

EDOD

EQUIP. DATA-DENSITY-MODEL NO.

String

LOG_HDR

EDSI

EQUIP. DATA-GAMMA-DISTANCE TO SOURCE

String

LOG_HDR

EDSN

EQUIP. DATA-DENSITY-SOURCE SERIAL NO.

String

LOG_HDR

EDT

EQUIP. DATA-GAMMA-DETECTOR MODEL NO.

String

LOG_HDR

EDTR

EQUIP. DATA-DENSITY-STRENGTH

String

LOG_HDR

EDUN

EQUIP. DATA-DENSITY-RUN NO.

String

LOG_HDR

EFWD

EQUIP. DATA-ACOUSTIC-FWDA

String

LOG_HDR

EGMD

EQUIP. DATA-GAMMA-MODEL NO.

String

LOG_HDR

EGRN

EQUIP. DATA-GAMMA-RUN NO.

String

LOG_HDR

EGSN

EQUIP. DATA-GAMMA-SERIAL NO.

String

LOG_HDR

EKB

ELEVATION OF KELLY BUSHING

String

LOG_HDR

ELGT

EQUIP. DATA-DENSITY-LOG TYPE

String

LOG_HDR

ELN1

EQUIP. DATA-GAMMA-LENGTH

String

LOG_HDR

EMIA

EQUIP. DATA-GAMMA-DIAMETER

String

LOG_HDR

ENER

EQUIP. DATA-DENSITY-SERIAL NO.

String

LOG_HDR

ENG2

ENGINEER 2 NAME

String

LOG_HDR

ENG3

ENGINEER 3 NAME

String

LOG_HDR

RNG4

ENGINEER 4 NAME

String

Mnemonics

Tool

Mnemonics

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

ENGI

ENGINEER 1 NAME

String

LOG_HDR

ENGT

EQUIP. DATA-NEUTRON-LOG TYPE

String

LOG_HDR

ENIA

EQUIP. DATA-NEUTRON-DIAMETER

String

LOG_HDR

ENOD

EQUIP. DATA-NEUTRON-MODEL NO.

String

LOG_HDR

EPD

ELEVATATION OF PERMANENT DATUM

String

LOG_HDR

EQLA

EQUIP. DATA-ACOUSTIC-LSA

String String

LOG_HDR

ERUN

EQUIP. DATA-ACOUSTIC-RUN NO.

LOG_HDR

ESAT

EQUIP. DATA-DENSITY-SOURCE TYPE

String

LOG_HDR

ESER

EQUIP. DATA-NEUTRON-SERIAL NO.

String

LOG_HDR

ESPC

EQUIP. DATA-ACOUSTIC-SPACING

String

LOG_HDR

ESRT

EQUIP. DATA-NEUTRON-SOURCE TYPE

String

LOG_HDR

ESSN

EQUIP. DATA-NEUTRON-SOURCE SERIAL NO.

String

LOG_HDR

ESTR

EQUIP. DATA-NEUTRON-STRENGTH

String

LOG_HDR

ETP1

EQUIP. DATA-GAMMA-TYPE

String

LOG_HDR

EURN

EQUIP. DATA-NEUTRON-RUN NO.

