Wireline Services Catalog

Wireline Services CatalogThe services in this catalog are grouped by their applications. Each service is briefly described and its measurement and mechanical specifications listed. For more information, contact your Schlumberger representative.

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*Mark of Schlumberger © 2015 Schlumberger. All rights reserved. Other company, product, and service names are the properties of their respective owners.

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Schlumberger 3750 Briarpark Drive Houston, Texas 77042

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Copyright © 2015 Schlumberger. All rights reserved.

No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of the publisher. While the information presented herein is believed to be accurate, it is provided “as is” without express or implied warranty. Specifications are current at the time of printing. Temperature ratings are for the internal tool components.

14-FE-0074

An asterisk (*) is used throughout this document to denote a mark of Schlumberger. Other company, product, and service names are the properties of their respective owners. Cover photograph of the Discoverer Enterprise courtesy of Transocean.

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Wireline Services Catalog ■ Contents iii

ContentsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Health, Safety, and the Environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Health, Safety, and the Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

HSE Management System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7HSE Policy Statement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Surface Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Surface acquisition and imaging systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Data delivery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

InterACT* global connectivity, collaboration, and information service . . . . . . . . . . . . 12Data formats . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Telemetry systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Field units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Optimum Service Land Carrier . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Universal Payload Medium Service Land Carrier. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1418,000- and 26,000-lbf offshore units. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Wireline high-tension conveyance systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Integrated wireline conveyance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Well Conveyance Planner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Conveyance in the hostile conditions of high pressure and high temperature . . . . 17Strengthening cable capabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Improving surface equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Enhancing telemetry and downhole tool power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

TuffLINE* torque-balanced composite wireline cable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19UltraTRAC* and UltraTRAC Mono* all-terrain wireline tractors . . . . . . . . . . . . . . . . . . . . . . . . . 20TuffTRAC* and TuffTRAC Mono* cased hole services tractors . . . . . . . . . . . . . . . . . . . . . . . . . . . 22MaxTRAC* downhole wireline tractor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Drillpipe-assisted wireline deployment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

LWF* logging-while-fishing service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24TLC* tough logging conditions system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Depth measurement. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Logging Platforms and Suites . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Scanner Family* rock and fluid characterization services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Openhole Scanner services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29Cased hole Scanner services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Platform Express* integrated wireline logging tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34ThruBit* through-the-bit logging services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36Multi Express* slim multiconveyance formation evaluation platform. . . . . . . . . . . . . . . . . . . . 39Xtreme* HPHT well logging platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42SlimXtreme* slimhole HPHT well logging platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45IPL* integrated porosity lithology service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47ABC* analysis behind casing services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49Carbonate Advisor* petrophysics and productivity analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52DecisionXpress* petrophysical evaluation system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53DeepLook-EM* crosswell electromagnetic imaging service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54PS Platform* production services platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

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Dielectric Dispersion Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Dielectric Scanner* multifrequency dielectric dispersion service. . . . . . . . . . . . . . . . . . . . . . . . 61

Resistivity Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63Rt Scanner* triaxial induction service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65Induction tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

AIT* array induction imager tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67Platform Express array induction imager tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67Hostile Environment Induction Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67SlimXtreme Array Induction Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Laterolog tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69ARI* azimuthal resistivity imager. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69HRLA* high-resolution laterolog array tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69High-Resolution Azimuthal Laterolog Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Microresistivity tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71MicroSFL* spherically focused resistivity tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Micro-Cylindrically Focused Log. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Powered Caliper Device with microlog tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

CHFR-Plus* and CHFR-Slim* cased hole formation resistivity tools . . . . . . . . . . . . . . . . . . . . 73

Nuclear Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75Gamma ray tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77Spectral gamma ray tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

NGS* natural gamma ray spectrometry tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79Hostile Environment Natural Gamma Ray Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Litho Scanner* high-definition spectroscopy service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81ECS* elemental capture spectroscopy sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83Neutron porosity tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

CNL* compensated neutron logging tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85Highly Integrated Gamma Ray Neutron Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85SlimXtreme Compensated Neutron Porosity Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85CHFP* cased hole formation porosity service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

Array Porosity Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87APS* accelerator porosity sonde. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87Hostile Environment Accelerator Porosity Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

RSTPro* reservoir saturation tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89Density tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Three-Detector Lithology Density. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91Litho-Density* Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92Hostile Environment Lithology Density Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92SlimXtreme Litho-Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Nuclear Magnetic Resonance Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95MR Scanner* expert magnetic resonance service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97CMR-Plus* combinable magnetic resonance tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Acoustic Logging. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101Sonic Scanner* acoustic scanning platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103ThruBit Dipole* through-the-bit acoustic service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105DSI* dipole shear sonic imager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107Monopole acoustic tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

Digital Sonic Logging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109SlimXtreme Sonic Logging Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

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Dipmeter and Imaging Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111Quanta Geo* photorealistic reservoir geology service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113FMI-HD* high-definition formation microimager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116FMI* fullbore formation microimager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118UBI* ultrasonic borehole imager. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120OBMI* oil-base microimager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

Drilling and Directional Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125GPIT general purpose inclinometry tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

Seismic Imaging Tools and Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129Q-Borehole* integrated borehole seismic system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

VSI* versatile seismic imager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131SWINGS* seismic navigation and positioning system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133TRISOR* acoustic source control element . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134Q-Borehole integrated borehole seismic system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

DeepLook-CS* crosswell seismic imaging service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136CSI* combinable seismic imager. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138Q-Borehole Explorer* high-output, wide-bandwidth truck vibrator . . . . . . . . . . . . . . . . . . . . . . . . 140

Other land seismic sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140Marine seismic sources. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Formation Testing and Sampling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143MDT Forte* and MDT Forte-HT* rugged and high-temperature modular formation dynamics testers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145MDT* modular formation dynamics tester. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147Saturn* 3D radial probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149Quicksilver Probe* focused fluid extraction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151InSitu Fluid Analyzer* real-time downhole fluid analysis system . . . . . . . . . . . . . . . . . . . . . . . . 153

InSitu Composition* and InSitu CO2* sensors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu GOR* sensor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu Color* sensor. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu Density* sensor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu Viscosity* sensor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu Fluorescence* sensor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu pH* sensor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153InSitu Resistivity* sensor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154Pressure and temperature sensors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154Fluid profiling characterization of reservoir fluid properties variation . . . . . . . . . . . 154

InSitu Pro* real-time quality control and interpretation software . . . . . . . . . . . . . . . . . . . . . . . 156Advanced MDT tester modules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

Dual-Packer Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157Dual-Probe Module. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159Flow-Control Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160Pumpout Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161LFA* live fluid analyzer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162CFA* composition fluid analyzer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163

MDT tester low-shock sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164MDT tester Multisample Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165


PressureXpress-HT* high-temperature reservoir pressure service . . . . . . . . . . . . . . . . . . . . . . . 166PressureXpress* reservoir pressure while logging service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168SRFT* slimhole repeat formation tester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170CHDT* cased hole dynamics tester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172XL-Rock* large-volume rotary sidewall coring service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174MSCT* mechanical sidewall coring tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176CST* chronological sample taker . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177

Well Integrity Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179Isolation Scanner* cement evaluation service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181Cement bond logging tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183

SlimXtreme Sonic Logging Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183Cement bond log from Digital Sonic Logging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183Cement bond log from Hostile Environment Sonic Logging Tool . . . . . . . . . . . . . . . . . . 184Slim Cement Mapping Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184Memory Slim Cement Bond Logging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184USI* ultrasonic imager. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185

EM Pipe Scanner* electromagnetic casing inspection tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187Corrosion monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189

UCI* ultrasonic casing imager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189PS Platform Multifinger Imaging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191

Production Logging Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193Flow Scanner* horizontal and deviated well production logging system. . . . . . . . . . . . . . . . . 195PS Platform production services platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197RSTPro reservoir saturation tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200

WFL* water flow log from the RSTPro reservoir saturation tool . . . . . . . . . . . . . . . . . . . 200RSTPro tool with silica activation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201

CPLT* combinable production logging tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 202Combinable Gamma Ray Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203Phase Velocity Sonde. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204FloView* holdup measurement tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206Multiple-Isotope Spectroscopy Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207

Perforating Services and Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209SPAN Rock* stressed rock perforating analysis and Schlumberger premium charges. . . 211

PowerJet Nova* extradeep penetrating shaped charges . . . . . . . . . . . . . . . . . . . . . . . . . . . 211PowerJet Omega* deep penetrating perforating shaped charge . . . . . . . . . . . . . . . . . . . 212PFrac Nova* perforating charge for optimizing stimulation treatment . . . . . . . . . . . . 212PowerFlow* slug-free big hole shaped charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

Perforating explosives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213Gun systems and charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214

Capsule gun systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214Enerjet* expendable strip gun system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214Pivot Gun* through-tubing perforating gun system . . . . . . . . . . . . . . . . . . . . . . . . . . 214PowerSpiral* spiral-phased capsule perforating system . . . . . . . . . . . . . . . . . . . . . 215

Hollow carrier perforating gun systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216HSD* high shot density perforating gun system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216Fractal* multistage stimulation perforating system. . . . . . . . . . . . . . . . . . . . . . . . . . 216Frac Gun multistage fracture stimulation perforating gun system . . . . . . . . . . 216

vi Wireline Services Catalog


Contents vii

PURE* clean perforations system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219Detonation systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

Secure2* RF-safe electronic detonator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221S.A.F.E.* slapper-actuated firing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

ASFS* addressable-switch firing system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222Perforating accessories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223

Casing collar locator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223UPCT* universal perforating and correlation tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224PGGT* powered gun gamma tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225WPP* wireline perforating platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226Wireline Oriented Perforating Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228

Through-tubing perforating positioning devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229Magnetic Positioning Device. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229Spring Positioning Device. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229

Wireline Perforating Anchor Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230Cutters and colliding tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231

PowerCutter* precision tubular cutter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231Punchers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232

Well Intervention Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 233ReSOLVE* instrumented wireline intervention service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235

High-force linear actuator tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235Selective universal shifting tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236Nonexplosive setting tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236Milling tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236

Casing Packer Setting Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238Gauge ring and junk basket . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239PosiSet* mechanical plugback tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 240

Auxiliary Measurements and Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 243Caliper log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 245Auxiliary Compression Tension Sub. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246Environmental Measurement Sonde . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 247FPIT* free-point indicator tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249CERT* correlated electromagnetic retrieval tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250


Introduction


During the early 1900s Conrad and Marcel Schlumberger experimented with surface electrical measurements as a way of defining the Earth’s subsurface structure. In 1927 they performed their experiment in an oil well in France for the Pechelbronn Oil Company.

The result was the first electrical log, and it showed conclusively that geo-logic formations penetrated by the drill could be identified by electrical mea-surements. The electric log gave eyes to the oil finders, who previously could rely only on drill cuttings and core samples.

In the years since that historic event in France, Schlumberger has become the world’s leading supplier of technol-ogy, integrated project management, and information solutions to custom-ers working in the oil and gas industry worldwide. Employing approximately 123,000 people representing over 140 nationalities and working in more than 85 countries, Schlumberger pro-vides the industry’s widest range of products and services from exploration through production.

Schlumberger is organized as an integrated oilfield services company in GeoMarket* regions that provide customers with a single point of contact at the local level for field operations and bring together geographically focused teams to meet local needs and deliver customized solutions. Working together

with the company’s 15 product lines, the GeoMarket regions provide a powerful conduit through which information and know-how flow to the customers, and through which Schlumberger engineers and geoscientists maximize technological synergies over the entire life of the field.

The importance of the timely flow of information is especially true in the oil and gas industry, where critical decisions hinge upon the availability of data. Data acquired by Schlumberger is made available to operators in real time by using the Internet and satellite communication networks. Decisions made on the basis of these data can be implemented quickly and efficiently.

As wells proliferate in deeper water depths with attendant high pressures and high temperatures, the operating envelope of logging tools is also being expanded to provide the same reliable performance and high-quality data as in conventional wells. Similarly, well geometries are becoming increasingly complex. To meet this challenge, most logging tools in use today can be conveyed on drillpipe, coiled tubing, or wireline tractors to address a wide range of well conditions.

Oil fields around the world are aging, driving an increasing need to evaluate old wells. Schlumberger provides state-of-the-art formation evaluation services

in cased wells, including measurements that until recently were available only in openhole environments. On a larger scale, efficient decision making for full-field enhanced oil recovery (EOR) projects progresses from measurements for determining feasibility to pilot projects for understanding the complex interaction of injected agents with existing reservoir fluids in the ever-changing downhole environment.

Production logging, cement and corrosion evaluation, and nuclear measurements made after casing has been set are increasingly used to identify problems and monitor well performance. The comprehensive Schlumberger line of production services is engineered for safety, reliability, and performance. New perforation systems have also been developed with a focus on maximizing production by engineering shaped charges to shoot deeper in stressed rock at downhole pressures and temperatures.

The services in this catalog are grouped according to their applications. A brief description of each service and its measurement and mechanical specifications are included. For more information on designing a logging program to meet your specific needs, contact your Schlumberger representative.

Wireline Services Catalog ■ Introduction 3

Introduction


Health, Safety, and the Environment


Schlumberger has a long-standing HSE commitment to the highest standards for the health and safety of our employ-ees, customers, and contractors as well as to the protection of the environment in the communities in which we live and work.

HSE Management System The Schlumberger HSE Management System defines the principles by which we conduct our operations worldwide with regards to health, safety, and the environment.

Management communicates the HSE philosophy to all employees, cus-tomers, contractors, and third parties associated with our business, and each Schlumberger organization must pro-vide positive evidence of conformance to the system.

The HSE Management System model comprises eight interrelated components: ■ commitment and leadership

and accountability ■ policies and objectives ■ organization and resources ■ contractor and supplier

management ■ risk management ■ business processes ■ performance monitoring and

improvement ■ audits and reviews.

These are continuously improved by conformance checks■ on day-to-day standards and

procedures (controls) ■ on the management system

(correction) ■ through modifications to

the management system (improvement).

Wireline Services Catalog ■ Health, Safety, and the Environment 7

Health, Safety, and the Environment

Commitment and Leadership and Accountability

Policies and Objectives

Corrections

Improvement

Controls

Organization and Resources

Contractor and Supplier Management

Risk Management

Business Processes

Performance Monitoring and Improvement

Audits and Reviews


8 Wireline Services Catalog

HSE Policy Statement Statement from Paal Kibsgaard, Schlumberger Chief Executive OfficerThe long-term business success of Schlumberger depends on our ability to continually improve the quality of our services and products while protecting people and the environment. Emphasis must be placed on ensuring human health, operational safety, environmental protection, quality enhancement, and community goodwill. This commitment is in the best interests of our customers, our employees and contractors, our stockholders, and the communities in which we live and work.

Schlumberger requires the active commitment to, and accountability for, QHSE from all employees and contractors. Line management has a leadership role in the communication and implementation of, and ensuring compliance with, QHSE policies and standards. We are committed to ■ Protect, and strive for improvement of, the health, safety and security of our people at all times; ■ Eliminate Quality non-conformances and HSE accidents; ■ Meet specified customer requirements and ensure continuous customer satisfaction; ■ Set Quality & HSE performance objectives, measure results, assess and continually improve processes,

services and product quality, through the use of an effective management system; ■ Plan for, respond to and recover from any emergency, crisis and business disruption; ■ Minimize our impact on the environment through pollution prevention, reduction of natural resource

consumption and emissions, and the reduction and recycling of waste; ■ Apply our technical skills to all HSE aspects in the design and engineering of our services and products; ■ Communicate openly with stakeholders and ensure an understanding of our QHSE policies, standards,

programs and performance. Reward outstanding QHSE performance; ■ Improve our performance on issues relevant to our stakeholders that are of global concern and on

which we can have an impact, and share with them our knowledge of successful QHSE programs and initiatives.

This Policy shall be regularly reviewed to ensure ongoing suitability. The commitments listed are in addition to our basic obligation to comply with Schlumberger standards, as well as all applicable laws and regulations where we operate. This is critical to our business success because it allows us to systematically minimize all losses and adds value for all our stakeholders.

Paal KibsgaardChief Executive Officer Last Update on 14 December 2011


Surface Systems


All Schlumberger new-generation wireline logging units are equipped with the Enhanced Wireline Acquisition Front-End (eWAFE). The eWAFE system’s modular, versatile, and fully redundant architecture improves on the predecessor MAXIS* multitask acquisition and imaging system to enable combining and conveying the latest and most complex array of sensors in the Schlumberger portfolio. Under the full configuration, eight programmable, high-density universal power modules (UPMs) can simultaneously supply several types of power (AC, DC, EMEX,

and three-phase AC) at more than 3 times the output power of the MAXIS system. In the event of a modular unit failure, the field engineer can switch to the built-in backup module with minimum downtime.

The eWAFE system interfaces down-hole tools with the high-end acquisition and data-recording processors of the Modular Configuration MAXIS system (MCM) through MaxWell* integrated field acquisition software. MaxWell soft-ware provides data acquisition and tool control functionality, real-time playback capabilities, wellsite answer solutions

comparable to those from a processing center, and real-time data transmission via satellite or the communications module built into the eWAFE system. In combination with InterACT* global connectivity, collaboration, and infor-mation service, the eWAFE system securely delivers real-time log data from remote sites to support timely deci-sion making concerning the reservoir and well.

Wireline Services Catalog ■ Surface Systems 11

Surface Acquisition and Imaging Systems


Schlumberger recognizes that the data gathered in the field must be transferred to the users as reliably and as quickly as possible. To this end, Schlumberger has a proven global data delivery network that securely, reliably, and efficiently transfers data from remote sites. Data can be transmitted from the wellsite and forwarded via e-mail, facsimile, and File Transfer Protocol (FTP). Schlumberger InterACT global connectivity, collabora-tion, and information service furthers real-time data accessibility from a Web browser. InterACT service supports■ transfer of real-time wireline, drilling,

and completion data■ secure, managed sharing of project

data with third parties and partners■ all project data gathered in one

location, regardless of who produced them.

InterACT global connectivity, collaboration, and information serviceInterACT global connectivity, collabo-ration, and information service is a user-friendly, intuitive system that requires no installation of specialized software. From a connection to either the Internet or a local intranet, data are downloaded or viewed using inter-active, customizable graphics viewers on a PC or conveniently on iPhone® and iPad® mobile digital devices by using InterACT service’s app. Real-time data can be automatically and continu-ously delivered to and viewed on the user’s computer or mobile device.

The wellsite engineer simply uploads graphical or digital data to the InterACT website for remote users to view or analyze in real time. Formats supported include Digital Log Information Standard (DLIS), Log ASCII Standard (LAS), and American Standard Code for Information Interchange (ASCII) for digital data and Picture Description System (PDS), Tagged Image File Format (TIFF), or many other file types for graphical data. The embedded log graphics viewer provides options to view and manipulate wireline data. For example, wireline and drilling data can be viewed concurrently on the same log presentation.

During operations such as reservoir sampling, experts at different loca-tions can collaborate on data viewed or interpreted in real time for immediate decision making on critical issues.

The most difficult part of data exchange is sending data from a remote site. Because local telecommunication systems in some areas can be unreli-able, Schlumberger uses proprietary transfer protocols to ensure robust data transfer. Encrypted data are com-pressed for efficiency, and automatic link recovery is available if telecommu-nications breaks occur. This superior transfer process means that InterACT service can be used even in areas with unsophisticated communication links.

InterACT service uses best-in-class security standards for both hardware and software. All data transfer uses 128-bit Secure Sockets Layer (SSL) encryption. The system meets industry security standards, minimizing the risk of data disclosure. If an intranet-only solution is preferred, Schlumberger can

install and maintain the system in the customer’s office.

The same process used for internal team members easily controls partner access to data. Because the data reside centrally in the system database, there is no need for continual updates and distribution. Partners access specified data at the operator’s discretion.

Data formatsMaxWell integrated field acquisition software creates and records three industry formats: ■ DLIS—Created by Schlumberger

initially as the Log Information Standard (LIS), DLIS is the industry standard today for all well acquisition data.

■ LAS and ASCII—This reduced dataset is regularly used for interpretation conducted on standard PCs and is compatible with customer-proprietary and commercially available software.

■ Portable document format (PDF)—This file format for electronic images is used for graphical display, manipulation, and printing of data curves and imaging logs.

Other limited formats can be gener-ated upon request.


Data Delivery


Telemetry systemsThe telemetry system provides the interface through which data are delivered from the downhole toolstring to the surface data acquisition and processing system.

High-rate telemetry system—The Enhanced Digital Telemetry System (EDTS) uses an enhanced fast tool bus (EFTB) in downhole tools to provide data rates up to 2 Mbps for the uplink rate. EDTS and EFTB Versions 2.0 double the data transmission bandwidth up to 4 Mbps and are backward compatible with all existing EDTS and EFTB systems. This represents a 40% increase in bandwidth compared with the first-generation Cable Telemetry System (CTS). Along with the enhanced wireline hepta

cable (AWG 18 and 16 conductors and new-generation polymer), EDTS 2.0 and EFTB 2.0 use state-of-the-art error detection and correction protocols to ensure highly reliable high-rate data transmission with the lowest error rate on cables exceeding 40,000 ft [12,200 m] in length.

Medium-rate telemetry system—The Monocable Telemetry System (MTS) has been specially developed for mono cable or coaxial cable operations in cased hole applications. MTS is a single-channel quadrature amplitude modulation (QAM) link with data speed rates from 10 to 100 Kbps for the uplink rate. MTS comes as a separate downhole cartridge or is incorporated in the hardware of a downhole tool using MTS.

Low-rate telemetry system—The Low-Bandwidth Telemetry System (LTS) is the latest addition to extend bandwidth coverage to very low data rates for certain services. LTS telemetry rates range from a few hundred bits per second up to 10 Kbps. LTS operates in parallel and transparently to the main EDTS and MTS telemetry systems, and the related downhole hardware is incorporated in the downhole tool.

Surface Systems 13

Specifications

EDTC-H Telemetry Cartridge

Temperature rating 400 degF [204 degC]

Pressure rating 20,000 psi [138 MPa] 30,000 psi [207 MPa]

Outside diameter 3.625 in [9.21 cm]


Optimum Service Land CarrierThe Optimum Service Land Carrier (OSLC) is used to perform open- or cased hole logging operations. The design emphasis for this integrated, full-service logging carrier minimizes the overall size of the truck but still provides full cable capacity by allowing the use of existing large-capacity winch drum reels (WDRs). The resulting unit efficiently performs full- service operations from an inter-mediate-size vehicle. The OSLC also has excellent off-road capabilities through its 6×4 drive configuration. The cabin layout has both the winch operator and engineer facing the rig.

The three versions of the OSLC are equipped with the fully redundant eWAFE acquisition system and can carry a maximum of 28,000 ft [8,500 m] of 7-46 standard cable or 26,500 ft [8,080 m] of high-power, high-tension hepta cable on the WDR-42 drum.■ OSLC-G is built on the Renault

Trucks 6×4 K 380 chassis meeting Euro 5 emissions regulations in Europe or Euro 3 outside Europe and North America.

■ OSLC-H is the equivalent North American truck, compliant with US EPA 2007 and recent 2010 emissions regulations. It is built on the Kenworth 6×4 T800 chassis.

■ OSLC-F is similar to the OSLC-G. Built on the Renault 6×6 K 380 chassis and equipped with Euro 3 engines, its main application is offroad desert operations.

Universal Payload Medium Service Land CarrierThe latest generation Medium Service Land Carrier is the Universal Payload (UPL), which features an eWAFE-equipped (upgradable to fully redun-dant eWAFE configuration) medium service logging cabin that is integrated with various chassis by employing specifically designed subframes. This modular design makes it easy to export the UPL to meet emissions regulations for different locations. The cabin is fitted onsite on a locally available and qualified chassis, which avoids delays from lengthy customs clearance and emissions compliance determination for a fully integrated vehicle. North American integration is conducted in the USA, Southeast Asia (right-hand drive) integration is in Australia, and all others are in France. The UPL replaces the MAXIS Express* Medium Service Land Carrier (MSLC) with similar specifications: 4×4 or 4×2 chassis, 16,000 ft [4,880 m] of stan-dard 7-46 logging cable on the WDR-56 drum, and suitable for most openhole and cased hole operations.

18,000- and 26,000-lbf offshore unitsSchlumberger heavy-duty modular off-shore skid units are used to deploy standard high-strength cable and TuffLINE* 18000 and 26000 torque-balanced composite wireline cables. The OSU-PA and OSU-PB units using TuffLINE 18000 cable can provide instantaneous pull of up to 18,000 lbf [80,070 N] for stick prevention and mitigation without a capstan. If oper-ating conditions will result in normal logging tension exceeding 13,000 lbf [57,800 N], the OSU-PA or OSU-PB can be interfaced with a capstan to pro-vide up to 21,500-lbf [95,640-N] pull capacity with standard high-strength cable. The OSU-N unit interfaced with the 26,000-lbf [115,660-N] capstan and TuffLINE 26000 cable can provide 26,000-lbf pull capacity with more than 43,000 ft [13,100 m] of cable capacity on the drum.

The OSU-PB and the MONU-B are CE-marked electrohydraulic units certified for Zone 2 operations.


Field Units


Specifications

OSU-PA and OSU-PB Offshore Units

MONU-B Offshore Unit OSU-N Offshore Unit

Modular components Power pack module (POSU):• Diesel (OSU-PA)• Electrohydraulic (OSU-PB)

Logging module (COSU):• High-tension cabin

Winch module (WOSU):• High-tension WOSU

with WDR-59 drum

Power pack module (EHPS):• Electrohydraulic

Logging module (ONCC): • Offshore NORSOK-compliant cabin

Winch module (WDDS or WOSU):• Zone-rated WDDS with

WDR-59 drum • High-tension WOSU

with WDR-59 drum

Power pack module (POSU): • Redundant, dual electrohydraulic,

base frame mounted

Logging module (COSU): • Ultradeepwater cabin• High-tension cabin

Winch module (WOSU): • Ultradeepwater WOSU

with WDR-70 drum• High-tension WOSU

with WDR-59 drum

Acquisition system Full-configuration dual eWAFE system

Full-configuration dual eWAFE system


Drum capacity WDR-59 with TuffLINE 18000 cable: 33,000 ft [10,060 m]

WDR-59 with TuffLINE 18000 cable: 33,000 ft [10,060 m]



Pull capacity without capstan WOSU: 18,000 lbf [80,070 N] WDDS: 11,400 lbf [50,710 N] WOSU: 18,000 lbf [80,070 N]

18,000 lbf [80,070 N]

Capstan pull capability Zone-rated, deck-mounted dual drum (WDDC-BB): 24,000 lbf [106,760 N]

ATEX zone-rated, CE-marked, deck- or derrick-mounted dual drum (ZPPC): 24,000 lbf [106,760 N]


Zone-rated, deck-mounted dual drum (WDDC-BC): 26,000 lbf [115,660 N]

Special applications Single or modular deployment DNV 2.7-1, 2.7-2, 2-22 OSU-PB: CE and ATEX Zone 2

Modular deployment WOSU: DNV 2.7-1, 2.7-2, 2-22 NORSOK and CE Zone 2

Single deployment DNV 2.7-1 Quick-swap winch drum capability

Surface Systems 15



Integrated wireline conveyanceFrom conventional well environments to ultradeep and highly deviated wells and where increased pulling power is required, Schlumberger provides efficient and reliable wireline conveyance. The deployment of TuffLINE torque-balanced composite wireline cable on an integrated high-tension conveyance system expands wireline data acquisition capabilities with unprecedented improvements in safety, efficiency, reliability, and sticking avoidance, especially for high-tension operations. The integration of high-strength cable, heavy-duty modular logging units, an optional capstan package providing complete

tension relief, WellSKATE* low-friction well conveyance accessories, and the SureLOC* electronically controlled cable release device (ECRD) as designed using the Well Conveyance Planner means that well trajectories and conditions that were not previously wireline accessible no longer have to automatically resort to alternative methods of conveyance. As necessary, wireline deployment can be augmented with the use of wireline tractors.

Well Conveyance PlannerReliable conveyance for both routine and high-tension operations begins with calculation of the pulling capabilities and associated operating risk by the Well Conveyance Planner.

This comprehensive planning tool recommends the optimal conveyance system while identifying system components that exceed specifications. The user can modify operational conditions and equipment and also specify customer requirements for the planner to recompute conveyance capabilities. To avoid the operational limitations of mechanical weakpoints and previous-generation ECRDs, a SureLOC cable release device is used. The design can also incorporate a wide range of WellSKATE low-friction conveyance accessories to significantly decrease the risk of differential sticking by rolling instead of sliding to reduce friction coefficients and by keeping the toolstring away from the borehole wall.

Wireline High-Tension Conveyance Systems

Sheave hanger

Sheave wheel

Antisticking accessoriesAntisticking accessories

Offshore unit

SureLOC cable release deviceSureLOC cable release device

Weakpoint

TuffLINE cable Winch drum

Optional capstan

Tieback sling

Capstan-free pull capability: 18,000 lbfPull capability with capstan: TuffLINE 26000 cable: 26,000 lbf

The integrated wireline high-tension conveyance system provides efficient and reliable deployment.


Surface Systems 17

Conveyance in the hostile conditions of high pressure and high temperatureWireline formation evaluation technol-ogy and its conveyance are put to the test when logging deep wells. As wells get deeper, the pressure and tempera-ture rise, which increases the risks asso-ciated with deployment and operation. Wells with static bottomhole tempera-tures greater than 302 degF [150 degC], bottomhole pressures higher than 20,000 psi [138 MPa], or both conditions are generally regarded as high pressure, high temperature (HPHT). However, despite the increased risks and costs of HPHT operations, the number of deep and ultradeep wells drilled continues to grow worldwide. The challenges that the depths, pressures, and tempera-tures of these wells present to forma-tion evaluation are met by the following significant technological developments in conveyance.

Strengthening cable capabilitiesWhen ultradeep wells are logged, their pressure and temperature are not the only concerns: extreme depths limit conventional high-strength wireline conveyance because of the high surface tension that results from increased drag and the weight of the logging cable itself. Deploying logging tools on drillpipe using the TLC* tough logging conditions system can overcome these limitations, but TLC operations take more time and cost more because of the reduced efficiency associated with tripping drillpipe. To solve the ultradeep well dilemma, TuffLINE 18000 and 26000 composite cables were developed as the central element of the integrated wireline high-tension conveyance system. From the cable through the surface equipment, the system provides a complete conveyance solution for every possible extreme well

environment: HPHT, ultradeepwater, extended-reach, and complex trajectory wells. The efficiency gains resulting from wireline logging of ultradeep wells by using the integrated conveyance system translate to significant cost savings for the operator.

TuffLINE torque-balanced compos-ite wireline cable employs the break-through technology of polymer-locked armors to effectively overcome the fundamental limitations of conven-tional armored cables. The result is not just high-strength capability, but also unprecedented improvements in safety. TuffLINE 26000 cable is the industry’s highest-strength cable, with a safe working load (SWL) of 26,000 lbf [115,650 N] and an ends-free break-ing strength in excess of 40,000 lbf [178,000 N].

Polymer locking of the inner and outer armors balances TuffLINE 18000 cable’s torque in a consistent low state. With only negligible torque buildup possible, birdcaging and premature cable breakage are prevented. TuffLINE 18000 cable also incorporates a unique polymer-reinforced crush-resistant core.

Improving surface equipmentImproved surface equipment is another critical component of the integrated conveyance system for deploying TuffLINE 18000 and 26000 cables at high tension and in HPHT conditions. Operations with continuous logging tensions of 13,000 lbf [57,800 N] or lower can deploy TuffLINE cable using a Schlumberger modular heavy-duty offshore unit without involving a capstan, which significantly reduces risk. When logging tension exceeds 13,000 lbf or maximum pull tension in excess of 18,000 lbf [80,070 N] is required, an optional dual-drum capstan can be employed. The dual-drum capstan is a powered multisheave conveyance system that is placed between the well and the logging unit to decrease the cable tension below the cable-crushing tension of 8,000 lbf [35,580 N] before the cable

SpecificationsSureLOC Cable Release Device

Safe working load SureLOC 8000: 8,000 lbf [35,580 N] SureLOC 12000: 12,000 lbf [53,380 N]

Max. tool-release head tension At surface: 1,000 lbf [4,450 N]

Temperature rating SureLOC 8000: 400 degF [204 degC] SureLOC 12000: 500 degF [260 degC]

Pressure rating SureLOC 8000: 20,000 psi [138 MPa] SureLOC 12000: 30,000 psi [207 MPa]

Special applications SureLOC 12000: MP35N® H₂S-resistant alloy

Reservoir pressure, psi

Reservoirtemperature,

degF

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

650

550

450

350

250

150Conventional

High temperatureHigh pressure

Global HPHT conditions pose challenges for wireline deployment and operations.



is spooled onto the storage drum. Full integration of capstan control with the storage drum provides a safer, seamless operation and enables the winch operator to focus on the well conditions. The specially designed high-tension dual-drum system conveying TuffLINE 26000 cable can safely sustain 26,000-lbf tension in the well at conveyance speeds to 15,000 ft/h [4,570 m/h].

Enhancing telemetry and downhole tool powerThe extralong cables required for ultradeep well logging must be capa-ble of transmitting sufficient power downhole to run high-power, complex toolstrings while enabling seamless transmission of increasingly larger

amounts of data uphole to the surface. Because of physical limitations, data transmission telemetry systems have proved to be unreliable at extreme well depths. When long cables are run in deep wells, the amount of power and telemetry bandwidth available at the tool end is limited by the cable conduc-tor line resistance. Increasing the well temperature raises the line resistance and adversely affects cable transmission characteristics, further limiting power and telemetry transmission.

Unlike standard high-strength cables, TuffLINE 18000 cable has 18 AWG gauge conductors and TuffLINE 26000 cable has industry-leading 16 AWG gauge conductors enabling reliable conveyance of tool combinations longer than 175 ft [53 m] and at 4,000-lbf [17,790-N] weight in well depths exceeding

40,000 ft [12,190 m]. Combining tools reduces the number of descents in the well, saving an average of 12 h or more per trip on a deepwater rig.

Complementing TuffLINE cable’s high-capacity electrical power and telemetry capabilities, the OSU-PA and OSU-PB surface units are Det Norske Veritas (DNV) 2.22 certified to pull to 18,000 lbf. The OSU-N unit com-bined with the high-tension dual-drum capstan system can store 43,000 ft [13,100 m] of TuffLINE 26000 cable and sustain 26,000-lbf tension. All these high-tension heavy-duty units are equipped with the highly integrated Enhanced Wireline Acquisition Front-End (eWAFE) acquisition system to pro-vide full redundancy, increased power, and enhanced telemetry for deploying large, seamless tool combinations in ultradeep wells.

Specifications

OSU-PA and OSU-PB Offshore Units

MONU-B Offshore Unit OSU-N Offshore Unit

Modular components Power pack module (POSU):• Diesel (OSU-PA)• Electrohydraulic (OSU-PB)

Logging module (COSU):• High-tension cabin

Winch module (WOSU):• High-tension WOSU

with WDR-59 drum

Power pack module (EHPS):• Electrohydraulic

Logging module (ONCC): • Offshore NORSOK-compliant cabin

Winch module (WDDS or WOSU):• Zone-rated WDDS with

WDR-59 drum • High-tension WOSU

with WDR-59 drum

Power pack module (POSU): • Redundant, dual electrohydraulic,

base frame mounted

Logging module (COSU): • Ultradeepwater cabin• High-tension cabin

Winch module (WOSU): • Ultradeepwater WOSU

with WDR-70 drum• High-tension WOSU

with WDR-59 drum

Acquisition system Full-configuration dual eWAFE system



Drum capacity WDR-59 with TuffLINE 18000 cable: 33,000 ft [10,060 m]




Pull capacity without capstan WOSU: 18,000 lbf [80,070 N] WDDS: 11,400 lbf [50,710 N] WOSU: 18,000 lbf [80,070 N]

18,000 lbf [80,070 N]

Capstan pull capability Zone-rated, deck-mounted dual drum (WDDC-BB): 24,000 lbf [106,760 N]



Zone-rated, deck-mounted dual drum (WDDC-BC): 26,000 lbf [115,660 N]

Special applications Single or modular deployment DNV 2.7-1, 2.7-2, 2-22 OSU-PB: CE and ATEX Zone 2

Modular deployment WOSU: DNV 2.7-1, 2.7-2, 2-22 NORSOK and CE Zone 2

Single deployment DNV 2.7-1 Quick-swap winch drum capability


Surface Systems 19

With high-strength capability, cable conveyance remains the most cost-effective method for deploying tools in and out of wells. For increasing well depths, trajectory complexity, and toolstring weight, Schlumberger has developed TuffLINE 18000 and 26000 ultrastrength wireline cables for operations with up to 18,000 lbf [80,070-N] and 26,000-lbf [115,650-N] tension, respectively. TuffLINE 18000 and 26000 composite cables employ the breakthrough technology of polymer-locked armors to overcome the fundamental limitations of current armored cables. Polymer locking of both the inner and outer armors means that the cable is torque balanced, remaining in a consistent state of low torque to prevent birdcaging and premature cable breakage. Polymer locking of the armors prevents rotation to effectively maintain TuffLINE

cable in a permanent ends-fixed situation, which raises the ends-free breaking strength safety margins to an unprecedented 9,000 lbf [40,000 N] for TuffLINE 18000 cable and 10,000 lbf [44,450 N] for TuffLINE 26000 cable above the safe working load.

The multilayered core of TuffLINE 18000 cable is crushproof. Cold flow and the permanent deformation it causes are further prevented by the polymer locking of the armors. Spooling tensions to 13,000 lbf [57,800 N] and instantaneous pull to 18,000 lbf are possible for TuffLINE 18000 cable without requiring use of a tension-relief capstan or having to resort to time-consuming pipe-conveyed opera-tions. TuffLINE 26000 cable can be spooled at any tension up to 26,000 lbf because it is deployed with a capstan.

Incorporation of 18 AWG gauge connectors in TuffLINE 18000 cable and AWG 16 gauge connectors in TuffLINE 26000 cable enables the reliable conveyance of significantly larger, seamless tool combinations in deeper wells.

Applications■ Deepwater and ultradeepwater

wells■ Extended-reach and complex

trajectory wells■ Deepwater wells with rig-up

constraints for capstan operations■ Reservoir sampling and pressure

measurement involving long station times with long and heavy toolstrings

TuffLINE Torque-Balanced Composite Wireline Cable

SpecificationsTuffLINE 18000 Cable TuffLINE 26000 Cable

Ends-fixed breaking strength 28,000 lbf [124,550 N] >40,000 lbf [>178,000 N]

Ends-free breaking strength 27,000 lbf [120,100 N] >36,000 lbf [>160,150 N]

Safe working load 18,000 lbf [80,070 N] 26,000 lbf [115,650 N]

Temperature rating 1 h: 465 degF [241 degC] 24 h: 240 degF [232 degC]

1 h: 465 degF [241 degC] 24 h: 240 degF [232 degC]

Cable OD 0.5 in [1.27 cm] 0.535 in [1.36 cm]

Cable weight In air: 416 lbm/1,000 ft [189 kg/300 m] In freshwater: 331 lbm/1,000 ft [150 kg/300 m]

In air: 524 lbm/1,000 ft [234 kg/300 m] In freshwater: 425 lbm/1,000 ft [190 kg/300 m]

Max. (rms) voltage, V Per helical conductor: 800 Center conductor: 1,250

Per helical conductor: 780 Center conductor: 1,235

Max. current per conductor, A 1.61 2.6



Delivering the farthest reach in the industry, the modular UltraTRAC* all-terrain wireline tractor provides the highest tractor force available in combi-nation with reverse tractoring capabil-ity, dynamic suspension, and traction control. The UltraTRAC Mono* tractor system adds logging-while-tractoring functionality. Although specifically engineered for openhole operations, the UltraTRAC tractor performs with the same reliability in cased hole envi-ronments, making it the ideal tractor for conveying most wireline openhole and cased hole services, especially for deployment on TuffLINE 18000 and 26000 torque-balanced composite wire-line cables in extended-reach wells and for heavy payloads.

The traction force applied by the bidirectional, high-torque UltraTRAC tractor is precisely controlled from the surface. Sensors incorporated in the UltraTRAC tractor enable the engineer to monitor tractor response and the progress of downhole operations as the automatic radial force regulation and dynamic suspension systems continu-ously configure the tractor in real time for optimal performance.

In addition to versatility in the number and configuration of the drive sections, a tandem sub can be added to increase functionality by enabling independent surface control of the drive above the tandem sub from those below. The drive section arms extend variably and independently to span hole diameters up to 15 in [38 cm] and are

fitted with wheels from a wide range of diameters and proprietary designs optimized for the well geometry and borehole conditions. Engineered to withstand the impact of perforating gun detonation as well as the vibration generated in rugose boreholes, the UltraTRAC tractor has low sensitivity to well conditions.

The UltraTRAC tractor is a CE certi-fied tool that meets the Low Voltage, Machinery, and Pressure Equipment Directives of the European Union.

The Tractor Planner app for iPad devices can be used to identify UltraTRAC tractor candidates for specific conveyance situations.