String

LOG_HDR

FL1

FIELD LOCATION LINE 1

String

LOG_HDR

FN

FIELD NAME

String

LOG_HDR

HDAT

DATUM

String

LOG_HDR

HDRT

HEADER TYPE

String

LOG_HDR

LAT

LATITUDE

String

LOG_HDR

LCC

LOGGING COMPANY_CODE

String

LOG_HDR

LCL1


String String

LOG_HDR

LCL2


LOG_HDR

LCL3


String

LOG_HDR

LCL4


String

LOG_HDR

LCL5


String

LOG_HDR

LCR1


String

LOG_HDR

LCR2


String

LOG_HDR

LCR3


String

LOG_HDR

LCR4


String

LOG_HDR

LCR5


String

LOG_HDR

LDAT

LOG_HDR

LDL1

LDAT

LOGGING DATE

String


String

LOG_HDR

LDL2


String

LOG_HDR

LDL3


String

LOG_HDR

LDL4


String

LOG_HDR

LDL5


String

LOG_HDR

LDR1


String

LOG_HDR

LDR2


String

LOG_HDR

LDR3


String

LOG_HDR

LDR4


String

LOG_HDR

LDR5


String

LOG_HDR

LDX1


String

LOG_HDR

LDX2


String

LOG_HDR

LDX3


String

LOG_HDR

LDX4


String

LOG_HDR

LDX5


String

LOG_HDR

LFR1


String

LOG_HDR

LFR2


String

9-55

Tool

9-56

LIS Mnem

Mnem

Description

Data_Location String

LOG_HDR

LFR3


LOG_HDR

LFR4


String

LOG_HDR

LFR5


String String

LOG_HDR

LGC1


LOG_HDR

LGC2


String

LOG_HDR

LGC3


String

LOG_HDR

LGC4


String

LOG_HDR

LGC5


String

LOG_HDR

LMF

LOG_HDR

LMT1

LMF

LOG MEASURED FROM

String


String

LOG_HDR

LMT2


String

LOG_HDR

LMT3


String

LOG_HDR

LMT4


String

LOG_HDR

LMT5


String

LOG_HDR

LMX1


String

LOG_HDR

LMX2


String

LOG_HDR

LMX3


String

LOG_HDR

LMX4


String

LOG_HDR

LMX5


String

LOG_HDR

LNAM

LNAM

String

LOG_HDR

LONG

LONGITUDE

String

LOG_HDR

LRU1


String

LOG_HDR

LRU2


String

LOG_HDR

LRU3


String

LOG_HDR

LRU4


String

LOG_HDR

LRU5


String

LOG_HDR

LSC1


String

LOG_HDR

LSC2


String

LOG_HDR

LSC3


String

LOG_HDR

LSC4


String

LOG_HDR

LSC5


String

LOG_HDR

LSL1


String

LOG_HDR

LSL2


String

LOG_HDR

LSL3


String

LOG_HDR

LSL4


String

LOG_HDR

LSL5


String

LOG_HDR

LSP1


String

LOG_HDR

LSP2


String

LOG_HDR

LSP3


String

LOG_HDR

LSP4


String

LOG_HDR

LSP5


String

XLONG

LOG_HDR

LSR1


String

LOG_HDR

LSR2


String

LOG_HDR

LSR3


String

LOG_HDR

LSR4


String

LOG_HDR

LSR5

LOG_HDR

LSRV

LSRV


String

NAME OF SERVICE

String

LOG_HDR

LTO1


String

LOG_HDR

LTO2


String

Mnemonics

Tool

Mnemonics

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

LTO3


String

LOG_HDR

LTO4


String

LOG_HDR

LTO5

LOG_HDR

LTYP


String

LTYP

LOG TYPE

String

LOG_HDR LOG_HDR

LUL

LUL1

LOGGING UNIT LOCATION

String

LUL2

LUL2


String

LOG_HDR

LUL3

LUL3


String

LOG_HDR

LUL4

LUL4


String

LOG_HDR

LUN

LUN1

LOGGING UNIT NUMBER

String

LOG_HDR

LUN2

LUN2


String

LOG_HDR

LUN3

LUN3


String

LOG_HDR

LUN4

LUN4


String

LOG_HDR

MCS2

MCS2


String

LOG_HDR

MCS3

MCS3


String

LOG_HDR

MCS4

MCS4


String

LOG_HDR

MCSS

MCSS

MUD CAKE SAMPLE SOURCE

String

LOG_HDR

MCST

TMC1

MUDCAKE SAMPLE TEMPERATURE

String

LOG_HDR

MCT2

TMC2


String

LOG_HDR

MCT3

TMC3


String

LOG_HDR

MCT4

TMC4


String

LOG_HDR

MFS2

MFSS2


String

LOG_HDR

MFS3

MFSS3


String

LOG_HDR

MFS4

MFSS4


String

LOG_HDR

MFSS

MFSS

MUD FILTRATE SAMPLE SOURCE

String

LOG_HDR

MFST

TMF1

MUD FILTRATE SAMPLE TEMPERATURE

String

LOG_HDR

MFT2

TMF2


String

LOG_HDR

MFT3

TMF3


String

LOG_HDR

MFT4

TMF4


String

LOG_HDR

MRT

MRT

MAXIMUM RECORDED TEMPERATURE

String

LOG_HDR

MRT2

MRT2


String

LOG_HDR

MRT3

MRT3


String

LOG_HDR

MRT4

MRT4


String

LOG_HDR

MSS

MSS

SOURCE OF MUD SAMPLE

String

LOG_HDR

MSS2

MSS2


String

LOG_HDR

MSS3

MSS3


String

LOG_HDR

MSS4

MSS4


String

LOG_HDR

MST

TM1

MUD SAMPLE TEMPERATURE

String

LOG_HDR

MST2

TM2

MUD SAMPLE TEMPERATURE 2

String

LOG_HDR

MST3

TM3


String

LOG_HDR

MST4

TM4


String

LOG_HDR

MST

TM1

MUD SAMPLE TEMPERATURE

Character

LOG_HDR

MST2

TM2


Character

LOG_HDR

MST3

TM3


Character

LOG_HDR

MST4

TM4


Character

LOG_HDR

OS1

OS1


String

LOG_HDR

OS2

OS2


String

LOG_HDR

OS3

OS3


String

LOG_HDR

OS4

OS4


String

LOG_HDR

OS5


String

9-57

9-58

Tool

LIS Mnem

LOG_HDR

OS6


String

LOG_HDR

OTH1


String

LOG_HDR

OTH2


String

LOG_HDR

OTH3


String

LOG_HDR

OTH4


String

LOG_HDR

OTH5


String

LOG_HDR

OTH6


String

LOG_HDR

PDAT

LOG_HDR

PGMV

Mnem

PDAT

Description

Data_Location

PERMANENT DATUM

String

PROGRAM VERSION

String

LOG_HDR

PT1


String

LOG_HDR

PT2


String

LOG_HDR

PT3


String

LOG_HDR

PT4


String

LOG_HDR

PT5


String

LOG_HDR

PT6


String

REMARKS LINE 9

Character

REMARKS LINE 1

String

LOG_HDR

R9

LOG_HDR

R1

LOG_HDR

R10

REMARKS LINE 10

String

LOG_HDR

R11

REMARKS LINE 11

String

LOG_HDR

R12

REMARKS LINE 12

String

LOG_HDR

R2

RMK2

REMARKS LINE 2

String

LOG_HDR

R3

RMK3

REMARKS LINE 3

String

LOG_HDR

R4

RMK4

REMARKS LINE 4

String

LOG_HDR

R5

REMARKS LINE 5

String

LOG_HDR

R6

REMARKS LINE 6

String

LOG_HDR

R7

REMARKS LINE 7

String

LOG_HDR

R8

REMARKS LINE 8

String

LOG_HDR

R9

REMARKS LINE 9

String

LOG_HDR

RIG

DRILLING RIG

String

RMK1

LOG_HDR

RMB

RMBH1

RESISTIVITY OF MUD - BHT

String

LOG_HDR

RMB2

RMBH2


String

LOG_HDR

RMB3

RMBH3


String

LOG_HDR

RMB4

RMBH4


String

LOG_HDR

RMC2

RMC2


String

LOG_HDR

RMC3

RMC3


String

LOG_HDR

RMC4

RMC4


String

LOG_HDR

RMCS

RMCS

RESISTIVITY OF MUD CAKE SAMPLE

String

LOG_HDR

RMF2

RMF2


String

LOG_HDR

RMF3

RMF3


String

LOG_HDR

RMF4

RMF4


String

LOG_HDR

RMFS

RMF1

RESISTIVITY OF MUD FILTRATE SAMPLE

String

LOG_HDR

RMS

RM1

RESISTIVITY OF MUD SAMPLE

String

LOG_HDR

RMS2

RM2


String

LOG_HDR

RMS3

RM3


String

LOG_HDR

RMS4

RM4


String

LOG_HDR

RRN1


String

LOG_HDR

RRN2


String

LOG_HDR

RRN3


String

LOG_HDR

RRN4


String

Mnemonics

Tool

Mnemonics

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

RRN5


String

LOG_HDR

RRN6


String

LOG_HDR

RUN

RUN NUMBER

String

LOG_HDR

RUN2

RUN NUMBER 2

String

LOG_HDR

RUN3

RUN NUMBER 3

String String

LOG_HDR

RUN4

RUN NUMBER 4

LOG_HDR

SDC1


String

LOG_HDR

SDC2


String

LOG_HDR

SDC3


String

LOG_HDR

SDC4


String

LOG_HDR

SDC5


String