ApplicationsHigh-force extended-reach tractor conveyance:■ Openhole formation evaluation■ Openhole formation testing■ Borehole imaging services■ Perforating■ Cement and corrosion evaluation■ ReSOLVE* instrumented wireline

intervention service– Nonexplosive plug setting– High-force axial shifting– Selective shifting with a universal

shifting tool (UST)– Milling

■ ABC* analysis behind casing services■ Production logging

UltraTRAC Tractor Configurations

4 drive

4-drivetandem

6-drivetandem

8-drivetandem

2 drive

3 drive

UltraTRAC and UltraTRAC Mono All-Terrain Wireline Tractors


Mechanical SpecificationsUltraTRAC Tractor UltraTRAC Mono Tractor

Output Openhole logging Cased hole perforating, logging, intervention

Openhole logging while tractoring Cased hole perforating, logging while tractoring, intervention

Maximum speed† 3,200 ft/h [975 m/h] 2,400 ft/h [730 m/h]

Temperature rating 350 degF [177 degC] 302 degF [150 degC]


Hole size—min. 3.6 in [9.1 cm] 3.6 in [9.1 cm]

Hole size—max. 15 in [38.1 cm] 15 in [38.1 cm]

Outside diameter† 3.375 in [8.57 cm] 3.375 in [8.57 cm]

Length‡ Drive sections: 2 to 8 Min. (2 drives): 15.35 ft [4.68 m] 8 drives: 39.19 ft [11.94 m]

Drive sections: 2 to 6 Min. (2 drives): 23.45 ft [7.15 m] 6 drives: 46.32 ft [14.12 m]

Max. pull per drive section† 400 lbf [1,780 N] 400 lbf [1,780 N]

Max. force 3,200 lbf [14,230 N] 2,400 lbf [10,675 N]

Power, cable requirements AC, heptacable DC, multiconductor cable (mono and hepta) † Depending on wheel size ‡ Depending on the configuration and excluding the 2.8-ft [0.85-m] logging head. The incorporated casing collar locator (CCL), head tension cell, addressable cable-release device,

and shock absorber are standard features that do not add extra length.

Surface Systems 21


The modular TuffTRAC* and TuffTRAC Mono* cased hole services tractors employ reverse tractoring and traction control capability through full control of the radial force applied by the tractor arms to operate with improved maneu-verability and reduced slippage. Because this force applied by the tractor arms is independent of borehole size, the tractor drives can achieve the same tractoring force in borehole IDs from 3.4 to 10.6 in [8.6 to 26.9 cm]. The tractor’s low sensi-tivity to borehole conditions allows it to deploy any Schlumberger cased hole ser-vice, including perforating and plug set-ting. The TuffTRAC Mono tractor adds logging-while-tractoring functionality.

The two-drive configuration of the TuffTRAC tractor is the shortest tractor available—only 14.2 ft [4.3 m] in length. The Tractor Planner app for iPad devices can be used to identify candidate TuffTRAC tractors. Up to six modular drive sections can be run as needed to push heavy loads. The tractor’s low power requirements reduce stress on auxiliary systems, eliminating the necessity for stops to cool down, and its wheels optimize surface electrical power to achieve

more than 45% conversion efficiency. The tractor achieves a maximum speed of 3,200 ft/h [975 m/h] at relatively low power usage.

To increase safety and reliability, the TuffTRAC tractor incorporates a head tension cell, electrical cable release, casing collar log (CCL), and addressable perforating safety switch. Other standard safety components include a multiple-use shock absorber and fail-safe opening system.

The TuffTRAC tractor is CE certi-fied for Low Voltage, Machinery, and Pressure Equipment Directives.

The Tractor Planner app for iPad devices can be used to identify UltraTRAC tractor candidates for specific conveyance situations.

Applications■ Perforating operations■ Plug setting■ Production logging■ ABC analysis behind casing services■ Cement and corrosion evaluation■ Mechanical intervention operations


Two drivesections

Three drivesections

Four drivesections

Six-drivetandem

Four-drivetandem

TuTRAC Mono Tractor Configurations

TuffTRAC and TuffTRAC Mono Cased Hole Services Tractors

Mechanical SpecificationsTuffTRAC Tractor TuffTRAC Mono Tractor

Output Cased hole perforating, logging, and intervention

Cased hole perforating, logging, log-ging while tractoring, and intervention

Maximum speed 3,200 ft/h [975 m/h] 2,400 ft/h [730 m/h]



Hole size—min. 3.4 in [8.6 cm] 3.4 in [8.6 cm]

Hole size—max. 10.6 in [26.9 cm] 10.6 in [26.9 cm]

Outside diameter 3.125 in [7.94 cm] 3.125 in [7.94 cm]

Length† Drive sections: 2 to 8 Min. (2 drives): 11.4 ft [3.5 m] 3 drives: 14.2 ft [4.3 m]

Drive sections: 2 to 6 Min. (2 drives): 18.2 ft [5.5 m] 3 drives: 21.1 ft [6.4 m]

Max. pull per drive section 300 lbf [1,330 N] 300 lbf [1,330 N]

Max. force 2,400 lbf [10,680 N] 1,800 lbf [8,010 N]

Power, cable requirements AC, heptacable DC, multiconductor cable (mono and hepta)

† Depending on the configuration and excluding the 2.8-ft [0.85-m] logging head. The incorporated CCL, head tension cell, addressable cable-release device, and shock absorber are standard features that do not add extra length


Surface Systems 23

The MaxTRAC* downhole wireline tractor employs an “inchworm” mechanism to extend the reach of wireline logging services in highly deviated and horizontal wells. Its grip design, high expansion ratio, and compatibility with the telemetry system of the logging tools enables it to traverse a wide range of completions in both cased and open holes while logging is conducted to acquire production logging data.

The integral three-arm grip of the tractor runs it centralized. A minimum of two tractor sondes are run for standard operations. Up to four sondes can be combined for additional flexibility in difficult well conditions. The tractor sonde uses a spring-loaded cam to grip the casing in one direction. The sonde then pulls the grip section backward against the locking direction

of the cam, which causes the toolstring to move forward. This action is synchronized with the other sondes in the toolstring. The reciprocating action of the sondes produces continuous motion of the conveyed tools.

The Tractor Planner app for iPad devices can be used to identify MaxTRAC tractor candidates for spe-cific conveyance situations.

Applications■ Conveyance in highly deviated

and horizontal wells■ Logging operations in perforated

casing, slotted liners, gravel-pack screens, and in-gauge barefoot completions

■ Perforating■ Production logging

MaxTRAC Downhole Wireline Tractor

SpecificationsMaxTRAC Tractor

Output Downward motion of logging tools

Tractoring speed Standard with 500-lbm [227-kg] load: 1,800 ft/h [549 m/h] Max. with 300-lbm [136-kg] load: 2,500 ft/h [762 m/h]

Mud type or weight limitations None

Combinability

Logging while tractoring Tools using PS Platform* production services platform telemetry such as the RSTPro* and SCMT* tools

No logging while tractoring Combinable with most other tools Combinable with perforating services

Special applications Maximum dogleg severity: 45° per 100 ft [30 m] in 7-in [17.78-cm] casing 30° per 100 ft in 4½-in [11.43-cm] casing



LWF logging-while-fishing serviceLWF* logging-while-fishing service saves time and reduces cost by enabling the resumption of logging operations during fishing. In most cases, employ-ing LWF service eliminates the condi-tioning trip required before relogging because the fishing job is converted to a drillpipe-assisted log that completes the original descent in the wellbore.

LWF service can be used with most stuck wireline tools. Operations begin by preparing the wireline for cut-and-thread fishing. The connected rope sockets on the cable ends are housed in a load-bearing protective torpedo to reestablish both the mechanical connection and electrical communica-tion with the stuck toolstring. The tool overshot and drillpipe are threaded over the cable until the placement depth is reached for the Cable Side Entry Sub (CSES).

The CSES is placed to provide an overlapping, continuous log, with the maximum continuous log interval equal to the distance between the casing shoe and rig floor. The wireline passes through the CSES to the outside of the drillpipe to prevent wireline damage during logging. A downhole cable-severing device is also installed to allow retrieval of the wireline if the drillpipe becomes stuck while logging.

The fishing tools on the rig floor are then removed from the wireline, and the tool is repowered to prepare for engagement of the overshot and tool. The speed of the operation now increases because tripping drillpipe is quicker than threading cable through drillpipe. When the stuck tool is reached, engagement is less likely to damage the tool because the reestab-lished electrical communication allows monitoring tension at the tool in addi-tion to the usual driller’s method.

Once the tool is freed, logging is con-ducted on the TLC tough logging condi-tions system to continue the recording of continuous or stationary logs.

TLC tough logging conditions systemThe TLC tough logging conditions system makes it possible to deploy tools for wireline logging in highly deviated or horizontal wells and also in hostile environments and deep wells. Wireline tools are mechanically connected beneath the drillpipe using the Downhole Wet Connector Head (DWCH) and run in to a predetermined latch point. The Pump-Down Wet Connector Head (PWCH) is then threaded through the CSES and pumped down to latch in the DWCH to provide an electrical connection.

The CSES provides a complete cable seal up to 5,000-psi [34-MPa] differential pressure. All standard tools are rated to 20,000 psi [138 MPa].

The TLC system enables conducting operations in otherwise impossible con-ditions. A key component of TLC system operations is thorough prejob planning that accounts for tool compressional and tensile strengths (especially for induction and sonic tools), hole and casing sizes, drillpipe internal diameter and conditions, and well conditions.

Because of the longer operational time related to deployment on the TLC system, special considerations apply when well temperatures exceed 350 degF [174 degC]. The logging program must be planned to reduce logging time at high temperatures. Wireline tools are typically rated to 350 degF, and all higher temperature tools use a Dewar flask to delay the well-generated heat from reaching the electronic components. Temperature limits are specified for a holding time beyond which damage occurs to tool electronics.

Drillpipe-Assisted Wireline Deployment


Surface Systems 25

Depth measurement is critical for wireline operations. An integrated depth dual-wheel spooler (IDW) provides calibrated absolute depth measurement recorded on two independent wheels kept constantly in contact with cable. A fastest wheel logic combined with wheel slippage automatic detection ensures depth accuracy at all times. Other downhole measurements are valuable, but they must be “secured” at the most precise point possible below the Earth’s surface. Decision makers rely on precise depths for mapping geologic intervals, designing completion procedures, and conducting other related operational and financial procedures. If the depth measurement is incorrect, incorrect geologic and economic decisions could result.

Cable and tool friction, especially when calipers are open, cause elastic downhole cable stretch not detected by the IDW at surface. Friction always opposes the movement of tool and cable, so stretch is highest when the tool is moving up and negligible when the tool is moving down. Because log data is recorded while moving up, the tool is physically deeper than what the IDW records on the way up but correctly positioned on the way down. The difference between the log-up and log-down tensions is used to compute the elastic stretch, and a positive correction is applied to the depth before logging up begins. As the friction progressively decreases while logging up, the tool returns to the same zero point when back at surface.

The depth and tension subsystems of the IDW feature alarms and winch shutdown for specified safe operating zones of depth and tension, respec-tively. The upper and lower limits of the safety zones are called setpoints and are provided for four conditions:■ low tension■ high tension■ top of well■ bottom of well.

Winch operation is shut down auto-matically when any of the limits estab-lished by these setpoints are exceeded.

Depth Measurement


Logging Platforms and Suites


Scanner Family* rock and fluid char-acterization services scan both radially and orthogonally at multiple depths of investigation to provide a true 3D image of the reservoir. Because the Scanner* services overcome conven-tional measurement limitations, the tools scan formation volumes to pro-vide new insight into the challenges of formation heterogeneity, anisotropy, and asymmetry. With the ability to measure both in open and cased holes comes the ability to better understand the reservoir.

Openhole Scanner services■ Litho Scanner* high-definition

spectroscopy service measures both inelastic and capture gamma ray spectra to deliver an expanded set of key elemental weight fractions with higher precision and accuracy than previously possible. Determining total organic carbon (TOC) solely from these direct measurements avoids the biases introduced by con-ventional models and the wait for laboratory analysis.

■ Dielectric Scanner* multifrequency dielectric dispersion service mea-sures permittivity and conductivity for the determination of water-filled porosity (hence water saturation within the total porosity), water salinity, and textural effects. In car-bonates, Dielectric Scanner analysis of rock texture delivers a continuous in situ measurement of the Archie mn exponents instead of relying on estimates or waiting for laboratory core analysis; in shaly sands, pro-cessing provides a continuous log of the cation exchange capacity (CEC).

Wireline Services Catalog ■ Logging Platforms and Suites 29

Scanner Family Rock and Fluid Characterization Services

Rt Scanner

IsolationScanner

MR Scanner

Flow Scanner

DielectricScanner

LithoScanner

EM PipeScanner

SonicScanner



■ Sonic Scanner* acoustic scanning platform measures compressional and shear slownesses with multiple borehole-compensated monopole and crossed-dipole transducers. The radial and axial measurements of the stress-dependent properties of the rocks are the basis of a comprehen-sive geomechanical characterization, including classifying formations as isotropic or anisotropic, along with determination of the type and cause of the anisotropy—intrinsic or stress induced from the drilling process. Logging with Sonic Scanner platform can be conducted in both open and cased holes.

■ MR Scanner* expert magnetic reso-nance service profiles fluid volumes and saturations to provide direct hydrocarbon characterization in any environment, including rugose bore-holes, varied formation resistivities and water salinities, heavy- and oil-base muds, low-contrast pay, and thin formations.

■ Rt Scanner* triaxial induction service calculates vertical and horizontal resistivity (Rv and Rh, respectively) from direct measure-ments while simultaneously solv-ing for formation dip at any well deviation. The result is enhanced estimates of hydrocarbon and water saturations, especially for lami-nated, anisotropic, or faulted forma-tions. In addition, formation dip and azimuth are calculated for struc-tural interpretation.

Cased hole Scanner services■ Isolation Scanner* cement evaluation

service combines classic pulse-echo technology with a new ultrasonic technique—flexural wave imaging—to accurately evaluate any type of cement, from traditional slurries and heavy cements to the latest light-weight cements. Cement channels are pinpointed, and the tool’s azimuthal and radial coverage readily differenti-ates low-density solids from liquids to distinguish lightweight cements from contaminated cement and liquids. Casing centralization is imaged in high resolution, and corrosion and drilling-induced wear are mapped and quantified.

■ Flow Scanner* horizontal and devi-ated well production logging sys-tem deploys multiple minispinners and arrays of electrical and optical probes to produce real-time multi-phase velocity and holdup profiles. The result is an unambiguous real-time production log in nonvertical wells, regardless of phase mixing or recirculation.

■ EM Pipe Scanner* electromagnetic casing inspection tool uses noninva-sive electromagnetic measurements to evaluate the integrity of well casings by locating, identifying, and quantifying damage and corrosion. Because the slim-diameter tool eas-ily passes through the tubing shoe, corrosion is measured in production casing without having to pull the completion tubing.

Applications■ Elemental measurements and quan-

titative mineralogy including TOC log for lithology and salinity-independent hydrocarbon saturation

■ Hydrocarbon volume in carbonates, shaly or low-resistivity sands, and heavy oil reservoirs

■ Location and identification of trapped fluids

■ Quantification of drilling process impact

■ Characterization of rock stresses and long-term formation integrity

■ Resistivity and resonance measure-ments in thin and low-resistivity beds, regardless of formation dip

■ Confirmation of zonal isolation, channel identification, and infor-mation on casing-within-casing centralization in a wide range of cement weights

■ Three-phase production logging in vertical and deviated wells

■ Corrosion damage evaluation in single and multiple casing strings


Logging Platforms and Suites 31

Openhole Scanner Services

Measurement Specifications

Litho Scanner Service Dielectric Scanner Service Sonic Scanner Platform MR Scanner Service Rt Scanner Service

Output Elemental yields, elemental weight fractions, TOC, dry-weight mineral concentrations, matrix properties

Relative dielectric permittivity and conductivity at four frequencies

Compressional and shear Δt, full waveforms, cement bond quality waveforms, anisotropy characterization

T1, T₂, and diffusion distributions; lithology-independent total porosity; bound- and free-fluid volumes; hydrocarbon-corrected permeability; pore-size distribution

Rv , Rh, AIT* tool resistivity logs, spontaneous potential, dip, azimuth

Logging speed Max.: 3,600 ft/h [1,097 m/h]† 3,600 ft/h [1,097 m/h] Max.: 3,600 ft/h [1,097 m/h] Bound-fluid logging: 3,600 ft/h [1,097 m/h] Basic NMR profiling: 1,800 ft/h [549 m/h] T₂ radial profiling: 900 ft/h [274 m/h] High-resolution logging: 400 ft/h [122 m/h] T1 radial profiling: 300 ft/h [91 m/h] Saturation profiling: 250 ft/h [76 m/h]

Max.: 3,600 ft/h [1,097 m/h]

Range of measurement 1 to 10 MeV (At highest frequency) Permittivity: 1 to 100 Conductivity: 0.1 to 3,000 mS

Standard shear slowness: <1,500 us/ft [<4,920 us/m]

Porosity: 1 to 100 pu T₂ distribution: 0.4 ms to 3.0 s T1 distribution: 0.5 ms to 9.0 s

na

Vertical resolution 18 in [45.72 cm] 1 in [2.5 cm]‡ <6 ft [<1.82 m] processing resolution for 6-in [15.24-cm] sampling rate

Main antenna: 18 in [45.72 cm]§ High-resolution antenna: 7.5 in [19.05 cm]‡

na

Accuracy na (At highest frequency and corresponding to 0.002-ft³/ft³ [0.002-m³/m³] water-filled porosity) Permittivity: ±1% or ±0.1 Conductivity: ±1% or ±5 mS

Δ t for up to 14-in [35.56-cm] hole size: ±2 us/ft [±6.56 us/m] or ±2% Δ t for >14-in [>35.56-cm] hole size: ±5 us/ft [±16.40 us/m] or ±5%

Total NMR porosity: ±1-pu standard deviation, three-level averaging at 75 degF [24 degC] NMR free-fluid porosity: ±0.5-pu standard deviation, three-level averaging at 75 degF [24 degC]

na

Depth of investigation 7 to 9 in [17.78 to 22.86 cm] To 4 in [10 cm] Typical presentation of up to 7 borehole radii

Main antenna: 1.5, 2.3, 2.7, and 4.0 in [3.81, 5.84, 6.86, and 10.16 cm] High-resolution antenna: 1.25 in [3.18 cm]

AIT tool: 10, 20, 30, 60, and 90 in [25.40, 50.80, 76.20, 152.40, and 228.60 cm]

Mud type or weight limitations

None None None Mud resistivity: 0.05 ohm.m†† Determined during job planning

Combinability Combinable with most openhole tools Conveyance on wireline, TLC* tough logging conditions system, or tractor

Conveyance on wireline, TLC tough logging conditions system, or tractor

Fully combinable with other tools

Combinable with most tools Bottom-only tool, combinable with Platform Express* integrated wireline logging tool and most openhole tools

Special applications Articulated pad for rugose boreholes

MRF* method station logging Rugose boreholes and thick mudcake

na = not available † A tool planner is used to estimate the precision of the elemental concentrations and interpreted properties for a given environment, with the recommended logging speed depending on the required precision. ‡ 1-in resolution depending on frequency § From measurement point 8.2 ft [2.5 m] above the bottom of the tool †† Main antenna only; stacking may be required. MR Scanner service logs have been acquired in 0.02-ohm.m environments with minor loss of precision.



Openhole Scanner Services

Mechanical Specifications

Litho Scanner Service Dielectric Scanner Service Sonic Scanner Platform MR Scanner Service Rt Scanner Service

Temperature rating Version A: 284 degF [140 degC] Version C: 350 degF [177 degC]

350 degF [177 degC] 350 degF [177 degC] 302 degF [150 degC] 302 degF [150 degC]

Pressure rating 20,000 psi [138 MPa] 25,000 psi [172 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa]

Borehole size—min. 5.5 in [13.97 cm] 5.5 in [13.97 cm] 4.75 in [12.07 cm] 5.875 in [14.92 cm] 6 in [15.24 cm]

Borehole size—max. 24 in [60.96 cm]† 22 in [55.88 cm] 22 in [55.88 cm] No limit 20 in [50.8 cm]

Outside diameter 4.5 in [11.4 cm] 4.77 in [12.12 cm] 3.625 in [9.21 cm] Sonde: 5 in [12.70 cm] Cartridge: 4.75 in [12.07 cm]

3.875 in [9.84 cm]‡

Length Version A: 14 ft [4.27 m] Version C: 9 ft [2.74 m]

11.27 ft [3.44 m] 41.28 ft [12.58 m] (including isolation joint) Basic toolstring (near monopoles only): 22 ft [6.71 m]

32.7 ft [9.97 m] 19.6 ft [5.97 m]

Weight Version A: 366 lbm [166 kg] Version C: 290 lbm [132 kg]

262 lbm [119 kg] 844 lbm [383 kg] (including isolation joint) Basic toolstring: 413 lbm [187 kg]

1,200 lbm [544 kg] 404 lbm [183 kg]

Tension 55,000 lbf [244,652 N] 50,000 lbf [222,411 N] 35,000 lbf [155,690 N] 50,000 lbf [222,410 N] 25,000 lbf [111,205 N]

Compression 22,500 lbf [100,085 N] 4,400 lbf [19,572 N]§ 3,000 lbf [13,340 N] 7,900 lbf [35,140 N] 6,000 lbf [26,690 N]

na = not available † With bow spring ‡ Does not include required standoff § 8,000 lbf [35,586 N] with TLC system stiffener kit

Cased Hole Scanner Services


Isolation Scanner Service Flow Scanner System EM Pipe Scanner Tool

Output Solid-liquid-gas map of annulus material, hydraulic communication map, acoustic impedence, flexural attenuation, rugosity image, casing thickness image, internal radius image

Oil, gas, and water holdups; oil, gas, and water velocities; relative bearing; caliper

Electromagnetic thickness, casing ID, casing properties, high- and low-frequency images, corrosion summary report†

Logging speed Standard resolution: 2,700 ft/h [823 m/h] High resolution: 563 ft/h [172 m/h]

1,800, 3,600, 5,400, and 7,200 ft/h [549, 1,097, 1,646, and 2,195 m/h]

Electromagnetic computed thickness (single and double strings): 3,600-ft/h [1,097-m/h] inspection pass for mandrel data Imaging (single string): 1,800-ft/h [549-m/h] standard-resolution inspection pass; 300-ft/h [91-m/h] high-resolution diagnostic pass

Range of measurement Min. casing thickness: 0.15 in [0.38 cm] Max. casing thickness: 0.79 in [2.01 cm]

Borehole coverage: 95% in 6-in- [15.24-cm-] ID casing

Max. metal thickness‡: 1.5 in [3.81 cm] at 8.75 Hz

Vertical resolution High resolution: 0.6 in [1.52 cm] High speed: 6 in [15.24 cm]

na Attenuation < 60 dB: 1% Electromagnetic thickness: 15%§

Accuracy Acoustic impedance: 0.2 Mrayl (resolution); 0 to 3.3 Mrayl = ±0.5 Mrayl; >3.3 Mrayl = ±15% (accuracy††) Flexural attenuation for 0.3-in [18-mm] casing thickness: 0.5 dB/cm (resolution), ±0.01 dB/cm (accuracy††)

Three-phase holdup: ±10% Casing ID: ±0.05 in‡‡

Depth of investigation Casing and annulus§§ Velocity: ±10% –‡


Conditions simulated before logging†††

Min. salinity for electrical probe measurement: 1,000 ppm at 212 degF [100 degC]

Any borehole fluid

Combinability Bottom-only, combinable with most wireline tools Telemetry: fast transfer bus (FTB) or enhanced FTB (EFTB)

Combinable with PS Platform platform and most cased hole tools

All PS Platform platform services Multiple-tool answer products

Special applications H₂S service H₂S service NACE compliant for H₂S and CO₂ resistance

na = not applicable † Corrosion report for single casing strings ‡ Measurement depends on casing geometry, properties, and chrome content. § Resolution depends on the accuracy of casing electrical conductivity (sigma). The usual method is to use API specifications in a “good”

casing section and adjust conductivity to match the nominal value, which has a typical 12.5% range (Oil Country Tubular Goods, API Spec 5CT, Specification for Casing and Tubing).

†† 8-mm calibration target ‡‡ Casing ID (dci) < 6 in and tool eccentered = [30% × (dci – 2.2 in)] §§ Investigation of complete annulus width depends on the presence of third-interface echoes. ††† Max. mud weight depends on the mud formulation, sub used, and casing size and weight, which are simulated before logging.



Cased Hole Scanner Services


Isolation Scanner Service Flow Scanner System EM Pipe Scanner Tool

Temperature rating 350 degF [177 degC] 350 degF [177 degC] 302 degF [150 degC]

Pressure rating 20,000 psi [138 MPa] 15,000 psi [103 MPa] 15,000 psi [103 MPa]

Borehole size—min. Casing: 41⁄2 in† 27⁄8 in [7.30 cm]‡ 2⅞ in (ID > 2.313 in)

Borehole size—max. Casing: 13⅜ in 9 in [22.86 cm] Electromagnetic thickness: 13⅜ in

Outside diameter IBCS-A: 3.375 in [8.57 cm] IBCS-B: 4.472 in [11.36 cm] IBCS-C: 6.657 in [16.91 cm] IBCS-D: 8.736 in [22.19 cm]

1.6875 in [4.29 cm] High-temperature (>302 degF [>150 degC]) operation: 2.25 in [5.72 cm]

2.125 in [5.4 cm]

Length Without sub: 19.73 ft [6.01 m] IBCS-A sub: 2.01 ft [0.61 m] IBCS-B sub: 1.98 ft [0.60 m] IBCS-C sub: 1.98 ft [0.60 m] IBCS-D sub: 1.98 ft [0.60 cm]

Flow Scanner system tool: 11.6 ft [3.54 m] With basic measurement sonde, swivel, and head: 26.2 ft [7.99 m]

19.7 ft [6.0 m]

Weight Without sub: 333 lbm [151 kg] IBCS-A sub: 16.75 lbm [7.59 kg] IBCS-B sub: 20.64 lbm [9.36 kg] IBCS-C sub: 23.66 lbm [10.73 kg] IBCS-D sub: 24.55 lbm [11.13 kg]

108 lbm [49 kg] 110 lbm [50 kg]

Tension Sub max.: 2,250 lbf [10,000 N] 10,000 lbf [44,480 N] Fishing: 10,000 lbf [44,480 N]

Compression Sub max.: 12,250 lbf [50,000 N] 1,000 lbf [4,450 N] 3,000 lbf [13,340 N]

† Min. pass-through restriction: 4 in [10.16 cm] ‡ Min. pass-through restriction: 1.813 in [4.61 cm]



The Platform Express* integrated wireline logging tool is a revolutionary milestone in wireline logging. Com-pared with the traditional triple-combo, the Platform Express tool logs faster and more cost effectively because it requires significantly less time from rig-up to delivery of the final answer. The Platform Express tool is less than half the length of the triple-combo—requiring less rathole—and it weighs about half as much. By using integrated sensors and innovative technology to improve pad contact, the Platform Express tool delivers high-resolution imaging measurements that are depth matched and speed corrected in real time.

The Platform Express toolstring includes either the AIT* array induc-tion imager tool or High-Resolution Azimuthal Laterolog Sonde (HALS) as the resistivity tool. The Three-Detector Lithology Density (TLD) tool and Micro-Cylindrically Focused Log (MCFL) are housed in the High-Resolution Mechanical Sonde (HRMS) powered caliper. Above the HRMS are a compen-sated thermal neutron and gamma ray in the Highly Integrated Gamma Ray Neutron Sonde (HGNS) and a single-axis acceler ometer.

Numerous innovative features are integrated in the Platform Express toolstring. The specially designed TLD skid reduces hole rugosity effects through improved pad application. The integrated hardware and software of the sensors improves system reli-ability. The real-time speed correction

provided by the single-axis accelerom-eter for sensor measurements enables accurate depth matching of all sensors even if the tool cannot move smoothly while recording data. The resistivity, density, and microresis tivity measure-ments are high reso lution. Logging speed is 3,600 ft/h [1,097 m/h], which is twice the speed at which a standard triple-combo is run.

PressureXpress* reservoir pressure-while-logging service can be combined with the Platform Express tool to efficiently obtain accurate pressure profiles and mobility measurements on the first logging run. The two tools’ data are integrated in real time by the PressureXpress Advisor* pretest quality indicator to produce a more complete interpretation of the reservoir.

Applications■ DecisionXpress* petrophysical

evaluation system■ Reservoir delineation■ Hydrocarbon saturation

determination and imaging■ Movable-hydrocarbon

determination ■ Location of porous and

permeable zones■ Gas detection■ Porosity analysis■ Lithology determination■ Well-to-well correlation■ Thin-bed analysis

Platform Express Integrated Wireline Logging Tool

HGNS

HRMS

HALS AIT




Platform Express Tool

Output HGNS: Gamma ray, neutron porosity, tool acceleration HRMS: Bulk density, photoelectric factor (PEF), borehole caliper, microresistivity HALS: Laterolog resistivity, spontaneous potential (SP), mud resistivity (Rm) AIT tool: Induction resistivity, SP, Rm

Logging speed 3,600 ft/h [1,097 m/h]

Mud weight or type limitations None

Combinability Bottom-only toolstring, combinable with most tools above

Special applications Good-quality data in sticky or rugose holes Measurements close to the bottom of the well

Platform Express Tool Component Specifications

HGNS HRMS HALS AIT-H and AIT-M Tools

Output Gamma ray, neutron porosity, tool acceleration

Bulk density, PEF, borehole caliper, microresistivity

Laterolog, resistivity, Rm

Induction resistivity, SP, Rm

Range of measurement

Gamma ray: 0 to 1,000 gAPI Neutron porosity: 0 to 60 pu

Bulk density: 1.04 to 3.3 g/cm3 PEF: 0.9 to 10 Caliper: 22 in [55.88 cm]

0.2 to 40,000 ohm.m 0.1 to 2,000 ohm.m

Vertical resolution Gamma ray: 12 in [30.48 cm] Porosity: 12 in [30.48 cm]

Bulk density: 18 in [45.72 cm] in 6-in [15.24-cm] borehole

Standard resolution: 18 in [45.72 cm] High resolution: 8 in [20.32 cm] in 6-in [15.24-cm] borehole

1, 2, and 4 ft [0.30, 0.61, and 1.22 m]

Accuracy Gamma ray: ±5% Porosity: 0 to 20 pu = ±1 pu 30 pu = ±2 pu 45 pu = ±6 pu

Bulk density: ±0.01 g/cm3 (accuracy), 0.025 g/cm3 (repeatability) Caliper: ±0.1 in [±0.25 cm] (accuracy), 0.05 in [0.127 cm] (repeatability)

1 to 2,000 ohm.m: ±5% Resistivities: ±0.75 ms/m (conductivity) or ±2% (whichever is greater)

Depth of investigation

Gamma ray: 24 in [61.0 cm] Porosity: ˜9 in [˜23 cm] (varies with hydrogen index of formation)

Density: 5 in [12.70 cm] 32 in [81 cm] (varies with formation and mud resistivities)

AO/AT/AF10†: 10 in [25.40 cm] AO/AT/AF20: 20 in [50.80 cm] AO/AT/AF30: 30 in [76.20 cm] AO/AT/AF60: 60 in [152.40 cm] AO/AT/AF90: 90 in [228.60 cm]

Outside diameter 3.375 in [8.57 cm] 4.77 in [12.11 cm] 3.625 in [9.21 cm] 3.875 in [9.84 cm]

Length 10.85 ft [3.31 m] 12.3 ft [3.75 m] 16 ft [4.88 m] 16 ft [4.88 m]

Weight 171.7 lbm [78 kg] 313 lbm [142 kg] 221 lbm [100 kg] AIT-H: 255 lbm [116 kg] AIT-M: 282 lbm [128 kg]

† AO = 1-ft [0.30-m] vertical resolution, AT = 2-ft [0.61-m] vertical resolution, AF = 4-ft [1.22-m] vertical resolution



ThruBit* through-the-bit logging ser-vices provide a full wireline measure-ment suite from a small-diameter quad- or triple-combo toolstring. This unique conveyance platform enables acquiring logs in wells that are difficult to access, including extended-reach wells where the tools can be pumped down. With a diameter of only 21⁄8 in, the entire logging suite is sufficiently slim to pass through the center of most drillpipe, jars, collars, and out the open-ing of the Portal* bit. The open bore-hole is then logged on wireline or as the drillpipe is tripped out of the hole, mak-ing it possible to log geometrically com-plicated wells with greater reliability, at reduced risk, and in less time than alternative conveyance techniques.

The logging tools of the ThruBit services suite can also be run as indi-vidual components:■ Telemetry, memory, and gamma

ray device provides communica-tions and memory functions for the entire logging string. The gamma ray detector measures naturally occurring gamma rays in the for-mation as a correlation basis and qualitative evaluation of clay con-tent. The multi axis accelerometer monitors tool orientation, motion, and vibration. Borehole inclination and temperature are also measured.

■ Array induction tool has five median depths of investigation and three vertical resolutions. The induction tool also incorporates a mud resis-tivity sensor for making corrections and analyzing borehole fluids.

■ Neutron tool operates in both open-hole and cased hole environments to obtain thermal neutron porosity measurements. Corrections can be made for borehole temperature and pressure and environmental factors such as hole size, mud type, mud weight, salinity, and tool standoff.

■ Density tool measures formation bulk density, photoelectric fac-tor (PEF), and borehole size. Raw measurement processing includes a correction algorithm that preserves overall density accuracy across a wide range of borehole sizes, mud types, and mud weights. The tool’s scintillation detectors are housed in an articulated pad for better contact with the formation, which maintains measurement quality in deviated and rugose holes. A single-arm cali-per also helps press the tool against the formation while it measures hole size.

■ ThruBit Dipole* through-the-bit acoustic service obtains both mono-pole and dipole waveforms along with Stoneley wave acquisition. A 3D anisotropy algorithm transforms the compressional, fast- and slow-shear, and Stoneley slowness measure-ments with respect to the borehole axes. The resulting referenced aniso-tropic moduli are used to classify the formation as isotropic or anisotropic and determine whether anisotropy is intrinsic or caused by drilling-induced stress.

■ Spectral gamma ray tool measures the total gamma ray spectra for resolution into potassium, thorium, and uranium. These three most common components of naturally occurring radiation in sands and shales are used to distinguish fea-tures, determine clay type, identify radioactivity in sands, and help in determining total organic carbon (TOC) content.

ThruBit services provide unpar-alleled operational flexibility for either conventional wireline logging or through-the-bit conveyance in memory mode. Where conventional wireline logging is not advisable or not possible in vertical or horizontal

ThruBit Through-the-Bit Logging Services

Drillpipe

Portal bit

Batteries

Telemetry, memory,gamma ray tool

Neutron tool

Density tool

Caliper

Induction arraytool

Hango� sub

No-go collar

Wireline dropo�and retrieval tool



wells, ThruBit services both reduce risk and deliver high-quality data. The hole can be reamed and conditioned using the Portal bit. The logging suite is then run through the drillstring on wireline, and when it reaches the end of the drillstring it is positioned on a hangoff sub so that the logging sensors are passed through the Portal bit and extend into the open hole. The wireline is disconnected and retrieved, and the logging string is used to log in memory mode as the pipe is tripped out.

In wells where a gravity descent is not possible, the logging toolstring is pumped down to the end of the drillstring and positioned for conducting memory mode logging while tripping out.

In either horizontal or vertical wells, the logging toolstring can be retrieved before the drillpipe is completely returned to surface to facilitate imple-mentation of completion operations. At all times during deployment and logging, the driller maintains complete control of the drillstring. Circulation and rotation are conducted as needed, and full pres-sure control is maintained at surface.

Applications■ Openhole logging in

– Horizontal and high-angle wells– Unconventional plays– Unstable boreholes– Poor-quality boreholes (washed

out, rugose, or tortuous)■ Reservoir quality and completion

quality data for completion optimi-zation in unconventional plays

Measurement SpecificationsThruBit Logging Services

Output Telemetry, memory, and gamma ray tool: gamma ray, three-axis acceleration, borehole temperature Array induction tool: induction resistivity, mud resistivity, optional SP Neutron tool: thermal neutron porosity Density tool: bulk density, PEF, borehole caliper ThruBit Dipole service:† Compressional and shear Δt, full waveforms, anisotropy characterization Spectral gamma ray tool: gamma ray; corrected gamma ray for uranium; potassium, thorium, and uranium curves

Logging speed Telemetry, memory, and gamma ray; neutron, density, induction, and ThruBit Dipole service: 1,800 ft/h [549 m/h]

Range of measurement Gamma ray: 0 to 1,000 gAPI Resistivity: 0.1 to 2,000 ohm.m Neutron: 0 to 60 pu Bulk density: 1.04 to 3.3 g/cm³ PEF: 0.9 to 10 Caliper: 18 in [45.72 cm] ThruBit Dipole service: Δts < 200 us/ft [656 us/m] Monopole: Δtc and Δts < 170 us/ft [558 us/m]

Vertical resolution Gamma ray: 12 to 24 in [30.48 to 60.96 cm] Resistivity: 1, 2, and 4 ft [0.3, 0.6, and 1.2 m] Neutron: 12 to 15 in [30.48 to 38.10 cm] Bulk density: 9 to 12 in [22.86 to 30.48 cm] ThruBit Dipole service: <44-in [<1.12-m] processing resolution for 6-in [15.24-cm] sampling rate

Accuracy Gamma ray: ±5% gAPI Resistivity: ±1 ohm.m or ±2%, whichever is greater for the 60-in [152.40-cm] measurement Neutron tool: ±1 pu or 5% of the porosity, whichever is greater Bulk density: ±0.02 g/cm³ PEF: ±0.15 Caliper: ±0.2 in [±0.51 cm] Δt: ±2 us/ft [±6.6 us/m] or ±2% for 8¾-in [22.22-cm] hole size Th: ±3.2 ppm or ±5% of reading U: ±1 ppm or ±5% of reading K: ±0.5% (weight) or ±10% of reading

Depth of investigation Gamma ray: 12 in [30.48 cm] Resistivity: 10, 20, 30, 60, and 90 in [25.40, 50.80, 76.20, 152.40, and 228.60 cm] Neutron: 10 in [25.40 cm] Bulk density: 2 in [5.08 cm] PEF: 4 in [10.16 cm] Δt: 3 in [7.62 cm]


Combinability All ThruBit services tools

Special applications † Limited availability, contact your Schlumberger representative.



Mechanical SpecificationsThruBit Logging Services

Temperature rating Triple-combo: 302 degF [150 degC]† Quad-combo: 302 degF [150 degC]

Pressure rating 15,000 psi [103 MPa]

Borehole size—min. 4 in [10.16 cm] ThruBit Dipole service: 5¾ in [14.60 cm]

Borehole size—max. Telemetry, memory, and gamma ray and induction array tool: 14 in [35.56 cm] Neutron and density tools: 16 in [40.64 cm] ThruBit Dipole service: 8¾ in [22.22 cm]


Length Telemetry, memory, and gamma ray tool: 73.6 in [186.9 cm] Array induction tool: 185 in [470 cm] Neutron: 74 in [188 cm] Density tool: 128 in [325 cm] ThruBit Dipole service: 349 in [444 cm] Monopole waveform sonic: 234.6 in [596 cm] Spectral gamma ray tool: 70.125 in [178.1 cm]

Weight Telemetry, memory, and gamma ray tool: 45 lbm [20.4 kg] Array induction tool: 94 lbm [42.6 kg] Neutron tool: 63 lbm [28.6 kg] Density tool: 94 lbm [42.6 kg] ThruBit Dipole service: 132 lbm [105 kg] Monopole waveform sonic: 114 lbm [52 kg] Spectral gamma ray tool: 38 lbm [17.2 kg]

Tension Depends on the configuration and application

Compression Depends on the configuration and application † 350 degF [177 degC] by special request



The Multi Express* slim multiconvey-ance formation evaluation platform delivers industry-standard log quality with the greater efficiency of a small-diameter, compact logging string. Additional efficiency is provided through memory logging capability and conveyance flexibility in open hole or through drillpipe, with deploy-ment on wireline or coiled tubing.

Designed with centralizers and bow springs that collapse to 2.25-in [5.72-cm] OD for slimhole and alter-native conveyance options, the Multi Express platform integrates a comprehensive set of tools:■ telemetry gamma neutron tool■ Litho-Density* tool■ sonic tool■ spherically focused resistivity tool■ dual induction formation

resistivity tool■ audio temperature tool.

The Multi Express platform's mea-surement suite provides answers in a wide variety of downhole environ-ments. The articulated pad of the Litho-Density tool reduces hole rugos-ity effects through improved pad application. Full characterization for coalbed methane (CBM) wells means that their characteristically low den-sity and photoelectric effect (PEF) are accurately read. In air-filled boreholes, the combination of audio tempera-ture and epithermal neutron mea-surements obtains reliable porosity measurements.

Applications■ Hydrocarbon saturation

and movable hydrocarbon determination

■ Identification of porous and permeable zones

■ Gas detection■ Lithology determination■ Well correlation■ CBM logging■ Air-filled borehole logging■ Slimhole logging to 3 in [7.62 cm]■ Through-drillpipe conveyance■ Coiled tubing in real-time mode

Triple-comboCombo forair-�lled

holes

Quad-combo

Multi Express Slim Multiconveyance Formation Evaluation Platform




Multi Express Platform

Output Telemetry gamma neutron tool: gamma ray, thermal neutron porosity (fluid-filled holes), epithermal neutron porosity (air-filled holes), casing collar log, head tension Litho-Density tool: bulk density, PEF, borehole caliper Sonic tool: Δt (compressional and shear in fast formations), cement bond log (CBL), and Variable Density* log (VDL) SFL* spherically focused resistivity tool: shallow focused laterolog resistivity (Rxo), spontaneous potential (SP) Dual induction formation resistivity tool: induction resistivity, mud resistivity (Rm) Audio temperature tool: borehole temperature, high-frequency audio measurement in air-filled holes

Logging speed Triple-combo and air combo: 4,500 ft/h [1,372 m/h] Quad-combo with sonic: 3,600 ft/h [1,097 m/h] High resolution: 3,600 ft/h [1,097 m/h]

Range of measurement Gamma ray: 0 to 500 gAPI Thermal neutron porosity: –2 to 100 pu Bulk density: 1.0 to 3.1 g/cm3 PEF: 0.3 to 6 Caliper: 2.25 to 14.5 in [5.72 to 36.83 cm] Δt: 42 to 155 us/ft [138 to 508 us/m] Deep and medium resistivity and SFL tool: 0.2 to 2,000 ohm.m Temperature: 13 to 194 degF [–25 to 90 degC] Audio: 44 kHz ± 2 kHz

Vertical resolution Gamma ray: 12 in [30.48 cm] Thermal and epithermal neutron porosity: 12 and 24 in [30.48 and 60.96 cm] Bulk density and PEF: 12 and 18 in [30.48 and 45.72 cm] Caliper: 2 in [5.08 cm] Δt: 6 and 24 in [15.24 and 61 cm] for borehole compensated (BHC), 24 in for slowness-time-coherence (STC) CBL: 6 in [15.24 cm] VDL: 2 in [5.08 cm] Deep and medium resistivity: 2 to 4 ft [0.61 to 1.22 m] SFL tool: 18 in [45.72 cm]

Accuracy Gamma ray: ±5% Thermal neutron porosity: ±0.5 pu for <10 pu, ±5% of reading for 10 to 50 pu (accuracy); 16Ci source: 0.55 pu at 10 pu, 1.1 pu at 30 pu, 2.8 pu at 45 pu, 8Ci source: 0.78 pu at 10 pu, 1.56 pu at 30 pu, 3.9 pu at 45 pu (precision) Epithermal neutron porosity: ±0.5 pu for <10 pu, ±7.5% of reading for 10 to 50 pu (accuracy); 16C source: 0.55 pu at 11 pu, 1.1 pu at 30 pu, 2.2 pu at 45 pu, 8Ci source: 0.77 pu at 10 pu, 1.6 pu at 30 pu, 3.3 pu at 45 pu (precision) Bulk density: ±0.015 g/cm³ in liquid, ±0.02 g/cm³ in air (accuracy); 0.011 g/cm³ at 2.7 g/cm3 (precision) PEF: ±0.1 below 1, ±10% above 1 (accuracy); 0.055 for Pe < 1, 5.5 % for Pe > 1 (precision) Caliper: ±0.2 in [±5.08 cm] for 3.5 to 9.875 in [8.89 to 25.08 cm] (accuracy); 0.1 in [0.25 cm] (precision) Δt: ±2 us/ft [±6.6 us/m] CBL: ±10% (accuracy), 2% (precision) Temperature: 70-ms response time, 1.4 degF [2.5 degC] (precision)

Depth of investigation Gamma ray: 8 in [20.32 cm] Thermal and epithermal neutron porosity: 10 in [25.4 cm] at 20 pu Bulk density: 4 to 6 in [10.16 to 15.24 cm] Δt, CBL, and VDL: 3 in [7.62 cm] Deep resistivity: 70 in [178 cm] Medium resistivity: 30 in [76 cm] SFL tool: 12 to 15 in [30.48 to 38.10 cm]


Combinability PS Platform production services platform, SCMT slim cement mapping tool

Special applications Small-diameter boreholes Alternative conveyance




Multi Express Platform



Borehole size—min. 3.0 in [7.62 cm]

Borehole size—max. 12.75 in [32.39 cm]


Length Triple-combo: 53 ft [16.1 m] Air combo: 47 ft [14.3 m] Quad-combo: 67 ft [20.4 m]

Weight Max. each tool component: 90 lbm [41 kg]

Tension Triple-combo: 15,000 lbf [66,720 N] Sonic: 5,750 lbf [25,580 N]

Compression 1,600 lbf [7,120 N]



Xtreme HPHT Well Logging Platform

HTGC

HNGS

HAPS

HLDS

HSLT

HIT

The Xtreme* high-pressure, high-tem-perature well platform provides mea-surements for formation evaluation in HPHT, hostile environments through the use of rugged, reliable sensors that deliver high-quality data. Rated to 500 degF [260 degC] and 25,000 psi [172 MPa], sensors featuring the lat-est technology are integrated into one wireline string that can log wells as deep as 30,000 ft [9,100 m]. A full range of tool accessories, set of com-prehensive measurements, and job planner software further facilitate the measurement of critical formation evaluation data in challenging logging environments.

The Xtreme platform consists of the following components:■ Hostile Environment Integrated

Telemetry and Gamma Ray Cart-ridge (HTGC) includes an acceler-ometer cartridge that supports real-time speed correction for all Xtreme platform measurements and monitors the bottomhole temperature.

■ Hostile Environment Natural Gamma Ray Sonde (HNGS) provides measurements of total gam ma ray, gamma ray corrected for uranium, as well as individual concentrations of thorium, uranium, and potassium in the formation.

■ Hostile Environment Accelerator Porosity Sonde (HAPS) uses a neutron generator to provide neu-tron porosity with environmen-tally corrected formation capture cross section for clay indication, grain-size estimation, and salinity computation.

■ Hostile Environment Lithology Density Sonde (HLDS) measures formation bulk density and photo-electric factor using full spectral data from a two-detector array.

■ Hostile Environment Sonic Logging Tool (HSLT) delivers robust forma-tion borehole-compensated (BHC) or depth-derived borehole compen-sated (DDBHC) slowness with full waveform recording. It also pro-vides cement bond and Variable Density logs in cased holes.

■ Hostile Environment Induction Imager Tool (HIT) provides the same high-quality resistivity mea-surements as the standard AIT tool. Real-time measurement of mud resistivity complements the computation of tool standoff for precise borehole environmental correction.

Applications■ In situ formation resistivity (Rt)

with array induction■ Formation evaluation and

lithology identification■ Borehole geometry■ High wellbore pressures

and temperatures



Mechanical Specifications HTGC HNGS HAPS HLDS HSLT HIT

Temperature rating 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC]

Pressure rating 25,000 psi [172 MPa] 25,000 psi [172 MPa] 25,000 psi [172 MPa] 25,000 psi [172 MPa] 25,000 psi [172 MPa 25,000 psi [172 MPa]

Borehole size—min. 4¾ in [12.07 cm] 4¾ in [12.07 cm] 5⅞ in [14.92 cm] 4½ in [11.43 cm] 4¾ in [12.07 cm] 4⅞ in [12.38 cm]

Borehole size—max. No limit No limit 21 in [53.34 cm] 20 in [50.8 cm] 20 in [50.8 cm] 20 in [50.8 cm]

Outside diameter 3.75 in [9.53 cm] 3.75 in [9.53 cm] 4 in [10.16 cm] 3.5 in [8.89 cm] 3.875 in [9.84 cm] 3.875 in [9.84 cm]

Length† 10.67 ft [3.25 m] 11.7 ft [3.57 m] 16 ft [4.88 m] 12.58 ft [3.83 m] 25.5 ft [7.77 m]‡ 29.2 ft [8.90 m]

Weight 265 lbm [120 kg] 276 lbm [125 kg] 400 lbm [181 lbm] 402 lbm [182 kg] 440 lbm [199 kg]‡ 625 lbm [283 kg]

Tension 50,000 lbf [222,410 N] 50,000 lbf [22,410 N] 50,000 lbf [22,410 N] 30,000 lbf [133,450 N] 29,700 lbf [132,110 N] 20,000 lbf [88,960 N]

Compression 20,000 lbf [88,960 N] 23,000 lbf [102,310 N] 15,000 lbf [66,720 N] 5,000 lbf [22,240 N] BHC HSLS-W sonde: 2,870 lbf [12,770 N] DDBHC HSLS-Z sonde: 1,650 lbf [7,340 N]

6,000 lbf [26,690 N]

Holding time at 500 degF§ 12 h 10 h 4 h 5 h 5 h 12 h † Makeup length

‡ BHC sonde

§ In logging conditions with tool powered

Hostile Environment Accelerator Porosity Sonde Measurement SpecificationsHAPS

Output Neutron porosity, formation sigma, tool standoff

Logging speed Standard: 1,800 ft/h [549 m/h] High speed: 3,600 ft/h [1097 m/h]

Range of measurement Neutron porosity: 0 to 60 pu

Vertical resolution 14 in [35.56 cm] Tool standoff: not applicable

Accuracy <7 pu: ±0.5 pu 7 to 30 pu: ±7% 30 to 60 pu: ±10% Sigma: ±1 cu [±0.1/m]

Depth of investigation 7 in [17.78 cm]


Special applications H₂S service

Hostile Environment Lithology Density Sonde Measurement Specifications

HLDS

Output Formation density, PEF, caliper

Logging speed Standard: 1,800 ft/h [549 m/h] High speed: 3,600 ft/h [1,097 m/h]

Range of measurement Density: 2 to 3 g/cm3 Porosity: 0 to 60 pu PEF: 1 to 6 Caliper: 16 in [40.64 cm]

Vertical resolution Density, porosity, and PEF: 15 in [38.10 cm]

Accuracy Density: ±0.01 g/cm3 PEF: ±6% Caliper: ±0.25 in [±0.64 cm]

Depth of investigation Density, porosity, and PEF: 6 in [15.24 cm]

Mud type or weight limitations Density and PEF sensitive to barite




Hostile Environment Sonic Logging Tool Measurement Specifications

HSLT

Output Compressional integral traveltime (Δt)


Range of measurement 40 to 180 us/ft [131 to 590 us/m]

Vertical resolution 12 in [30.48 cm]

Accuracy ±2 us/ft [±6.6 us/m]




Hostile Environment Induction Imager Tool Measurement Specifications

HIT

Output 10-, 20-, 30-, 60-, and 90-in [25.40-, 50.80-, 76.20-, 152.40-, and 228.60-cm] resistivity


Resistivity 0.1 to 2,000 ohm.m

Vertical resolution 1, 2, and 4 ft [0.30, 0.61, and 1.22 m]

Accuracy ±0.75 mS/m or ±2% (whichever is greater)

Depth of investigation AHT10: 10 in [25.40 cm] AHT20: 20 in [50.80 cm] AHT30: 30 in [76.20 cm] AHT60: 60 in [152.40 cm] AHT90: 90 in [228.60 cm]

Mud type or weight limitations Some salt-saturated muds may be outside the induction tool operating range




SlimXtreme Slimhole HPHT Well Logging Platform

The SlimXtreme* slimhole HPHT well logging platform provides reliable formation evaluation data in hostile drilling environments. The integra-tion of durable sensors rated to high pressures and temperatures, slimhole design, and a full range of accessories results in high-quality data for real-time wellsite answers. The advanced engineering of the 3-in [7.62-cm] SlimXtreme platform profile combines AIT tool resistivity, digital borehole-compensated sonic, bulk density, ther-mal neutron porosity, and gamma ray tools for one trip into the borehole. High-speed logging is at 3,600 ft/h [1,097 m/h], with standard mode at 1,800 ft/h [549 m/h]. The component tools use advanced wireline digital telemetry rated to the same pressure and temperature as the complete SlimXtreme platform and capable of data transmission through wireline cables as long as 36,000 ft [10,970 m].■ SlimXtreme Array Induction Imager

Tool (QAIT) has five depths of investigation, and its three vertical resolution measurements are of the same high quality as those recorded with conventional AIT tools. The tool output is fully corrected for borehole and environmental effects, so the computed values of water resistivity and saturation, invasion profile, and true and invaded zone resistivities provide a good charac-terization of the reservoir. Real-time measurement of mud resistivity complements the computation of tool standoff for precise borehole environmental correction.

■ SlimXtreme Sonic Logging Tool (QSLT) is a monopole tool that uses a digital algorithm for detect-ing first arrival to deliver robust BHC formation slowness (3 to 5 ft [0.91 to 1.52 m] or 5 to 7 ft [1.52 to 2.13 m]). CBL, attenuation, and

Variable Density cement bond qual-ity logs can be recorded to evaluate cemented casing. The CBL features a 1-ft [30-cm] receiver measure-ment for cement bond evaluation in extremely fast formations.

■ SlimXtreme Litho-Density Tool (QLDT) measures formation density and photoelectric factor using full spectral data from a three-detector array. The QLDT controls the elec-tronics of a bowspring-type caliper (QSCS), which provides eccentral-ization force as well as a caliper measurement in both up and down logging directions.

■ SlimXtreme Compensated Neutron Porosity Tool (QCNT) delivers the same high-quality, environmentally corrected porosity data as those from the traditional CNL* compensated neutron logging tool.

■ SlimXtreme Telemetry and Gamma Ray Cartridge (QTGC) includes an integrated accelerometer to provide real-time speed correction for all measurements by the SlimXtreme platform. The cartridge also performs real-time monitoring of the mud temperature.

Applications■ Quad-combo formation evaluation in

– Slimhole wells– Extreme pressure and

temperature environments– Multilateral wells– Extended-reach wells– Reentry wells

■ Contingency through-drillpipe (min i mum 3.5-in [8.89-cm] inside diameter [ID]) logging

■ Drillpipe-conveyed logging




QAIT QSLT QLDT QCNT QTGC

Output 10-, 20-, 30-, 60-, and 90-in [25.40-, 50.80-, 76.20-, 152.40- and 228.60-cm] deep induction resistivities, SP, mud resistivity

Compressional and shear Δ t, porosity, waveforms, and Variable Density log waveforms

Bulk density, porosity, photoelectric factor (PEF)

Thermal neutron porosity (uncorrected, environmentally corrected, or alpha processed)

Formation gamma ray

Logging speed 3,600 ft/h [1,097 m/h] 3,600 ft/h [1,097 m/h] 1,800 ft/h [549 m/h] 1,800 ft/h [549 m/h] 1,800 ft/h [549 m/h]

Range of measurement 0.1 to 2,000 ohm.m 40 to 400 us/ft [131 to 1,312 us/m]

Bulk density: 1.3 to 3.05 g/cm³ PEF: 1 to 6 Caliper: 9.5 in [24.13]

0 to 2000 gAPI


Compressional Δ t: 2 ft [0.61 m] (standard), 6 in [15.24 cm] short spacing Shear Δ t: 2 ft [0.61 m] Cement bond log: 3 ft [0.91 m] (amplitude), 5 ft [1.52 m] (Variable Density log)

Density: 15 in [38.10 cm] 12 in [30.48 cm] 12 in [30.48 cm]

Accuracy ±0.75 us/m (conductivity) or ±2% (whichever is greater)

Δ t: ±2 us/ft [±6.6 us/m] Bulk density: ±0.15 g/cm³ (accuracy), 0.014 g/cm³ (repeatability) Caliper: ±0.1 in [±0.25 cm] (accuracy), 0.05 in [0.127 cm] (repeabability)

0 to 20 pu: ±1 pu 30 pu: ±2 pu 45 pu: ±6 pu

±5%

Depth of investigation AO/AT/AF10: 10 in [25.40 cm] AO/AT/AF20: 20 in [50.80 cm] AO/AT/AF30: 30 in [76.20 cm] AO/AT/AF60: 60 in [152.40 cm] AO/AT/AF90: 90 in [228.60 cm]

3 in [7.62 cm] 4 in [10.16 cm] ∼9 in [∼23 cm] (varies with hydrogen index of formation)

24 in [60.96 cm]


Salt-saturated muds usually outside the operating range of induction tools

None Sensitive to barite Thermal measurements not possible in air- or gas-filled wellbores

None

Special applications Slim wellbores, HPHT


QAIT QSLT QLDT QCNT QTGC

Temperature rating 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC]


Borehole size—min. 3⅞ in [9.84 cm] 4 in [10.16 cm] 3⅞ in [9.84 cm] 4 in [10.16 cm] 3⅞ in [9.84 cm]

Borehole size—max. 20 in [50.80 cm] 8 in [20.32 cm] 9 in [22.86 cm] 12 in [30.48 cm] No limit

Outside diameter 3 in [7.62 cm] 3 in [7.62 cm] 3 in [7.62 cm] 3 in [7.62 cm] 3 in [7.62 cm]

Length 30.8 ft [9.39 m] 23 ft [7.01 m] With inline centralizer: 29.9 ft [9.11 m]

14.7 ft [4.48 m] 11.9 ft [3.63 m] 10.67 ft [3.25 m]

Weight 499 lbm [226 kg] 270 lbm [122 kg] 253 lbm [115 kg] 191 lbm [87 kg] 180 lbm [82 kg]

Holding time at 500 degF [260 degC]

8 h† 5 h 5 h† 8 h† 8 h†

† In logging conditions with tool powered



IPL* integrated porosity lithology service is a nuclear measurement string. It provides an integrated measurement of various petrophysical parameters of the formation, such as neutron porosity, bulk density, photoelectric factor, and gamma ray as well as gamma ray components. The acquisition electronics allow running the individual components of the toolstring as stand-alone tools. The integrated string comprises the following sensors:■ Hostile Environment Natural

Gamma Ray Sonde (HNGS) features a set of detectors with increased sensitivity that provides a better sta-tistical response to the formation gamma rays. The result is improved spectral analysis over that of previ-ous tools. The improvement in mea-surement also results from the use of two detectors instead of one. The HNGS can log at a faster speed than other tools that measure formation natural gamma ray emissions. Its 500 degF [260 degC] temperature rating makes it suitable for opera-tions in hot borehole environments.

■ APS* accelerator porosity sonde uses an electronic pulsed neutron generator source instead of a chemical source. The large yield of the neutron source enables the use of epithermal neutron detection and borehole shielding. As a result, porosity mea-sure ment is affected only minimally by the borehole environment and formation characteristics, such as lithology and salinity. Five detectors provide information for porosity evaluation, gas detection, shale evaluation, improvement of vertical resolution, and borehole correction. The measurements can be performed in both cased and open holes.

■ Litho-Density photoelectric density logging tool is deployed as the LDS sonde to measure formation bulk density and photoelectric factor. The gamma ray source and two detectors are pad mounted. Magnetic shielding and high-speed electronics ensure excellent measurement stability. The LDS records the full-pulse-height gamma ray spectra from both detectors and processes them into windows. Bulk density and photoelectric cross section are derived conventionally from the windows counts with enhanced quality control.

Applications■ Evaluation of formation porosity

and lithology■ Evaluation of formation bulk

density and photoelectric factor■ Determination of total formation

gamma ray and uranium-corrected gamma ray

■ Gas identification■ Formation sigma

IPL Integrated Porosity Lithology Service




IPL Service

Output Formation bulk density, PEF, gamma ray, porosity, caliper

Logging speed Min. 1,800 ft/h [549 m/h]

Range of measurement See measurement specifications for individual tools

Vertical resolution See measurement specifications for individual tools

Accuracy See measurement specifications for individual tools

Depth of investigation See measurement specifications for individual tools

Mud type or weight limitations HNGS: In potassium chloride (KCl) mud, the KCl content must be known. Density and PEF readings are affected by barite.



IPL Service



Borehole size—min. 6 in [15.24 cm]

Borehole size—max. 21 in [53.34 cm]


Length 40.5 ft [12.34 m]

Weight 845 lbm [383 kg]

IPL Service Component Mechanical Specifications

HNGS APS Sonde LDS



Borehole size—min. 4¾ in [12.07 cm] 4⅝ in [11.75 cm] 5½ in [13.97 cm]

Borehole size—max. No limit 21 in [53.34 cm] 21 in [53.34 cm]

Outside diameter 3.75 in [9.53 cm] 3.625 in [9.40 cm] 4.5 in [11.43 cm]

Length 11.7 ft [3.57 m] 13 ft [3.96 m] 11 ft [3.35 m]

Weight 276 lbm [125 kg] 222 lbm [101 kg] 292 lbm [132 kg]

Tension 50,000 lbf [222,410 N] 50,000 lbf [222,410 N] 30,000 lbf [133,450 N]

Compression 23,000 lbf [102,310 N] 23,000 lbf [102,310 N] 5,000 lbf [22,240 N]



Since first logging an openhole well in 1927, Schlumberger has used advanced technology to acquire essen-tial reservoir data. Today the same high-quality formation evaluation mea-surements can be made in cased holes. ABC analysis behind casing services satisfy three primary requirements for operators:■ Obtaining essential well log data

under any conditions—If the well being drilled has, or is expected to have, hole stability problems, the operators may prefer to case the well as soon as it is drilled. Formation evaluation, which until recently could be performed only in open hole, can now be performed in cased hole.

■ Finding and evaluating bypassed pay—Large amounts of bypassed hydrocarbons exist in old wells. It is considerably more cost effective, and often more environmentally friendly, to explore for those hidden hydrocarbons in old wells rather than to drill new wells.

■ Optimizing reservoir manage-ment—Formation evaluation mea-surements made in representative old wells in a reservoir, whether one time or a time-lapse series, can greatly assist efficient management of the reservoir.ABC services evaluation of forma-

tion petrophysical properties such as formation density, porosity, and acous-tic properties in cased wells is even more significant in wells for which primary evaluation data were lost, of poor quality, or never acquired. In old wells, an operator may want to reevaluate the formation with mea-surements that were unavailable at the time the well was drilled. ABC services enable applying the latest formation evaluation technology in wells that were drilled decades ago.

CHDT

DSI transmitter and isolation joint

RSTPro

SonicScanner

CHFP

CHFR-Plus

CHFR-Slim

ABC Analysis Behind Casing Services



It is no longer necessary to drill new wells in existing fields solely for the purpose of data gathering.

ABC services do not end with opti-mal data acquisition. The data are processed and interpreted to provide a total solution for efficient operations, enhanced production, and extension of the economic life of an asset. ABC services can provide comprehensive formation evaluation under most con-ditions. Because they are a suite of services rather than a single platform, measurements can be chosen on the basis of objectives, type of formation, type of completion, borehole environ-ment, lithology, reservoir dynamics, and the availability of primary evalua-tion data.

ABC services are as follows:■ CHFR-Plus* cased hole forma-

tion resistivity tool makes direct, deep-reading formation resistivity measurements through casing and cement. The concept of measur-ing resistivity through casing is not new, but recent breakthroughs in downhole electronics and electrode design have made these challeng-ing measurements possible. Now the same basic measurements can be compared for open and cased holes, thereby eliminating the errors caused by comparing different types of measurements. The CHFR-Slim* slimhole tool version operates in cas-ing from 27⁄8 to 7 in.

■ RSTPro reservoir saturation tool makes both formation sigma and C/O ratio measurements. In forma-tions with high-salinity formation water, the sigma measurement has been used for several decades to determine the saturations. Now the C/O ratio measurement can accu-rately evaluate formation water saturation in moderate- to high-porosity formations. Time-lapse measurements of formation water saturation can be used to monitor the performance of a well or reservoir over time.

■ CHFP* cased hole formation porosity service makes accurate formation porosity and sigma measurements in cased wells. Instead of a chemical source, CHFP service uses an elec-tronic neutron source in combination with borehole shielding and focus-ing to obtain porosity measurements that are affected only minimally by borehole environment, casing stand-off, and formation characteristics such as lithology and salinity.

■ CNL compensated neutron logging tool has traditionally been run as a porosity indicator in cased wells. Although it provides a good estima-tion of formation porosity in most conditions, the unfocused nature of the CNL tool does not allow correc-tion for environmental effects, such as thickness of casing and cement, or effects resulting from the position of the tool and casing in the borehole. For the highest possible accuracy, CHFP service is the measurement of choice.

■ CHFD* cased hole formation den-sity service makes accurate forma-tion density measurements in cased wells. A chemical gamma ray source and three-detector measurement system are used to make measure-ments in a wide range of casing and borehole sizes. The density mea-surement made by the three-detec-tor system is corrected for casing and cement thickness.

■ Sonic Scanner acoustic scanning platform acquires borehole-compen-sated long- and short-spaced mono-pole, cross-dipole, and cement bond quality measurements. In addition to these axial and azimuthal mea-surements, the fully characterized tool radially measures the formation for both near-wellbore and far-field slowness. A 3D anisotropy algorithm makes it possible to characterize formations as isotropic or anisotro-pic, along with the type and cause of the anisotropy.

■ DSI* dipole shear sonic imager, coupled with the BestDT* automated sonic waveform processing, provides accurate formation compressional and shear slowness measurements in cased wells. BestDT processing is based on optimally designed frequency filters and advanced signal processing. This method significantly attenuates casing arrivals to facilitate the clean extraction of formation slowness.

■ CHDT* cased hole dynamics tester is used to determine formation pres-sure in old or new cased wells. It also provides efficient, cost-effective fluid sampling without the inher-ent risks of standard sampling tech-niques. The innovative CHDT tool seals against the casing and uses a flexible drill shaft to penetrate through the casing and cement into the formation. The use of explosives is eliminated. Down hole sensors measure formation pressure, pres-sure transients, and formation fluid resistivity. Com bining the CHDT tool with various modules of the MDT* modular formation dynamics tester enables enhanced fluid identifica-tion, con tamination monitoring, and high-quality sampling.

Applications■ Evaluation of bypassed pay■ Evaluation of old wells with new

measurements■ Reevaluation of existing fields■ Primary formation evaluation

in cased wells■ Complement to logging-while-

drilling (LWD) data■ Alternative to openhole data acqui-

sition under difficult well conditions■ Evaluation of wells drilled with casing■ Reservoir monitoring■ Fluid contact movement, saturation

and pressure changes, and depletion and injection



Mea

sure

men

t Spe

cific

atio

ns

CHFR

-Plu

s an

d CH

FR-S

lim T

ools

RSTP

ro T

ool

CHFP

Ser

vice

CHFD

Ser

vice

Soni

c Sc

anne

r Pla

tform

DSI I

mag

erCH

DT T

este

r

Outp

utFo

rmat

ion

resi

stiv

ityIn

elas

tic a

nd c

aptu

re y

ield

s

of v

ario

us e

lem

ents

, C/O

ratio

, fo

rmat

ion

capt

ure

cros

s se

ctio

n

(sig

ma)

, neu

tron

poro

sity

Neu

tron

poro

sity

, fo

rmat

ion

sigm

a m

easu

rem

ent q

ualit

y

Bulk

den

sity

Com

pres

sion

al a

nd s

hear

Δt,

full

wav

efor

ms,

cem

ent b

ond

qu

ality

wav

efor

ms,

ani

sotro

py

char

acte

rizat

ion

Com

pres

sion

al a

nd s

hear

Δ

t, w

avef

orm

s, V

aria

ble

Dens

ity w

avef

orm

s

Form

atio

n pr

essu

re, f

luid

m

obili

ty, f

orm

atio

n flu

id s

ampl

es

Logg

ing

spee

dSt

atio

nary

: ~1

min

/sta

tion

Ef

fect

ive

logg

ing

spee

d†:

240

ft/h

[73

m/h

]

Inel

astic

mod

e: 1

00 ft

/h [3

0.5

m/h

] (fo

rmat

ion

depe

nden

t) Ca

ptur

e m

ode:

600

ft/h

[183

m/h

] Si

gma

mod

e: 1

,800

ft/h

[549

m/h

]

900

ft/h

[274

m/h

]90

0 ft/

h [2

74 m

/h]

Max

.: 3,

600

ft/h

[1,0

97 m

/h]

1,80

0 ft/

h [5

49 m

/h]

Stat

iona

ry

Rang

e of

mea

sure

men

t1

to 1

00 o

hm.m

‡Po

rosi

ty: 0

to 6

0 pu

Poro

sity

: 0 to

60

pu

2 to

3 g

/cm

3 St

anda

rd s

hear

slo

wne

ss:

<1,5

00 u

s/ft

[<4,

920

us/m

]St

anda

rd s

hear

slo

wne

ss:

700

ms/

ft [2

,296

ms/

m]

Max

. slo

wne

ss (S

-DSI

):

1,20

0 m

s/ft

[3,9

37 m

s/m

]

0 to

20,

000

psi

[0 to

138

MPa

]

Verti

cal r

esol

utio

n4

ft [1

.22

m]

15 in

[38.

10 c

m]

14 in

[35.

56 c

m]

18 in

[45.

72 c

m]

<6-ft

[<1.

82-m

] pro

cess

ing

re

solu

tion

for 6

-in [1

5.24

-cm

] sa

mpl

ing

rate

3.5-

ft [1

.1-m

] pro

cess

ing

re

solu

tion

for 6

-in

[15-

cm] s

ampl

ing

rate

Poin

t mea

sure

men

t

Accu

racy

±10%

Base

d on

hyd

roge

n in

dex

of

form

atio

n Po

rosi

ty: <

7 pu

= ±

1 pu

7

to 3

0 pu

= ±

10%

30

to 6

0 pu

= ±

15%

Si

gma:

±1

cu [±

0.1/

m]

±0.0

5 g/

cm3

Δt f

or u

p to

14-

in [3

5.56

-cm

] hol

e siz

e: ±

2 us

/ft [±

6.56

us/

m] o

r ±2%

Δ

t for

>14

-in [>

35.5

6-cm

] hol

e

size:

±5

us/ft

[±16

.40

us/m

] or ±

5%

Δt :

±2

ms/

ft [±

6.6

ms/

m]

CQG

gaug

e: ±

(2 p

si [1

3,78

9 Pa

] +

0.01

% o

f rea

ding

) (ac

cura

cy),

0.

008

psi [

55 P

a] a

t 1.3

-s g

ate

time

(reso

lutio

n)

Dept

h of

inve

stig

atio

nSi

mila

r to

deep

late

rolo

g,

up to

32

ft [9

.75

m],

de

pend

ing

on e

nviro

nmen

t§

10 in

[20.

54 c

m]

∼7 in

[∼18

cm

]††5

in [1

2.70

cm

]Ty

pica

l pre

sent

atio

n of

up

to 7

bor

ehol

e ra

dii

9 in

[22.

86 c

m]

Drill

ed d

epth

: 6 in

[15.

24 c

m]

Mud

type

or w

eigh

t lim

itatio

nsN

one

Non

eN

one

Cem

ent t

hick

ness

<

1.75

in [4

.44

cm]

Non

eN

one

Non

e

Com

bina

bilit

yGa

mm

a ra

y, c

asin

g

colla

r loc

ator

Com

bina

ble

with

tool

s us

ing

th

e PS

Pla

tform

pla

tform

tele

met

ry

syst

em, C

PLT

tool

, Com

bina

ble

Gam

ma

Ray

Sond

e (C

GRS)

Com

bina

ble

with

mos

t to

olst

rings

Com

bina

ble

with

mos

t to

olst

rings

Fully

com

bina

ble

with

ot

her t

ools

Co

mbi

nabl

e w

ith

mos

t too

ls

Com

bina

ble

with

mos

t too

lstri

ngs,

an

othe

r CHD

T to

ol, M

DT te

ster

m

odul

es

Spec

ial a

pplic

atio

nsH₂

S se

rvic

eH₂

S se

rvic

e

† Sta

tions

are

reco

rded

eve

ry 4

ft [1

.22

m].

Two

resi

stiv

ity m

easu

rem

ents

, 2 ft

[0.6

1 m

] apa

rt, a

re m

ade

sim

ulta

neou

sly

at e

ach

stat

ion.

‡ M

easu

rem

ents

abo

ve 1

00 o

hm.m

may

be

poss

ible

bas

ed o

n en

viro

nmen

t.

§ F

or a

n in

finite

ly th

ick

bed

†† D

epen

ds o

n ca

sing

and

cem

ent t

hick

ness

Mec

hani

cal S

peci

ficat

ions CH

FR-P

lus

and

CHFR

-Slim

Too

lsRS

TPro

Too

lCH

FP S

ervi

ceCH

FD S

ervi

ceSo

nic

Scan

ner P

latfo

rmDS

I Im

ager

CHDT

Tes

ter

Tem

pera

ture

ratin

g30

2 de

gF [1

50 d

egC]

302

degF

[150

deg

C]

With

flas

k: 4

00 d

egF

[204

deg

C]35

0 de

gF [1

77 d

egC]

257

degF

[125

deg

C]35

0 de

gF [1

77 d

egC]

350

degF

[177

deg

C]35

0 de

gF [1

77 d

egC]

Pres

sure

ratin

g15

,000

psi

[103

MPa

]15

,000

psi

[103

MPa

] W

ith fl

ask:

20,

000

psi [

138

MPa

]20

,000

psi

[138

MPa

]15

,000

psi

[103

MPa

]20

,000

psi

[138

MPa

]20

,000

psi

[138

MPa

]20

,000

psi

[138

MPa

]

Casi

ng s

ize—

min

.CH

FR-P

lus:

4½

in [1

1.43

cm

] CH

FR-S

lim: 2

¼ in

[5.7

2 cm

]†2⅜

in [6

.03

cm]

5 in

[12.

70 c

m]

6⅝ in

[16.

83 c

m]

4.75

in [1

2.07

cm

]5

in [1

2.70

cm

]5½

in [1

3.97

cm

]

Casi

ng s

ize—

max

.CH

FR-P

lus:

9⅝

in [2

4.45

cm

] CH

FR-S

lim: 7

in [1

7.78

cm

]9⅝

in [2

4.45

cm

]13

⅜ in

[33.

97 c

m]

13⅜

in [3

3.97

cm

]22

in [5

5.88

cm

]13

⅜ in

[33.

97 c

m]

9⅝ in

[24.

45 c

m]

Outs

ide

diam

eter

CHFR

-Plu

s: 3

.375

in [8

.57

cm]

CHFR

-Slim

: 2.1

25 in

[5.4

0 cm

]RS

T-C:

1.7

1 in

[4.3

4 cm

] RS

T-D:

2.5

1 in

[6.3

7 cm

]3.

625

in [9

.21

cm]

4.77

in [1

2.11

cm

]3.

625

in [9

.21

cm]

3.62

5 in

[9.2

1 cm

]4.

25 in

[10.

80 c

m]

†

Min

. ID:

2.4

in [6

.10

cm]



Carbonate Advisor* petrophysics and productivity analysis integrates a comprehensive suite of petrophysical logging measurements to quantita-tively determine reservoir producibility in carbonate formations. Unlike sand-stones, with their well-characterized correlations of porosity, permeability, and other reservoir properties, the heterogeneous pore systems of carbonate rocks defy routine petro-physical analysis. Carbonate Advisor analysis accurately evaluates carbonate formations by accounting for reservoir heterogeneity on a multiplicity of scales—of the grains, the pores, and the textures.

The systematic analytical framework of Carbonate Advisor analysis uses the pore geometry to sequentially interre-late logging data to producibility. The evaluation centers on characterization and size partitioning of the pore geom-etry by using texture-sensitive borehole logs, such as MR Scanner expert mag-netic resonance service and borehole imaging. This advanced methodology leverages pore geometry analysis to con-firm the identification of petrophysical rock types (mineralogy and pore system class), determine fluid saturations, and estimate permeabilities and relative permeabilities.

The three steps of the integrated workflow are the determination of■ lithology and porosity—simultane-

ously integrating measurements sensitive to rock matrix properties, such as Litho Scanner high-defi-nition spectroscopy service, ECS* elemental capture spectroscopy sonde, photoelectric factor (PEF), and neutron capture spectroscopy, with measurements sensitive to both the rock matrix and contained fluids, such as density and neu-tron porosity, and measurements sensitive primarily to the fluids and pore space, such as nuclear magnetic resonance (NMR) porosity and bound-fluid volume

■ pore type and permeability— partitioning the total porosity into eight pore system classes based on pore-throat sizes, revealing the influ-ence of the pore geometry, which is not well correlated with mineralogy in carbonates, unlike in sandstones

■ relative permeability and satu-ration—using a powerful for-ward model to account for the radial variation of resistivity, from both array induction and array laterolog measurements, resulting from borehole fluid invasion during drilling.

At each step, customized log displays and crossplots facilitate quality con-trol, parameter selection, and graphical zonation. Within hours of data acquisi-tion, a continuous log of the analyzed carbonate formation is produced.

Application■ Quantitative producibility and

textural analysis for carbonate reservoirs

Carbonate Advisor Petrophysics and Productivity Analysis



DecisionXpress Petrophysical Evaluation System

The DecisionXpress petrophysical eval-uation system provides nearly auto-matic processing of data from modern spectroscopy and Platform Express log-ging tools to enable fast, objective, and reliable log interpretation.

This advanced petrophysical eval-uation is developed with only mini-mal user input from the integration of all the formation, borehole, and quality control measurements of the Platform Express integrated wireline logging tool and ECS elemental cap-ture spectroscopy sonde. The accuracy of the spectroscopy measurements is relatively insensitive to mud weight, most fluid types, and borehole size and rugosity. SpectroLith* lithology processing of the ECS sonde mea-surements of elemental concentra-tions employs empirical relationships derived from an extensive proprietary core chemistry and mineralogy data-base to determine quantitative lithol-ogy and matrix properties data. The unique DecisionXpress system combi-nation of elemental concentration logs and outputs from SpectroLith process-ing forms a robust foundation for the highly accurate, consistent derivation of mineralogy and matrix parameters.

Delivered with the data, the stand-alone PC-based viewer application provides rapid data visualization and reprocessing capabilities, again with minimal user input. The resulting pet-rophysical evaluations are securely delivered through Web-based InterACT global connectivity, collaboration, and information service. Answer products are available within minutes of data acquisition, as data are processed lin-early for each depth level, starting with mineralogy and matrix properties and proceeding through the computation of matrix-corrected porosity, perme-ability, and fluid saturations. Unlike conventional processing, answer prod-ucts from the DecisionXpress system are accurate and reliable for most siliciclastic reservoirs worldwide, with-out requiring manual customization of parameter definitions for specific environments.

Applications■ Casing, drilling-ahead, and side-

tracking decisions■ Planning for mechanical and

percussion sidewall coring■ Designing pressure measurement

and reservoir fluid sampling operations

■ Drillstem testing■ Completion strategies■ Sensitivity analysis



The DeepLook-EM* crosswell elec-tromagnetic imaging service directly measures formation resistivity between wells to produce a reservoir-scale resistivity image. The two wells in which the transmitter and receiver tools of DeepLook-EM service are run can be separated by up to 3,280 ft [1,000 m], depending on the con-straints of the well environments, formations, and resistivity contrasts. A global positioning system is used for synchronized communication of the tools, which are deployed on standard wireline equipment.

Generating a magnetic moment more than 100,000 times that of stan-dard induction tools, the transmitter tool of DeepLook-EM service induces electrical currents to flow in the for-mation. The currents induce a sec-ondary magnetic field that is detected by the four-coil array of the receiver tool. The data are inverted for forma-tion resistivity using a baseline model constructed with the Petrel* E&P software platform.

Applications■ Fluid front monitoring■ Bypassed pay identification■ Reservoir simulation optimization■ Enhanced reservoir

characterization■ Drilling optimization

DeepLook-EM Crosswell Electromagnetic Imaging Service

Receiver

Transmitter

DeepLook-EM Service Interwell Distances

Transmitter Well Receiver Well Well Spacing, ft [m]

Open hole Open hole 3,280 [1,000]

Open hole Steel casing 1,640 [500]

Open hole Chromium casing 2,953 [900]

Chromium casing Chromium casing 1,312 [400]

Chromium casing Steel casing 984 [300]



Measurement SpecificationsDeepLook-EM Service

Output Resistivity imagesLogging speed Transmitter: 2,000–5,000 ft/h [600–1,520 m/h]

Receiver: StationaryRange of measurement 5–1,000 HzVertical resolution >14.75 ft [>4.5 m]Depth of investigation See “DeepLook-EM Service Interwell Distances” tableMud type or weight limitations NoneCombinabilitySpecial applications Crosswell logging


DeepLook-EM Service Transmitter DeepLook-EM Service Receiver



Well size—min.

Open hole 4.5 in [11.43 cm] 2.5 in [6.35 cm]

Cased hole 4.5 in [11.43 cm] 2.5 in [6.35 cm]

Well size—max.

Open hole No limit No limit

Cased hole 13.75 in [34.93 cm] No limit


Length 32.4 ft [9.88 m] Four receivers: 73.8 ft [22.5 m]

Weight 410 lbm [186 kg] 416 lbm [189 kg]

Tension 18,000 lbf [80,070 N] 18,000 lbf [80,070 N]

Compression 10,000 lbf [44,450 N] na na = not available



PS Platform Production Services PlatformThe PS Platform production services platform performs in vertical, horizontal, or any angle of borehole deviation to provide three-phase flow profiles and production monitoring or diagnostic information. Measurement capability is in both real-time and memory modes.

The following tools and their measurements constitute the basic platform string:■ Platform Basic Measurement Sonde

(PBMS) houses the gamma ray and casing collar locator (CCL) for cor-relation and also measures pressure (with either a Sapphire* or quartz pressure gauge) and temperature.

■ Flow-Caliper Imaging Sonde (PFCS) measures the average fluid velocity, water and hydrocarbon holdups, and bubble counts from four indepen-dent probes. It also provides dual-axis (x-y) caliper mea surements and relative-bearing mea surements. The bubble count image is used to identify the first fluid entry.

■ Gradiomanometer* specific gravity profile tool (PGMS) measures the average density of the wellbore fluid, from which the water, oil, and gas holdups are derived. Accelerometer measurements provide deviation cor-rection for the measured fluid density.

Additional services can be combined with the basic PS Platform platform:■ PS Platform Inline Spinner (PILS)

can be used in high-flow-rate envi-ronments to determine fluid velocity.

■ UNIGAGE* pressure gauge system (PUCS) is run if data from two pres-sure gauges (Sapphire and quartz gauges) are required.

■ GHOST* gas holdup optical sensor tool uses optical sensing technology to directly detect and quantify gas in multiphase flows.

■ FloView Plus* holdup measurement tool for highly deviated and hori-zontal wells is an imaging tool that helps identify the flow regime and measures holdup.

■ RSTPro reservoir saturation tool provides sigma, carbon/oxygen (C/O) ratio, water flow, three-phase holdup, and spectrometry logging.

■ SCMT slim cement mapping tool is a 111⁄16-in [4.29-cm] sonic tool that produces an eight-segment cement map and conventional 3-ft [0.91-m] CBL and 5-ft [1.52-m] Variable Density log displays.

■ PS Platform Multifinger Imaging Tool (PMIT) makes internal casing or tubing condition measurements from multiple caliper measurements around the casing or tubing.