LOG_HDR

SCT1


String String

LOG_HDR

SCT2


LOG_HDR

SCT3


String

LOG_HDR

SCT4


String

LOG_HDR

SCT5

LOG_HDR

SDAT

DATLOG


String

DATE SECTION STARTED

String

LOG_HDR

SDH1


String

LOG_HDR

SDH2


String

LOG_HDR

SDH3


String

LOG_HDR

SDH4


String

LOG_HDR

SDH5


String

LOG_HDR

SON

SON1

SERVICE/TICKET ORDER NUMBER

String

LOG_HDR

STAT

STATE

STATE

String

LOG_HDR

STEM

STEM

SURFACE TEMP

String

LOG_HDR

STIM

TIMLOG

TIME SECTION STARTED

String

LOG_HDR

SUH1


String

LOG_HDR

SUH2


String

LOG_HDR

SUH3


String

LOG_HDR

SUH4


String

LOG_HDR

SUH5


String

LOG_HDR

TCS

TCS

TIME CIRCULATION STOPPED

String

LOG_HDR

TCS2

TCS2


String

LOG_HDR

TCS3

TCS3


String

LOG_HDR

TCS4

TCS4


String

LOG_HDR

TDD1

TDD1

DRILLERS DEPTH 1

String

LOG_HDR

TDD2

TDD2

DRILLERS DEPTH 2

String

LOG_HDR

TDD3

TDD3

DRILLERS DEPTH 3

String

LOG_HDR

TDD4

TDD4

DRILLERS DEPTH 4

String

LOG_HDR

TDL

TDL

LOGGERS DEPTH

String

LOG_HDR

TDL2

TDL2

LOGGERS DEPTH 2

String

LOG_HDR

TDL3

TDL3

LOGGERS DEPTH 3

String

LOG_HDR

TDL4

TDL4

LOGGERS DEPTH 4

String

LOG_HDR

TLA2

TLAB2


String

LOG_HDR

TLA3

TLAB3


String

LOG_HDR

TLA4

TLAB4


String

LOG_HDR

TLAB

TLAB

TIME LOGGING ON BOTTOM

String

LOG_HDR

TLI

TLI

TOP LOGGED INTERVAL

String

LOG_HDR

TLI2

TLI2


String

9-59

9-60

Tool

LIS Mnem

Mnem

Description

Data_Location

LOG_HDR

TLI3

TLI3


String

LOG_HDR

TLI4

TL4


String

LOG_HDR

TN1


String

LOG_HDR

TN2


String

LOG_HDR

TN3


String

LOG_HDR

TN4


String

LOG_HDR

TN5


String

LOG_HDR

TN6

LOG_HDR

TOOL

LOG_HDR

TPS1


String

LOG_HDR

TPS2


String

LOG_HDR

TPS3


String

LOG_HDR

TPS4


String

LOG_HDR

TPS5


String

LOG_HDR

TPS6


String

TOOL


String

TOOL STRING

String

LOG_HDR

TTL1

HEADER TITLE LINE 1

String

LOG_HDR

TTL4

HEADER TITLE LINE 4

String

LOG_HDR

WIT2

WITN2

WITNESS 2 NAME

String

LOG_HDR

WIT3

WITN3

WITNESS 3 NAME

String

LOG_HDR

WIT4

WITN4

WITNESS 4 NAME

String

LOG_HDR

WITN

WITN1

WITNESS 1 NAME

String

LOG_HDR

WN

NAMWEL

WELL NAME

String

LOG_HDR

X

X

X COORDINATE

String

LOG_HDR

XTP


String

LOG_HDR

XTP2


String

LOG_HDR

XTP3


String

LOG_HDR

XTP4


String

LOG_HDR

Y

Y

Y COORDINATE

String

LOG_HDR

BS

BITDI

BIT SIZE

Character

LOG_HDR

CS

CASDI

CASING DIAMETER

Character

LOG_HDR

CBD

DEDRI

CASING BOTTOM DRILLER

Character

LOG_HDR

CBL

DELOG

CASING BOTTOM LOGGER

Character

LOG_HDR

CSW

CASWE

CASING WEIGHT

Character

LOG_HDR

TDD

TDD

DRILLERS DEPTH

Character

Mnemonics

Index A Acoustics 3-24 BSAT Borehole Compensated Sonic Array Tool 3-24 FWS™ Full Wave Sonic Tool 3-27 WaveSonic® Tool 3-25 Acoustics and Rock Properties 2-30 AcidXpert™ Analysis 2-36 Anisotropy Analysis 2-30 FracXpert™ Analysis 2-34 RockXpert2™ Analysis 2-32 Advanced Measurement System Electronic Advanced Measurement System (Portable) 7-26 JobTrak® Data Job Logger 7-28 SmartETD® System 7-27 Advanced Measurement System (AMS) 7-25 Advanced® Slickline Services 7-16 Deepwater Riserless