Typical PS Platform production log-ging platform toolstrings are configured for the well position and number of production phases:■ Vertical well configuration

– Single- or two-phase production or single-phase injection: Basic toolstring with optional PGMS

– Three-phase production: Basic toolstring with GHOST tool and PGMS

■ High-angle or horizontal well configuration– Single-phase production: Basic

toolstring– Two- or three-phase production:

Basic toolstring with FloView Plus or GHOST tool

Applications■ Three-phase production logging■ Vertical and deviated wells■ Formation stimulation evaluation■ Depth correlation■ Reservoir and production

monitoring■ Transient analysis■ Short periods of multiple-layer

testing



RST-C

CCL-N

SCMT-BB

PMIT-A

FloView Plus

GHOST-A

PUCS-A

PILS-A

PGMS

PBMS

PFCS



Measurement SpecificationsPBMS PFCS PGMS GHOST Tool RSTPro Tool SCMT Tool

Output Gamma ray, CCL, pressure (Sapphire or CQG* crystal quartz gauge), temperature, relative bearing, tool acceleration

Fluid velocity, caliper Fluid density Gas holdup, bubble size, caliper, relative bearing

Sigma, porosity, C/O ratio, spectrometry, WFL* water flow log, TPHL* three-phase fluid holdup log

CBL amplitude, Variable Density log, cement map

Logging speed Depends on the application

Variable Depends on the application

Depends on the application

Depends on the application

1,800 ft/h [549 m/h]

Range of measurement Sapphire gauge: 1 to 10,000 psi [6,895 Pa to 69 MPa] High-pressure Sapphire gauge: 1,000 to 1,500 psi [6.9 to 103 MPa] CQG gauge: 14.5 to 15,000 psi [0.1 to 103 MPa] Temperature: Ambient to 302 degF [150 degC]

Spinner: 0.5 to 200 rps Caliper: 2 to 11 in [5.08 to 27.94 cm] (diameter)

0 to 2.0 g/cm3 Gas holdup: 0 to 100% Caliper: 2 to 9 in [5.08 to 22.86 cm]

Sigma: 0 to 60 cu [0 to 6.0/m] Capture mode: 0 to 60% (uncorrected)

VDL window length: 1,200 ms Firing center accuracy: 20 kHz

Vertical resolution Point of measurement Point of measurement 15 in [38.10 cm] Point of measurement 15 in [38.10 cm] CBL: 3 ft [0.91 m] VDL: 5 ft [1.52 m] Cement map: 2 ft [0.61 m]

Accuracy Sapphire gauge: ±6 psi [±41,370 Pa] (accuracy), 0.1 psi [689 Pa] (resolution) High-pressure Sapphire gauge: ±13 psi [±89,632 Pa] (accuracy), 0.2 psi [1,379 Pa] at 1-s gate time (resolution) CQG gauge: ±(1 psi [6,894 Pa] + 0.01% of reading) (accuracy), 0.01 psi [69 Pa] at 1-s gate time (resolution) Temperature: ±1.8 degF [±1 degC] (accuracy), 0.01 degF [0.018 degC] (resolution)

Caliper: ±0.2 in [±5.1 mm] (accuracy), 0.04 in [1.0 mm] on diameter (resolution)

±0.04 g/cm3 (accuracy), 0.002 g/cm3 (resolution)

Gas holdup between 2% and 98%: ±1% (otherwise without probe protector: ±5%, with probe protector: ±7%) Caliper: ±0.20 in [±5.1 mm]

Based on formation, casing, and borehole characteristics

CBL: 2% (repeatability)

Depth of investigation Borehole Borehole Borehole Borehole 10 in [25.40 cm] CBL and cement map: Casing to cement bond


None None Measurement not valid in horizontal wells

None None None

Special applications Exceeds NACE standards for H₂S resistance

Mechanical SpecificationsPBMS PFCS PGMS GHOST Tool RSTPro Tool SCMT Tool

Temperature rating† 302 degF [150 degC] 302 degF [150 degC] 302 degF [150 degC] 302 degF [150 degC] 302 degF [150 degC] 302 degF [150 degC]

Pressure rating 15,000 psi [103 MPa] 15,000 psi [103 MPa] 15,000 psi [103 MPa] 15,000 psi [103 MPa] 15,000 psi [103 MPa] 10,000 psi [69 MPa]

Borehole size—min. 2⅜ in [6.03 cm]‡ 2⅜ in [6.03 cm]‡ 2⅜ in [6.03 cm]‡ 2 in [5.08 cm]‡ RST-C: 113⁄16 in [4.60 cm] RST-D: 2⅞ in [7.30 cm]

2⅜ in [6.03 cm]‡

Borehole size—max. No limit 11 in [27.94 cm] No limit 9 in [22.86 cm] RST-C: 7⅝ in [19.37 cm] RST-D: 9⅝ in [24.45 cm]

7 in [17.78 cm]

Outside diameter 1.6875 in [4.29 cm] 1.6875 in [4.29 cm] 1.6875 in [4.29 cm] 1.71 in [4.34 cm] RST-C: 1.71 in [4.34 cm] RST-D: 2.51 in [6.37 cm]

1.6875 in [4.29 cm]

Length 8.27 ft [2.52 m] 5.14 ft [1.57 m] 4.8 ft [1.46 m] 7.1 ft [2.16 m] RST-C: 23.0 ft [7.01 m] RST-D: 22.2 ft [6.77 m]

11 ft [3.35 m]

Weight 38.3 lbm [17.4 kg] 19.7 lbm [8.9 kg] 29.5 lbm [13.4 kg] 28.4 lbm [12.9 kg] RST-C: 101 lbm [46 kg] RST-D: 208 lbm [94 kg]

50 lbm [23 kg]

† For high-temperature applications, ask your Schlumberger representative for the individual tool specifications. ‡ Minimum tubing size


Dielectric Dispersion Logging


Wireline Services Catalog ■ Dielectric Dispersion Logging 61

Dielectric Scanner multifrequency dielectric dispersion service provides continuous, high-resolution measure-ment of the variation of formation dielectric properties as a function of frequency. Radial interpretation of each frequency provides permittivity and conductivity, which are input to a petrophysical model to obtain water-filled porosity (hence water satura-tion within the total porosity), water salinity, and textural effects. Pressure, temperature, and the permittivity and conductivity of the borehole mudcake are also measured to correct for envi-ronmental effects.

In carbonates, Dielectric Scanner service’s analysis of textural effects provides a continuous in situ mea-surement the Archie mn exponents instead of requiring their estimation or a wait for laboratory core analysis. In shaly sands, processing provides a continuous log of the cation exchange capacity (CEC), accounting for the effect of the clay volume.

The articulated pad of Dielectric Scanner service improves contact with the formation in rugose boreholes, a condition that previous mandrel-type electromagnetic propagation tools were sensitive to.

Applications■ Direct measurement of water

volume independent of water resistivity (Rw) at a depth of investigation to 4 in [10 cm], solving for– Residual hydrocarbon volume

in produced reservoirs– Hydrocarbon volume in low-

resistivity or low-contrast shaly and laminated sand formations

– Hydrocarbon volume and mobility in heavy oil reservoirs

– Water salinity

■ Continuous Archie mn exponent log from rock texture measurements in carbonates for determining saturations beyond the invaded zone

■ CEC to account for the effect of clay volume in siliciclastics

■ High-resolution water-filled porosity for thin-bed analysis

Dielectric Scanner Multifrequency Dielectric Dispersion Service



Measurement SpecificationsDielectric Scanner Service

Output Relative dielectric permittivity and conductivity at four frequencies


Range of measurement at highest frequency

Permittivity: 1 to 100 Conductivity: 0.1 to 3,000 mS

Vertical resolution† 1 in [2.5 cm]

Accuracy at highest frequency Corresponding to 0.002-ft3/ft3 [0.002-m3/m3] water-filled porosity Permittivity: ±1% or ±0.1 Conductivity: ±1% or ±5 mS

Depth of investigation To 4 in [10 cm]


Combinability Conveyance on wireline, TLC tough logging conditions system, or tractor

Special applications Articulated pad for rugose boreholes† 1-in resolution depending on frequency

Mechanical SpecificationsDielectric Scanner Service






Min. restriction 5.25 in [13.34 cm]

Length 11.27 ft [3.44 m]


Tension 50,000 lbf [222,411 N]

Compression† 4,400 lbf [19,572 N]† 8,000 lbf [35,586 N] with stiffener kit for the TLC system


Resistivity Logging


Rt Scanner triaxial induction service calculates vertical and horizontal resis-tivity (Rv and Rh, respectively) from direct measurements while simultane-ously solving for formation dip at any well deviation. Making measurements at multiple depths of investigation in three dimensions ensures that the derived resistivities are true 3D mea-surements. The enhanced hydrocarbon and water saturation estimates com-puted from these measurements result in a more accurate reservoir model and reserves estimates, especially for low-resistivity laminated, anisotropic, or faulted formations.

Compact, one-piece Rt Scanner service has multiple triaxial arrays, each containing three collocated coils measuring at various depths into the formation. Rv and Rh are calculated at each of the triaxial spacings. Short single-axis receivers and collocated triaxial receivers are used to fully characterize the borehole signal and remove the borehole effect.

Rt Scanner service also simulta-neously measures formation dip and azimuth for making advanced correc-tions for the effects of bed boundar-ies and formation dip. Accurate dip and azimuth measurements can be obtained for a wide range of borehole conditions and formation environ-ments, including at any well angle to the formation layers, in air-filled bore-holes, and in the presence of invasion. Layer dip is computed at 10- to 50-ft [3- to 15-m] intervals.

Although the intervals are at lower vertical resolution than dip from an image tool or dipmeter, measure-ments from Rt Scanner service are sufficiently robust to provide criti-cal structural information and detect major events, such as bed boundaries and unconformities or faults crossing the borehole.

Along with advanced resistivity and structural information, Rt Scanner service delivers standard AIT array induction imager tool measurements for correlation with existing field logs. The tool’s innovative single-piece design requires the addition of only a caliper and the GPIT* general purpose inclinometry tool to the toolstring to operate. Rt Scanner service is also fully combinable with most openhole services and the Platform Express integrated wireline logging tool, adding only 7 ft [2 m] to the length of a triple-combo Platform Express tool when replacing the AIT resistivity tool.

Applications■ Quantification of laminated or

low-resistivity formations■ Corrected resistivity for shoulder

beds at any dip■ Determination of water

saturation, Sw

■ Geometric reservoir modeling■ Structural analysis■ Completion design and facilities

optimization

Wireline Services Catalog ■ Resistivity Logging 65

Rt Scanner Triaxial Induction Service




Rt Scanner Service

Output Rv, Rh, AIT tool logs, spontaneous potential, dip, azimuth

Logging speed Max.: 3,600 ft/h [1,097 m/h]

Depth of investigation AIT: 10, 20, 30, 60, and 90 in [25.40, 50.80, 76.20, 152.40, and 228.60 cm]

Mud type or weight limitations Determined during job planning

Combinability Bottom-only tool, combinable with Platform Express tool and most openhole tools

Special applications


Rt Scanner Service





Outside diameter† 3.875 in [9.84 cm]

Length 19.6 ft [5.97 m]


Tension 25,000 lbf [111,205 N]

Compression 6,000 lbf [26,690 N] † Does not include required standoff


Resistivity Logging 67

Induction logging tools accurately mea-sure open borehole formation conduc-tivity as a function of both well depth and radius into the formation at differ-ent borehole conditions and environ-ments. Various tools cater to special operating environments, including slim wells and hostile, HPHT environments.

Wireline array induction tools use an array induction coil that operates at multiple frequencies. Software focusing of the received signals gen-erates a series of resistivity logs with different depths of investigation. Multichannel signal processing pro-vides robust, stable tool responses with enhanced radial and vertical resolution and correction for environ-mental effects. Quantitative 2D imag-ing of formation resistivity is possible because of the large number of mea-surements made. The images repre-sent bedding and invasion features clearly and quantitatively. Advanced invasion description parameters are used to describe the presence of tran-sition zones and annuli. The quantita-tive information about invasion can be converted to a 2D image of water saturation Sw, which can be plotted in color at the wellsite.

AIT array induction imager toolThe standard AIT-B and AIT-C tools are used in moderate-environment wellbore conditions to measure the true resistivity of geologic forma-tions. The AIT tools’s measurement of conductivity as a function of both depth and distance from the borehole revolutionized induction logging by increasing the depth of investigation of the measured signal concurrent with reducing the vertical resolution from 4 to 2 ft [1.22 to 0.61 m] and to 1 ft [0.30 m] in smooth wellbores.

Platform Express array induction imager toolThe AIT-H tool is designed expressly for the Platform Express integrated wireline logging tool. It is approxi-mately one-half the length of the AIT-B and AIT-C tools, yet provides the same high-quality measurement. The tool is used primarily in stan-dard logging conditions of pressure to 15,000 psi [103 MPa] and tem-perature to 257 degF [125 degC]. The more recent AIT-M tool provides the same measurements with a tempera-ture rating of 302 degF [150 degC].

Hostile Environment Induction Imager ToolThe HIT is a component of the Xtreme platform for logging hostile envi-ronment wells. Even under severe temperature and pressure condi-tions, the induction measurement quality matches that of the standard AIT tools.

SlimXtreme Array Induction Imager ToolThe QAIT tool is used with the SlimXtreme platform to log slim wellbores under severe environmen-tal conditions. The slim tool diam-eter is also useful for logging through severe doglegs.

Induction Tools

QAIT AIT-BAAIT-C


Applications■ Reservoir delineation■ Determination of Rt

■ Determination of Sw

■ Hydrocarbon identification and imaging

■ Determination of movable hydrocarbons

■ Invasion profiling■ Thin-bed analysis



AIT-B and AIT-C AIT-H and AIT-M HIT QAIT

Output 10-, 20-, 30-, 60-, and 90-in [25.40-, 50.80-, 76.20-, 152.40-, and 228.60-cm] deep induction resistivities, SP, Rm


Range of measurement 0.1 to 2,000 ohm.m


Accuracy Resistivities: ±0.75 us/m (conductivity) or ±2% (whichever is greater)

Depth of investigation† AO/AT/AF10: 10 in [25.40 cm] AO/AT/AF20: 20 in [50.80 cm] AO/AT/AF30: 30 in [76.20 cm] AO/AT/AF60: 60 in [152.40 cm] AO/AT/AF90: 90 in [228.60 cm]

Mud type or weight limitations Salt-saturated muds usually outside the operating range of induction tools

Combinability Combinable with most services Platform Express tool Xtreme platform SlimXtreme platform

Special applications High temperature H₂S service

Slim wellbores HPHT

† AO = 1-ft [0.30-m] vertical resolution, AT = 2-ft [0.61-m] vertical resolution, AF = 4-ft [1.22-m] vertical resolution


AIT-B and AIT-C AIT-H AIT-M HIT QAIT



Borehole size—min. 4¾ in [12.07 cm] 4¾ in [12.07 cm] 4¾ in [12.07 cm] 4⅞ in [12.38 cm] 3⅞ in [9.84 cm]

Borehole size—max. 20 in [50.80 cm] 20 in [50.80 cm] 20 in [50.80 cm] 20 in [50.80 cm] 20 in [50.80 cm]

Outside diameter 3.875 in [9.84 cm] 3.875 in [9.84 cm] 3.875 in [9.84 cm] 3.875 in [9.84 cm] 3 in [7.62 cm]

Length 33.5 ft [10.21 m]† 16 ft [4.88 m] 16 ft [4.88 m] 29.2 ft [8.90 m]† 30.8 ft [9.39 m]†

Weight 575 lbm [261 kg] 255 lbm [116 kg] 282 lbm [128 kg] 625 lbm [283 kg] 499 lbm [226 kg]


Compression 2,300 lbf [10,230 N] 6,000 lbf [26,690 N] 6,000 lbf [26,690 N] 6,000 lbf [26,690 N] 2,000 lbf [8,900 N] † Without SP sub



ARI azimuthal resistivity imagerThe ARI* azimuthal resistivity imager combines standard laterolog measure-ments with a 12-channel azimuthal resistivity image and a high-resolution deep resistivity measurement. The resis tivity image has 100% borehole coverage and complements high-resolution borehole images from the FMI* fullbore formation microimager by differentiating between natural deep fractures and shallow, drilling-induced cracks. Azi muthal resistivity measurements also enable the detec-tion of nearby conductive beds in horizontal wells.

Applications■ Determination of Rt

■ Deviated and horizontal well evaluation

■ Azimuthal resistivity evaluation

HRLA high-resolution laterolog array toolThe HRLA* high-resolution laterolog array tool provides five independent, actively focused, depth- and resolution-matched measurements that can resolve the true formation resistivity in thinly bedded and deeply invaded formations. Unprecedented combinability results from the through-wired tool design. The absence of a current return at surface as well as no required use of a bridle greatly improves wellsite efficiency.


■ Deviated and horizontal well evaluation

■ Thin-bed analysis■ Rt measurements free

of Gröningen effects■ Short-radius wells

High-Resolution Azimuthal Laterolog SondeThe HALS uses a central azimuthal array of electrodes to produce deep and shallow resistivity images and an image of the electrical standoff for the Platform Express integrated wire-line logging tool. A computed focusing scheme increases the accuracy of the measurement and enables the simul-taneous computation of standard and high-resolution curves by changing the focusing conditions.


■ Resistivity logs and azimuthal images with 1-ft [0.30-m] vertical resolution

■ Thin-bed analysis■ Fracture identification and

characterization■ Deviated and horizontal well

evaluation■ Gröningen-corrected resistivity■ Evaluation of heterogeneous

reservoirs ■ Borehole profiling■ Invasion characterization for

permeability indication■ Identification of fluid contacts

Laterolog Tools

HALS

HRLA

ARI




ARI Imager HRLA Tool† HALS

Output Deep laterolog, shallow laterolog, high-resolution deep laterolog, Gröningen laterolog, azimuthal resistivity, resistivity images

Deep laterolog, shallow laterolog, high-resolution resistivity, diameter of invasion, resistivity images, mud resistivity

High-resolution deep laterolog, high-resolution shallow laterolog, resistivity images, mud resistivity

Logging speed 1,800 ft/h [549 m/h] 3,600 ft/h [1,097 m/h] 3,600 ft/h [1,097 m/h]

Range of measurement 0.2 to 100,000 ohm.m Rm = 1 ohm.m: 0.2 to 100,000 ohm.m Rm = 0.02 ohm.m: 0.2 to 20,000 ohm.m

0.2 to 40,000 ohm.m

Vertical resolution

Deep and shallow laterolog: 29-in [73.66-cm] beam width High-resolution laterolog: 8-in [20.32-cm] beam width

12 in [30.48 cm]

Standard resolution: 18 in [45.72 cm] in 6-in [15.24-cm] borehole High resolution: 8 in [20.32 cm] in 6-in [15.24-cm] borehole

Accuracy

1 to 2,000 ohm.m: ±5% 2,000 to 5,000 ohm.m: ±10% 5,000 to 100,000 ohm.m: ±20%

1 to 2,000 ohm.m: ±5% 2,000 to 5,000 ohm.m: ±10% 5,000 to 100,000 ohm.m: ±20%

1 to 2,000 ohm.m: ±5%

Depth of investigation

40 in [101.6 cm] (varies with formation and mud resistivities)

50 in [127.0 cm]‡ 32 in [81.3 cm] (varies with formation and mud resistivities)

Mud type or weight limitations Rm < 5 ohm.m Conductive mud systems only Conductive mud systems only

Combinability Combinable with most tools Combinable with most tools Bottom component of Platform Express tool

† HRLA performance specifications are for 8-in borehole. ‡ Median response at 10:1 contrast of true to invaded zone resistivity


ARI Imager HRLA Tool HALS



Borehole size—min. 4½ in [11.43 cm] 5 in [12.70 cm] 5½ in [13.97 cm]

Borehole size—max. 21 in [53.34 cm] 16 in [40.64 cm] 16 in [40.64 cm]

Outside diameter 3⅝ in [9.21 cm]† 7¼ in [18.41 cm]†

3⅝ in [9.21 cm] 3⅝ in [9.21 cm]

Length 33.25 ft [10.13 m] 24.1 ft [7.34 m] 16 ft [4.88 m]



30,000 lbf [133,450 N] 20,000 lbf [88,960 N]

Compression 2,000 lbf [8,900 N] With fin standoff: 3,600 lbf [16,010 N] With rigid centralizers: 7,800 lbf [34,700 N]

2,400 lbf [10,675 N] With four rigid centralizers: 9,400 lbf [41,810 N]

† ARI tool is available in two sizes to fit different borehole sizes.



Microresistivity tools measure the resistivity of the invaded zone Rxo. Micro-normal and -inverse measure-ments are made for permeability indication.

MicroSFL spherically focused resistivity toolThe MicroSFL* spherically focused resistivity tool (MSFL) achieves the very shallow depth of investigation necessary to measure formation resistivity close to the borehole wall through its electrode spacing arrange-ment in combination with control of the bucking current. The MicroSFL tool also provides an indication of the mudcake thickness hmc and a real-time synthetic microlog generated from the micro-normal (MNOR) and micro-inverse (MINV) measurements.

Micro-Cylindrically Focused LogThe Micro-Cylindrically Focused Log (MCFL) and Three-Detector Lith ology Density (TLD) tools are collocated on the Platform Express integrated wire-line logging tool. The MCFL consists of a narrow, wear-resistant metallic pad and provides three basic mea-surements: Rxo, hmc, and the mudcake resistivity Rmc.

The MCFL has several advantages over previous devices for measuring invaded zone resistivity. The MCFL uses a dual-focusing method to cre-ate cylindrical equipotential surfaces that are the optimal shape for the cylindrical borehole and mudcake and make the tool insensitive to variations

in mudcake thickness and borehole geometry. The 3-in [7.62-cm] depth of investigation also makes the measure-ment insensitive to mudcake up to 0.4 in [1 cm] thick, and correction can be made for thicker mudcake. The measurement of mudcake thickness is input to quality control processes for the TLD and other tools sensitive to standoff.

Powered Caliper Device with microlog toolThe Powered Caliper Device (PCD) with microlog tool consists of a hydraulic sonde containing two cali-per arms and a microlog pad. The microlog pad is mounted on the larger caliper arm, which eccenters the tool. The smaller caliper arm is mounted opposite the large arm and is used as a borehole rugosity indicator. The microlog micro-normal and micro-inverse measurements are used to indicate permeability.

Applications■ Rxo measurement■ Invasion correction of deep

resistivity measurements■ Detection of permeable zones■ Quantitative estimate of water

saturation in the flushed zone (Sxo) (movable oil)

■ Evaluation of sand-shale laminations (sand count)

■ Measurement of hole diameter■ Indication of hole rugosity

Microresistivity Tools

MSFL

PCD

MCFL




MicroSFL Tool MCFL PCD with Microlog

Output Resistivity of the invaded zone Resistivity of the invaded zone Micro-normal, micro-inverse, two calipers (single axis)

Logging speed 1,800 ft/h [549 m/h] 3,600 ft/h [1,097 m/h] 3,600 ft/h [1,097 m/h]

Range of measurement 0.2 to 1,000 ohm.m 0.2 to 2,000 ohm.m Short arm: 1.25 in [3.18 cm] Hole diameter: 22 in [55.9 cm]

Vertical resolution 2 to 3 in [5.08 to 7.67 cm] 0.70 in [1.78 cm] Micro-normal: 2 in [5.08 cm] Micro-inverse: 1 in [2.54 cm]

Accuracy ±2 ohm.m ±5% Caliper: ±0.2 in [±0.51 cm]

Depth of investigation 0.7 in [1.78 cm] 3.0 in [7.62 cm] Micro-normal: �1.5 in [�3.8 cm] Micro-inverse: �0.5 in [�1.3 cm]

Mud type or weight limitations Oil-base mud Oil-base mud Oil-base mud

Combinability Combinable with most tools Housed with the TLD in the High-Resolution Mechanical Sonde of the Platform Express tool

Combinable with most tools

Special applications Provides eccentric positioning for other services that require it


MicroSFL Tool MCFL PCD with Microlog



Borehole size—min. 5½ in [13.97 cm] Without bow spring: 51⁄5 in [13.21 cm] With bow spring: 6 in [15.24 cm]

Without microlog pad: 6½ in [16.51 cm] With microlog pad: 7 in [22.23 cm]

Borehole size—max. 17½ in [44.45 cm] 16 in [40.64 cm] 22 in [55.88 cm]

Outside diameter Caliper closed: 4.77 in [12.11 cm]

4.625 in [11.75 cm] Without pad: 3.375 in [8.57 cm] With slim pad: 5 in [12.70 cm] With standard pad: 6.25 in [15.87 cm]

Length 12.3 ft [3.75 m] 10.85 ft [3.31 m] 17.25 ft [5.26 m]

Weight 313 lbm [142 kg] 171.7 lbm [78 kg] 345 lbm [156 kg]


Compression 5,000 lbf [22,240 N] 8,800 lbf [39,140 N] 5,000 lbf [22,240 N]



The CHFR-Plus cased hole formation resistivity tool and CHFR-Slim slimhole tool provide deep-reading resistivity measurements from behind steel casing. The tools induce a current that travels in the casing, where it flows both upward and downward before returning to the surface along a path similar to that employed by openhole laterolog tools. Most of the current remains in the casing, but a very small portion escapes to the formation. Electrodes on the tools measure the potential difference created by the leaked current, which is proportional to the formation conductivity.

Typical formation resistivity values are about 109 times the resistivity value of the steel casing. The measurement current escaping to the formation causes a voltage drop in the casing segment. Because the resistance of casing is a few tens of microohms and the leaked current is typically on the order of few milliamperes, the potential difference measured by the CHFR-Plus and CHFR-Slim tools is in nanovolts.

Measurement is performed while the CHFR-Plus and CHFR-Slim tools are stationary to avoid the noise introduced by tool movement. Contact

between the electrodes and the casing is optimized by the design of the electrodes, which scrape through small amounts of casing scale and corrosion. Because the electrodes are in direct contact with the casing, the CHFR-Plus and CHFR-Slim tools are not limited to operations in conductive borehole fluids and operate in wells with oil, oil-base mud, or gas in the casing. The typical low-resistivity (1- to 5-ohm.m) cements used in well construction do not have a significant effect on cased hole resistivity measurement.

Applications■ Measuring resistivity behind

casing in new or old wells■ Reservoir monitoring■ Locating bypassed hydrocarbons■ Determining residual oil

saturation and identifying gas/oil/water contacts

■ Contingency logging in wells where openhole logs cannot be run

■ Reevaluating existing fields

CHFR-Plus and CHFR-Slim Cased Hole Formation Resistivity Tools

CHFR-Plus

CHFR-Slim




CHFR-Plus and CHFR-Slim Tools

Output Formation resistivity

Logging speed Stationary: �1 min/station†

Range of measurement 1 to 100 ohm.m‡

Vertical resolution 4 ft [1.2 m]

Accuracy ±3% to ±10%

Depth of investigation§ 7 to 32 ft [2.1 to 9.75 m]


Combinability Gamma ray, CCL

Special applications H₂S service † Stations are recorded every 4 ft [1.22 m]. Two resistivity measurements, 2 ft [0.61 m] apart are made simultaneously by redundant electrodes at each

station. The resulting effective logging speed is 240 ft/h [73 m/h]. ‡ Measurement of resistivities greater than 100 ohm.m may be possible based on the environment. § For an infinitely thick bed


CHFR-Plus Tool CHFR-Slim Tool



Casing size—min. 4½ in 2⅞ in (min. ID: 2.4 in [6.10 cm])

Casing size—max. 9⅝ in 7 in


Length 48 ft [14.63 m] 37 ft [11.28 m]



Compression 2,400 lbf [10,675 N] 1,000 lbf [4,448 N]


Nuclear Measurements


Wireline Services Catalog ■ Nuclear Measurements 77

Gamma ray tools record naturally occurring gamma rays in the forma-tions adjacent to the wellbore. This nuclear measurement indicates the radioactive content of the formations. Effective in any environment, gamma ray tools are the standard device used for the correlation of logs in cased and open holes.

Applications■ Depth determination■ Depth correlation within the well

and between wells■ Lithology identification■ Qualitative evaluation of shaliness■ Qualitative evaluation of radioactive

mineral deposits■ Cased hole perforating

depth control■ Positioning for openhole

sampling tools

Gamma Ray Tools

SGT-N

HGNS

CGRS

HTGC

QTGC




Highly Integrated Gamma Neutron Sonde (HGNS)

Hostile Environment Telemetry and Gamma Ray Cartridge (HTGC)

Scintillation Gamma Ray Tool (SGT)

SlimXtreme Telemetry and Gamma Ray Cartridge (QTGC)

Combinable Gamma Ray Sonde (CGRS)

Output Formation gamma ray Formation gamma ray Formation gamma ray Formation gamma ray Gamma ray activity

Logging speed 3,600 ft/h [1,097 m/h] 1,800 ft/h [549 m/h] 3,600 ft/h [1,097 m/h] 1,800 ft/h [549 m/h] Up to 3,600 ft/h [1,097 m/h]

Range of measurement 0 to 1,000 gAPI 0 to 2,000 gAPI 0 to 2,000 gAPI 0 to 2,000 gAPI 0 to 2,000 gAPI

Vertical resolution 12 in [30.48 cm] 12 in [30.48 cm] 12 in [30.48 cm] 12 in [30.48 cm] 12 in [30.48 cm]

Accuracy ±5% ±5% ±5% ±5% ±5%

Depth of investigation 24 in [60.96 cm] 24 in [60.96 cm] 24 in [60.96 cm] 24 in [60.96 cm] 24 in [60.96 cm]


None None None None None

Combinability Part of Platform Express tool




Combinable with CPLT tool, RSTPro tool



HGNS HTGC SGT QTGC CGRS



Borehole size—min. 4½ in [11.43 cm] 4¾ in [12.07 cm] 4⅞ in [12.38 cm] 3⅞ in [9.84 cm] 113⁄16-in [4.61-cm] seating nipple

Borehole size—max. No limit for gamma ray measurement

No limit No limit No limit No limit

Outside diameter 3.375 in [8.57 cm] 3.75 in [9.53 cm] 3.375 in [8.57 cm] 3.0 in [7.62 cm] 111⁄16 in [4.29 cm]

Length 10.85 ft [3.31 m] 10.7 ft [3.26 m] 5.5 ft [1.68 m] 10.67 ft [3.25 m] 3.2 ft [0.97 m]

Weight 171.7 lbm [78 kg] 265 lbm [120 kg] 83 lbm [38 kg] 180 lbm [82 kg] 16 lbm [7 kg]


Compression 37,000 lbf [164,580 N] 20,000 lbf [88,960 N] 23,000 lbf [103,210 N] 20,000 lbf [88,960 N] 1,000 lbf [4,450 N]


Nuclear Measurements 79

Spectral gamma ray tools provide insight into the mineral composition of formations. The total gamma ray spectra measured is resolved into the three most common components of naturally occurring radiation in sands and shales—potassium, thorium, and uranium (K, Th, and U, respectively). These data are used to distinguish important features of the clay or sand around the wellbore. The clay type can be determined, and sand can be identified as radioactive. The deposi-tion of radioactive salts behind the casing by the movement of water can also be identified.

NGS natural gamma ray spectrometry toolThe NGS* natural gamma ray spec-trometry tool uses five-window spec-troscopy to resolve the total gamma ray spectra into K, Th, and U curves. The standard gamma ray and the gamma ray minus the uranium component are also presented. The computed gamma ray or Th curve can be used to evalu-ate the clay content where radioactive minerals are present.

Hostile Environment Natural Gamma Ray SondeThe increased sensitivity of the HNGS set of detectors improves the tool’s statistical response to the formation gamma rays to produce a better spec-tral analysis than that of previous tools. The improvement in measure-ment also results from the use of two detectors instead of one. The HNGS can log at a faster speed than other tools that measure the formation natural gamma ray emissions. Its 500 degF [260 degC] temperature rating makes it suitable for operations in hot borehole environments.

Applications■ Cation exchange capacity studies■ Reservoir delineation■ Detailed well-to-well correlation■ Definition of facies and

depositional environment■ Igneous rock recognition■ Recognition of other radioactive

materials■ Estimated uranium and potassium

potentials■ Lithologic analysis log input

Spectral Gamma Ray Tools

HNGS




NGS Tool HNGS

Output Gamma ray; corrected gamma ray for uranium; potassium, thorium, and uranium curves

Gamma ray; corrected gamma ray for uranium; potassium, thorium, and uranium curves

Logging speed 1,800 ft/h [549 m/h] 1,800 ft/h [549 m/h]

Range of measurement 0 to 2,000 gAPI 0 to 2,000 gAPI

Vertical resolution 8 to 12 in [20.32 to 30.48 cm] 8 to 12 in [20.32 to 30.48 cm]

Accuracy K: ±0.4% (accuracy), 0.25% (repeatability)

Th: ±3.2 ppm (accuracy), 1.5 ppm (repeatability)

U: ±2.3 ppm (accuracy), 0.9 ppm (repeatability)

K: ±0.5% (accuracy), 0.14% (repeatability)

Th: ±2% (accuracy), 0.9 ppm (repeatability)

U: ±2% (accuracy), 0.4 ppm (repeatability)

Depth of investigation 9.5 in [24.13 cm] 9.5 in [24.13 cm]

Mud type or weight limitations In KCl muds, KCl content must be known In KCl muds, KCl content must be known

Combinability Combinable with most tools Combinable with most tools


NGS Tool HNGS



Borehole size—min. 4½ in [11.43 cm] 4¾ in [12.07 cm]

Borehole size—max. No limit No limit

Outside diameter NGT-C: 3⅝ in [9.21 cm] NGT-D: 3⅞ in [9.84 cm]

3¾ in [9.53 cm]

Length 8.6 ft [2.62 m] 11.7 ft [3.57 m]

Weight NGT-C: 165 lbm [75 kg]

NGT-D: 189 lbm [86 kg]

276 lbm [125 kg]




Litho Scanner high-definition spec-troscopy service employs dual spectral acquisition as the basis for accurate elemental weight fractions, miner-alogy, and lithology—including a stand-alone, quantitative, in situ deter-mination of total organic carbon (TOC). The decay of the gamma ray signal over time can also be simultaneously mea-sured to determine the average ther-mal neutron capture cross section, or sigma (Σ), for characterizing fluids in the pore space. The service combines a high-output pulsed neutron generator (PNG), unique cerium-doped lantha-num bromide (LaBr3:Ce) crystal, and specialized high-performance electron-ics for acquisition and processing to measure both inelastic and capture spectra for an expanded set of key ele-ments in a wide variety of rock forma-tions at higher precision and accuracy than possible from previous-generation spectroscopy tools in both open and cased holes.

In carbonates the measurement of magnesium from the uncontaminated inelastic spectrum is highly useful for clearly distinguishing between calcite and dolomite. The improved sulfur measurement similarly supports the quantification of anhydrite from calcite.

In situ TOC is computed by subtracting the amount of inorganic carbon (IC) associated with carbonate minerals from the total inelastic measurement of carbon. Thus the Litho Scanner service’s TOC consists of the carbon contributions of all organic matter present in the formation: kerogen, oil, bitumen, filtrate, gas, coal, etc. Presented as a continuous wellsite log, instead of individual laboratory measurements, the TOC output is based solely on direct measurements by Litho Scanner service, which makes it independent of the environment and reservoir.

In shale gas reservoirs the in situ TOC is a direct quantification of the kerogen in place. In shale oil reservoirs, comparing the in situ TOC with NMR measurements easily differentiates the movable hydrocarbon from the nonmovable kerogen in place without requiring the use of a multisolver model. In both shale gas and shale oil reservoirs, the matrix density provided by Litho Scanner service is used as a reference to quantify additional density porosity in the kerogen content.

Combinable with most openhole services and conveyed on wireline, drillpipe, or tractor, 4.5-in-OD Litho Scanner service also delivers 4 times better precision than current technology at a higher speed and with outstanding high-temperature performance from the LaBr3:Ce scintillator. No detector cooling system is needed, and the high spectral quality is maintained even during lengthy logging operations at the rated tool temperature of 350 degF [177 degC].

Applications■ Detailed quantitative mineralogy

in complex lithologies■ Real-time element measurements

and robust quantitative lithology– Ca, Fe, Mg, and S for carbonate

lithology– Al, Fe, and Si for siliciclastic

lithology– Al, Ca, Fe, K, and Si for uncon-

ventional reservoirs■ Continuous in situ TOC log

– Kerogen volume in shale oil and shale gas reservoirs

– Weight-percent oil in heavy oil reservoirs and oil sands


Litho Scanner High-Definition Spectroscopy Service


■ Independent measurement of oil volume – Identification of low-resistivity

pay– Identification of oil zones in

freshwater, mixed, and unknown salinity reservoirs

– Better delineation of the oil/water contact in low-permeability reservoirs

■ Formation fluid sigma– Gas identification – Baseline to monitor fluid move-

ment for enhanced oil recovery (EOR)

■ Matrix properties for petrophysical evaluation– Accurate density porosity– Neutron mineralogy correction– Mud-independent photoelectric

factor – Dielectric permittivity and sigma

■ Element logs for well-to-well cor-relation and sequence stratigraphy

■ Cased hole formation evaluation behind casing– Identification of bypassed zones– Wireline measurements as a

complement to LWD

■ Quick, accurate bulk mineralogy and TOC inputs to sCore* lithofacies classification scheme used to target intervals with superior reservoir and completion quality in the Mangrove* engineered stimulation design in the Petrel E&P software platform

■ Metals for mining exploration: Cu, Gd, Ni, and Ti



Litho Scanner Service

Output Elemental yields, elemental weight fractions, TOC, dry-weight mineral concentrations, formation sigma, matrix properties

Logging speed† Max.: 3,600 ft/h [1,097 m/h]

Range of measurement 1 to 10 MeV


Depth of investigation 7 to 9 in [17.78 to 22.86 cm]


Combinability Combinable with most openhole tools Conveyance on wireline, TLC tough logging conditions system, or tractor

Special applications † A tool planner is used to estimate the precision of the elemental concentrations and interpreted properties such as matrix density

for a given environment, with the recommended logging speed depending on the required precision.


Litho Scanner Service

Temperature rating Version A: 284 degF [140 degC] Version C: 350 degF [177 degC]



Borehole size—max. 24 in [60.96 cm]†


Length Version A: 14 ft [4.27 m] Version C: 9 ft [2.74 m]

Weight Version A: 366 lbm [166 kg] Version C: 290 lbm [132 kg]

Tension 55,000 lbf [244,652 N]

Compression 22,500 lbf [100,085 N] † With bow spring


The ECS elemental capture spectroscopy sonde uses a standard 16Ci [59.2 × 1010-Bq] americium beryllium (AmBe) neutron source and a large bismuth germanate (BGO) detector to measure relative elemental yields based on neutron-induced capture gamma ray spectroscopy. The primary elements measured in both open and cased holes are for the formation elements silicon (Si), iron (Fe), calcium (Ca), sulfur (S), titan-ium (Ti), gadolinium (Gd), chlorine (Cl), barium (Ba), and hydrogen (H).

Wellsite processing uses the 254-channel gamma ray energy spec-trum to produce dry-weight elements, lithology, and matrix properties. The first step involves spectral deconvo-lution of the composite gamma ray energy spectrum by using a set of ele-mental standards to produce relative elemental yields. The relative yields are then converted to dry-weight elemen-tal concentration logs for the elements Si, Fe, Ca, S, Ti, and Gd using an oxides closure method. Matrix prop erties and quantitative dry-weight lithologies are then calculated from the dry-weight elemental fractions by SpectroLith lithology processing for spectroscopy tools using empirical relationships derived from an extensive core chem-istry and mineralogy database.

The outputs of SpectroLith lithology processing are■ dry-weight lithology fractions

(from elements)– total clay– total carbonate– anhydrite + gypsum from

S and Ca– QFM (quartz + feldspar + mica)– pyrite– siderite– coal– salt

■ matrix properties (from elements)– matrix grain density– matrix thermal and epithermal

neutron– matrix sigma.

Applications■ DecisionXpress integrated

petrophysical analysis■ Clay fraction independent of

gamma ray, spontaneous potential, and density neutron

■ Carbonate, gypsum or anhydrite, QFM, pyrite, siderite, coal, and salt fractions for complex- reservoir analysis

■ Matrix density and matrix neutron values for more accurate porosity calculation

■ Sigma matrix for cased and open-hole sigma saturation analysis

■ Mineralogy-based permeability estimates

■ Quantitative lithology for rock properties modeling and pore pressure prediction from seismic data

■ Geochemical stratigraphy (chemo-stratigraphy) for well-to-well cor-relation

■ Enhanced completion and drilling fluid recommendations based on clay versus carbonate cementation

■ Coalbed methane bed delineation, producibility, and in situ reserves estimation


ECS Elemental Capture Spectroscopy Sonde

ECS




ECS Sonde

Output Elemental yields, dry-weight elemental fractions, dry-weight SpectroLith lithology, matrix properties

Logging speed 1,800 ft/h [549 m/h]

Range of measurement 600 keV to 8 MeV


Accuracy† ±2% – coherence to standards computed



Combinability Combinable with most tools

Special applications Automatic wellsite petrophysical interpretation † Elemental statistical uncertainty at nominal conditions (1,800-ft/h logging speed, resolution degradation factor of 5, 16,000-cps count rate,

and closure normalization factor of 3): Si 2.16%, Ca 2.19%, Fe 0.36%, S 1.04%, Ti 0.10%, and Gd 3.48 ppm.


ECS Sonde

Temperature rating 350 degF [177 degC] 500 degF [260 degC] (internal flask, CO₂ cooling)

Pressure rating 20,000 psi [138 MPa] High-pressure housing: 25,000 psi [172 MPa]



Outside diameter 5.0 in [12.70 cm] High-pressure housing: 5.5 in [13.97 cm]

Length 10.15 ft [3.09 m]


Tension 50,000 lbf [222,410 N]

Compression 20,000 lbf [88, 960 N]



Compensated neutron tools measure the hydrogen index of downhole for-mations. The measurements are con-verted to porosity values, which in combination with density tool mea-surements provide an indication of lithology and gas in zones of interest. Some compensated neutron tools pro-vide thermal and epithermal measure-ments. Thermal measurements require a liquid-filled borehole. Epithermal measurements can be made in air- or gas-filled boreholes.

CNL compensated neutron logging toolThe CNL compensated neutron logging tool contains a radioactive source that bombards the formation with fast neu-trons. The neutrons are slowed, primar-ily by hydrogen atoms in the formation. Detectors count the slowed neutrons deflected back to the tool. Because the CNL tool responds primarily to the hydrogen content of the formation, the measurements are scaled in porosity units. Both epithermal (intermediate energy) neutrons and thermal (slow) neutrons can be measured depending on the detector design. The CNL tool uses two thermal detectors to produce a borehole-compensated thermal neu-tron measurement. The DNL* dual-energy neutron logging tool (CNT-G) has two thermal and two epithermal detectors that make separate energy measurements for gas detection and improved reservoir description.

Highly Integrated Gamma Ray Neutron SondeThe Highly Integrated Gamma Ray Neutron Sonde (HGNS) is the com-ponent of the Platform Express inte-grated wireline logging tool that

measures neutron porosity. The HGNS contains sensors for neutron porosity determination and makes gamma ray and tool acceleration measurements. Starting from the same neutron poros-ity measurement principle as for the standard CNL tool, the HGNS applies speed correction to the measure-ments, which also benefit from the enhanced reliability characteristics of the Platform Express tool.

SlimXtreme Compensated Neutron Porosity ToolThe SlimXtreme Compensated Neu-tron Porosity Tool (QCNT) provides the same high-quality, environmen-tally corrected thermal neutron poros-ity data as the standard CNL tool. The 3-in [7.62-cm] diameter tool is rated for up to 8 h of continuous logging at 500 degF [260 degC] and 30,000 psi [207 MPa].

CHFP cased hole formation porosity serviceCHFP cased hole formation poros-ity service makes accurate formation porosity and sigma measurements in cased wells. The combination of a pulsed neutron generator with bore-hole shielding and focusing obtains porosity measurements that are affected only minimally by the bore-hole environment. Epithermal neu-tron detection virtually eliminates the effects of thermal neutron absorbers and formation and borehole salinity, as well as sensitivity to matrix density, tool standoff, and temperature.

Neutron Porosity Tools

CNL

QCNT-AHGNS

CHFP


Applications■ Porosity determination■ Lithology identification■ Gas detection■ Correlation in cased wells■ Option to pump slim tools

down drillpipe


Measurement SpecificationsCNL Tool HGNS QCNT CHFP Service

Output Thermal neutron porosity (uncorrected, environmentally corrected, or alpha processed) CNT-G: Epithermal neutron porosity

Thermal neutron porosity (uncorrected, environmentally corrected, or alpha processed), formation gamma ray, tool acceleration

Thermal neutron porosity (uncorrected, environmentally corrected, or alpha processed)

Neutron porosity, formation sigma, measurement quality

Logging speed Standard: 1,800 ft/h [549 m/h] High resolution: 900 ft/h [247 m/h]

3,600 ft/h [1,097 m/h] 1,800 ft/h [549 m/h] Recommended: 900 ft/h [274 m/h] Max.: 1,800 ft/h [549 m/h]

Range of measurement 0 to 60 pu [0 to 60% uncorrected porosity]

Porosity: 0 to 50 pu

Vertical resolution 12 in [30.48 cm] 12 in [30.48 cm] 12 in [30.48 cm] 14 in [35.6 cm]

Accuracy 0 to 20 pu: ±1 pu 30 pu: ±2 pu 45 pu: ±6 pu

0 to 20 pu: ±1 pu 30 pu: ±2 pu 45 pu: ±6 pu

0 to 20 pu: ±1 pu 30 pu: ±2 pu 45 pu: ±6 pu

Porosity: ±1 pu for 0 to 10 pu ±2 pu for 10 to 25 pu ±3 pu for 25 to 40 pu ±4 pu for >40 pu Sigma: ±1 cu for <20 cu

Depth of investigation � 9 in [�23 cm] (varies with hydrogen index of formation) �7 in [�18 cm]†


Thermal measurements not possible in air- or gas-filled wellbores None

Combinability Combinable with most tools Part of Platform Express tool Combinable with most tools Combinable with most toolstrings

Special applications Slim wellbores Short-radius wells Tubing-conveyed logging On tractor

† Depends on casing and cement thickness, with deployment in casing thickness from 0.205 to 0.545 in [5.21 to 13.84 mm] and correction for combined cement and casing thickness up to 1.5 in [3.8 cm]

Mechanical SpecificationsCNL Tool HGNS QCNT CHFP Service

Temperature rating 400 degF [204 degC] 302 degF [150 degC] 500 degF [260 degC] 350 degF [177 degC]

Pressure rating 20,000 psi [138 MPa] 15,000 psi [103 MPa] 30,000 psi [207 MPa] 20,000 psi [138 MPa]

Borehole size—min. 4½ in [12.07 cm] 4½ in [11.43 cm] 4 in [10.16 cm] 4½ in [11.43 cm]

Borehole size—max. 20 in [50.80 cm] 16 in [40.64 cm] 12 in [30.48 cm] 9⅝ in [24.45 cm]

Outside diameter Without bow-spring eccentralizer: 3.375 in [8.57 cm]

3.375 in [8.57 cm] 3 in [7.62 cm] 3.625 in [9.21 cm]

Length 7.25 ft [2.21 m] 10.85 ft [3.31 m] 11.9 ft [3.63 m] 12.94 ft [3.94 m]

Weight 120 lbm [54 kg] 171.7 lbm [78 kg] 191 lbm [87 kgm] 222 lbm [101 kg]

Tension 50,000 lbf [222,410 N] 50,000 lbf [222,410 N] 50,000 lbf [222,410 N] 50,000 lbf [222,410 N]

Compression 23,000 lbf [102,310 N] 37,000 lbf [164,580 N] 15,000 lbf [66,720 N] 23,000 lbf [102,310 N]



APS accelerator porosity sondeThe APS accelerator porosity sonde delivers both epithermal and thermal neutron measurements by using an electronic pulsed neutron generator (PNG) instead of a conventional radioactive chemical source. The combination of the large neutron yield from the PNG and detector shielding incorporated in the tool results in measurements that are relatively insensitive to the borehole environment and formation characteristics, such as lithology and salinity.

Five detectors provide accurate information for conducting porosity evaluation, gas detection, shale evalu-ation with greater vertical resolution, and borehole correction. APS sonde measurements can be performed in both open and cased holes.

A proprietary algorithm computes an equivalent thermal neutron porosity from the hydrogen index and sigma measurements by the APS sonde. Because the calculation is derived using physics and modeling, it is free of the biases typically introduced by empirical techniques. The equivalent thermal neutron porosity from the APS sonde represents the measurement that would be obtained by a traditional thermal neutron tool using an americium beryllium (AmBe) source.

The APS sonde’s thermal neutron porosity measurement provides conti-nuity for comparison with conventional logs while reducing security and envi-ronmental concerns associated with chemical radioactive neutron sources.

Hostile Environment Accelerator Porosity SondeThe Hostile Environment Accelerator Porosity Sonde (HAPS) is a compo-nent of the Xtreme high-pressure, high temperature well logging platform. It provides APS sonde measurements in HPHT environments. The installation of a conventional APS sonde inside a thermal Dewar flask makes HAPS operations possible at bottomhole tem-peratures up to 500 degF [260 degC].

Applications■ Formation evaluation in open hole

and behind casing■ Accurate neutron porosity

measurement in environments with thermal neutron absorbers

■ Accurate hydrogen index measurement

■ Clay analysis■ Gas detection■ Identification of thin pay zones

Array Porosity Measurements

APS




APS Sonde HAPS

Output Hydrogen index, thermal neutron porosity, formation sigma

Neutron porosity index, formation sigma

Logging speed Standard: 1,800 ft/h [549 m/h] High resolution: 900 ft/h [274 m/h] High speed: 3,600 ft/h [1,097 m/h]

Standard: 1,800 ft/h [549 m/h] High resolution: 900 ft/h [274 m/h] High speed: 3,600 ft/h [1,097 m/h]

Range of measurement Porosity: 0 to 60 pu [0 to 60% uncorrected porosity] Porosity: 0 to 60 pu [0 to 60% uncorrected porosity]

Vertical resolution 14 in [35.56 cm] 14 in [35.56 cm]

Accuracy <7 pu: ±0.5 pu 7 to 30 pu: ±7% 30 to 60 pu: ±10% Sigma: ±1 cu [±0.1/m]

<7 pu: ±0.5 pu 7 to 30 pu: ±7% 30 to 60 pu: ±10% Sigma: ±1 cu [±0.1/m]

Depth of investigation 7 in [17.78 cm] 7 in [17.78 cm]

Mud type or weight limitations None None

Combinability Combinable with most services If combined with ECS sonde, the APS sonde must be run below it

Combinable with most services If combined with ECS sonde, the HAPS sonde must be run below it


APS Sonde HAPS



Borehole size—min. 4⅝ in [11.75 cm] 5⅞ in [14.92 cm]

Borehole size—max. 21 in [53.34 cm] 21 in [53.34 cm]

Outside diameter 3.625 in [9.21 cm] Without bow spring: 4 in [10.16 cm]

Length 13 ft [3.96 m] 16 ft [4.88 m]






The unique dual-detector spectrometry system of the through-tubing RSTPro reservoir saturation tool measures the gamma rays that result from inelastic scattering, thermal neutron capture, and neutron activation during the same trip in the well. Processing of the inelastic and capture spectra provides the carbon/oxygen (C/O) ratio, which is used to determine the formation oil saturation independent of formation water salinity that is low or unknown. If the salinity of the formation water is high, the sigma mode measurement of the formation thermal neutron cap-ture cross section is used to calcu-late formation oil saturation in the saline water environment. The mea-surements can also be used to detect and quantify the presence of injection water of a different salinity from that of the connate water.

The RSTPro tool is used with the PS Platform production services plat-form. The tool is available in two sizes to address a range of casing sizes and applications and the issues associated with wellbores under static or flowing conditions: 111 ⁄16-in [4.34-cm] RST-C and 2½-in [6.37-cm] RST-D tools. The RST-D tool has the added advantage of shielded detectors; the near detector is shielded from the formation and the far detector is shielded from the borehole.

Applications■ Formation evaluation behind

casing■ Sigma, porosity, and C/O measure-

ment in one trip in the wellbore■ Water saturation evaluation in old

wells where modern openhole logs have not been run

■ Measurement of water velocity inside casing, irrespective of well-bore angle (production logging)

■ Measurement of near-wellbore water velocity outside the casing (remedial applications)

■ Formation oil volume from C/O ratio, independent of formation water salinity

■ Flowing wells (in combination with an external borehole holdup sensor)

■ Capture yields (H, Cl, Ca, Si, Fe, S, Gd, and Mg)

■ Inelastic yields (C, O, Si, Ca, and Fe)

■ TPHL three-phase borehole holdup

■ PVL* phase velocity log■ Borehole salinity■ SpectroLith processing lithology

indicators

RSTPro Reservoir Saturation Tool

111⁄16-in RST-C 21⁄2-in RST-D




RSTPro Tool

Output Inelastic and capture yields of various elements, carbon/oxygen ratio, formation capture cross section (sigma), porosity, borehole holdup, water velocity, phase velocity, SpectroLith processing

Logging speed† Inelastic mode: 100 ft/h [30 m/h] (formation dependent) Capture mode: 600 ft/h [183 m/h] (formation and salinity dependent) Sigma mode: 3,600 ft/h [1,097 m/h]

Range of measurement Porosity: 0 to 60 pu


Accuracy Based on hydrogen index of formation



Combinability Combinable with the CGRS and tools that use the telemetry system of the PS Platform production services platform

† See tool planner application for advice on logging speed


RST-C RST-D

Temperature rating 302 degF [150 degC] With flask: 400 degF [204 degC]

302 degF [150°C]

Pressure rating 15,000 psi [103 MPa] With flask: 20,000 psi [138 MPa]

15,000 psi [103 MPa]

Borehole size—min. 113⁄16 in [4.60 cm] With flask: 2¼ in [5.72 cm]

2⅞ in [7.30 cm]

Borehole size—max. 9⅝ in [24.45 cm] With flask: 9⅝ in [24.45 cm]

9⅝ in [24.45 cm]

Outside diameter 1.71 in [4.34 cm] With flask: 2⅛ in [5.40 cm]

2.51 in [6.37 cm]

Length 23.0 ft [7.01 m] With flask: 33.7 ft [10.27 m]

22.2 ft [6.76 m]

Weight 101 lbm [46 kg] With flask: 243 lbm [110 kg]

208 lbm [94 kg]





Density tools provide measurements of formation density, formation pho-toelectric factor, and borehole diam-eter. The density data are used to calculate porosity and determine the lithology. The combination of density and CNL tool data is used to indicate the presence of gas.

Three-Detector Lithology DensityThe high-resolution measurements of the Platform Express integrated wireline logging tool include the Three-Detector Lithology Density (TLD) tool, which is housed in the High-Resolution Mechanical Sonde (HRMS). The TLD measures forma-tion density and formation photo-electric factor. Part of the TLD measure ment is called a backscatter density measurement because it uses a third detector located close to the source. Mudcake density, mudcake photoelectric factor, and mudcake thickness are computed using a recur-sive inversion scheme that is based on a large set of data points. This approach provides compensated den-sity and photoelectric factor in non-barite mud and compensated density in barite mud.

Density Tools

QLDT-B

LDS-C

HRMS

HLDS


Litho-Density SondeThe Litho-Density photoelectric density logging sonde (LDS) component of the IPL integrated porosity lithology service measures the formation bulk density and photoelectric factor. It has a pad with a gamma ray source and two detectors. Magnetic shielding and high-speed electronics ensure excellent measurement stability. The LDS records the full-pulse-height gamma ray spectra from both detectors and processes them into windows. Bulk density and photoelectric cross section are derived conventionally from the windows counts with enhanced quality control.

Hostile Environment Lithology Density SondeThe Hostile Environment Lithology Density Sonde (HLDS) is a component of the Xtreme HPHT well logging platform. Its design and operation

are similar to those of the LDS but adapted for hostile environment logging. It is rated to a temperature of 500 degF [260 degC] and pressure of 25,000 psi [172 MPa]. The HLDS uses a pad-mounted gamma ray source and two detectors to make three primary measurements: formation density, long- and short-spacing photo electric factor, and hole diameter.

SlimXtreme Litho-Density ToolThe SlimXtreme Litho-Density Tool (QLDT) is designed for operation in slim and hostile environments with temperature and pressure ratings of 500 degF and 30,000 psi [207 MPa], res pectively. It measures density and photoelectric factor using full spectral data from a three-detector array. The formation density is determined using an extended spine-and-ribs algorithm.

Applications■ Porosity determination■ Lithology analysis and

identification of minerals■ Gas detection■ Hydrocarbon density determination■ Shaly sand interpretation■ Rock mechanical properties

calculations■ Determination of overburden

pressure■ Synthetic seismogram for correlation

with seismic data




Measurement SpecificationsTLD LDS HLDS QLDT

Output Bulk density, porosity, PEF, caliper Bulk density, porosity, PEF, caliper Bulk density, porosity, PEF, caliper Bulk density, porosity, PEF

Logging speed Standard: 3,600 ft/h [1,097 m/h] High resolution: 1,800 ft/h [549 m/h]

Standard: 1,800 ft/h [549 m/h) High resolution: 900 ft/h [274 m/h] High speed: 3,600 ft/h [1,097 m/h]

Standard: 1,800 ft/h [549 m/h] High resolution: 900 ft/h [274 m/h] High speed: 3,600 ft/h [1,097 m/h]

1,800 ft/h [549 m/h]

Range of measurement Bulk density: 1.04 to 3.3 g/cm3 PEF: 0.9 to 10 Caliper: 22 in [55.88 cm]

Bulk density: 1.3 to 3.05 g/cm3 PEF: 1 to 6 Caliper: 16 in [40.64 cm]

Bulk density: 2 to 3 g/cm3 PEF: 1 to 6 Caliper: 16 in [40.64 cm]

Bulk density: 1.3 to 3.05 g/cm3 PEF: 1 to 6 Caliper: 9.5 in [24.13 cm]

Vertical resolution Density: 18 in [45.72 cm] Density: 15 in [38.10 cm] Density: 15 in [38.10 cm] Density: 15 in [38.10 cm]

Accuracy Bulk density: ±0.01 g/cm3† (accuracy), 0.025 g/cm3 (repeatability) Caliper: ±0.1 in [±0.25 cm] (accuracy), 0.05 in [0.127 cm] (repeatability)




Depth of investigation‡ 5 in [12.70 cm] 4 in [10.16 cm] 4 in [10.16 cm] 4 in [10.16 cm]

Mud type or weight limitations Sensitive to barite Sensitive to barite Sensitive to barite Sensitive to barite

Combinability Part of Platform Express tool, combinable with most tools

Combinable with most tools Combinable with most tools Part of SlimXtreme platform, combinable with most tools

Special applications Spectral processing of formation gamma ray measurement

HPHT Spectral processing of formation gamma ray measurement

HPHT Slim wellbores Short-radius wells Tubing-conveyed logging On tractor

† At 1,800 ft/h [549 m/h] in nonbarite mud‡ Average values (depth of investigation depends on density)

Mechanical SpecificationsTLD LDS HLDS QLDT


Pressure rating 15,000 psi [103 MPa] 20,000 psi [138 MPa] 25,000 psi [172 MPa] 30,000 psi [207 MPa]

Borehole size—min. 6 in [15.24 cm] 5½ in [13.97 cm] 4½ in [11.43 cm] 3⅞ in [9.84 cm]

Borehole size—max. 22 in [55.88 cm] 21 in [53.34 cm] 18 in [45.72 cm] 9 in [22.86 cm]

Outside diameter 4.77 in [12.11 cm] 4.5 in [11.43 cm] 3.5 in [8.89 cm] 3 in [7.62 cm]

Length 12.26 ft [3.74 m] 11 ft [3.35 m] 12.58 ft [3.83 m] 14.7 ft [4.48 m]

Weight 314 lbm [142 kg] 292 lbm [132 kg] 402 lbm [182 kg] 253 lbm [115 kg]

Tension 50,000 lbf [222,410 N] 30,000 lbf [133,450 N] 30,000 lbf [133,450 N] 50,000 lbm [222,410 N]

Compression Without stiffener and locked flex head: 4,400 lbf [19,570 N] With stiffener and locked: flex head: 8,000 lbf [35,590 N]

5,000 lbf [22,240 N] 5,000 lbf [22,240 N] 17,000 lbf [75,620 N]


Nuclear Magnetic Resonance Logging


MR Scanner expert magnetic reso-nance service uses multifrequency nuclear magnetic resonance (NMR) measurements in a gradient field design to investigate multiple depths of investigation in a single pass. The measurement depths of the main antenna, ranging from 1.5 to 4 in [3.81 to 10.16 cm], are maintained regard-less of hole size, deviation, shape, or temperature. The deep DOIs—beyond the zone of formation dam-age—make it easy to identify and avoid data-quality problems associ-ated with rugose boreholes, mudcake thickness, and fluids invasion.

The measurement sequence of MR Scanner service produces a detailed evaluation of the near-wellbore region:■ oil and water saturation■ total and effective porosity for the

determination of pore volume and storage capacity

■ bulk volume irreducible water for the determination of water-production rate

■ crude oil T2 distribution for the determination of oil viscosity and to assist in standard T2 log interpretation

■ brine T2 distribution corrected for hydrocarbon effects to improve pore size analysis

■ hydrocarbon-corrected Timur-Coates permeability for the determination of producibility

■ T1 for use when T2 is not available (e.g., logging vuggy porosity or light hydrocarbons).

This detailed profile view of the reservoir fluid contents is insensitive to borehole condition and fluid salin-ity and independent of conventional formation evaluation measurements, such as resistivity and density logs. The combination of MR Scanner service’s diffusion-editing acquisition methods and MRF* magnetic resonance fluid characterization produces robust, advanced fluid characterization, especially in the challenging environ-ments of low-resistivity, low-contrast pay and hydrocarbon-bearing fresh-water formations.

Applications■ Radial profile of fluid volumes

and saturations■ Direct hydrocarbon characteriza-

tion, independent of formation water resistivity and also achiev-able in low-resistivity, low-contrast pay zones and thin beds

■ Formation evaluation, including thin beds, regardless of borehole rugosity or mudcake thickness

■ Thin-bed evaluation with high- vertical-resolution measurements

■ Continuous logging of oil viscosity for perforation and completion optimization

■ Determination of fluid storage volume based on lithology- independent porosity

■ Residual oil saturation in water-base muds and residual water saturation in oil-base muds

Wireline Services Catalog ■ Nuclear Magnetic Resonance Logging 97

MR Scanner Expert Magnetic Resonance Service




MR Scanner Service

Output T1, T2, and diffusion distributions, lithology-independent total porosity, bound- and free-fluid volumes, hydrocarbon-corrected permeability, pore-size distribution

Logging speed Bound-fluid logging: 3,600 ft/h [1,097 m/h] Basic NMR profiling: 1,800 ft/h [549 m/h] T2 radial profiling: 900 ft/h [274 m/h] High-resolution logging: 400 ft/h [122 m/h] T1 radial profiling: 300 ft/h [91 m/h] Saturation profiling: 250 ft/h [76 m/h]

Range of measurement Porosity: 1 to 100 pu T2 distribution: 0.4 ms to 3.0 s T1 distribution: 0.5 ms to 9.0 s

Vertical resolution† Main antenna: 18 in [45.72 cm] High-resolution antenna: 7.5 in [19.05 cm]

Accuracy Total NMR porosity: 1-pu standard deviation, three-level averaging at 75 degF [24 degC] NMR free-fluid porosity: 0.5-pu standard deviation, three-level averaging at 75 degF [24 degC]

Depth of investigation Main antenna: 1.5, 2.3, 2.7, and 4.0 in [3.81, 5.84, 6.86, and 10.16 cm] High-resolution antenna: 1.25 in [3.18 cm]

Mud type or weight limitations Mud resistivity: 0.05 ohm.m‡


Special applications Station logging for MRF characterization Rugose boreholes and thick mudcake

† From measurement point 8.2 ft [2.5 m] above the bottom of the tool ‡ Main antenna only; stacking may be required. Logs have been acquired in 0.02-ohm.m environments with minor loss of precision.


MR Scanner Service




Borehole size—max.† No limit

Outside diameter 5 in [12.70 cm] Cartridge: 4.75 in [12.07 cm]

Length 32.7 ft [9.97 m]

Weight 1,200 lbm [544 kg]

Tension 50,000 lbf [222,410 N]

Compression 7,900 lbf [35,140 N] † In good borehole conditions


The CMR-Plus* combinable mag-netic resonance tool makes NMR measurements of the buildup and decay of the polarization of hydro-gen nuclei (protons) in the liquids contained in the pore space of rock formations. One primary measure-ment of the CMR-Plus tool is the total formation porosity. Borehole NMR measurement is unaffected by solid materials, so the measurement is not sensitive to matrix type and therefore lithology independent. The total porosity can be partitioned into the spectrum of pore sizes present, which provides information on the irreducible water saturation. Perme- ability can be estimated from the free-fluid to bound-fluid ratio and the shape of the pore-size distribution. NMR measurement is also useful for fluid identification because it is a hydrogen index measurement, and various fluids have different hydrogen index values as well as polarization characteristics. NMR data can be pro-cessed to yield formation fluid proper-ties such as gas and oil saturation and oil viscosity.

Applications■ Lithology-independent porosity

for storage quantification■ Pore-size distribution for reservoir

rock quality■ Bound- and free-fluid volume

indicators of reservoir producibility

■ Identification of thin, permeable beds in laminated reservoirs

■ Hydrocarbon identification, especially in low-contrast, low-resistivity pay zones

■ Determination of hydrocarbon pore volume for reserve calculations

■ Improved irreducible water saturation estimates for reducing or eliminating water production

■ Comparison with neutron, density, and data from the MDT modular formation dynamics tester for porosity, lithology, and fluid determination

■ Critical information for setting pipe, determining coring and testing needs, and optimizing completion and fracture programs

■ Integrated solutions of CMR-Plus tool logging and PowerSTIM* well optimization service, combining petrophysical expertise and reservoir knowledge with completion design, execution, and evaluation

■ Salt-saturated muds, deviated and horizontal holes, large (no limit) and small (to 57⁄8-in [14.92-cm]) boreholes

■ Increased efficiency of formation testing program in combination with the MDT tester

Nuclear Magnetic Resonance Logging 99

CMR-Plus Combinable Magnetic Resonance Tool




CMR-Plus Tool

Output Transverse relaxation time (T₂) distribution, total porosity, free- and bound-fluid volumes, permeability determined with Schlumberger-Doll Research (SDR) and Timur-Coates equations, capillary bound porosity, small-pore bound porosity, quality control curves and flags MRF magnetic resonance fluid characterization station log: Saturation; oil, gas, and water volumes; oil viscosity; water and oil T₂ distributions; hydrocarbon-corrected permeability; oil and water log-mean T₂ distributions

Logging speed Bound-fluid mode: 3,600 ft/h [1,097 m/h] Short time constant for the polarizing process (T₁) environment: 2,400 ft/h [731 m/h] Long T₁ environment: 800 ft/h [244 m/h]

Range of measurement Porosity: 0 to 100 pu Minimum echo spacing: 200 us T₂ distribution: 0.3 ms to 3.0 s Nominal raw signal-to-noise ratio: 32 dB

Vertical resolution Static: 6-in [15.24-cm] measurement aperture Dynamic (high-resolution mode): 9-in [22.86-cm], three-level averaging Dynamic (standard mode): 18-in [45.72-cm] vertical resolution, three-level averaging Dynamic (fast mode): 30-in [76.20-cm] vertical resolution, three-level averaging

Accuracy Total CMR porosity standard deviation: ±1.0 pu at 75 degF [24 degC], three-level averaging CMR free-fluid porosity standard deviation: ±0.5 pu at 75 degF [24 degC], three-level averaging

Depth of investigation Blind zone (2.5% point): 0.50 in [1.27 cm] Median (50% point): 1.12 in [2.84 cm] Maximum (95% point): 1.50 in [3.81 cm]



Special applications Station logging for MRF magnetic resonance fluid characterization method


CMR-Plus Tool


Pressure rating 20,000 psi [138 MPa] High-pressure version: 25,000 psi [172 MPa]

Borehole size—min. Without integral bow spring: 5⅞ in [14.92 cm] With integral bow spring: 7⅞ in [20.00 cm]

Borehole size—max. No limit, but must be eccentered

Outside diameter Without bow spring: 5.3 in [13.46 cm] With bow spring: 6.6 in [16.76 cm]

Length 15.6 ft [4.75 m]

Weight Without bow spring: 374 lbm [170 kg] With bow spring: 413 lbm [187 kg]

Tension 50,000 lbf [222,410 N]



Acoustic Logging


Wireline Services Catalog ■ Acoustic Logging 103

The Sonic Scanner acoustic scanning platform provides a true 3D repre-sentation of the formations surround-ing the borehole by scanning both orthogonally and radially. The latest acoustic technology is used to acquire borehole-compensated monopole with long and short spacings, cross-dipole, and cement bond quality measure-ments. In addition to making axial and azimuthal measurements, the fully characterized tool radially mea-sures the formation for both near-wellbore and far-field slowness. The typical depths of investigation are 2 to 3 times the borehole diameter.

The wide frequency spectrum used by the Sonic Scanner platform captures data at a high signal-to-noise ratio, regardless of the formation slowness, and eliminates the need for multiple logging passes. The combination of a longer azimuthal array than on con-ventional acoustic tools—13 stations with 8 azimuthal receivers each—and multiple transmitter-receiver spacings enables the measurement of a radial monopole profile across the near-well-bore altered zone.

A 3D anisotropy algorithm is used to transform compressional, fast- and slow-shear, and Stoneley slowness mea-surements made by the Sonic Scanner platform with respect to the borehole axes to referenced anisotropic moduli. The formation can then be classified as isotropic or anisotropic, along with determining the type and cause of the anisotropy—intrinsic or stress induced from the drilling process.

The Sonic Scanner platform also provides a discriminated cement bond log (DCBL), which is obtained simultaneously with the behind-casing acoustic measurements. The 3- and 5-ft [0.91- and 1.52-m] bond logs and bond quality measurements are independent of fluid and temperature effects and do not require calibration. Additional Sonic Scanner platform capabilities are imaging with greatly improved resolution in comparison with surface seismic and using Stoneley waves for a quick estimation of permeability and to build a continuous mobility profile in sands and carbonates.

Applications■ Identify formation heterogeneity

through anisotropy detection■ Improve 3D seismic analysis

and seismic tie-ins■ Provide input to fluid substitution■ Evaluate well placement

and stability through stress regime identification and pore pressure determination

■ Characterize the reservoir for gas zones, mobility, and open fractures

■ Guide selective perforating for sand control

■ Optimize hydraulic fracturing■ Evaluate cement bond quality

Sonic Scanner Acoustic Scanning Platform




Sonic Scanner Platform

Output Compressional and shear ∆t, full waveforms, cement bond quality waveforms, anisotropy characterization

Logging speed Max.: 3,600 ft/h [1,097 m/h]

Range of measurement Standard shear slowness: <1,500 us/ft [<4,920 us/m]

Vertical resolution <6 ft [<1.82 m] processing resolution for 6-in [15.24-cm] sampling rate

Accuracy ∆t for up to 14-in [35.56-cm] hole size: ±2 us/ft [±6.56 us/m] or ±2% ∆t for >14-in [>35.56-cm] hole size: ±5 us/ft [±16.40 us/m] or ±5%

Depth of investigation Typical presentation of up to 7 borehole radii


Combinability Fully combinable with other tools


Sonic Scanner Platform






Length 41.28 ft [12.58 m] (including isolation joint) Basic toolstring (near monopoles only): 22 ft [6.71 m]

Weight 844 lbm [383 kg] (including isolation joint) Basic toolstring: 413 lbm [187 kg]

Tension 35,000 lbf [155,690 N]



Acoustic Logging 105

The uniquely conveyed ThruBit Dipole* through-the-bit acoustic service pro-vides a detailed acoustic representa-tion of the formations surrounding the borehole for horizontal or difficult-to-access wells. The latest acoustic technology is used to acquire borehole-compensated monopole, cross-dipole, and Stoneley wave measurements.

ThruBit Dipole service’s receiver section has an array of 12 receiver stations spaced 4 in [10.16 cm] apart. The receiver array is 70.2 in [1.78 m] from the monopole transmitter and 78 in [1.98 m] from the dipole transmitters. Each receiver station consists of two pairs of wideband piezoelectric hydrophones aligned with the dipole transmitters. Summing the signals recorded by one pair of hydrophones provides the monopole waveform, whereas finding the difference between them cancels the monopole signal and provides the dipole waveform. When a dipole transmitter is fired, the hydrophone pair diagonally in line with the transmitter is used. Four sets of 12 waveforms can be acquired from the four basic operating modes fired in sequence.

The transmitter section houses two sets of transmitters and a mechanical isolation assembly to prevent direct flexural wave transmission through the tool body of ThruBit Dipole service. A piezoelectric monopole transmitter is fired at standard frequency or a specific low-frequency pulse for Stoneley wave acquisition. The two collocated, perpendicular, piezoceramic bender element dipole transmitters fire a wideband frequency spectrum to capture dipole data at a high signal-to-noise ratio.

A 3D anisotropy algorithm is used to transform compressional, fast- and slow-shear, and Stoneley slowness measurements with respect to the borehole axes to referenced anisotropic moduli. The formation can then be classified as isotropic or anisotropic, along with determining the type and cause of the anisotropy—intrinsic or stress induced from the drilling process.

Applications■ Geophysics

– Velocity calibration, time-depth conversion

– Improved 3D seismic analysis and seismic tie-ins

– Synthetic seismograms– Identifcation of formation

heterogeneity through anisotropy detection

■ Petrophysics– Porosity estimation– Lithology and clay identification– Gas identification

■ Stoneley wave measurement– Fracture evaluation– Permeability (mobility)

■ Geomechanics– Well placement and stability

evaluation based on stress regime identification and pore pressure determination

– Optimized hydraulic fracturing– Guidance for selective

perforating for sand control

ThruBit Dipole Through-the-Bit Acoustic Service




ThruBit Dipole Service†

Output Compressional and shear Δt, full waveforms, anisotropy characterization


Range of measurement Standard shear slowness: <200 us/ft [<656 us/m]

Vertical resolution <44-in [<1.12-m] processing resolution for 6-in [15.24-cm] sampling rate

Accuracy Δt for <8¾-in [22.22-cm] hole size: ±2 us/ft [±6.6 us/m] or ±2%

Depth of investigation Δt: 3 in [7.62 cm]


Combinability Fully combinable with ThruBit services logging strings

Special applications † Limited availability, contact your Schlumberger representative.


ThruBit Dipole Service





Casing OD range 4½ to 5½ in [11.43 to 13.97 cm]


Length 29.11 ft [8.87 m]


Tension 25,000 lbf [111,210 N]

Compression Depends on the configuration and application



The DSI dipole shear sonic imager combines monopole and dipole sonic acquisition capabilities. The trans-mitter section contains a piezoelec-tric monopole transmitter and two electrodynamic dipole transmitters perpendicular to each other. An electric pulse at sonic frequencies is applied to the monopole transmitter to excite compressional- and shear-wave propagation in the formation. For Stoneley wave acquisition a spe-cific low-frequency pulse is used. The dipole transmitters are also driven at low frequency to excite the flexural wave around the borehole and obtain borehole shear measurements in both soft- and hard-rock formations.

The tool is made up of three sec-tions—acquisition cartridge, receiver section, and transmitter section. An isolation joint is placed between the transmitter and receiver sections to prevent direct flexural wave transmis-sion through the tool body.

The receiver section has an array of eight receiver stations spaced 6 in [15.24 cm] apart and 9 ft [2.74 m] from the monopole transmitter, 11 ft [3.35 m] from the upper dipole trans-mitter, and 11.5 ft [3.50 m] from the lower dipole transmitter. Each receiver station consists of two pairs

of wideband-piezoelectric hydrophones aligned with the dipole transmitters. Sum ming the signals recorded by one pair of hydrophones provides the mono-pole waveform, whereas differentiat-ing them cancels the monopole signal and provides the dipole waveform. When a dipole transmitter is fired, the hydrophone pair diagonally in line with the transmitter is used. Four sets of eight waveforms can be acquired from the four basic operating modes fired in sequence.

A special dipole mode enables recording both the inline and cross-line (perpendicular) waveforms for each dipole mode. This mode, called both cross receivers (BCR), is used for anisotropy evaluation.

The optional S-DSI modification to the DSI imager uses a special slow sleeve to extend the slowness measure-ment to 1,200 us/ft [3,937 us/m] from the standard 700 us/ft [2,296 us/m].

As part of the suite of ABC analysis behind casing services, the DSI imager can also provide accurate compressional and shear slowness measurements through casing by using recently developed acquisition strategies and BestDT automated sonic waveform processing.

DSI Dipole Shear Sonic Imager

Transmitter

Isolation joint

Receiver sectionand cartridge


Applications■ Geophysics

– Velocity calibration, time/depth conversion

– Synthetic seismograms– Amplitude variation with offset

(AVO) calibration– Shear seismic interpretation

■ Anisotropy■ Petrophysics

– Porosity estimation (also in cased hole)

– Lithology and clay identification– Gas identification

■ Stoneley wave measurement– Fracture evaluation– Permeability (mobility)

■ Geomechanics– Pore pressure– Wellbore stability– Fracture design– Sand strength

■ Sonic imaging■ Sonic imaging with borehole acous-

tic reflection survey (BARS)– Very long spacing tool

(using spacers)– Reflection analysis– Highly dipping beds– Horizontal wells

(apparent dip > 45°)– Well placement with respect

to cap rock



DSI Imager

Output Compressional and shear ∆t, waveforms, Variable Density log waveforms

Logging speed† Max.: 3,600 ft/h [1,097 m/h]

Range of measurement Standard shear slowness: 700 us/ft [2,297 us/m] S-DSI max. slowness: 1,200 us/ft [3,937 us/m] Max. slowness in casing: 250 to 350 us/ft [820 to 1,148 us/m]

Vertical resolution 3.5-ft [1.07-m] processing resolution for 6-in [15.24-cm] sampling rate

Accuracy ∆t: ±2 us/ft [±6.56 us/m]



Combinability Fully combinable with other tools

Special applications † Actual acquisition speed depends on the number of acquisition modes used and the data sampling rate.


DSI Imager



Borehole size—min. 4¾ in [12.07 cm]


Casing OD range 5½ to 20 in [13.97 to 50.80 cm]

Outside diameter 3⅝ in [9.21 cm]

Length 51 ft [15.54 m] (including isolation joint)


Tension 5,000 lbf [22,240 N]

3,500 lbf [15,570 N]


S-DSI: 1,000 lbf [4,450 N]



Acoustic, or sonic, tools provide a measurement of the formation inte-gral travel time (∆ t) in a variety of environments. Acoustic logs recognize secondary, or vugular, porosity in hard- rock sediments. Acoustic tools can be run in conjunction with density and compensated neutron tools in bad borehole conditions to measure poros-ity, and this third porosity is also used to identify complex lithology. Certain sonic tools can measure shear ∆ t in very slow formations.

Digital Sonic Logging ToolThe Digital Sonic Logging Tool (DSLT) is made up with a Sonic Logging Sonde (SLS) and the Digital Sonic Logging Cartridge (DSLC), which uses the digi-tal telemetry system, to provide either compressional ∆ t measurements or cement bond log (CBL) and Variable Density log (VDL) measurements and digital waveform recording and display. The conventional sonic mea-surements are borehole-compensated (BHC) (3- to 5-ft [0.91- to 1.52-m]) transit time and long-spacing depth-derived BHC (DDBHC) (8- to 12-ft [2.43- to 3.65-m]) transit time. These measurements are made by combin-ing an HSLS-W or HSLS-Z sonde, respectively, with the DSLC. For high-pressure and high-temperature app li -ca tions, the same mea sure ments are available from the Hostile Environ-ment Sonic Logging Tool (HSLT).

SlimXtreme Sonic Logging ToolThe SlimXtreme slimhole, HPHT well logging platform addresses the growth and challenges of HPHT drilling activity. The monopole SlimXtreme Sonic Logging Tool (QSLT) delivers a robust formation slowness using first-motion detection, borehole compen-sation, and slowness-time-coherence (STC) semblance techniques. A 6-in [15.24-cm] high-resolution measure-ment identifies thin-bed slowness. A tool extension provides a long-spacing sonic measurement in unconsolidated formations. Measure ment of CBL amplitudes and VDL waveforms is supported in cased wells.

Applications■ Formation porosity from

compressional slowness■ Shear slowness from STC for

hard rocks■ Formation mechanical properties

from shear slowness■ Correlation to surface seismic data

with synthetic seismograms■ Well placement with respect

to cap rock■ Sonic waveforms for fracture

identification■ CBL and VDL for cased hole

cement evaluation

Monopole Acoustic Tools

QSLT-ADSLT




DSLT and HSLT with BHC or DDBHC Sonde QSLT

Output All sondes: Compressional ∆t SLS-C, SLS-D, and SLS-E: 3-ft [0.91-m] CBL, Variable Density log waveforms

Compressional and shear ∆t, porosity, waveforms and Variable Density log waveforms

Logging speed 3,600 ft/h [1,097 m/h] 3,600 ft/h [1,097 m/h]

Range of measurement 40 to 200 us/ft [131 to 656 us/m] 40 to 400 us/ft [131 to 1,312 us/m]

Vertical resolution

Compressional ∆t 2 ft [0.61 m] Standard: 2 ft [0.61 m] Short spacing: 6 in [15.24 cm]

Shear ∆t SLS-F 8 to 10 ft [2.43 to 3.05 m] or 10 to 12 ft [3.05 to 3.66 m]: 2 ft [0.61 m]

2 ft [0.61 m]

Cement bond log Amplitude: 3 ft [0.91 m] Variable Density log: 5 ft [1.52 m]

Amplitude: 3 ft [0.91 m] Variable Density log: 5 ft [1.52 m]

Accuracy ∆t: ±2 us/ft [±6.6 us/m] ∆t: ±2 us/ft [±6.6 us/m]

Depth of investigation 3 in [7.62 cm] 3 in [7.62 cm]


Combinability Combinable with most services Combinable with most services

Special applications Run on wireline, drillpipe conveyed, or coiled tubing conveyed


DSLT HSLT QSLT



Borehole size—min. 4⅝ in [11.75 cm] 4¾ in [12.07 cm] 4 in [10.16 cm]

Borehole size—max. 18 in [45.72 cm] 18 in [45.72 cm] 8 in [20.32 cm]

Outside diameter 3⅝ in [9.21 cm] 3⅞ in [9.84 cm] 3 in [7.62 cm]

Length SLS-D: 18.73 ft [5.71 m] SLS-F: 23.81 ft [7.26 m]

With HSLS-W sonde: 25.5 ft [7.77 m]

23 ft [7.01 m] With inline centralizer: 29.9 ft [9.11 m]

Weight SLS-D: 273 lbm [124 kg] SLS-F: 353 lbm [160 kg]

With HSLS-W sonde: 440 lbm [199 kg]

270 lbm [122 kg]


Compression 1,650 lbf [7,340 N] With HSLS-W sonde: 2,870 lbf [12,770 N] With HSLS-Z sonde: 1,650 lbf [7,340 N]

4,400 lbf [19,570 N]


Dipmeter and Imaging Services


Quanta Geo photorealistic reservoir geology service redefines imaging in oil-base mud (OBM) with new measurement physics enabled by a simplified electrode geometry and innovative mechanical design to deliver superb resolution and nearly total circumferential coverage in 8-in boreholes. The resulting micro-resistivity images are a true visual representation of the formation geol-ogy, unaffected by the characteristic nonrepresentative artifacts, incom-plete coverage, and low resolution of images from conventional OBM-adapted imagers.

The innovative sonde significantly improves image resolution and clarity by measuring the applied AC current at each of 192 microelectrodes distrib-uted among 8 pads for greatly height-ened sensitivity to both vertical and lateral features. Because Quanta Geo service independently applies each pad to the borehole wall instead of using the pad arms as centralizers, inconsistent pad application is mini-mized in inclined wells and poor hole conditions and Quanta Geo service can acquire primary data during the tool’s descent. Downlogging reduces the frequency and severity of stick-and-slip events and their effects on image quality while efficiently provid-ing comprehensive information early in the logging program to save rig time and additional runs.