Subsea Light Well Intervention System 7-33 DPU® Downhole Power Unit 7-19 DPU Tubing Punch 7-22 LineTrak® Slickline Inspection Device and Wire Management Program 7-31 Memory Production Logging (MPL) Service 7-29 Ancillary Equipment 5-71 Annular Pressure-Control Line Swivel Sub 5-92 Annular Pressure-Control Line Tubing Release 5-93 Annular Pressure-Control Line Vent 5-91 AutoLatch™ Release Gun Connector 5-75 Automatic Release 5-99 Automatic-Release Gun Hanger— Automatic-J Mandrel 5-84 Automatic-Release Gun Hanger— Rotational Set 5-82 Balanced Isolation Tool 5-72 Bar Pressure Vent 5-94 Below-Packer Vent Device 5-95 Centralizer Tandem 5-89 Detach™ Separating Gun Connector 5-79 DPU Downhole Power Unit 5-104 Emergency Release Assembly 5-90 Explosive Transfer Swivel Sub 5-86 EZ Pass™ Gun Hanger 5-80 Fast Gauge Recorder 5-110 Fill Disk Assembly 5-71 Gamma Perforator Logging Tool 5-112 Gun Guides 5-107

Index

Hydraulic Metering Release Tool for the Single Trip System (STPP™-GH) Tool 5-108 Isolation Sub-Assembly 5-76 Maximum Differential Bar Vent 5-96 Mechanical Tubing Release 5-101 Pressure-Actuated Tubing Release 5-103 Pressure-Operated Vent 5-97 Quick Torque™ Connector 5-77 Ratchet Gun Connector 5-74 Roller Tandem Assembly 5-88 Shearable Safety Sub 5-87 SmartETD® Advanced Electronic Triggering Device 5-105 Vann™ Circulating Valve 5-98 Y-Block Assembly 5-106 Auxiliary Services 3-57 BHPT™ Borehole Properties Tool 3-63 CTL™ Coiled Tubing Logging 3-62 FIAC™ Four Independent Arm Caliper Tool 3-65 Multi-Conductor LockJar®* System 3-57 RWCH™ Releaseable Wireline Cable Head 3-59 SDDT™ Stand-Alone DITS™ Directional Tool 3-67 Toolpusher™ Logging (TPL) Service 3-60

B Borehole Geophysics 2-26, 3-33 Reservoir Geophysics 2-27, 3-34 GeoChain VSP Downhole Receiver Array 2-27, 3-34 Long Array Multi-Component Acquisition Tools 2-27, 3-34 Synthetic Seismic and Sonic Log Calibration 2-27, 3-34 ExactFrac® Services 2-29, 3-36 Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis 2-28, 3-35 Wellbore Seismic 2-26, 3-33 High Resolution Seismic Imaging 2-26, 3-33

C Cased-Hole Wireline and Perforating Services 4-1 Casing and Tubing Evaluation 4-28 CAST-V™ Circumferential Acoustic Scanning Tool-Visualization 4-29 MAC™ Multi-Arm Caliper Tool 4-28 *LockJar is a registered trademark of Evans Engineering, Inc.

10-1

The FASTCAST™ Fast Circumferential Acoustic Scanning Tool 4-31 Cement Evaluation 4-33 ACE™ Advanced Cement Evaluation Process 4-37 Cement Bond Log (CBL) 4-33 Radial Cement Bond Tools 4-35 CollarTrak® Slickline Collar Locator 7-23

D Detonators 5-113 Block RED® Detonators 5-115 Capsule RED Detonators 5-113 RED GO™-Style Thermal Igniter 5-114 Top Fire RED Detonators 5-116 Downhole Video 6-1 Downhole Video Services 6-1 EyeDeal™ Camera System 6-4 Fiber-Optic Camera System 6-3 Hawkeye™ Camera System 6-2 Dynamic Modeling 5-117 Near-Wellbore Stimulation and PulsFrac™ Software 5-120 PerfPro® Process 5-117 Predicting In-Situ Charge Performance 5-117 ShockProSM Shockload Evaluation Service 5-125 SurgeProSM Service 5-122

F Firing Heads 5-45 Annulus Pressure Crossover Assembly 5-67 Annulus Pressure Firer-Control Line 5-54 Annulus Pressure Transfer Reservoir 5-55 Detonation Interruption Device 5-45 Differential Firing Head 5-57 Extended Delay Fuses 5-63 EZ Cycle™ Multi-Pressure Cycle Firing Head 5-68 Hydraulic-Actuator Firing Head and Swivel-Type Hydraulic-Actuator Firing Head 5-58 Mechanical Firing Head 5-46 Mechanical Metering Hydraulic-Delay Firing Head 5-59 Model II-D Mechanical Firing Head 5-47 Model III-D Mechanical Firing Head 5-48 Model K and K-II Firing Heads 5-50 Model KV-II Firing Head 5-51 Modular Mechanical Firing Head 5-64 Drop Bar Options 5-65 Skirt-Centralizer Selection Chart 5-65 Multiaction-Delay Firing Head 5-53 Pressure-Actuated Firing Head 5-49

10-2

Pump-Through Firing Head 5-70 Side-Pocket Mandrel Firing Head 5-66 Slickline-Retrievable Mechanical Firing Head 5-60 Slickline-Retrievable Time-Delay Firer Firing Head 5-62 Slimhole Annulus Pressure Firer— Internal Control 5-56 Time-Delay Firer 5-52 Formation Evaluation 4-1 CASE™ Casing Evaluation and Inspection Software 4-10 DSN™ Dual-Spaced Neutron Tool 4-7 FCMT™ Formation Compaction Monitoring Tool 4-9 RMT Elite™ Reservoir Monitor Tool 4-3 Spectra Flow™ Logging Service (SpFl) 4-5 TMD-L™ Thermal Multigate Decay-Lithology Logging Tool 4-1

G Gun Systems 5-10 Capsule Gun Systems 5-41 Deep Star™ Capsule Gun 5-42 Dyna-Star® Capsule Gun 5-41 Ported Gun Perforating System 5-44 VannGun® Assemblies 1 9/16 in. to 7 in. and 4 SPF to 21 SPF 5-10 Gun Swell Information 5-39 Gun Washover/Fishing Specifications 5-38 Tensile Ratings 5-16 1 9/16-in. Premium VannGun Assemblies 5-16 2-in. Premium VannGun Assemblies 5-17 2 1/2-in. Premium VannGun Assemblies 5-18 2 3/4-in. Premium VannGun Assemblies 5-19 2 7/8-in. Premium VannGun Assemblies 5-20 3 3/8-in. Premium VannGun Assemblies 5-21 4-in. Premium VannGun Assemblies 5-23 4 1/2-in. Premium VannGun Assemblies 5-24 4 5/8-in. Premium VannGun Assemblies 5-25 4 3/4-in. Premium VannGun Assemblies 5-28

Index

5-in. Premium VannGun® Assemblies 5-29 5 1/8-in. Premium VannGun Assemblies 5-31 5 3/4-in. Premium VannGun Assemblies 5-33 6-in. Premium VannGun Assemblies 5-33 6 1/2-in. High-Pressure Premium VannGun Assemblies 5-35 6 1/2-in. Premium VannGun Assemblies 5-34 7-in. Premium VannGun Assemblies 5-36 VannGun Phasing and Shot Patterns 5-11 0° Phasing 4 and 5 SPF 5-11 138° Phasing 14 SPF 5-15 140°/160° Phasing 11 SPF 5-14 180° Phasing 4 and 8 SPF 5-12 25.7°/128.5° Phasing 14 SPF 5-15 30°/150° Phasing 12 SPF 5-14 45°/135° Phasing 5, 6, 8, 12, and 18 SPF 5-13 51.4°/154.3° Phasing 12 SPF 5-14 60° Phasing 4, 5, and 6 SPF 5-11 60° Phasing 6 SPF Two Planes 5-13 60°/120° Phasing 18 and 21 SPF 5-15 90° Phasing 4 SPF 5-12