Image interpretation is fully powered by the Techlog* wellbore software platform. The wide range of applications enables geologists to readily perform tasks such as distinguishing channels and measuring their orientation. New 2D and 3D visualization methods fill in gaps to provide 360° coverage in larger boreholes and generate virtual core slab images. Workflow results from processing with the Techlog platform are ready to use in the Petrel E&P software platform to refine models and support informed decision making.

Applications■ High-resolution imaging in bore-

holes with nonconductive fluids and OBM– deviated and horizontal wells– irregular and rugose boreholes

■ Sedimentology and sequence stratigraphy

■ Structural and geomechanical analysis and modeling

■ Thin-bed detection and evaluation■ Complement to coring and

formation tester programs

Wireline Services Catalog ■ Dipmeter and Imaging Services 113

Quanta Geo Photorealistic Reservoir Geology Service




Quanta Geo Service

Output Formation images and dip

Logging speed 0.2-in sampling: 3,600 ft/h [1,097 m/h] 0.1-in sampling: 1,800 ft/h [549 m/h]

Range of measurement Sampling rate: 0.1 in [0.25 cm] Borehole coverage: 98% in 8-in [20.32-cm] borehole Formation resistivity: 0.2–20,000 ohm.m

Resolution Vertical resolution: 0.24 in [6 mm] Horizontal resolution: 0.13 in [3 mm]

Accuracy Caliper: ±0.1 in [±0.26 cm] Deviation: ±0.2° Azimuth: ±2°

Depth of investigation 0.2 in [5 mm]

Mud type or weight limitations Nonconductive mud systems such as oil-base mud

Combinability Fully combinable, top and bottom

Special applications Downlogging and uplogging Horizontal wells


Quanta Geo Service


Pressure rating Standard: 25,000 psi [173 MPa] High pressure: 30,000 psi [207 MPa]



Outside diameter Tool: 4.5 in [11.43 cm] Arms section: 6.5 in [16.51 cm]

Length 31.2 ft [9.5 m]


Tension 27,000 lbf [122,300 N]



Dipmeter and Imaging Services 115

Visualization and interpretation of Quanta Geo service’s images are performed using apps in the Techlog wellbore software platform to produce hard data that improves the accuracy of reservoir models in the Petrel E&P software platform.

Next >

Mangrove*UFN modeling

StructuralModeling

FaciesModeling

FractureModeling

Techlog wellbore software program

Hard data

Reservoir model ready

Quanta Geo Engines

Quanta Geo Interpretation

Quanta GeoZ90 Filter

Quanta GeoWizard

Discovery360

Quanta GeoVirtual Core

Quanta GeoVirtual Slab

Quanta Geo Inversion

Wellbore Geomechanics

FractureAnalysis

Structural Analysis

Rock Type

SandCount

PorosityAnalysis

SidewallCoring Advisor

Sedimentology & Stratigraphy

Stress orientation

Failure conditions

Optimal sampling

Core-logdepth tie

Faults

Surfaces

Structural dip

Depositionalarchitecture

3rd & 4th order sequences

Orientation

Density

Porosityheterogeneity

Rock type

Net to gross

Reservoir Geomechanics

PetrophysicalModeling

eXpandBG*Near-Well Model

Zm

Zf

m

Zb

Re(Z)

Im(Z)

Z90



The FMI-HD* high-definition forma-tion microimager takes high-definition imaging to a new level of clarity. The visibility and interpretability of small features is significantly increased for all environmental conditions—even across extreme variations in forma-tion resistivity or resistivity anisot-ropy between the formation and mud (Rt/Rm). This means that environ-ments that cannot be clearly imaged with conventional microresistivity imaging technology can now be seen in great detail, including wells drilled with salt-saturated muds or high-resistivity reservoirs.

The FMI-HD high-definition formation microimager builds on the well-proven microresistivity imaging design of the industry-standard FMI fullbore formation microimager. Completely new electronics provide a step-improvement in operating range, reliability, and image quality. Enhanced parallel signal processing and high-resolution analog-to-digital conversion improve the tool’s signal-to-noise ratio to increase the sensitivity to fine contrasts in formation resistivity. The result is an increase in image definition by a factor of four.

The microresistivity image of the borehole wall is created from the current measured by the tool’s array of 192 buttons on four pads. Microresistivity changes related to lithologic and petrophysical varia-tions in the rock, which are con-veyed mainly by the high-resolution current component, are interpreted on the image in terms of rock texture, stratigraphic and structural features including dip, and fractures.

Automatic signal processing optimization of the FMI-HD micro-imager eliminates manual setting of the tool parameters. Wellsite opera-tions are streamlined as the entire dynamic range of formation resistivity

is imaged in one run. Even in environ-ments with Rt/Rm ratios as high as 200,000:1, the FMI-HD microimager obtains clear, representative images of the formation geology.

Applications■ Structural analysis and modeling

– 3D near-wellbore and interwell structural modeling

– Structural cross sections– Detection and determination of

faults, folds, and unconformities– True, accurate structural dip

in almost any formation■ Naturally fractured reservoir

characterization and modeling– Discrete fracture network

(DFN) modeling– Direct visual quantification of

fracture orientation and density– Quantification of fracture

aperture and fracture porosity■ Secondary porosity evaluation in

carbonate and igneous reservoirs– Quantification of matrix and

vuggy fractions of porosity– Partitioning of isolated,

connected, and fracture-connected vuggy porosity

– Direct visual identification of macroporosity and nonporous nodules

– Estimation of permeability and variable cementation exponent m

■ Thin-bed detection and evaluation– Layer delineation for high-

resolution deterministic petrophysical evaluation

– Fast quantification of interval net-to-gross ratio and net pay

– Direct visualization of beds down to millimeter scale

FMI-HD High-Definition Formation Microimager



■ Reservoir characterization workflow– Direct visual or automatic

textural classification of facies and rock types

– Realistic population of reservoir bodies with petrophysical parameters

– Recognition of anisotropy, permeability barriers, and permeability paths

■ Sedimentology and sequence stratigraphy– Deterministic or stochastic

modeling of reservoir bodies– Definition and characterization

of sedimentary bodies and their boundaries

– Qualitative vertical profiles of grain size and stacking pattern

– Paleocurrent directions■ Geomechanics

– Determination of principal stress directions

– Calibration of mechanical earth model (MEM)

– Mud weight selection■ Complement to coring and formation

tester programs– Depth matching and orientation

for whole cores– Reservoir description for

intervals not cored

– Information about the reservoir before core analysis is available

– Depth matching for sidewall core samples and wireline formation testers


FMI-HD Microimager

Output Formation images and dip

Logging speed Image mode: 1,800 ft/h [549 m/h] Dipmeter mode: 3,600 ft/h [1,097 m/h]

Range of measurement Sampling rate: 0.1 in [0.25 cm] Borehole coverage: 80% in 8-in [20.32-cm] borehole

Vertical resolution Horizontal resolution: 0.2 in [0.51 cm] Vertical resolution: 0.2 in [0.51 cm]


Depth of investigation High-frequency component (image details): 0.39 in [1 cm] Low-frequency component (for calibration to resistivity logs): 30 in [76.2 cm]

Mud type of weight limitations Water-base mud (max. mud resistivity = 50 ohm.m) Oil-base mud under specific conditions†

Combinability Bottom-only tool, combinable with most tools

Special applications Horizontal wells † For oil-base mud, contact your Schlumberger representative.


FMI-HD Microimager



Borehole size—min. 6½ in [15.87 cm] 5⅞ in [14.92 cm] in good hole conditions using a kit


Outside diameter 5 in [12.70 cm]

Length 25.43 ft [7.75 m]


Tension 12,000 lbf [53,380 N]




The FMI fullbore formation micro-imager provides an electrical borehole image generated from up to 192 microresistivity measurements. Special focusing circuitry ensures that the measuring currents are forced into the formation, where they modulate in amplitude with the formation conductivities to produce low-frequency signals rich in petro-physical and lithological information and a high-resolution component that provides the microscale information used for imaging and dip interpretation. Image calibration is achieved through calibration with low-frequency, deeper resistivity measurements available from the tool signal or input from other resistivity measurements, such as from the AIT array induction imager tool or ARI azimuthal resistivity imager. Image normalization further increases the completeness and reliability of this versatile tool for geological and reservoir characterization.

The combination of measuring button diameter, pad design, and high-speed telemetry system produces a vertical and azimuthal resolution of 0.2 in [0.51 cm] for the FMI imager. This means that the dimensions of a feature larger than 0.2 in can be estimated from the image. The size of features smaller than 0.2 in is estimated by quantifying the current flow to the electrode. Fine details such as 0.002-in [0.051-mm] wide fractures filled with conductive fluids are visible in images from the FMI imager.

The answers provided by the FMI imager help in understanding the reservoir structure, identify and evaluate sedimentary features and fractures, visualize rock texture, and complement coring programs. FMI imager data are increasingly used for geomechanical analysis of the reservoir. Drilling-induced features such as breakouts are readily identified. In combination with stress field analysis, FMI imager information is used to control wellbore stability problems by guiding design of the mud program.

FMI Fullbore Formation Microimager



Applications■ Structural geology

– Structural dips, even in fractured and conglomeratic formations

– Detection and determination of faults

■ Sedimentary features– Determination of sedimentary

dips– Paleocurrent directions– Definition and characterization

of sedimentary bodies and their boundaries

– Recognition of anisotropy, permeability barriers, and permeability paths

– Recognition and evaluation of thinly bedded reservoirs

■ Rock texture– Qualitative vertical grain-size

profile– Determination of carbonate

texture– Detection and evaluation

of secondary porosity– Detection and evaluation

of fracture systems■ Complement to coring and formation

tester programs– Depth matching and orientation

for whole cores– Reservoir description for intervals

not cored– Information about the reservoir

before core analysis is available– Depth matching for sidewall core

samples and MDT tester settings

■ Geomechanics– Identification and analysis

of drilling-induced features– Calibration data for mechanical

earth model (MEM)– Mud weight selection

■ Reservoir characterization workflow– Deterministic modeling

of reservoir bodies– Guidance for the distribution

of stochastically modeled reservoir bodies

– Realistic population of reservoir bodies with petrophysical parameters


FMI Microimager

Output Formation dip, borehole images

Logging speed Image mode: 1,800 ft/h [549 m/h] Dipmeter mode: 3,600 ft/h [1,097 m/h]

Range of measurement Sampling rate: 0.1 in [0.25 cm] Borehole coverage: 80% in 8-in [20.32-cm] borehole

Vertical resolution Spatial resolution: 0.2 in [0.51 cm] Vertical resolution: 0.2 in [0.51 cm]



Mud type or weight limitations Water-base mud (max. mud resistivity = 50 ohm.m)


Special applications Horizontal wells


FMI Microimager



Borehole size—min.† 6¼ in [15.87 cm]



Length 24.42 ft [7.44 m]

Weight 433.7 lbm [197 kg]

Tension 12,000 lbf [53,380 N]

Compression 8,000 lbf [35,580 N] † 5⅞ in [14.92 cm] in good hole conditions using a kit



The UBI* ultrasonic borehole imager produces high-resolution acoustic images of the wellbore in water-base or oil-base mud. The images are used to identify dipping beds, fractures, and other features intersecting the borehole. Critical information on borehole stability and breakouts can be derived from the accurate borehole cross section measured by the tool.

The UBI imager has a transducer that is mounted on an Ultrasonic Rotating Sub (USRS). The transducer emits ultrasonic pulses and measures the transit time and amplitude of the resulting echo. The transducer assembly is available in a variety of sizes to match the complete range of normal openhole sizes. The transducer subassembly is also selected to optimize the distance traveled by the ultrasonic pulse in the borehole fluid, which reduces attenuation in heavy fluids and maintains a good signal-to-noise ratio.

The UBI tool is relatively insen-sitive to eccentralization—up to 0.25 in [0.63 cm]—and provides clean images that are easy to interpret, even

in highly deviated wells. Processing software available both in MaxWell integrated field acquisition software and at Data Services Hubs further enhances the images by correcting amplitude and transit-time informa-tion for the effects of logging speed variations and tool eccentering and by applying noise filtering. The images are oriented with inclinometer data from the combinable GPIT general purpose inclin ometry tool and then enhanced by dynamic normalization for easy visual interpretation.

Applications■ Fracture identification including

drilling-induced fractures■ Differentiation of closed and open

fractures (in combination with the OBMI* oil-base microimager)

■ Borehole profiling and calculation of cement volume

■ Stress analysis and borehole stability studies

■ Mud weight selection

■ Structural and bedding analysis

UBI Ultrasonic Borehole Imager

Interchangeablerotating subs




UBI Imager

Output Borehole images, amplitude, and transit time in analog and digital imagery

Logging speed 425 to 2,125 ft/h [130 to 648 m/h] (depends on desired resolution)

Range of measurement 4⅞ to 12⅞ in [12.38 to 32.70 cm]

Vertical resolution 0.2 in [0.51 cm] at 500 kHz 0.4 in [1.02 cm] at 250 kHz 0.6 in [1.52 cm] at 250 kHz 1.0 in [2.54 cm] at 250 kHz Azimuthal sampling: 2.0° or 2.6°

Accuracy Borehole radius: ±0.12 in [±3 mm] (absolute) Resolution: 0.003 in [0.075 mm] at 500 kHz

Depth of investigation Borehole wall

Mud type or weight limitations High mud weights (>15 ppg) can cause significant signal attenuation




UBI Imager



Borehole size—min. 4⅞ in [12.38 cm]

Borehole size—max. 12⅞ in [32.70 cm]

Outside diameter Without sub: 3.375 in [8.57 cm]

Length 21 ft [6.40 m]

Weight 377.6 lbm [171 kg] (with 7-in [17.78-cm] USRS-B sub)

Tension 40,000 lbf [177,930 N]




The OBMI oil-base microimager extends microresistivity imaging to the environment of nonconductive, invert-emulsion mud systems. The increasing use of oil- and synthetic-base mud systems to limit drilling risks and improve efficiency poses many challenges for formation imaging. Even a thin film of nonconductive mud is essentially an opaque curtain, preventing conventional microresistivity imagers from measuring the formation. The presence of non conduc tive mudcake or mud filtrate further complicates the situation. The OBMI imager meets these challenges by integrating unique technology with simple resistivity logging principles to produce an image that enables virtual visualization of the reservoir.

The short-normal resistivity prin-ciple employed is inherently quantita-tive and does not require calibration with another log. Petrophysicists frequently use the Rxo measurement from the OBMI imager to discrimi-nate sand and shale beds as thin as 1.2 in [3.05 cm]. Geologists use OBMI imager logging to recognize bedding and other sedimentary features as small as 0.4 in [1.02 cm], the tool mea-surement aperture. Open and closed fractures smaller than 0.4 in have also been successfully imaged.

The OBMI2* integrated dual oil-base microimagers use two OBMI sondes at a 45° offset to double the hole coverage.

High-pressure, high-temperature and slimhole versions of the OBMI imager are available on a limited basis.

Applications■ Structural analysis

– Structural dip determination– Fracture and fault detection

■ Stratigraphic analysis– Characterization of

sedimentary deposits– Stratigraphic dip determination– Thin-bed detection

■ Core analysis– Depth matching– Orientation– Missed interval coverage

■ Compartmentalization and permeability analyses

■ High-resolution net pay count■ Sample and formation test

positioning■ Detection of drilling-induced

features■ Detection and measurement

of features too small for conventional logs

■ Detection of anisotropic features■ Differentiation of structural

and stratigraphic features■ Flexibility in choosing mud

systems■ Quantitative measurement

of invaded zone resistivity

OBMI Oil-Base Microimager




OBMI Imager

Output High-resolution, oriented formation images, dual-axis caliper


Range of measurement 32% coverage in 8-in [20.32-cm] borehole

Vertical resolution 0.4-in [1.02-cm] nominal image resolution 1.2-in [3.05-cm] petrophysical resolution

Accuracy ±20%

Depth of investigation 3.5 in [8.89 cm]

Mud type or weight limitations Operates in any oil-, diesel-, or synthetic-base mud

Combinability Top and bottom combinable Slim OBMI and OBMI2 imagers: bottom-only

Special applications Wireline or TLC tough logging conditions system


OBMI Imager

Temperature rating 320 degF [160 degC] 350 degF [177 degC]†

Pressure rating 20,000 psi [138 MPa] 25,000 psi [173 MPa]†

Borehole size—min. Standard: 7 in [17.78 cm] Slim OBMT-E: 6 in [15.24 cm]

Borehole size—max. 16 in [40.64 cm] Caliper: 17½ in [44.45 cm]

Outside diameter Standard: 5.75 in [14.60 cm] Slim OBMT-E: 5.25 in [13.33 cm]



Tension 50,000 lbf [222,410 N]

Compression Standard: 10,000 lbf [44,482 N] Slim OBMT-E: 8,000 lbf [35,590 N]

† Limited availability


Drilling and Directional Services


The GPIT general purpose inclinom-etry tool provides inclinometer mea-surements. Tool orientation is defined by three parameters: tool deviation, tool azimuth, and relative bearing. The GPIT tool uses both a three-axis inclinometer and a three-axis magne-tometer to make mea surements for determining these parameters.

The basic principle of downhole inclinometer measurements is to accurately define the tool system axis with respect to the Earth’s gravity (G) and magnetic field (F). Because both vectors are well defined within the Earth system, a relation can be established between the tool and Earth systems. The magnetometer determines Fx, Fy, and Fz, and the inclinometer determines Ax, Ay, and Az for the acceleration due to G. MaxWell integrated field acquisition software computes deviation, azimuth, and relative bearing from these values.

When the GPIT tool is used in an open wellbore, the tools above and below it must have nonmagnetic housings. In cased hole the tool can be used only for deviation and relative-bearing measurements.

Applications■ Borehole azimuth■ Borehole deviation■ Borehole relative bearing■ Tool azimuth information■ Deviation and direction of uncased

wellbores for plotting■ Direction and orientation measure-

ments for various dipmeters■ Orientation of USI* ultrasonic

imager tool images with respect to the wellbore

Wireline Services Catalog ■ Drilling and Directional Services 127

GPIT General Purpose Inclinometry Tool




GPIT Tool

Output Borehole azimuth, deviation and relative bearing, tool azimuth


Range of measurement 0 to 360°


Accuracy Azimuth: ±2° (for deviation between 5° and 175°) Deviation: ±0.2°

Depth of investigation Not applicable


Combinability Combinable with most services, anywhere in the logging string (tools immediately above and below must have nonmagnetic housings)



GPIT Tool



Borehole size—min. 4⅝ in [11.75 cm]

Borehole size—max. No limit




Tension 50,000 lbf [222,410 N]



Seismic Imaging Tools and Services


The Q-Borehole* integrated borehole seismic system optimizes all aspects of borehole seismic services, during wireline operations and while drilling.

VSI versatile seismic imagerThe VSI* versatile seismic imager uses Q-Technology* point-receiver seismic hardware and software and advanced wireline telemetry for efficient data delivery from the borehole to the sur-face. Each sensor package delivers high-fidelity wavefields through the use of three-axis geophone accelerometers, which are acoustically isolated from the main body of the tool. The number of sensors, intersensor spacing, con-nection type (either stiff or flexible), and tool diameter are field configu-rable to ensure the maximum versatility of the array. The design focus of the VSI imager on data fidelity and quick adaptation to changing survey needs avoids the compromise in data quality that typically results from efficiency limitations. The result is sharper, more accurate images and reduced operating logistics, which are fundamental ele-ments for achieving complex surveys in a cost-effective manner and with timely delivery of answer products.

The operating efficiency of the VSI imager is enhanced by■ rapid mechanical deployment■ very little time between stations■ short shot-cycle time during

remote source surveys (walkaway, offset VSP)

■ real-time quality control and data processing.

Applications■ Integrated processing for

interpretation of borehole and surface seismic data

■ Images for reservoir definition ■ Images ahead of the bit ■ 3D VSPs■ Pore pressure predictions ■ Planning for well placement■ Simultaneous surface and bore-

hole seismic recording for high-definition images

■ Shear wave processing and analysis■ Microseismic monitoring during

hydraulic fracturing

Wireline Services Catalog ■ Seismic Imaging Tools and Services 131

Q-Borehole Integrated Borehole Seismic System




VSI Imager

Output Seismic waveform produced by acoustic reflections from bed boundaries

Logging speed Stationary Seismic waveform recording: 0.5-, 1-, 2-, or 4-ms output sampling rate

Array capability Up to 40 shuttles

Sensor package

Length 11.4 in [28.96 cm]

Weight 6.4 lbm [2.9 kg]

Sensor Geophone accelerometer (GAC-D)

Sensitivity >0.5 V/g ± 5%

Sensor natural frequency 25 Hz Flat bandwidth in acceleration: 2 to 200 Hz

Dynamic range >105 dB at 36-dB gain

Distortion <–90 dB

Digitization 24-bit analog-to-digital converter

Combinability Bottom-only combinable

Special applications Conveyance on wireline, TLC system, or tractor Through drillpipe


VSI Imager





Outside diameter Standard: 3⅜ in [8.57 cm] Slim: 2½ in [6.35 cm]

Length Up to 1,040 ft [317 m] for 20 shuttles

Weight Up to 2,200 lbm [998 kg]

Tension 18,000 lbf [80,070 N]

Compression Standard: 5,000 lbf [22,240 N] With stiffener: 10,000 lbf [44,480 N]

Coupling

Anchoring force 246 lbf [1,170 N] in 3-in [7.62-cm] hole 214 lbf [915 N] in 6-in [15.24-cm] hole 255 lbf [1,130 N] in 12¼-in [31.75-cm] hole 160 lbf [951 N] in 17-in [43.18-cm] hole

Sensor package coupling force 64 lbf [285 N]

Coupling force/sensor weight ratio 10:1


SWINGS seismic navigation and positioning systemThe SWINGS* seismic navigation and positioning system is used to accurately deploy seismic source equipment and control source vessel position. It is com-patible with the integrated Q-Borehole seismic system. SWINGS system capa-bilities include borehole seismic con-figurations encom passing complex 3D VSP geometries and seismic measure-ment while drilling to optimize borehole seismic operations while providing a consistently high level of service quality.

The SWINGS system continually relays source position, fix quality, and other data to the rigside logging unit, where they are displayed graphically. The submeter accuracy of the global positioning system (GPS) provides source determination within 10 to 16 ft [3 to 5 m]. The source position is passed to MaxWell integrated field acquisition software at every shot for immediate recording with the seismic trace headers to eliminate any delay in merging navigation and seismic data.

Specifications of this portable and robust system include■ twin internal 12-channel GPS

receivers■ pressure transducer interface

for gun pressure monitoring■ ultrahigh-frequency (UHF)

telemetry link■ dedicated display at the helm.

Application■ Accurate source deployment

and positioning for all borehole seismic surveys

Seismic Imaging Tools and Services 133


TRISOR acoustic source control elementThe TRISOR* acoustic source control element for the integrated borehole seismic system was developed from the industry-leading WesternGeco TRISOR marine seismic source controller to provide the same stable, noise-free dig-ital signatures with advanced source control and quality control (QC). TRISOR control delivers the clean, con-sistent signals necessary for advanced borehole seismic applications, and the consistent signals also enable fast auto-tuning for more efficient operations and more powerful source strength. In-sea electronics control each gun and are connected by a ruggedized eth-ernet cable for digital communication with the surface acquisition system of the VSI imager. This configuration avoids the corruption that may occur to

analog signals carried on conventional umbilicals. The direct interface to the acquisition software allows monitor-ing surface and downhole operations from one integrated QC panel, which eliminates shot number mismatches and ensures accurate recording and reporting of source positioning and downhole data.

Gun synchronization accuracy of the TRISOR element is typically 0.1 ms. Continuous monitoring of the QC data significantly reduces the possibility of continuing a survey if there is an equip-ment malfunction. Safety is also intrin-sic to operations with the TRISOR element because the guns cannot be fired while out of the water, and the TRISOR element defaults to automatic power-down mode if the cable becomes disconnected or leakage is detected.

Other features are as follows:■ Depth sensor at source—The source

depth is logged with each shot, but if the measured source depth is not in a specified range, the source is prevented from firing.

■ Pressure sensor at source—The source pressure is logged with each shot. The pressure sensor prevents source signature variations caused by variations of source pressure.

■ Calibrated near-field hydrophone (NFH)—The integrated NFH pro-vides a superior signal compared with conventional hydrophones for sig-nificantly improved source-signature deconvolution.

Applications■ Borehole seismic applications that

require a high-quality, consistent source signature with calibrated amplitude

■ Shot-by-shot source signature deconvolution

■ Effective Q-factor derivation from source to downhole sensor by using the near-field signature to generate calibrated far-field signature



TRISOR Acoustic Source Control Element

Gun time break (TB) sensor 12-bit resolution at 0.1-ms sampling Gain: –24 to 24 dB

NFH 16-bit resolution at 0.25-ms sampling Gain: –24 to 24 dB

Depth sensor 12-bit with one sample per shot Accuracy: ±1.5%

Pressure sensor 12-bit with one sample per shot Accuracy: ±2%

Auxiliary measurements Electronics current, temperature, pressure, humidity


TRISOR Acoustic Source Control Element

Temperature rating Operating: 5 to 131 degF [–15 to 55 degC] Storage: –40 to 158 degF [–40 to 70 degC]

Max. recommended operating depth below sea level

33 ft [10 m]


Q-Borehole integrated borehole seismic systemThe dedicated synchronization equip-ment of the Q-Borehole system enables conducting simultaneous surface and borehole seismic acquisition with WesternGeco Q-Land* and Q-Marine* point-receiver seismic systems and the Q-Seabed* multicomponent sea-bed seismic system. The VSI vertical seismic imager is integrally controlled by the surface acquisition process to provide a transparent acquisition process and eliminate the need for additional survey time. The result is high-resolution seismic data around the well.

Applications■ Borehole calibration of surface

seismic■ Optimized reconciliation of log with

borehole and surface seismic data■ Merged navigation records and

con sistency of seismic source and wavelet between borehole and surface seismic data for enhanced and faster processing and interpretation

■ Borehole data to optimize surface seismic acquisition through tuning



DeepLook-CS* crosswell seismic imaging service uniquely combines wellbore sonic sources and receivers to provide up to 100 times the resolution of conventional surface seismic. With these high-resolution reservoir images, operators now have the information they need to engage truly proactive development strategies and optimize production throughout the entire life cycle of the reservoir.

Crosswell imaging employs a seis-mic source and receivers, both placed in wells at the depth of the reservoir. To image reservoir intervals with a vertical resolution of 5 ft [1.5 m], the DeepLook-CS service passes specially engineered sonic energy through the zone of interest, from source to receiver. The piezoelectric source is normally operated while moving for fast acquisition. Velocity, reflection, and other sonic properties are mea-sured to provide structural and physi-cal characteristics of the zone in both the horizontal and vertical directions.

Applications■ Reservoir characterization■ Bypassed pay identification■ Enhanced oil recovery■ CO2 sequestration■ Waterflooding monitoring■ Unconventional gas■ Heavy oil and thermal operations


DeepLook-CS Crosswell Seismic Imaging Service



DeepLook-CS Service Interwell Distance†

Source Well Receiver Well Well Spacing, ft [m]

Cased hole Cased hole 100–3,280 [30–1,000]

Open hole Open hole 100–3,280 [30–1,000] † Depends on noise, completion, and formation attenuation characteristics.


DeepLook-CS Service Piezoelectric Source DeepLook-CS Service Hydrophone Receiver Array

Temperature rating, degF [degC] 302 [150] 350 [177]

Pressure rating, psi [MPa] 10,000 [69] 10,000 [69]

Well size—min., in [cm]

Open hole 4.5 [11.5] 2.25 [5.7]

Cased hole 4.5 [11.5] 2.25 [5.7]

Well size—max., in [cm]

Open hole No limit No limit

Cased hole No limit No limit

Outside diameter, in [cm] 3.5 [8.9] 1.6875 [4.2]

Length, ft [m] 17.2 [5.24] Twenty levels,† 5-ft spacing: 118 [36] Twenty levels,† 10-ft spacing: 218 [66.4]

Mud type or weight limitations No fluid restrictions No fluid restrictions

Frequency range, Hz 100–2,000 100–4,000 † Eight hydrophones per level


The CSI* combinable seismic imager is a three-axis borehole seismic acquisition tool for open- and cased hole applications. The CSI imager is designed to physically isolate the sensor components from the heavy tool body during seismic acquisition. The small size and low mass of the sensor module and the strong anchoring force of the tool ensure optimal acoustic coupling, even in soft formations, which guarantees the high quality of

the recorded seismic data. The CSI imager is self-combinable using stiff or flexible interconnects, and it is also fully combinable with other logging tools. Deployment can be on wireline, TLC tough logging conditions system, or wireline tractor.

Applications■ Time-depth determination■ Vertical seismic profiles (VSPs)


CSI Combinable Seismic Imager


CSI Imager

Output Seismic waveform produced by acoustic reflections from bed boundaries

Logging speed Stationary Seismic waveform recording: 1-, 2-, or 4-ms output sampling rate

Array capability Up to 4 tools

Sensor package


Weight 19.9 lbm [9 kg]

Sensor Geophone accelerometer (GAC-A)

Sensitivity >0.5 V/g ± 5%

Sensor natural frequency 25 Hz Flat bandwidth in acceleration: 2 to 200 Hz

Dynamic range 90 dB

Distortion <–60 dB

Digitization 16 bit


Special applications Conveyance on wireline, TLC system, or tractor




CSI Imager




Borehole size—max. 19 in [48.26 cm] With extension: 22 in [55.88 cm]

Outside diameter 4⅝ in [11.75 cm] Without standoff: 4 in [10.16 cm]

Length 17.8 ft [5.42 m]


Tension 50,000 lbf [222,240 N]


Coupling

Anchoring force 630 lbf [2,800 N] in 5-in [12.70-cm] hole 719 lbf [3,200 N] in 10-in [25.40-cm] hole 1,124 lbf [5,000 N] in 19-in [28.26-cm] hole

Sensor package coupling force 240 lbf [1,067 N]

Coupling force/sensor weight ratio 10:1


The new Q-Borehole Explorer* truck vibrator meets the challenges of borehole seismic acquisition in deeper and more complex formations while it also improves the safety, data quality, and efficiency of conventional truck-based vibrators.

Using the low-frequency-enhanced MD Sweep* maximum-displacement transmission method, the truck vibrator delivers the high-output, wide-bandwidth, low-distortion vibroseis signal required for modern borehole seismic operations. MD Sweep transmission efficiently achieves full power at the displacement limit of the Q-Borehole Explorer truck vibrator by optimally adjusting the drive rate and force level at the beginning of the sweep. Tests demonstrate that this sweep design can add up to half an octave of full-power, low-frequency bandwidth over that possible using conventional sweeps.

The truck vibrator’s design is optimized for both on- and off-road mobility. Trailer transport to and from the wellsite is not necessary

for land operations using the Q-Borehole Explorer truck. The truck vibrator is US highway compliant, and its eight-wheel drive and ground clearance provide excellent off-road agility. Four drive axles evenly distribute vehicle weight for stability and low ground pressure on station. The result is excellent ground coupling, which in combination with optimized hydraulic flow to the vibrator actuator delivers strong, low-frequency energy.

Applications■ All US land borehole seismic

applications requiring a high-output, wide-bandwidth, low-distortion vibroseis source

■ Look-ahead and acoustic impedance (AI) inversion applications requiring strong, low-frequency energy down to deep targets


Q-Borehole Explorer High-Output, Wide-Bandwidth Truck Vibrator


Q-Borehole Explorer Truck

Vehicle length 438 in [11.13 m]

Vehicle wheelbase 265 in [6.73 m]

Vehicle width 101 in [2.56 m]

Vehicle height 151 in [3.84 m]

Vehicle gross weight 59,000 lbm [27,000 kg]

Hold-down weight 54,000 lbm [24,500 kg]

Peak hydraulic force 60,000 lbf [267,000 N]

Baseplate clearance, moving 13 in [33 cm]

Maximum vehicle speed† 70 mi/h [113 km/h]

Emission compliance Deck and vehicle engines: California and US EPA continental standards

Ambient operating temperature –30 to 130 degF [–34 to 54 degC] † Subject to local regulations and road conditions



Other land seismic sourcesSchlumberger provides land borehole seismic sources suitable for all types of terrain.

In open terrain, the vibrator source provides the best productivity with the frequency range and strength controlled to meet survey requirements.

In difficult or wet terrain where access by vibrator vehicles is restricted, the buried airgun, positioned below the weathered zone, provides a consistent broad-bandwidth source that is ideal for zero- and fixed-offset survey geometries. The slim housing provides ease of hole drilling, deployment, and retrieval.

Dynamite is a lightweight, high-band-width source that is ideal for moving source geometries such as walkaway lines in difficult or wet terrain.

Applications ■ Fixed and moving source

geometries for VSP surveys■ Sources for all types of terrain


Schlumberger offers a range of standard marine seismic sources of different strengths. Sources are designed to output predictable and consistent source signatures. All sources have been fully characterized through recording of far-field signatures. Spectral outputs are characterized for deployment depth, operating pressure, and array volume. All sources are mechanically qualified to ensure safety and reliability. When used with the TRISOR acoustic source control element, full QC of array performance is available.

Applications■ VSP surveys: zero offset, offset,

walkaway, 3D, and SeismicVISION* seismic-while-drilling service

■ Subsalt imaging■ Shallow-water surveys ■ Deepwater and deep wells ■ Calibration of complex surveys:

anisotropy and amplitude variation with offset (AVO)

■ Repeatability and wavelet matching for time-lapse surveys

■ All borehole seismic applications requiring high-quality, consistent source signatures with calibrated amplitude


Marine Seismic Sources

Seismic Source RecommendationsCheckshot Single gun

Checkshot, deep well Two- or three-gun cluster

VSP Two- or three-gun cluster

VSP, offset or walkaway, deep well Single or dual six-gun array

VSP, offset, walkaway or 3D, ultradeep well Single or dual six-gun array or surface seismic vessel

Example Seismic Source Specifications

Source Source Depth, ft [m]

Capacity, in3 [L]

Firing Pressure, psi [MPa]

Zero-Peak Amplitude, bar.m

Peak-Peak Amplitude, bar.m

Primary to Bubble Ratio

Single gun 16.4 [5] 150 [2.5] 2,000 [14] 3.0 5.3 4.4

Two-gun cluster 9.8 [3] 300 [4.9] 2,000 [14] 5.2 9.2 7.5

Three-gun cluster 16.4 [5] 450 [7.4] 2,000 [14] 6.7 12.2 12.2

Three-gun cluster, large 16.4 [5] 750 [12.3] 2,000 [14] 8.3 14.8 15.1

Dual Delta six-gun array 16.4 [5] 1,200 [19.7] 2,000 [14] 14.0 23.1 21.5

HyperCluster* low-frequency airgun source

16.4 [5] 1,500 [24.6] 3,000 [20] 18.4 29.0 22.6


Formation Testing and Sampling


The extensively qualified MDT Forte* rugged modular formation dynamics tester and MDT Forte-HT* rugged high-temperature tester are a complete redesign and reengineering of the workhorse MDT modular formation dynamics tester for sampling and formation testing. By extending the reliability, efficiency, and applicability of the MDT tester platform while minimizing operational risk, the MDT Forte and MDT Forte-HT testers are run with Quicksilver Probe* focused fluid extraction and the Saturn* 3D radial probe to deliver robust downhole fluid analysis (DFA) using the InSitu Fluid Analyzer* system, fluid sampling, and transient testing to meet the challenges of today’s oilfield operations.

Extensive qualification testing of the design, components, and entire tester systems proves that the MDT Forte and MDT Forte-HT testers tolerate excessive vibration at all stages of use: from low-frequency shaking during transit to high-impact shock and vibration downhole at extreme temperatures. The redesigned electronics system incorporates surface-mounted components on a ruggedized chassis that overcomes the conventional fragility of electronics when operating in tough logging conditions. Qualified for 100 cumulative operating hours at temperatures up to 400 degF [204 degC], the testers are ideally suited for operations in the most challenging environments, such as deep water, drillpipe conveyance, HPHT wells, and remote operations.

The innovative modular design of the MDT Forte and MDT Forte-HT testers means that the tester compo-nents are readily customizable to meet operational requirements:■ Telemetry system with greatly

expanded capabilities means that the length of the toolstrings is lim-ited primarily by the cable strength and well conditions. Using extended tool combinations to meet multiple objectives in one trip results in sig-nificant efficiency gains and cost savings.

■ Next-generation Axton* dynamically compensated single quartz gauge has an operating range to 410 degF [210 degC] and 31,500 psi [217 MPa]. Calibration to 30,000 psi [207 MPa] and 374 degF [190 degC] or to 20,000 psi [138 MPa] and 392 degF [200 degC] ensures consistent pres-sure metrology performance with the same accuracy and resolution expected in standard conditions.

■ High-temperature InSitu Density* reservoir fluid density sensor helps manage the challenges of sampling formation fluids from HPHT reservoirs by monitoring contamination levels in addition to indicating compositional grading and fluid gradients.

■ Dual-Packer Module comprises two inflatable packer elements with an asymmetrical design that reduces the risk of sticking and fishing, with downtime further reduced through greater durability, longer replacement cycles, and more stations per run.

By sealing against the borehole wall to isolate an interval of the formation, the dual packers significantly improve the effectiveness of pressure measurement and fluid sampling in low-permeability, laminated, or fractured formations.

■ Advanced sealing technology of the O-rings of the MDT Forte-HT tester feature carbon nanotube technology. The engineered material provides the strength to withstand downhole effects and ensure extended sealing performance to capture and confidently retain HPHT samples.

■ Advanced Pumpout Modules, rated from standard conditions through extra-extrahigh pressure provide an increased flow area and enhance run time, resistance to plugging, and solids handling.

■ Multisample Modules are used to collect and subsequently transport high-quality samples of formation fluids for PVT analysis. The Single-Phase Multisample Changer (SPMC) is HPHT rated and pressure compen-sating for single-phase sampling.

Wireline Services Catalog ■ Formation Testing and Sampling 145

MDT Forte and MDT Forte-HT Rugged and High-Temperature

Modular Formation Dynamics Testers



Measurement SpecificationsMDT Forte Tester MDT Forte-HT Tester

Output Formation pressure; ultralow-contamination fluid samples; downhole fluid analysis; flowline pressure, resistivity, and temperature; permeability and permeability anisotropy; in situ stress

Logging speed Stationary Stationary

Range of measurement Quartz gauge: 750 to 15,000 psi [5 to 103 MPa] Resistivity: 0.01 to 20 ohm.m Temperature: –40 to 350 degF [–40 to 177 degC]

Axton gauge: 0 to 30,000 psi [207 MPa] to 374 degF [190 degC] and 0 to 20,000 psi [138 MPa] to 392 degF [200 degC]† Resistivity: 0.01 to 20 ohm.m Temperature: –40 to 400 degF [–40 to 204 degC]

Resolution Quartz gauge: 0.008 psi [55 Pa] at 1.3-s gate time Resistivity: 0.001 ohm.m Temperature: 1.0 degF [0.5 degC]

Axton gauge: 0.008-psi [55-Pa] rms at 1-s gate time Resistivity: 0.001 ohm.m Temperature: 1.0 degF [0.5 degC]

Accuracy Quartz gauge: ±(2 psi [13,789 Pa] + 0.01% of reading)‡ Resistivity: ±0.01 ohm.m Flowline temperature: ±1.0 degF [±0.5 degC]

Axton gauge: ±2.0 psi [±13,789 Pa] for typical HPHT operational range (>212 degF [>100 degC] and >15,000 psi [103 MPa]) and ±6.0 psi [±41,368 Pa] for full range‡ Resistivity: 0.01 ohm.m Flowline temperature: ±0.5 degF [±0.2 degC]


Combinability Fully integrates with Saturn 3D radial probe, Quicksilver Probe focused fluid extraction, and InSitu Fluid Analyzer system Conveyance on wireline, drillpipe, and UltraTRAC all-terrain wireline tractor

Special applications Downhole fluid analysis at reservoir conditions, interval pressure transient test (IPTT), stress test, mini-DST † Operating range up to 400 degF [204 degC] and default calibration to 392 degF [200 degC] with calibration to higher temperature on request. ‡ Includes fitting error, hysteresis, repeatability, and some allowance for sensor aging; the corresponding percentages of the pressure reading account for the incertitude of the calibration equipment.


MDT Forte Tester MDT Forte-HT Tester


Pressure rating 20,000, 25,000, and 30,000 psi [138, 172, and 207 MPa]

20,000 psi [138 MPa]

Borehole size—min. 20,000 psi: 55⁄8 in [14.41 cm] 25,000 and 30,000 psi: 57⁄8 in [14.92 cm]

5⅝ in [14.41 cm]

Borehole size—max. 22 in [55.88 in] 22 in [55.88 in]

Outside diameter† 20,000 psi: 4.75 in [12.07 cm] 25,000 psi: 5 in [12.70 cm] 30,000 psi: 5.25 in [13.33 cm]

4.75 in [12.07 cm]

Length Depends upon configuration Depends upon configuration

Weigh Depends upon configuration Depends upon configuration

Shock and vibration Electronic shock rating: 250 g Vibration transmissibility: 3.0 g, 10 to 450 Hz

Electronic shock rating: 250 g Vibration transmissibility: 3.0 g, 10 to 450 Hz


Compression‡ 85,000 lbf [378,100 N] 85,000 lbf [378,100 N] † Tester only, not including probe ‡ At 15,000 psi and 320 degF; the compression rating is a function of temperature and pressure.

Applications■ Challenging environments: deep

water, remote operations, drillpipe conveyance, high temperature, high pressure, and harsh operating conditions

■ Formation pressure measurement■ Accurate determination of pressure

gradients and fluid contacts■ Reservoir fluid characterization

through DFA

■ Identification of compositional grading

■ Formation fluid sampling■ Sample assurance: single phase and

purity■ Identification of compartments

and lateral sealing boundaries■ Formation permeability

and permeability anisotropy measurements

■ Reservoir simulation (equation-of-state [EOS] modeling)

■ Asphaltene gradient determination and heavy-ends EOS modeling

■ Identification of volatile oil and gas condensate

■ Determination of gas/oil ratio (GOR) and condensate/gas ratio (CGR)

■ In situ stress determination


The MDT modular formation dynam-ics tester measures reservoir pressure quickly and accurately, collects repre-sentative fluid samples from multiple layers, and provides permeability and anisotropy data through a variety of interval pressure transient tests. The MDT tester can also be used to conduct a mini-frac test to obtain the minimum in situ horizontal stress in several lay-ers. Its modular design and combinabil-ity with Quicksilver Probe focused fluid extraction, the InSitu Fluid Analyzer system, and almost all Schlumberger measurement systems make the MDT tester readily customizable to meet specific objectives. The MDT tester con-tinues to evolve, incorporating newly available measurement technologies to always feature state-of-the art downhole devices for reservoir evaluation and management needs.