SED™ Six Arm Dipmeter 3-16 XRMI™ X-Tended Range Micro Imager Tool 3-11 InSite Anywhere® Service 1-3

K Knowledge and Data Transfer 1-1

L LOGIQ™ Logging Truck 8-1 LOGIQ Modular Skid Unit 8-3

M Mechanical Services 4-39 C-4 Casing Cutters 4-50 Casing and Drillpipe Cutters 4-48 Chemical Cutter 4-39 Coiled Tubing Cutters 4-46 Drill Collar Severing Tool 4-51 Junk Shot 4-53 Pipe Recovery 4-39 Super Tubing Cutters 4-44 Tubing Cutters 4-42 Mnemonics 9-1 Log Header Mnemonics 9-44 Mobilization 8-1

H

N

HalLink® Satellite Systems 1-2 Hostile—Slimhole Formation Evaluation 3-47 HEAT™ Hostile Environment Applications Tool Suite 3-47 HDSN™ Hostile Dual-Spaced Neutron Tool 3-53 HEDL™ Hostile Environment Dual Laterolog Tool 3-48 HFWS™ Hostile Full Wave Sonic Tool 3-49 HNGR™ Hostile Natural Gamma Ray Tool 3-55 HSDL™ Hostile Spectral Density Log 3-51 HSFT™ Hostile Sequential Formation Tester Tool 3-56

Near-Wellbore Stimulation 5-127 PerfStim™ Process 5-133 POWR*PERFSM Perforation/Stimulation Process 5-132 Propellent Stimulation Tool Assembly 5-130 StimGun™* Assembly 5-127 NMR 3-29 MRILab® Magnetic Resonance Image Fluid Analyzer 3-31 MRIL-XL™ and MRIL®-Prime Magnetic Resonance Image Logging Tools 3-29 Nuclear 3-17 CSNG™ Compensated Spectral Natural Gamma Ray 3-22 DSEN™ Dual-Spaced Epithermal Neutron Log Tool 3-21 DSN™ Dual-Spaced Neutron Tool 3-19 SDL™ Spectral Density Log 3-17

I Imaging 3-9 CAST-V™ Circumferential Acoustic Scanning Tool-Visualization 3-15 EMI™ Electrical Micro Imaging Service 3-9 OMRI™ Oil-Based Micro-Imager Tool 3-13

Index

*StimGun is a trademark of Marathon Oil Company.

10-3

O Open-Hole Wireline and Perforating Services 3-1 Oriented Perforating 5-134 Eccentric Orienting Tandem 5-138 Finned Orienting Tandem 5-137 G-Force® Precision Oriented Perforating System 5-134 Oriented Perforating with Modular Guns 5-136

P Perforating Solutions 5-1 Petrophysics 2-1 MRI Petrophysics 2-1 Diffusion Analysis (DIFAN) 2-5 Enhanced Diffusion Method™ (EDM™) Technique 2-6 Heavy Oil MRIANSM Service 2-7 MRIAN™ Magnetic Resonance Imaging Analysis 2-2 MRIL® Simultaneous T1 and T2 Measurements 2-1 StiMRIL™ Process 2-8 Time Domain Analysis (TDA) 2-4 Volumetric Petrophysics 2-10 Chi Modeling® Computation Service 2-10 CORAL™ Complex Lithology Analysis 2-15 LARA™ Laminated Reservoir Analysis 2-16 SASHA™ Shaly Sand Analysis 2-14 ULTRA™ Module Suite 2-12 Plug Setting Equipment 4-54 EZ Drill® Bridge Plugs 4-54 Fas Drill® Bridge Plugs 4-55 Production Logging 4-18 FloImager® Service 4-21 GHT™ Gas Holdup Tool 4-23 MPL™ Memory Production Logging Tool 4-24 Production Logging Tools 4-18 Quartz Pressure Tool 4-27

R Real-Time Operations 1-1 Real-Time Data/Solution Delivery 1-1 Reservoir and Production Engineering 2-38 FloImager Analysis Service 2-54 FloImager® 3D Software Analysis 2-54 Production Logging Analysis 2-51 Reservoir Evaluation 2-48 CarbOxSat™ Model 2-49 SigmaSat™ Model 2-48