The basic MDT tester modules are as follows:■ Electronic Power Module (MRPC)

converts power from the surface to power for the tool modules.

■ Hydraulic Power Module (MRHY) contains an electric motor and pump to provide hydraulic power for setting and retracting the single- and dual-probe modules. The MRHY has an accumulator that enables automatic retraction of the probes if electric power fails, which prevents potential stuck tool situations.

■ Single-Probe Module (MRPS) con-sists of the probe assembly (i.e., packer and telescoping backup pis-tons), pressure gauges, fluid resistiv-ity and temperature sensors, and 20-cm3 [0.005-galUS] pretest cham-ber. The MRPS contains both a strain gauge and the accurate, high-reso-lution, quick-response CQG crystal quartz gauge. The volume, rate, and drawdown of the pretest chamber can be controlled from the surface and adjusted depending on the for-mation characteristics.

■ Modular Sample Chambers (MRSC) module is available in three sizes: 1, 2.75, and 6 galUS [3.8, 10.4, and 22.7 L]. The 1- and 2.75-galUS cham-bers are avail able in H2S and stan-dard service versions.

Applications■ Formation pressure measurement

and fluid gradient estimation■ Formation fluid sampling and down-

hole fluid analysis■ Pretest drawdown mobility values

(permeability/viscosity) ■ Permeability and permeability

anisotropy determination away from the well

■ In situ stress determination

Formation Testing and Sampling 147

MDT Modular Formation Dynamics Tester

MRPC

MRPS

MRSC

MRHY



Standard MDT Tester Measurement SpecificationsAccuracy Resolution Range

Logging speed Stationary Stationary Stationary

Strain gauge ±10 psi [±68,947 Pa] ±20 psi [±137,895 Pa]

0.1 psi [689 Pa] 0.2 psi [1,379 Pa]

0 to 10,000 psi [0 to 69 MPa] 0 to 20,000 psi [0 to 138 MPa]

CQG gauge ±(2 psi [13,789 Pa] + 0.01% of reading) †

0.008 psi [55 Pa] at 1.3-s gate time 750 to 15,000 psi [5 to 103 MPa]

Resistivity ±5% of reading 0.001 ohm.m 0.01 to 20 ohm.m

Flowline temperature ±1.0 degF [±0.5 degC] 1.0 degF [0.5 degC] –67 to 392 degF [–55 to 200 degC] † Includes calibration fitting error, hysteresis, repeatability, and some allowance for sensor aging;

the corresponding percentages of the pressure readings account for the incertitude of the calibration equipment.

Basic MDT Tester Modules Mechanical Specifications

MRPC MRHY MRSC MRPS

Temperature rating 350 degF [177 degC] 350 degF [177 degC] 350 degF [177 degC] 350 degF [177 degC]†

Pressure rating 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa]†

Borehole size—min. 5⅝ in [14.29 cm] 5⅝ in [14.29 cm] 5⅝ in [14.29 cm] Standard: 5⅝ in [14.29 cm] Large-hole kit: 8½ in [21.59 cm] Super-large-hole kit: 11½ in [29.21 cm]

Borehole size—max. No limit No limit No limit Standard: 14 in [35.56 cm] Large-hole kit: 19 in [48.26 cm] Super-large-hole kit: 22 in [55.88 cm]

Outside diameter 4.75 in [12.07 cm] 4.75 in [12.07 cm] 4.75 in [12.07 cm] Standard: 4.75 in [12.07 cm] Large-hole kit: 7.5 in [19.05 cm] Super-large-hole kit: 10.5 in [26.67 cm]

Length 4.98 ft [1.52 m] 8.42 ft [2.57 m] 8.04 ft [2.45 m] 6.25 ft [1.91 m]

Weight 160 lbm [73 kg] 275 lbm [125 kg] 225 lbm [102 kg] 200 lbm [91 kg]

Tension‡ 160,000 lbf [711,710 N] 160,000 lbf [711,710 N] 160,000 lbf [711,710 N] 160,000 lbf [711,710 N]

Compression‡ 85,000 lbf [378,100 N] 85,000 lbf [378,100 N] 85,000 lbf [378,100 N] 85,000 lbf [378,100 N]

H₂S service Yes Yes Yes Yes † These ratings reduce the dependence on using a quartz gauge.

‡ At 15,000 psi [103 MPa] and 320 degF [160 degC]. These ratings apply to all MDT tester modules except the Dual-Packer Module (MRPA). The compressive load is a function of temperature and pressure.

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With a total surface flow area of 79.44 in2—a 1,200% increase over the largest conventional single-probe formation tester—the Saturn 3D radial probe extends formation testing to previously inaccessible fluids and reservoir environments:■ low-permeability formations■ heavy oil■ unconsolidated formations■ near-critical fluids■ rugose boreholes.

The Saturn 3D radial probe can perform pressure tests efficiently and conclusively at mobilities as low as 0.01 mD/cP. With minimal storage volume effects and greatly reduced susceptibility to supercharging, the Saturn probe brings unprecedented pressure-testing capability to very tight formations.

The drain assembly of the Saturn 3D radial probe positions four self-sealing suction ports at 90° intervals against the borehole wall to pull fluid circumferentially from the reservoir, instead of funneling it to the single access point of a conventional probe. Because fluid is extracted across a large reservoir volume, flow is read-ily induced and sustained for viscous fluids and in low-mobility formations or uncemented matrix. Filtrate is quickly removed to draw in uncontam-inated formation fluid for downhole fluid analysis (DFA) and sampling.

The improvement in testing effi-ciency over conventional probes is dis-tinct at mobilities of 500 mD/cP, with the performance gap expanding as the mobility decreases. At 10 mD/cP the Saturn probe is an enabling technology because even an extralarge-diameter conventional probe can be challenged to move the formation fluid.

The proprietary rubber technology used in the probe assembly provides additional flexibility for sealing in rugose hole conditions in combination with the probe’s self-sealing suction ports. The probe assembly also cir-cumferentially supports the formation to enable sampling in unconsolidated formations without the risk of plugging or formation collapse.

Applications■ Formation fluid sampling■ Downhole fluid analysis■ Formation pressure measurement■ Fluid-gradient determination■ Far-field permeability

measurement and anisotropy determination

■ Well testing design optimization

Saturn 3D Radial Probe




Saturn Probe

Output Ultralow-contamination formation fluids, formation pressure, fluid mobility, downhole fluid analysis, permeability anisotropy

Logging speed† Stationary

Range of measurement Gauges specified for the operation and formation conditions

Resolution Gauges specified for the operation and formation conditions

Accuracy Gauges specified for the operation and formation conditions


Combinability Fully integrates with MDT modular formation dynamics tester and InSitu Family* measurements sensors

Special applications Low-permeability formations, heavy oil, near-critical fluids, unconsolidated formations, and rugose boreholes

† Includes fitting error, hysteresis, repeatability, and some allowance for sensor aging; the corresponding percentages of the pressure reading account for the incertitude of the calibration equipment


Saturn Probe


Pressure rating 20,000 psi [138 MPa] High-pressure version: 25,000 psi [172 MPa] Ultrahigh-pressure version: 30,000 psi [207 MPa]

Borehole size—min. 7-in version: 77⁄8 in [20.0 cm] 9-in version: 97⁄8 in [25.08 cm]

Borehole size—max. 7-in version: 9½ in [24.13 cm] 9-in version: 14½ in [36.83 cm]

Max. hole ovality 20%

Outside diameter Tool body: 4.75 in [12.06 cm] 7-in version drain assembly: 7 in [17.78 cm] 9-in version drain assembly: 8.75 in [22.23 cm]

Length 5.7 ft [1.74 m] With Modular Reservoir Sonde and Electronics (MRSE): 12.4 ft [3.78 m]

Weight† 7-in version: 385 lbm [175 kg] 9-in version: 485 lbm [220 kg]

Tension Depends on wellbore pressure and temperature

Compression Depends on wellbore pressure and temperature † In air, fully assembled on a mandrel



Quicksilver Probe* focused fluid extrac-tion acquires reservoir fluids samples that, in many cases, have levels of fil-trate contamination below measurable limits. In addition, the time required on station is significantly reduced compared with conventional openhole sampling operations. Other enhance-ments over single-probe methods are a reduced risk of differential sticking and more reliable laboratory results for PVT analysis.

The innovative focused probe fea-tures concentric packers with “guard” and fluid-acquisition flowlines to efficiently separate mud filtrate con-tamination from virgin reservoir fluid during the fluid-extraction process.

Beyond setting new standards in fluid purity and extraction speed, Quicksilver Probe focused fluid extraction makes downhole fluid analysis possible even in miscible oil-base mud. Fluid properties can be accurately measured at reservoir con-ditions without contamination effects. Comparison between reservoir layers yields information concerning zonal connectivity and fluid compartmen-talization that cannot be measured by other logs.

Applications■ Formation pressure measurement

and fluid gradient estimation■ Formation fluid sampling■ Downhole fluid analysis■ Fluid profiling characterization

of reservoir fluid properties and quantification of their variation

Quicksilver Probe Focused Fluid Extraction




Quicksilver Probe Extraction

Output Extracted ultralow-contamination formation fluids; flowline pressure, resistivity, and temperature

Logging speed Stationary

Range of measurement CQG gauge: 750 to 15,000 psi [5 to 103 MPa] 25,000-psi high-pressure Quartzdyne® gauge: 0 to 25,000 psi [0 to 172 MPa] Axton gauge: 0 to 30,000 psi [207 MPa] to 374 degF [190 degC] and 0 to 20,000 psi [138 MPa] to 392 degF [200 degC]† Resistivity: 0.01 to 20 ohm.m Temperature: –67 to 400 degF [–55 to 204 degC]

Resolution CQG gauge: 0.008 psi [55 Pa] at 1.3-s gate time 25,000-psi high-pressure Quartzdyne gauge: 0.01 psi/s [69 Pa/s] Axton gauge: 0.008-psi [55-Pa] rms at 1-s gate time Resistivity: 0.001 ohm.m Temperature: 1.0 degF [0.5 degC]

Accuracy CQG gauge: ±(2 psi [13,789 Pa] + 0.01% of reading)‡ 25,000-psi high-pressure Quartzdyne gauge: ±0.02% of full range Axton gauge: ±2.0 psi [±13,789 Pa] for typical HPHT operational range (>212 degF [>100 degC] and >15,000 psi [>103 MPa]) and ±6.0 psi [±41,368 Pa] for full range Resistivity: ±5% of reading Flowline temperature: ±1.0 degF [±0.5 degC]


Combinability Fully integrates with MDT modular formation dynamics tester and InSitu Family measurement sensors

Special applications Downhole fluid analysis at reservoir conditions † Operating range up to 400 degF [204 degC] and default calibration to 392 degF [200 degC] with calibration to higher temperature on request.

‡ Includes fitting error, hysteresis, repeatability, and some allowance for sensor aging; the corresponding percentages of the pressure reading account for the incertitude of the calibration equipment


Quicksilver Probe Extraction





Outside diameter 4.75 in [12.07 cm] While sampling: 5 in [12.70 cm] High-pressure version: 5.25 in [13.34 cm]

Length Probe module: 8.48 ft [2.58 m]

Weight 308 lbm [140 kg] High-pressure version: 351 lbm [159 kg]

Tension 160,000 lbf [711,710 N]

Compression† 85,000 lbf [378,100 N] † At 15,000 psi [103 MPa] and 320 degF [160 degC]. The compressive load is a function of temperature and pressure.



The InSitu Fluid Analyzer system is used to acquire InSitu Family downhole quantitative fluid properties measurements for real-time downhole fluid analysis (DFA):■ hydrocarbon composition

(C1, C2, C3–C5, and C6+)■ gas/oil ratio (GOR)■ live-oil density and viscosity■ CO2

■ pH of water (aquifer, connate, injection, or water-base mud [WBM] filtrate)

■ reservoir fluid color■ free-gas detection■ downhole fluorescence (dew

precipitation in retrograde gas condensates)

■ flowline pressure and temperature (regime of sample chamber, not the probe)

■ resistivity of reservoir water■ oil-base mud (OBM) filtrate

contamination.

InSitu Composition and InSitu CO2 sensorsBecause quantified DFA is based on optical absorption spectroscopy, the InSitu Composition* reservoir fluid composition measurement uses the first downhole deployment of a laboratory-grade grating spectrometer in addition to the conventional filter array spectrometer. The filter array spectrometer measures wavelengths in the visible to near-infrared (Vis-NIR) range from 400 to 2,100 nm across 20 channels that indicate the color and molecular vibration absorptions of the reservoir fluid and also show the main absorption peaks of water and CO2. The

grating spectrometer has 16 channels focused on the 1,600- to 1,800-nm range, where reservoir fluid has characteristic absorptions that reflect molecular structure. Measurement of the Vis-NIR spectrum by the two spectrometers is used for the DFA of fluid hydrocarbon composition, water content, and mud filtrate contamination. The CO2 content is determined from the spectrometer measurements by the InSitu CO2* reservoir fluid CO2 sensor.

InSitu GOR sensorFrom the enhanced composition mea-surement, the InSitu GOR* reservoir fluid sensor determines the GOR and condensate/gas ratio (CGR) from the vaporizations of the hydrocarbon and CO2 components at standard conditions for flashing a live fluid.

InSitu Color sensorWith optical filters improved for high-temperature performance, the InSitu Color* reservoir fluid color sen-sor uses the extended measurement range of the 20-channel filter array spectrometer to determine fluid color. The reliability of the measurement is supported by continuous real-time autocalibration, application of a con-tamination algorithm that uses all the spectrometer channels, and a coated-window detection flag for enhanced QC. The color measurement supports fluid identification, determination of asphal-tene gradients, and pH measurement.

InSitu Density sensorThe InSitu Density reservoir fluid density measurement is based on the resonance characteristics of a vibrating rod that

oscillates in two perpendicular modes within the fluid. Simple physical models describe the resonance frequency and quality factor of the sensor in relation to the fluid density. Dual-mode oscillation is superior to other resonant techniques because it minimizes the effects of pressure and temperature on the sensor through common mode rejection, which further improves the accuracy of the measurement. The measurement is made under flowing conditions, and the resonator is resistive to corrosive fluids.

InSitu Viscosity sensorThe InSitu Viscosity* reservoir fluid viscosity sensor measures viscosity under flowing conditions with either a dual-mode microresonator rod or a vibrating wire. Which technology is used depends on the downhole and reservoir conditions.

InSitu Fluorescence sensorThe InSitu Fluorescence* reservoir fluid fluorescence sensor detects free gas bubbles and retrograde conden-sate liquid dropout for single-phase assurance while conducting DFA and sampling. Fluid type is also identified. The resulting fluid phase information is especially useful for defining the difference between retrograde con-densates and volatile oils, which can have similar GORs and live-oil densi-ties. Because the fluorescence mea-surement is also sensitive to liquid precipitation from a condensate gas when the flowing pressure falls below the dewpoint, it can be used to monitor phase separation in real time to ensure the collection of representative single-phase samples.

InSitu Fluid Analyzer Real-Time Downhole Fluid Analysis System



InSitu pH sensorThe InSitu pH* reservoir fluid pH sen-sor measures the water pH by inject-ing dye into the formation fluid being pumped through the flowline of the InSitu Fluid Analyzer system. The pH is calculated with 0.1-unit accuracy from the relevant visible wavelengths of the dye signal measured by an optical fluid analyzer. Making the measurement at reservoir conditions avoids the irrevers-ible pH changes that occur when sam-ples are brought to the surface, as acid gases and salts come out of solution with reduced temperature and pressure and routine laboratory flashing of the sample. The InSitu pH sensor mea-sures fluids across the entire flowline cross section, which makes it more robust than potentiometric methods of measurement, which are compromised when oil and mud foul electrode sur-faces. Direct pH measurements with dye also avoid the limitations of resis-tivity measurement in monitoring con-tamination, which requires a sufficient resistivity contrast between the filtrate and formation water.

InSitu Resistivity sensorThe InSitu Resistivity* reservoir fluid resistivity sensor measures the fluid in the flowline using the same proven technology employed in Schlumberger formation testing tools. With the InSitu Resistivity sensor included in the DFA assembly, it is possible to monitor resistivity during dual-packer sampling operations in WBM.

Pressure and temperature sensorsThe high-resolution pressure and temperature sensors incorporated in Schlumberger formation testing tools are used in the InSitu Fluid Analyzer system. Direct measurement of pressure and temperature is essential to identify the position in the PVT envelope where the other fluid properties, such as den-sity, are measured, especially when the sensors are placed downstream of the

flowline pump. The DFA measurements within the flowline can then be accu-rately translated back to virginal reser-voir conditions by employing well-known equation-of-state (EOS) algorithms.

Fluid profiling characterization of reservoir fluid properties variationFluid profiling characterization based on the InSitu Fluid Analyzer system measurements provides the distri-bution of fluid properties across the reservoir, beyond what a traditional sampling program can achieve. The quantified accuracy of InSitu Family measurements expands DFA appli-cation from a single well to multi-ple-well analysis, defining reservoir architecture across the entire field. Quantification of the variation of fluid properties at higher resolution than conventional sampling and analysis is key to identifying and differentiating compositional grading, fluid contacts, and reservoir compartments.

For integrated analysis, compre-hensive InSitu Pro* real-time quality control and interpretation software combines the results of pressure and fluids analysis from multiple data sources.

Applications■ Reservoir fluid characterization■ Identification of compartments

and lateral sealing boundaries■ Quantification of compositional

grading■ Strategy development for corrosion

and scale■ Sample assurance: single phase

and purity■ Reservoir simulation (EOS

modeling)■ Improved-accuracy determination

of pretest gradients and fluid contacts

■ Asphaltene gradient determination■ Differentiation of biogenic

and thermogenic dry gas■ Identification of volatile oil

and gas condensate■ Determination of GOR and CGR

InSitu Fluid Analyzer system integrates multiple InSitu Family reservoir fluid measurements and sensors.

Fluorescence detector

Grating spectrometer

Resistivity sensor

Density andviscosity sensors

Pressure and temperature gauge

Flowline

Filter array spectrometer




InSitu Fluid Analyzer System

Output Hydrocarbon composition, GOR, live-oil density and viscosity, CO₂, pH of water, reservoir fluid color, free-gas detection, downhole fluorescence, flowline pressure and temperature, resistivity, OBM contamination


Range of measurement InSitu Density sensor: 0.05 to 1.2 g/cm³ InSitu Viscosity sensor: 0.2 to 300 cP

Resolution InSitu Density sensor: 0.001 g/cm³

Accuracy InSitu Density sensor: ±0.012 g/cm³ InSitu Viscosity sensor: ±10% for wire, ±12% for rod

Depth of investigation na


Combinability Fully integrates with the MDT, MDT Forte, and MDT Forte-HT testers; Saturn 3D radial probe; Quicksilver Probe focused fluid extraction; and InSitu Pro software

Special applications Real-time downhole fluid analysis na = not applicable


InSitu Fluid Analyzer System




Borehole size—max. Determined by probe or packer

Outside diameter Determined by probe or packer

Length 10.43 ft [3.18 m]


Tension 160,000 lbf [711,710 N]



The InSitu Pro software is used for detailed analysis and reporting of pre-test, sampling, and downhole fluid analysis (DFA) station data, both in real time and postacquisition. It is com-patible with Quicksilver Probe focused fluid extraction, MDT modular for-mation dynamics tester, InSitu Fluid Analyzer system, PressureXpress reser-voir pressure-while-logging service, and PressureXpress-HT high-temperature reservoir pressure service. Data analysis by InSitu Pro software also supports fluid profiling comprehensive charac-terization of reservoir fluid properties and quantification of their variation.

For real-time monitoring and QC, data can be received via InterACT global connectivity, collaboration, and informa-tion service directly at the operator’s office or a Schlumberger iCenter* secure networked collaborative environment.

Because operators and Schlumberger engineers share the InSitu Pro software access for powerful data analysis, all users efficiently view the same data and presentations in real time for their oper-ation. Detailed interpretation can also be conducted after the job to combine reservoir fluid information with petro-physical data.

InSitu Pro software has three main modules:■ pressure module for conducting

comprehensive QC and analysis of pretests

■ fluids module for conducting QC and viewing DFA and sampling data

■ integration module for combining pressure and fluid analysis results from all available stations with other petrophysical and correlation logs in an integrated depth display.

Applications■ Real-time monitoring, QC, and

interpretation of pretest, fluid sampling, and DFA data for both wireline and LWD formation testing services

■ Production strategy guidance through the determination of fluid types and contacts and the swift identification of compartmentalization

■ Postjob data integration from multiple data sources, evaluation, interpretation, and reporting

InSitu Pro Real-Time Quality Control and Interpretation Software


The comprehensive depth view from InSitu Pro software combines the results of pressure and fluids analysis from multiple data sources.



DualPacker ModuleThe Dual-Packer Module (MRPA) con-sists of two inflatable packer elements that seal against the borehole wall to isolate an interval, improving the effectiveness of pressure measurement and fluid sampling in low-permeability, laminated, or fractured formations. The MDT Pumpout Module (MRPO) is used to inflate the packers with fluid.

High-performance packers are run with the MRPA to expand the oper-ating envelope for the MDT tester, with a temperature rating to 410 degF [210 degC] and compatibility with both water- and oil-base mud systems. The superior elasticity and improved durability of the high-performance packers enable performing more stations per run and lessen packer replacement. The asymmetrical packer design reduces sticking and bulging potential. Operational reliability is further enhanced by the autoretract mechanism (ARM), which applies a longitudinal tensile force to assist in retracting the packers after deflation, in turn minimizing drag. At tempera-tures below 225 degF [107 degC], the elements retain sufficient elasticity for operation without the ARM.

For operations in H2S environ-ments, the Dual-Packer Module is available in a NACE-compliant ver-sion for sampling up to 50% H2S in hole sizes from 57⁄8 to 95⁄8 in.

The length of the test interval between the packers is 3.2 ft [0.98 m] and can be extended to 5.2, 8.2, or 11.2 ft [1.58, 2.5, or 3.41 m] by using 2- and 3-ft [0.61- and 0.91-m] spac-ers with large-diameter mandrels. For

the 3.2-ft interval, the area of the iso-lated interval of the borehole is about 3,000 times larger than the area of the borehole wall isolated by the MDT tester’s Single-Probe Module (MRPS). For fluid sampling, the large area results in flowing pressures that are only slightly below the reservoir pres-sure, which avoids phase separation even for pressure-sensitive fluids such as gas condensates or volatile oils. In low-permeability formations, high drawdown usually occurs with the probe, whereas fluid can be withdrawn from the formation using the MRPA with minimum pressure drop through the larger flowing area. In finely lami-nated formations, the MRPA can be used to straddle permeable streaks that would be difficult to locate with a probe. In fractured formations, the MRPA can usually seal the interval whereas a probe could not.

For pressure transient testing, following a large-volume flow from the formation, the resulting pressure buildup has a radius of investigation of 50 to 80 ft [15 to 24 m]. Depending on the application, interval pressure transient testing (IPTT) provides advantages over a conventional drill-stem test (DST). It is environmen-tally friendly because no fluids flow to the surface, and it is cost effective because many zones can be tested in a short time.

The MRPA can be used to create a micro-hydraulic fracture that can be pressure tested to determine the min-imum in situ stress magnitude. The fracture is created by pumping well-bore fluid into the interval between the inflatable packer elements.

Advanced MDT Tester Modules



Dual-Packer Module Packers Mechanical Specifications

Packer Outside Diameter, in [cm]

Hole Size— Min., in

Hole Size— Max., in

Temperature Rating, degF [degC]

Pressure Rating, psi [MPa]

Differential Pressure Rating, psi [MPa]

Type Recommended Number of Settings†

SIP-A3-5in 5 [12.70] 5.875 7.5 350 [177] 20,000 [138] 4,500 [31] Symmetrical 10 settings at 3,000 psi in 6-in hole

SIP-A3A-5in 5 [12.70] 5.875 7.5 350 [177] 20,000 [138] 4,500 [31] Asymmetrical 10 settings at 3,000 psi in 6-in hole

IPCF-H2S-500 5 [12.70] 5.875 7.5 350 [177] 20,000 [138] TBQ‡ Asymmetrical TBQ‡

SIP-A3-6.75in 7 [17.78] 7.875 9.625 350 [177] 20,000 [138] 3,000 [21] Symmetrical 10 settings at 3,000 psi in 8.75-in hole

SIP-A3A-6.75in 7 [17.78] 7.875 9.625 350 [177] 20,000 [138] 3,000 [21] Asymmetrical 10 settings at 3,000 psi in 8.75-in hole

IPCF-PAS-700 7 [17.78] 7.875 9.625 350 [177] 20,000 [138] 3,000 [21] Symmetrical 10 settings at 3,000 psi in 8.5-in hole

IPCF-PA-700 7 [17.78] 7.875 9.625 350 [177] 20,000 [138] 3,000 [21] Asymmetrical 10 settings at 3,000 psi in 8.5-in hole

IPCF-PC-700 7 [17.78] 7.875 9.625 350 [177] 20,000 [138] 4,500 [31] Asymmetrical 5 settings at 4,500 psi in 8.5-in hole

IPCF-BA-700 7 [17.78] 7.875 9.625 410 [210] 20,000 [138] 3,000 [21] Asymmetrical 3 settings at 3,000 psi in 8.5-in hole

IPCF-H2S-700 7 [17.78] 7.875 9.625 350 [177] 20,000 [138] 3,000 [21] Asymmetrical 10 settings at 3,000 psi in 8.5-in hole

SIP-A3A-8.5in 8.5 [21.59] 9.875 14 350 [177] 20,000 [138] 3,000 [21] Asymmetrical 10 settings at 3,000 psi in 12.25-in hole

SIP-A3A-10in 10 [25.40] 11 17.5 350 [177] 20,000 [138] 2,100 [14] Asymmetrical 7 settings at 2,100 psi in 14.4-in hole † At the specified pressure and hole size ‡ To be qualified



DualProbe ModuleIn combination with the Single-Probe Module (MRPS), the Dual-Probe Module (MRDP) provides measure-ments for determining both the verti-cal and horizontal mobility unaffected by near-wellbore permeability altera-tions. Analysis of a pre test pressure transient from only a single probe

cannot separate vertical from hori-zontal mobility, nor can it avoid the effects of near-wellbore alteration.

For a layer less than 2 ft [0.61 m] thick, the combination of the dual-probe and single-probe modules can straddle the layer to determine if the layer is a pressure barrier.


MRDP




Borehole size—max. 13¼ in [33.65 cm]


Length 6.75 ft [2.06 m] MRDP-BA, MRDP-BB, MRDP-BC, and MRDP-BX: 8.6 ft [2.62 m]


Tension† 160,000 lbf [711,710 N]

Compression† 85,000 lbf [378,100 N]

H₂S service Yes † At 15,000 psi [103 MPa] and 320 degF [160 degC]. These ratings apply to all MDT tester modules except the MRPA.

The compressive load is a function of temperature and pressure.




MRFC






Length 7.58 ft [2.31 m]


Tension† 160,000 lbf [711,710 N]

Compression† 85,000 lbf [378,100 N]

H₂S service Yes † At 15,000 psi [103 MPa] and 320 degF [160 degC]. These ratings apply to all MDT tester modules except the MRPA.

The compressive load is a function of temperature and pressure.

FlowControl ModuleThe Flow-Control Module (MRFC) is used to control the withdrawal of fluid from the formation for specific pressure transient tests that are typically done in combination with the Single-Probe Module (MRPS) and Dual-Probe Module (MRDP). The withdrawal of fluid can be accomplished at a selected rate or pressure that does

not have to be constant. The rate of fluid withdrawal is measured. The total volume of withdrawn fluid is limited to 1 L [0.26 galUS], which is 50 times the volume of the pretest chamber in the MRPS. Following withdrawal of a 1-L volume, the module can be emptied and used for repeated withdrawals. The module can be used to provide an extended pretest volume when combined with the single probe.



Pumpout ModuleThe Pumpout Module (MRPO) is used to flow fluids from the reservoir at a controlled flowing pressure. Pressure control is required to avoid the separa-tion of phases (i.e., gas or solids sepa-rating from oil, or liquid condensing from gas). Representative fluid samples require a “single-phase” fluid.

Pressure control is accomplished by varying the duty cycle (i.e., motor voltage) or motor speed. The engineer changes the duty cycle or motor speed until the flowing pressure, as measured by the pressure gauge (located where the fluid enters the tool), is safely above the pressure at which the phases separate. The LFA* live fluid analyzer, CFA* composition fluid anal yzer, or both these modules are used in combination with the MRPO to detect phase separation.

Fluid is withdrawn from the formation and pumped into the wellbore fluid system until an acceptably low percentage of drilling fluid filtrate contamination is achieved. The LFA analyzer is used to measure the level of filtrate contamination. The fluid is then diverted to a sample chamber, where it is preserved for later analysis.

The fluid exits the MRPO at a pressure equalized to the wellbore hydrostatic pressure. The rate at which the fluid flows depends upon the difference between the wellbore pressure and the flowing pressure. The minimum to maximum pumpout flow range can be from 0.08 to 32.8 cm3/s [0.0013 to 0.52 galUS/min]. The maximum differential pressure is 4,100 psi [28 MPa] for the standard displacement unit and 11,700 psi [81 MPa] for the extra-extrahigh-pressure displacement unit.


MRPO


Pressure rating† 20,000 psi [138 MPa]




Length 10.63 ft [3.24 m]


Tension‡ 160,000 lbf [711,710 N]

Compression‡ 85,000 lbf [378,100 N]

H₂S service Yes † 25,000-psi [172-MPa] and 30,000-psi [207-MPa] versions are available upon request. ‡ At 15,000 psi [103 MPa] and 320 degF [160 degC]. These ratings apply to all MDT modular formation dynamics tester modules

except the Dual-Packer Module (MRPA). The compressive load is a function of temperature and pressure.



LFA live fluid analyzerBoth the Pumpout Module (MRPO) and LFA live-fluid analyzer are required in the MDT tester toolstring for fluid sampling. The LFA analyzer measures the percentage of drilling fluid filtrate mixed with the forma-tion fluid as a function of time. This measurement is the basis for making real-time decisions on when to stop discarding the fluid to the wellbore and capture the sample in a chamber. The filtrate percentage is determined with a 10-channel optical spectrometer. Specific near-infrared wavelengths are used to determine the percentage of water-base filtrate in oil or of oil-base filtrate in water. A range of visible and

near-infrared wavelengths is used to determine the percentage of oil-base mud filtrate in oil. The LFA analyzer also measures methane content and hydrocarbon content. From the ratio of the two, the gas/oil ratio (GOR) is calculated using a measurement made on oil above the bubblepoint.

In addition to measuring contami-nation, the LFA analyzer detects the presence of gas if the flowing pressure is below the bubblepoint. The engineer is alerted to slow the pumping rate to raise the pressure above the bubble-point to avoid phase separation. The presence of a distinct gas phase is detected with an optical refractometer.


LFA Live Fluid Analyzer






Length 6.17 ft [1.88 m]


H₂S service Yes † 25,000-psi [172-MPa] and 30,000-psi [207-MPa] versions are available upon request.



CFA composition fluid analyzerThe addition of the CFA composition fluid analyzer to the MDT tester per-forms real-time compositional analysis of sampled retrograde gases, conden-sates, and volatile oils. The module has two detectors, a fluorescence device and an optical spectrometer. If liq-uids drop out from the gas phase, the dew that forms can be detected by an increase in the fluorescence level. The fluorescence detector ensures that the sample is above the dewpoint and in single-phase condition for gas sampling. The optical spectrometer is based on principles similar to those of the LFA analyzer. However, the spread of the optical density channels enables the tool to measure the optical density at the peaks corresponding to methane (C1), ethane to pen tane group (C2 to C5), heavier hydrocarbon molecules (C6+), carbon dioxide, and water to quantitatively measure their downhole concentrations.

Computation of the GOR or its inverse, the condensate/gas ratio (CGR), of the flowline fluid extends the range of GOR measurement to about 30,000 ft3/bbl from the LFA analyzer’s maximum GOR of 2,500.

In a hydrocarbon-bearing formation the CFA analyzer is used to character-ize the fluid with respect to depth. Conducting compositional analysis at various depths can provide composi-tional grading within the oil column below the gas zone. This information is valuable for reservoir engineers but was previously difficult to obtain.

The CFA analyzer can be used in combination with the LFA analyzer to provide a total of 20 optical chan-nels downhole for real-time assurance of single-phase conditions, detection of contamination, and measurement of composition.


CFA Analyzer






Length 5.1 ft [1.55 m] With handling caps: 6.6 ft [2.01 m]


H₂S service Yes † 25,000-psi [172-MPa] and 30,000-psi [207-MPa] versions are available upon request.


Conducting low-shock sampling with the MDT modular formation dynamics tester limits the pressure drawdown during fluid extraction and sampling. This approach helps avoid crossing the bubblepoint pressure, which would induce a two-phase condition in the flowline and the sample chambers. The successful collection of representative pressure-volume-temperature (PVT) samples also requires low filtrate con-tamination, which is determined by using the LFA live fluid analyzer.

The sample chambers and bottles consist of a cylinder with a valve at the top and opening at the bottom and contain a sliding piston. While the fluid is pumped from the formation to the wellbore, the valve at the top is closed and the piston is positioned at the top

of the cylinder. Beneath the piston in the cylinder is water. Because there is an opening at the bottom, the water pressure in the cylinder is equal to the wellbore hydrostatic pressure. Sample capture begins by opening the valve at the top and pumping fluid into the bottle rather than to the wellbore. The entering fluid pushes the piston down and causes the water to exit to the wellbore. Because the pump is pushing fluid to the wellbore, there is no change in the flowing pressure fol-lowing opening of the valve. With this innovative technique, low-shock sam-pling minimizes pressure disruption.

Previous methods of sampling did not employ an opening at the bottom of the chamber. Before sampling, the internal pressure was close to the atmospheric

pressure. When the valve at the top of the cylinder was opened, a sudden pressure reduction occurred. The reduction was typically sufficiently large to induce phase separation, resulting in an unrepresentative sample. It could even cause a shock so large that the formation would collapse, resulting in a loss of seal and the entry of drilling fluid to the tool.

The Dual-Packer Module (MRPA) can be used in low-shock sampling to further reduce the pressure drawdown caused by the area of flow.

In addition to enabling single-phase sample recovery, low-shock sampling avoids breaking down the formation while sampling in unconsolidated reservoirs, which would cause the mobilization and flow of sand grains.

MDT Tester Low-Shock Sampling




The MDT tester Multisample Module (MRMS) can retrieve six representa-tive formation fluid samples on a single trip into the well. Two types of sample bottles can be used in the MRMS:■ Multisample Production Sample

Receptacle (MPSR)■ Single-Phase Multisample

Chamber (SPMC).

The MRMS may be fitted with any combination of MPSR and SPMC bot-tles. A maximum of five MRMS mod-ules (i.e., a total of 30 bottles) can be combined in one toolstring.

The MPSR bottle has a 450-cm3 [0.12-galUS] volume and is approved for transport by the US Department of Transportation (DOT). It can be heated to 200 degF [93 degC] for recombining the sample but is not suitable for long-term storage. The SPMC has a 250-cm3 [0.07-galUS] vol-ume and can be heated to 400 degF [204 degC]. It is also DOT transport-able. Upon retrieval, an integrated

agitation component is used to restore samples to reservoir conditions of up to 25,000 psi [172 MPa] and 400 degF [204 degC] prior to sample transfer or analysis. Heating to the reservoir tem-perature is required for revaporizing condensed liquids in gas condensate samples, and heating to 180 degF [82 degC] is required for recombining wax precipitants.

The SPMC maintains the sample pressure at or above the reservoir pressure despite the reduction in tem-perature at the surface. The SPMC must be used to prevent asphaltene solids from precipitating in oil sam-ples because the precipitation of asphaltenes can be irreversible. The opening pressure on MPSR samples is much lower than the reservoir pres-sure because of the reduction in tem-perature at the surface. Gas, liquid, and solid phases separate within the MPSR bottle, and the sample cannot be validated, transferred, or analyzed until it has been recombined.

MDT Tester Multisample Module


MRMS





Outside diameter 5 in [12.70 cm] (max.)

Length 13.19 ft [4.02 m]

Weight 465 lbm [211 kg] (max.)

Tension‡ 160,000 lbf [711,710 N]

Compression‡ 85,000 lbf [378,100 N] † 25,000-psi [172-MPa] and 30,000-psi [207-MPa] versions are available on request.

‡ At 15,000 psi [103 MPa] and 320 degF [160 degC]. These ratings apply to all MDT tester modules except the Dual-Packer Module (MRPA). The compressive load is a function of temperature and pressure.


PressureXpress-HT* service extends the efficiency and accuracy of PressureXpress reservoir pressure while logging service to high-tem-perature environments. Specifically engineered for pressure and mobil-ity testing, as compared with conven-tional multifunction formation tester tools that also collect fluid samples, PressureXpress-HT service provides exceptional pressure measurement quality and significantly reduces the time and risk involved with testing. With a flasked tool design and the superior thermal stability of the quartz gauge eliminating the need for gauge temperature stabilization, highly accu-rate reservoir pressure and mobility measurements are typically made in less than a minute. PressureXpress-HT service is also compatible with most openhole services to deliver pressure measurements on the first logging run.

Innovative tool architecture enables the superior thermal stability of the quartz gauge and extended holding time. By combining these capabilities with the precision of electromechani-cal pretest control, PressureXpress-HT service provides accurate gradients and overall data quality not achiev-able by either conventional standard or high-temperature formation tes-ter tools. The location of the HPHT Quartzdyne gauge in a flasked section isolates it from changes in borehole temperature and eliminates the need for temperature stabilization of the gauge, thus significantly improving overall operational efficiency.

These simple, effective design changes and an extended qualification process that tests the entire tool system as well as individual components, electronics boards, and subassemblies deliver exceptional tool performance in challenging conditions. Extended single-trip survey programs are possible

with the industry’s longest holding time: 14 h at 450 degF [232 degC]. Even with flasking, the slim-diameter, streamlined profile of PressureXpress-HT service greatly reduces the risk of tool sticking.

The dynamically controlled pres-sure-pretest system incorporated in PressureXpress-HT service enables precise, real-time control of volume and drawdown rates across a wide mobility range. A pressure limit can be set as necessary. The enhanced pretest system makes pressure test-ing possible in formations where con-ventional hydraulic technology cannot measure accurately because it allows ultrasmall pretest volumes and mini-mal flowline storage volume. The pres-sure differential for drawdown is up to 8,000 psi [55 MPa]. A dedicated wellbore pressure gauge can be used to develop procedures and algorithms to overcome the supercharging effect that commonly occurs in many low-permeability applications. Multiple pretests can be performed at a given depth to verify the accuracy of a pres-sure measurement without having to cycle the tool, or they can be per-formed at multiple depths to produce a profile of pressure versus depth. The resulting pressure profile can be converted directly to the density of the formation’s continuous fluid phase for use in defining fluid contacts.

To select the candidate zones for successful reservoir pressure and fluid mobility measurement, PressureXpress Advisor* pretest quality indicator uses real-time data from the logging string that the service is run on. For pressure and gradient analysis, InSitu Pro real-time quality control and interpretation can be performed. A concise wellsite report is generated, with optional display of other log data.

PressureXpress-HT High-Temperature Reservoir Pressure Service




Applications■ Accurate, fast pressure and

mobility measurements from high-temperature and low-permeability environments

■ Measurements from the first logging run, in tool combinations with most wireline logging services

■ Heat-management-optimized design for performing extended surveys at the industry-leading holding time of 14 h at 450 degF [232 degC]

■ Pressure profiles and mobility measurements to combine with petrophysical, seismic, and conventional log data for developing a static reservoir model

■ Identification of depleted zones in a wider mobility range

■ Measurement of reservoir fluid density with gradients and gas/oil/water contacts

Measurement SpecificationsOutput Formation pressure, fluid mobility

Logging speed Stationary Set and retract time: 15 s

Range of measurement Max. measured overbalance: 8,000 psi [55 MPa] Pretest volume: 0.1 to 37 cm³ Pretest rate: 0.02 to 2 cm³/s

Resolution Quartzdyne gauge: 0.01 psi [29 Pa/s] Secondary Sapphire* gauge: 0.4 psi [276 Pa] at 1 Hz Flowline temperature: 0.18 degF [0.1 degC]

Accuracy Quartzdyne gauge: ±(0.02% of full scale + 0.01% of reading) Secondary Sapphire gauge: ±(5 psi [34 kPa] + 0.01% of reading) Flowline temperature: ±3.6 degF [±2 degC]


Combinability Combinable with SlimXtreme platform and most openhole tools

Special applications High-temperature operations, slim wellbores

Mechanical SpecificationsTemperature rating† 450 degF [232 degC] for 14 h


Borehole size—min. 4¾ in [12.07 cm]


Outside diameter Tool: 3.75 in [9.53 cm] Tool with bumpers or probe section without bumpers: 4.0625 in [10.32 cm]



Tension 50,000 lbf [222,410 N]

Compression 22,000 lbf [97,860 N] † For operations > 400 degF [204 degC], contact your Schlumberger representative for information on required operating procedures.


PressureXpress reservoir pressure while logging service collects pressure and fluid mobility measurements dur-ing the first logging run, bringing new efficiency to formation pressure test-ing. This streamlined service signifi-cantly reduces both the time and risk of employing conventional multifunc-tion pressure testers that perform pre-tests by taking formation fluid samples.