10-4

TripleSat™ Model 2-50 Reservoir Testing Studio 2-38 Exact™ Anisotropy Analysis Plot 2-39 Exact Buildup Analysis 2-39 FasTest® Buildup Analysis 2-40 Formation Test Summary Program (FTS) 2-42 Horner Time Plots 2-40 Log-Log Derivative Analysis Plot 2-41 PVT Analysis 2-42 Well Testing 2-44 Reservoir Characterization 2-17 Borehole Image Analysis 2-17 AutoDip™ and TrendSetter™ Services 2-17 Facies Profile 2-22 ReadyView™ Open-Hole Imaging 2-20 ImagePerm 2-25 Net2Gross Sand Count 2-24 Reservoir Evaluation Services 2-1 Resistivity 3-1 ACRt™ Array Compensated Resistivity Tool System 3-1 DLL™ Dual Laterolog Service 3-6 HDIL™ Hostile Dual Induction Log 3-5 HFDT™ High Frequency Dielectric Tool 3-8 HRAI™ High Resolution Array Induction Tool 3-3 HRI™ High Resolution Induction Tool 3-4 MSFL™ Micro-Spherically Focused Log and Microlog (ML) 3-7

S Sampling 3-37 HRSCT™ Hostile Rotary Side Wall Coring Tool 3-46 Hydraulic Valve Section 3-46 Mandrel Section 3-46 Motor Drive Section 3-46 RDT™ Reservoir Description Tool 3-37 CVS Chamber Valve Section 3-40 DPS Dual Probe Section 3-39 FPS Flow-Control Pump-Out Section 3-39 MCS Multi Chamber Section 3-40 MRILab® Section 3-40 Oval Pad 3-39 QGS Quartz Gauge Section 3-39 Straddle Packer 3-39 RSCT™ Rotary Sidewall Coring Tool 3-43 SFT-IV™ Sequential Formation Tester IV Tool 3-41 SFTT™ Sequential Formation Test Tool 3-42 SWC™ Side Wall Coring Tool 3-45 Shaped Charges 5-1 Charge Performance Data 5-7 Dominator® Shaped Charges 5-2

Index

KISS™ Low-Damage Perforating Charge 5-6 MaxForce™ Shaped Charges 5-1 Maxim™ Shaped Charges 5-5 Mirage® Shaped Charges 5-3 Slickline Service Equipment and Services 7-1 Slickline Skid Units and Trucks 7-14 Special Applications 5-139 Coiled Tubing Conveyed Perforating 5-142 DrillGun™ Perforating Systems 5-143 Modular Gun System 5-139 Select Fire™ Systems 5-141 Setting Tools for the Auto-Release Gun Hanger 5-145 Subsurface Service Tools 7-2 Auxiliary Tools For Use with Slickline Toolstring 7-6 Expandable Wirefinder 7-7 Otis® Go-Devil 7-7 Otis M Magnetic Fishing Tool 7-6 Otis P Wireline Grab 7-7 Otis Tubing Broach 7-6 Otis G Fishing Socket 7-7 Otis Gauge Cutter and Swaging Tools 7-6 Otis Impression Tool 7-6 Otis Quick Connect Toolstring Connection 7-5 Plugs For Wells Without Landing Nipples 7-10 Monolock® Plug 7-10 Positioning Tools 7-12 Otis BO Selective Positioning Tools 7-12 Pulling Tools 7-9 External Fishing Necks 7-9 Internal Fishing Necks 7-9 Running Tools 7-8 Otis MR Running Tools 7-8 Otis RXN Running Tools 7-8 Otis SAFETYSET® Running Tools 7-8 Otis UP Running Tool 7-8 Otis X® and R® Running Tools 7-8 Slickline Detent Jars 7-4 Slickline Service Tools 7-2 Slickline Toolstring 7-2 Otis Accelerators 7-3 Otis B Blind Box 7-3 Otis Jars 7-3 Otis Knuckle Joints 7-3 Otis Rope Sockets 7-2 Otis Stems 7-2 Wireline Toolstring 7-2 Test Tools 7-11 Otis Non-Selective Test Tools 7-11 Tubing Perforators and Bailers 7-13 Surface Service Equipment 7-15

Index

T Through Casing Acoustic Services 4-12 FWS™ Full Wave Sonic Tool 4-14 HFWS™ Hostile Full Wave Sonic Tool 4-16 WaveSonic Tool 4-12

10-5

10-6

Index

Wireline and Perforating Service_Hallibuton

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