The dynamically controlled pres-sure-pretest system integrated in PressureXpress service enables pre-cise control of volume and drawdown rates over a wide mobility range, which makes pressure testing possible in many formations where conventional technology cannot function. For low-permeability rock, the standard probe can be replaced with one of several optional probes with effective inlet areas up to 7.5 in2 [48.4 cm2]. A pres-sure drawdown limit can also be set. The pretest assembly is not linked to the hydraulic anchoring system and is therefore not susceptible to leaks, tool movement, or other hydraulic affects on testing. Multiple pretests can be performed at a given depth to verify the accuracy of a pressure measure-ment without having to cycle the tool. Pretests performed at multiple depths are used to produce a pressure profile, which can be converted directly to the density of the formation’s continuous fluid phase.

PressureXpress Advisor pretest quality indicator analyzes real-time data from the Platform Express integrated wireline logging tool to select candidate zones for successful reservoir pressure and fluid mobil-ity testing. For pressure and gradi-ent analysis, interpretation can be performed with InSitu Pro real-time quality control and interpretation software. A concise wellsite report is generated, along with an optional display of other log data.

Applications■ Formation pressure and mobility

measurements on the first run■ Determination of reservoir fluid

density, contacts, and gradients■ Mobility and permeability

measurement to aid the selection of sampling points

■ Identification of depleted zones, thief zones, and zones to avoid during fracture stimulation operations

PressureXpress Reservoir Pressure While Logging Service





PressureXpress Service

Output Formation pressure, fluid mobility (permeability/viscosity), fluid density


Range of measurement Max. measured overbalance: XPT-B: 6,500 psi [44.8 MPa] XPT-C: 8,000 psi [55 MPa]

Resolution Sapphire gauge: 0.04 psi [276 Pa] CQG gauge: 0.005 psi [34 Pa] at 1-s gate time Quartzdyne gauge: 0.01 psi/s [69 Pa/s] Temperature: 0.01 degF [0.005 degC]

Accuracy Sapphire gauge: ±5 psi [±34 kPa] CQG gauge: ±(2 psi [14 kPa] + 0.01% of reading) Quartzdyne gauge: ±(0.02% of full scale + 0.01% of reading) Temperature: ±1.0 degF [±0.5 degC]

Depth of investigation Probe extension beyond packer surface: 0.45 in [1.14 cm]


Combinability Combinable with Platform Express tool



XPT-B XPT-C


Pressure rating 20,000 psi [138 MPa] With CQG gauge: 15,000 psi [103 MPa]

20,000 psi [138 MPa] With CQG gauge: 15,000 psi [103 MPa]

Borehole size—min. 4.75 in [12.07 cm] 4.75 in [12.07 cm]

Borehole size—max. 14.5 in [36.83 cm] 14.5 in [36.83 cm]

Outside diameter Tool: 3.375 in [8.57 cm] Probe section: 3.875 in [9.84 cm]

Tool: 3.375 in [8.57 cm] Probe section: 3.875 in [9.84 cm]

Length 21.31 ft [6.49 m] 21.54 ft [6.57 m]





The SRFT* slimhole repeat for-mation tester—with a 3.375-in [8.57-cm] OD—brings wireline forma-tion tester services to small-diameter boreholes. It can also be run in wells where conventional tools cannot oper-ate because of abrupt changes in angle, swelling formations, hole restrictions, and other drilling problems.

The SRFT tester can be repeatedly set and retracted during a single trip in the well. The CQG crystal quartz gauge is used to provide quick, accu-rate pressure measurements. One seg-regated sample can be recovered in a sample bottle that is DOT approved for transport. Alternatively, two fluid samples can be recovered from two different depths.

Sample chambers are available in two sizes: 450 cm3 [0.12 galUS] and 23⁄8 galUS [9 L]. An optional water cushion is used to reduce the shock resulting from pressure drawdown when a sample chamber is opened for sampling.

Applications■ Formation pressure measure-

ment in slim holes, short-radius horizontal wells, and unstable or restricted wells

■ Fluid sampling in slim holes, short-radius horizontal wells, and unstable or restricted wells

SRFT Slimhole Repeat Formation Tester



SRFT Tester

Output Pressure measurement, fluid samples

Logging speed Stationary measurements

Range of measurement 0 to 20,000 psi [0 to 138 MPa] at up to 350 degF [177 degC]

Accuracy CQG gauge: Accuracy: ±(2 psi [13,789 Pa] + 0.01% of reading) Resolution: 0.02 psi [138 Pa] at 1-s gate time Strain gauge: 5,000-, 10,000-, and 20,000-psi [34-, 69-, and 138-MPa] ranges Accuracy: ±0.1% of full scale Resolution: 0.001% of full scale

Special applications Slim or restricted holes




SRFT Tester

Standard Probe and Piston Telescoping Pistons (SRTP) Large-Hole Kit (SRLH)



Borehole size—min.† 4.125 in [10.48 cm] 4.8 in [12.19 cm]‡ 6.5 in [16.51 cm]‡

Borehole size—max. 6.3 in [16.00 cm] 7.8 in [19.81 cm] 9.8 in [24.89 cm]

Outside diameter Fully retracted: 3.375 in [8.57 cm] Fully extended: 6.5 in [16.51 cm]

Fully retracted: 3.375 in [8.57 cm] Fully extended: 8.0 in [20.32 cm]

Fully retracted: 4.5 in [11.43 cm] Fully extended: 10.0 in [25.40 cm]




Compression 3,900 lbf [17,350 N] 3,900 lbf [17,350 N] 3,900 lbf [17,350 N] † Minimum borehole size is dependent on the borehole conditions and whether the SRFT tester is run on cable or pipe. ‡ If an SRFT tester with telescoping pistons is set in a hole smaller than recommended, the larger section of the telescoping pistons will touch the borehole. Standoffs should be used in this case.

Sample Chamber Specifications

SRSU-AA with MPSR-BA† SRSC-AA Water Cushion (SRSW-AA)

Capacity 450 cm3 [0.12 galUS] 2.375 galUS [9.0 L] 2.375 galUS [9.0 L]


Pressure rating 20,000 psi [138 MPa]‡ 20,000 psi [138 MPa]‡ 20,000 psi [138 MPa]



Weight 106 lbm [48 kg] 97 lbm [44 kg] 91 lbm [41 kg]§

Special applications DOT-approved MPSR H₂S service PVT samples

H₂S service H₂S service Optional water cushion for SRSC-AA

† The SRSU is only the carrier and also provides water cushion for the MPSR. ‡ Rated to 20,000 psi [138 MPa] for both internal and external pressure. § The SRSW filled with water weighs 111 lbm [50 kg].


The technologically advanced CHDT cased hole dynamics tester, a compo-nent of the ABC analysis behind cas-ing services suite of services, makes multiple pressure measurements and collects fluid samples from behind a cased wellbore. Developed with support from the Gas Technology Insti tute (GTI), the CHDT tester has the unique ability to drill through a cased borehole and into the forma-tion, acquire multiple pressure mea-surements, recover high-quality fluid samples, and then plug the hole made in the casing to restore pressure integ-rity—in a single trip. The restor ation of pressure integrity saves the costs associated with conventional plug-set-ting runs, cement-squeeze operations, pressure tests, and scraper runs as well as the rig costs associated with these operations.

The tool seals against the casing and uses a flexible drill shaft to penetrate both the casing and cement and into the formation. As the drill penetrates the target, the integrated instrument package simultaneously monitors pressure, fluid resistivity, and drilling parameters. This additional information about the casing/cement/formation interfaces enables real-time quality control of the operation.

The CHDT tester is combinable with MDT tester modules in 65⁄8-in [16.83-cm] and larger casing. The module combinations are used to perform high-quality single-phase

sampling, enhanced fluid identification, and contamination monitoring, which were previously possible only for openhole applications. In combination with the other through-casing formation evaluation tools in the ABC services suite—CHFR-Plus cased hole form ation resistivity tool, RSTPro reser-voir saturation tool, CHFD cased hole formation density service, CHFP cased hole formation porosity service, Sonic Scanner acoustic scanning platform, and DSI dipole shear sonic imager—the CHDT tester delivers comprehensive reservoir analysis behind casing.

Applications■ Evaluation of old wells for bypassed

hydrocarbons■ Development of critical economic

data for well evaluation■ Reduced risk alternative to open-

hole formation testing under difficult conditions

■ Pressure monitoring during water, steam, and CO2 injection

■ Identification of collector zones in gas storage wells

■ Stress testing and leakoff evaluation in cased holes

■ Production and injection through known-diameter drillholes

CHDT Cased Hole Dynamics Tester





CHDT Tester

Output Behind-casing pressure measurement, PVT and conventional fluid samples, fluid mobility


Accuracy CQG gauge: ±(2 psi [13,789 Pa] + 0.01% of reading) (accuracy), 0.008 psi [55 Pa] at 1.3-s gate time (resolution)

Depth of drillhole 6 in [152 mm] (max. from casing)

Drillhole diameter 0.281 in [7.137 mm]

Pretest volume 6.1 in³ [100 cm3]

Limitations Max. casing thickness: 0.625 in [1.59 cm] in 13⅜-in casing

Combinability MDT tester modules,† another CHDT tester, most other tools

Special applications Up to six holes drilled and plugged per run‡ H₂S service Fluid identification (resistivity and LFA live fluid analyzer)

† Combinable with MDT tester modules in 6⅝-in [16.83-cm] and larger casing ‡ Formation and casing dependent


CHDT Tester


Pressure rating 20,000 psi [138 MPa] Max. underbalance: 4,000 psi [27 MPa] Plug rating: 10,000 psi [69 MPa] (bidirectional)

Casing size—min. 5½ in [13.97 cm]

Casing size—max. 9⅝ in [24.45 cm]


Length Pressure measurement only: 34.1 ft [10.4 m] Optional sample chamber: 9.7 ft [2.96 m]

Weight Depends on configuration

Tension Depends on configuration

Compression Depends on configuration


XL-Rock* large-volume rotary sidewall coring service closes the gap between core plugs from continuous conven-tional core and wireline-conveyed rotary sidewall cores by retrieving up to fifty 1.5-in-OD by 2.5- to 3.5-in-long sidewall core samples in a single descent. These large-volume core sam-ples deliver a rock volume equivalent to or larger than that of conventional core plugs. The industry’s standard sample size is matched or exceeded for routine (RCAL) and most special core analysis (SCAL) measurements with delivery in less time and at lower cost than conventional coring. At more than 3 times the rock volume of stan-dard 0.92-in-diameter sidewall cores, XL-Rock sidewall core samples recover a sufficient volume of rock to extract three triaxial minicores for full analy-sis of completion quality, which previ-ously required conventional coring. In addition, XL-Rock service provides the flexibility to core multiple intervals in the same descent, which is not possible with conventional coring.

Ruggedized electronics provide additional capabilities in retrieving the larger rock samples. Compatibility with the latest Schlumberger telemetry systems accesses features such as the GPIT general purpose inclinometry tool and standard electronically controlled release device (ECRD) that were previously reserved for sophisticated logging toolstrings. The ability to record gamma ray measurements in the background both saves time otherwise spent on correlation and improves the depth accuracy of every core. Physical drilling parameters, such as weight on bit, are under real-time control to ensure that XL-Rock service is coring at

the optimal settings for every core point. Powered by an in-house hydraulic motor, XL-Rock service efficiently recovers high-quality cores across a wide variety of lithologies, from hard, brittle igneous rocks to friable sandstones, carbonates, and shale plays.

Operational risk is greatly reduced for XL-Rock service. Not only is it the shortest rotary sidewall coring tool in the market today, at only 37 ft in length, but the shaft attached to the core bit has a special built-in safety feature to enable controlled release of the core bit if the bit becomes stuck in the formation. Compatibility with the ECRD also greatly increases the amount of pull allowed on the wireline cable, further reducing the chance of a stuck tool.

Applications■ Geomechanics■ Relative permeability■ Mineralogy: X-ray diffraction,

scanning electron microscopy, isotopes

■ Petrographic description■ Source rock and oil

characterization■ Log calibration: grain density,

resistivity m and n exponents, nuclear magnetic resonance (NMR) T2 cutoff, mineralogy and total organic carbon (TOC), and mechanical properties to acoustic logs

■ Grain-size analysis■ Reservoir storage capacity■ Reservoir flow capacity■ Capillary pressure characteristics

XL-Rock Large-Volume Rotary Sidewall Coring Service




Measurement SpecificationsXL-Rock Service

Output Sidewall core samples

Logging speed Stationary Avg. coring time: 3–8 min per sidewall core†

Range of measurement Sidewall core size:

1.5-in [3.81-cm] diameter × 2.5-in [6.35-cm] long (50 per descent)

1.5-in diameter × 3.0-in [7.62-cm] long (50 per descent)

1.5-in diameter × 3.5-in [8.89-cm] long (44 per descent)


Special applications Conveyance on wireline, drillpipe with the TLC tough logging conditions system, and coiled tubing† Lithology dependent

Mechanical SpecificationsTemperature rating 350 degF [177 degC]†




Outside diameter 6.5 in [16.51 cm]‡

Length 36.5 ft [11.2 m]

Weight (in air) 970 lbm [440 kg]

Tension 22,900 lbf [101,860 N]

Compression 12,500 lbf [55,600 N]† Can be run at 400 degF [204 degC] with a Dewar flask‡ At the coring bit assembly



The standard configuration of the rotary MSCT mechanical sidewall coring tool recovers 50 core samples. Optional configurations for recovering 75 core or 20 core-catcher (dictated by core-catcher capacity) samples are available. Each sample is isolated for positive identification, and a summary output at surface lists all samples with the exact depth and time that each was taken.

The real-time display at the logging unit confirms proper tool operation and sample acquisition. The MSCT tool is run in combination with a gamma ray tool to correlate with openhole logs for accurate, real-time depth control of the coring points.

Applications■ Lithology analysis■ Secondary porosity analysis■ Porosity and permeability

determination■ Confirmation of hydrocarbon shows■ Determination of clay content■ Determination of grain density■ Lithology determination■ Detection of fracture occurrence

MSCT Mechanical Sidewall Coring Tool


MSCT Tool

Output Sidewall core samples†

Logging speed Stationary Coring time (avg.): 3 to 5 min per core

Range of measurement Core size: 2 in [50.8 mm] long × 0.92 in [23.4 mm] diameter

Depth of core sample Core length: 1.5 or 1.75 in [38.1 or 44.4 mm]


Special applications † The MCFU-AA is used for 50 cores per descent and the MCCU is used for 20 cores per descent.


MSCT Tool

Temperature rating 350 degF [177 degC]†


Borehole size—min. 6¼ in [15.87 cm]


Outside diameter 5.375 in [13.65 cm]‡

Length 31.29 ft [9.54 m]

Weight 750 lbm [340 kg]§

Tension 22,900 lbf [101,860 N]

Compression 12,500 lbf [55,600 N] † The MSCT-A can be run at 400 degF [204 degC] with a Dewar flask (UDFH-KF).

Successful jobs have also been performed at 425 degF [218 degC]. ‡ With the standoffs removed, the MSCT tool can be stripped down to 5 in [12.70 cm] and run in 5⅞-in [14.92-cm] holes. § The sonde weighs 580 lbm [263 kg].



The CST* chronological sample taker can collect up to 90 core samples in one trip using a series of core recovery bullets. This percussion-type gun is accurately depth positioned by using an SP or gamma ray log. A surface-controlled, electrically ignited powder charge fires a hollow cylindrical bul-let into the formation at each sample depth. Each bullet is attached by two retaining wires to the gun; these are used to retrieve the bullet and core. The wires have a breaking strength of approximately 1,800 lbf [8,000 N] to release the gun from the core bullet, which prevents a stuck core resulting in a stuck CST sample taker.

The guns vary in the number of bul-lets per gun. Bullet designs are avail-able for optimal core recovery in various ranges of formation consolidation. The recovered samples are usually large enough for conducting core analysis.

Applications■ Porosity measurement■ Permeability estimate■ Lithology identification■ Grain size, density, and shape

indication■ Hydrocarbon identification■ Oil, gas, and water volume estimates

CST Chronological Sample Taker


CST Sample Taker

Output Sidewall cores


Mud type or weight limitations Hydrostatic pressure and formation characteristics determine charge selection

Combinability Usually run with PGGT* powered gun gamma tool for correlation Up to 3 guns can be used to collect a maximum of 90 core samples



CST Sample Taker

Temperature rating Explosive charges: 280 degF [138 degC] for 1 h or 450 degF [232 degC] for 1 h


Borehole size—min.† 4⅛ in [10.48 cm]

Borehole size—max.† 25 in [63.50 cm]

Outside diameter† 3.375 to 5.25 in [8.57 to 13.33 cm]

Length† 6.83 to 17.08 ft [2.08 to 5.21 m]

Weight† 125 to 406 lbm [57 to 184 kg]

Tension 50,000 lbf [222,410 N]

Compression 23,000 lbf [102,310 N] † Depends on the gun, see “CST Sample Taker Specifications”



CST Sample Taker Specifications

CST-AA CST-BA CST-C CST-DA CST-G CST-G60N CST-G60P CST-G60Y

Core samples 30 30 30 30 30 60 60 60

Temperature rating 450 degF [232 degC] 450 degF [232 degC] 450 degF [232 degC] 280 degF [138 degC] 280 degF [138 degC] 280 degF [138 degC] 280 degF [138 degC] 280 degF [138 degC]

Pressure rating 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa]

Borehole size—min. 8½ in [21.59 cm] 8½ in [21.59 cm] 8½ in [21.59 cm] 8½ in [21.59 cm] 5½ in [13.97 cm] 5½ in [13.97 cm] 5½ in [13.97 cm] 6⅛in [15.55 cm]

Borehole size—max. 25 in [63.50 cm] 25 in [63.50 cm] 25 in [63.50 cm] 25 in [63.50 cm] 12½ in [31.75 cm] 12½ in [31.75 cm] 12½ in [31.75 cm] 12½ in [31.75 cm]

Outside diameter 5.25 in [13.33 cm] 4.5 in [11.43 cm] 5.25 in [13.33 cm] 4.5 in [11.43 cm] 4 in [10.16 cm] 4 in [10.16 cm] 4 in [10.16 cm] 4.375 in [11.11 cm]

Length 9.08 ft [2.77 m] 7.92 ft [2.41 m] 7.86 ft [2.39 m] 11.42 ft [3.48 m] 9.50 ft [2.89 m] 17.08 ft [5.21 m] 17.08 ft [5.21 m] 16.71 ft [5.09 m]

Weight 262 lbm [119 kg] 229 lbm [104 kg] 200 lbm [91 kg] 326 lbm [148 kg] 175 lbm [79 kg] 308 lbm [140 kg] 308 lbm [140 kg] 308 lbm [140 kg]

CST Sample Taker Specifications

CST-GY CST-J CST-U CST-V CST-W CST-Y CST-Z

Core samples 30 25 24 21 12 21 30

Temperature rating 280 degF [138 degC] 450 degF [232 degC] 450 degF [232 degC] 450 degF [232 degC] 450 degF [232 degC] 450 degF [232 degC] 450 degF [232 degC]

Pressure rating 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa] 20,000 psi [138 MPa]

Borehole size—min. 6⅛ in [15.56 cm] 4⅛ in [10.46 cm] 5½ in [13.97 cm] 5½ in [13.97 cm] 4¾ in [12.07 cm] 5½ in [13.97 cm] 8½ in [21.59 cm]

Borehole size—max. 12½ in [31.75 cm] 10 in [25.40 cm] 12½ in [31.75 cm] 12½ in [31.75 cm] 12½ in [31.75 cm] 12½ in [31.75 cm] 25 in [63.50 cm]

Outside diameter 4.375 in [11.11 cm] 3.375 in [8.57 cm] 4.375 in [11.11 cm] 4.375 in [11.11 cm] 4.375 in [11.11 cm] 4.375 in [11.11 cm] 5.25 in [13.33 cm]

Length 9.50 ft [2.89 m] 12.92 ft [3.93 m] 6.83 ft [2.08 m] 7.60 ft [2.32 m] 8.08 ft [2.46 m] 7.60 ft [2.32 m] 11.42 ft [3.48 m]

Weight 175 lbm [79 kg] 187 lbm [85 kg] 125 lbm [57 kg] 168 lbm [76 kg] 148 lbm [67 kg] 168 lbm [76 kg] 406 lbm [184 kg]


Well Integrity Evaluation


Isolation Scanner cement evaluation service combines classic pulse-echo technology with a new ultrasonic technique—flexural wave imaging—to accurately evaluate any type of cement, from traditional slurries and heavy cements to the latest light-weight cements. This innovative method provides real-time informa-tion on cement jobs in a wider range of conditions than previously possible with conventional technologies.

In addition to confirming the effectiveness of a cement job for zonal isolation, Isolation Scanner service pinpoints any channels in the cement. The tool’s azimuthal and radial coverage readily differentiates low-density solids from liquids to distinguish lightweight cements from contaminated cement and liquids. The service also provides detailed images of casing centralization and identifies corrosion or drilling-induced wear through measurement of the inside diameter and thickness of the casing.

Flexural wave imaging is used by Isolation Scanner service as a significant complement to pulse-echo acoustic impedance measurement. It relies on the pulsed excitation and propagation of a casing flexural mode, which leaks deep-penetrating acoustic bulk waves into the annulus. Attenuation of the first casing arrival, estimated at two receivers, is used to unambiguously determine the state of the material coupled to the casing as solid, liquid, or gas

(SLG). Third-interface reflection echoes arising from the annulus/formation interface yield additional characterization of the cased hole environment:■ acoustic velocity (P or S) of the

annulus material■ position of the casing within the

borehole or a second casing string■ geometrical shape of the wellbore.

Vertical sampling is selectable to as low as 0.6 in [1.52 cm], and the azimuthal resolution has a maximum of 10°. Because acoustic impedance and flexural attenuation are indepen-dent measurements, their combined analysis provides borehole fluid prop-erties, not requiring a separate fluid-property measurement.

Applications■ Differentiate high-performance

lightweight cements from liquids■ Map annulus material as SLG■ Assess hydraulic isolation■ Image channels and defects

in annular isolating material■ Visualize position of casing

in the borehole■ Assess annulus beyond casing/

cement interface■ Determine casing internal

diameter and thickness■ Determine depth for sidetracking

and casing milling

Wireline Services Catalog ■ Well Integrity Evaluation 181

Isolation Scanner Cement Evaluation Service




Isolation Scanner Service

Output† Solid-liquid-gas map of annulus material, hydraulic communication map, acoustic impedence, flexural attenuation, rugosity image, casing thickness image, internal radius image

Logging speed Standard resolution (6 in, 10° sampling): 2,700 ft/h [823 m/h] High resolution (0.6 in, 5° sampling): 563 ft/h [172 m/h]

Range of measurement Min. casing thickness: 0.15 in [0.38 cm] Max. casing thickness: 0.79 in [2.01 cm]

Vertical resolution High resolution: 0.6 in [1.52 cm] High speed: 6 in [15.24 cm]

Accuracy‡ Acoustic impedance:§ 0 to 10 Mrayl (range); 0.2 Mrayl (resolution); 0 to 3.3 Mrayl = ±0.5 Mrayl, >3.3 Mrayl = ±15% (accuracy) Flexural attenuation:†† 0 to 2 dB/cm (range), 0.05 dB/cm (resolution), ±0.01 dB/cm (accuracy)

Depth of investigation Casing and annulus up to 3 in [7.62 cm]

Mud type or weight limitations‡‡ Conditions simulated before logging

Combinability Bottom only, combinable with most wireline tools Telemetry: fast transfer bus (FTB) or enhanced FTB (EFTB)

Special applications H₂S service † Investigation of annulus width depends on the presence of third-interface echoes. Analysis and processing beyond cement evaluation can yield additional answers through additional outputs,

including the Variable Density log of the annulus waveform and polar movies in AVI format. ‡ 8-mm calibration target § Differentiation of materials by acoustic impedance alone requires a minimum gap of 0.5 Mrayl between the fluid behind the casing and a solid. †† For 0.3-in [8-mm] casing thickness ‡‡ Max. mud weight depends on the mud formulation, sub used, and casing size and weight, which are simulated before logging.


Isolation Scanner Service



Casing size—min.† 4½ in (min. pass-through restriction: 4 in [10.16 cm])

Casing size—max.† 13⅜ in

Outside diameter IBCS-A: 3.375 in [8.57 cm] IBCS-B: 4.472 in [11.36 cm] IBCS-C: 6.657 in [16.91 cm] IBCS-D: 8.736 in [22.19 cm]

Length Without sub: 19.73 ft [6.01 m] IBCS-A sub: 2.01 ft [0.61 m] IBCS-B sub: 1.98 ft [0.60 m] IBCS-C sub: 1.98 ft [0.60 m] IBCS-D sub: 1.98 ft [0.60 m]

Weight Without sub: 333 lbm [151 kg] IBCS-A sub: 16.75 lbm [7.59 kg] IBCS-B sub: 20.64 lbm [9.36 kg] IBCS-C sub: 23.66 lbm [10.73 kg] IBCS-D sub: 24.55 lbm [11.13 kg]

Sub max. tension 2,250 lbf [10,000 N]

Sub max. compression 12,250 lbf [50,000 N] † Limits for casing size depend on the sub used. Data can be acquired in casing larger than 9⅝ in with low-attenuation mud (e.g., water, brine).


Well Integrity Evaluation 183

Cement bond tools measure the bond between the casing and the cement placed in the annulus between the casing and the wellbore. The mea-surement is made by using acoustic sonic and ultrasonic tools. In the case of sonic tools, the measurement is usually displayed on a cement bond log (CBL) in millivolt units, decibel attenuation, or both. Reduction of the reading in millivolts or increase of the decibel attenuation is an indication of better-quality bonding of the cement behind the casing to the casing wall. Factors that affect the quality of the cement bonding are■ cement job design and execution

as well as effective mud removal■ compressive strength of the

cement in place■ temperature and pressure

changes applied to the casing after cementing

■ epoxy resin applied to the outer wall of the casing.

SlimXtreme Sonic Logging ToolThe SlimXtreme Sonic Logging Tool (QSLT) is a digital sonic tool for evaluating the cement bond quality of cemented casing in high-pressure and high-temperature slim holes. The QSLT provides conventional openhole sonic measurements, standard CBL amplitude and Variable Density log (VDL), and attenuation measure-ments, which are less affected by the borehole environmental conditions.

The QSLT can also make a short-spacing (1-ft [0.30-m]) CBL measure-ment for cement evaluation in fast formations. The two transmitters and six receivers of the QSLT sonde have transmitter–receiver spacings of 1, 3, 3.5, 4, 4.5, and 5 ft [0.30, 0.91, 1.07, 1.22, 1.37, and 1.52 m] to compute the following:■ standard 3-ft CBL and 5-ft VDL

measurements■ borehole-compensated (BHC)

attenuation from the 3.5- and 4.5-ft-spacing receivers

■ near-pseudoattenuation from the 3-ft-spacing receivers

■ short-spacing attenuation from the 1-ft-spacing receiver for cement bond measurement in fast forma-tions that may affect the standard 3-ft spacing.

Cement bond log from Digital Sonic Logging ToolThe Digital Sonic Logging Tool (DSLT) uses the Sonic Logging Sonde (SLS) to measure the cement bond ampli-tude and provide a VDL display for evaluation of the cement bond qual-ity of a cemented casing string. VDL or x-y waveform display of the sonic signal is presented in conjunction with the bond index and amplitude signal. The DSLT is also used in the open borehole environ ment for conventional sonic measure ments of BHC (3- to 5-ft) transit time and long-spacing depth-derived BHC (DDBHC) (9- to 11-ft [2.74 to 3.35-m]) transit time.

Cement Bond Logging Tools

HSLT

SCMT

DSLT

QSLT

Memory SlimCBL Tool



Cement bond log from Hostile Environment Sonic Logging ToolThe Hostile Environment Sonic Logging Tool (HSLT) provides the same measurements of the cement bond amplitude and Variable Density log for evaluation of the cement bond quality of a cemented casing string as the QSLT in standard-diameter wells at high pressure and high temperature.

Slim Cement Mapping ToolThe Slim Cement Mapping Tool (SCMT) is a through-tubing cement evaluation tool combinable with the PS Platform production logging platform for a variety of well diagnostics. The two sizes are 111⁄16 in [4.29 cm] for the standard (302 degF [150 degC]) tem-perature rating and 21⁄16 in [5.24 cm] with a 392 degF [200 degC] tempera-ture rating. The SCMT is suitable for running workover operations and in new wells. SCMT operations provide a clear advantage in workover wells because there is no need to pull tubing above

the zone of interest for cement evalu-ation. The SCMT is capable of running through most tubings to evaluate the casing below. In new wells the SCMT is an excellent tool for evaluating casing that is 75⁄8 in [19.36 cm] or less.

The SCMT features a single trans-mitter, two receivers spaced at 3 and 5 ft from the transmitter, and eight segmented receivers 2 ft [0.61 m] from the transmitter. The output of the near (3-ft) receiver is used for CBL and transit-time measurement. The out-put of the far (5-ft) receiver is used for the VDL measurement. The eight segmented receivers generate a radial image of the cement bond variation.

Memory Slim Cement Bond Logging ToolThe Memory Slim Cement Bond Logging Tool provides through-tubing 3-ft CBL and 5-ft VDL measurements with the same accuracy and quality as surface-readout logs. Because of its slim size, the 111⁄16-in tool can be run into the zone of interest without having to remove the tubing from the well. The

tool simultaneously records gamma ray, casing collar location, pressure, tem-perature, and waveforms in a single pass, with the waveforms fully digitized down-hole. More than 40 h of combined tool running time is possible, including 16 h of continuous waveform recording time. Depth-recording systems are available for both hazardous and nonhazardous environments.

The Memory Slim CBL Tool can be run with other PS Platform production logging tools for complete well and reservoir evaluation in one descent. The tools and sensors can be conveyed in the borehole by drillpipe, coiled tub-ing, slickline, or unintelligent tractor. Software for the PS Platform platform is used to perform onsite data process-ing or any necessary postprocessing and prepare the log presentation.

Applications■ Evaluation of cement quality■ Determination of zone isolation■ Location of cement top

Measurement SpecificationsQSLT DSLT HSLT SCMT-C and SCMT-H Memory Slim CBL Tool

Output 3-ft [0.91-m] CBL and attenuation, 1-ft [0.30-m] attenuation, 5-ft [1.52-m] Variable Density log

3-ft [0.91-m] amplitude CBL With SLS-C and SLS-D: 5-ft [1.52-m] Variable Density log

3-ft [0.91-m] amplitude CBL, 5-ft [1.52-m] Variable Density log

3-ft [0.91-m] amplitude CBL, 5-ft [1.52-m] Variable Density log, cement bond variation map

3-ft [0.91-m] CBL, 5-ft [1.52-m] Variable Density log, gamma ray, CCL, traveltime, cement compressive strength

Logging speed 3,600 ft/h [1,097 m/h] 3,600 ft/h [1,097 m/h] 3,600 ft/h [1,097 m/h] 1,800 ft/h [549 m/h] 1,800 ft/h [549 m/h]

Vertical resolution Near attenuation: 1 ft [0.30 m] CBL: 3 ft [0.91 m] VDL: 5 ft [1.52 m]

CBL: 3 ft [0.91 m] VDL: 5 ft [1.52 m]

CBL: 3 ft [0.91 m] VDL: 5 ft [1.52 m]

CBL: 3 ft [0.91 m] VDL: 5 ft [1.52 m]

CBL: 3 ft [0.91 m] VDL: 5 ft [1.52 m] Cement bond variation map: 2 ft [0.61 m]

Depth of investigation CBL: Casing and cement interface VDL: Depends on bonding and formation

CBL: Casing and cement interface VDL: Depends on bonding and formation




Mud type or weight limitations None None None None None

Combinability Part of SlimXtreme platform Combinable with most tools Part of Xtreme platform, combinable with most tools

Combinable with PS Platform platform Combinable with PS Platform platform

Special applications Logging through drillpipe, tubing, and in small casing Fast formations

Logging through drillpipe, tubing, and in small casing Fast formations

Logging through drillpipe, tubing, and in small casing

Mechanical SpecificationsQSLT DSLT HSLT SCMT-C and SCMT-H Memory Slim CBL Tool

Temperature rating 500 degF [260 degC] 302 degF [150 degC] 500 degF [260 degC] SCMT-C: 302 degF [150 degC] SCMT-H: 392 degF [200 degC]

302 degF [150 degC]


Casing size—min. 4½ in [11.43 cm] 5½ in [13.97 cm] 5½ in [13.97 cm] SCMT-C: 2⅜ in [6.03 cm] SCMT-H: 2⅞ in [7.30 cm]

2⅞ in [7.30 cm]

Casing size—max. 8⅝ in [21.91 cm] 13⅜ in [33.97 cm] 13⅜ in [33.97 cm] 7⅝ in [19.37 cm] 7⅝ in [19.37 cm]

Outside diameter 3 in [7.62 cm] 3.625 in [9.21 cm] 3.875 in [9.84 cm] SCMT-C: 1.6875 in [4.29 cm] SCMT-H: 2.06 in [5.23 cm]

1.6875 in [4.29 cm]

Length Without inline centralizer: 23 ft [7 m] With inline centralizer: 29.9 ft [9.11 m]

With SLS-E: 20.63 ft [6.29 m] With SLS-F: 23.81 ft [7.26 m]

25.5 ft [7.77 m] SCMT-C: 23.45 ft [7.14 m] SCMT-H: 28.85 ft [8.79 m]

23.45 ft [7.15 m]

Weight† 270 lbm [122 kg] With SLS-E: 313 lbm [142 kg] With SLS-F: 353 lbm [160 kg]

440 lbm [199 kg] SCMT-C: 100 lbm [45 kg] SCMT-H: 162 lbm [73 kg]

100.2 lbm [45.4 kg]


Compression 4,400 lbf [19,570 N] 2,870 lbf [12,270 N] 6,000 lbf [26,690 N] 150 lbf [670 N] 150 lbf [670 N]

† In air



USI ultrasonic imagerThe USI ultrasonic imager uses a single transducer mounted on an Ultrasonic Rotating Sub (USRS) on the bottom of the tool. The transmitter emits ultrasonic pulses between 200 and 700 kHz and measures the received ultrasonic waveforms reflected from the internal and external casing interfaces. The rate of decay of the waveforms received indicates the quality of the cement bond at the cement/casing interface, and the resonant frequency of the casing provides the casing wall thickness required for pipe inspection. Because the transducer is mounted on the rotating sub, the entire circumference of the casing is scanned. This 360° data coverage enables evaluation of the quality of the cement bond as well as determination of the internal and external casing condition. The very high angular and vertical resolutions can detect channels as narrow as 1.2 in [3.05 cm]. Cement bond, thickness, internal and external radii, and self-explanatory maps are generated in real time at the wellsite.

Applications■ Cement evaluation■ Casing inspection

– Corrosion detection and monitoring

– Detection of internal and external damage or deformation

– Casing thickness analysis for collapse and burst pressure calculations




USI Imager

Output Acoustic impedance, cement bonding to casing, internal radius, casing thickness


Range of measurement Acoustic impedance: 0 to 10 Mrayl [0 to 10 MPa.s/m]

Vertical resolution Standard: 6 in [15.24 cm]

Accuracy Less than 3.3 Mrayl: ±0.5 Mrayl†

Depth of investigation Casing-to-cement interface

Mud type or weight limitations‡ Water-base mud: Up to 15.9 lbm/galUS Oil-base mud: Up to 11.2 lbm/galUS


Special applications Identification and orientation of narrow channels † 8-mm calibration target

‡ Exact value depends on the type of mud system and casing size.


USI Imager




Casing size—max. 20 in [50.80 cm]


Length† 19.75 ft [6.02 m]

Weight† 333 lbm [151 kg]

Tension 40,000 lbf [177,930 N]

Compression 4,000 lbf [17,790 N] † Excluding the rotating sub

USI Imager Rotating Sub Mechanical Specifications

USRS-AB USRS-A USRS-B USRS-C USRS-D USRS-E USRS-F†


3.58 in [9.09 cm]

4.625 in [11.75 cm]

6.625 in [16.83 cm]

8.625 in [21.91 cm]

9.39 in [23.85 cm]

11.40 in [28.96 cm]


9.92 in [25.20 cm]

9.8 in [24.89 cm]

8.3 in [21.08 cm]

8.3 in [21.08 cm]

9.06 in [23.01 cm]

9.06 in [23.01 cm]

Weight 7.7 lbm [3.5 kg]

7.7 lbm [3.5 kg]

10.6 lbm [4.8 Kg]

15.0 lbm [6.8 kg]

18.3 lbm [8.3 kg]

17.64 lbm [8.0 kg]

20.06 lbm [9.1 kg]

† Logging in 20-in casing can be acquired with low-attenuation muds (e.g., water, brine).



The EM Pipe Scanner electromagnetic casing inspection tool uses noninva-sive electromagnetic measurements to evaluate the integrity of well casings by locating, identifying, and quantifying damage and corrosion.

Even while running in hole, the EM Pipe Scanner tool delivers valu-able monitoring data, recording a con-tinuous log of the average casing inner diameter and total metal thickness in single or double casing strings at speeds up to 3,600 ft/h [1,097 m/h]. This information is used to plan the acquisition mode of the upward pass.

For logging in single casing strings, the EM Pipe Scanner tool can be run in two modes: casing inspection mode at 1,800 ft/h [548 m/h] to identify any potential corrosion issues and then, as required, a slower diagnostic pass to pinpoint the exact severity and nature of the corrosion. In both modes a low-frequency image and high-frequency image are produced. A detailed cas-ing summary report (CSR) is output for single-string casing surveys, listing average metal loss, maximum penetra-tion, and histograms of the data joint by joint.

The EM Pipe Scanner tool also pro-vides measurements to evaluate and identify corrosion in two concentric completion strings such as casing and tubing. The coil section of the tool determines the total-metal electro-magnetic thickness of both strings combined but does not resolve the thickness of each string individually. Combined interpretation of the low-frequency thickness image and the high-frequency discrimination image enables determination of whether an observed metal loss is from the inner tubing wall or elsewhere.

With a slim 2.125-in [5.4-cm] diam-eter, the EM Pipe Scanner tool easily passes through tubing to evaluate cas-ing below the tubing shoe and quantify metal loss in percentage and aver-age ID of casing ranging from 27⁄8- to 133⁄8-in OD. The tool’s pad sensors azi-muthally image casing up to 95⁄8-in OD. The tool is fluid insensitive, operating in liquid or gas environments.

Applications■ Quantitative evaluation of corrosion

damage in single casing strings■ Qualitative evaluation in multiple

casing strings■ Corrosion rate estimates from time-

lapse comparison■ Identification of casing corrosion

behind tubing■ Casing inspection below tubing

string■ Determination of inner radius

behind scale

EM Pipe Scanner Electromagnetic Casing Inspection Tool




EM Pipe Scanner Tool

Output Electromagnetic thickness, casing ID, casing properties, high- and low-frequency images, corrosion summary report†

Logging speed Electromagnetic computed thickness (ETHK) (single and double strings): 3,600-ft/h [1,097-m/h] inspection pass for mandrel data

Imaging (single string): 1,800-ft/h [549-m/h] standard-resolution inspection pass 300-ft/h [91-m/h] high-resolution diagnostic pass

Range of measurement Maximum metal thickness‡: 1.5 in [3.81 cm] at 8.75 Hz

Resolution Attenuation < 60 dB: 1%

Electromagnetic thickness: 15%§

Accuracy Casing ID: ±0.5 in††

Mud type or weight limitations Any borehole fluid

Combinability All PS Platform platform tools

Multiple-tool answer products

Special applications NACE compliant for H₂S and CO₂ resistance † Corrosion report for single casing strings ‡ Measurement depends on casing geometry, properties, and chrome content. § The resolution depends on the accuracy of casing electrical conductivity (sigma). The usual method is to use API specifications in a ”good“

casing section and adjust conductivity to match the nominal value, which has a typical 12.5% range (Oil Country Tubular Goods, API Spec 5CT, Specification for Casing and Tubing)

†† Casing ID (dci) < 6 in and tool eccentered = [30% × (dci – 2.2 in)]


EM Pipe Scanner Tool



Casing size—min. 2⅞ in (ID > 2.313 in)

Casing size—max. 13⅜ in for electromagnetic thickness


Pad sensor arms 18 coupled

Max. diameter 9⅝-in casing

100% image coverage 7-in casing



Tension Fishing: 10,000 lbf [44,480 N]

Compression Fishing: 3,000 lbf [13,340 N]



UCI ultrasonic casing imagerThe UCI* ultrasonic casing imager is an evolution of the USI ultrasonic imager. The UCI imager provides all the answers required to locate, iden-tify, and quantify casing damage or corrosion. The design is specifically engineered for high-azimuthal-resolu-tion images and detailed examination of both the inner and outer surfaces of casing ranging from 4½ to 133⁄8 in [11.43 to 33.97 cm], resulting in improved echo detection.

Full azimuthal coverage with a 2-MHz focused ultrasonic transducer is used to analyze the reflections. Signal arrivals are analyzed to provide the casing thickness and surface con-dition images, and even small defects on both internal and external casing surfaces are quantified. An improved centralization system ensures proper centralization even in hori-zontal wells, and eccentering effects are reduced through wellsite signal correction.

Applications■ Casing integrity evaluation■ Identification, location, and

quantification of casing corrosion■ Estimated damage to casing

caused by milling, fishing, or plastic deformation

■ Internal and external metal loss■ Internal and external scale buildup■ Location and identification of

perforated intervals■ Identification of holes in casing■ Identification of casing profile

and weight changes■ Identification of centralizers

and other casing anomalies

Corrosion Monitoring




UCI Imager

Output Amplitude image, casing thickness image, internal radius image, fluid velocity

Logging speed 3,000 ft/h [914 m/h] High resolution: 400 ft/h [122 m/h]

Range of measurement Min. casing thickness: In water = 0.15 in [0.38 cm] In attenuating fluids, including oil-base mud = 0.2 in [0.51 cm]

Vertical resolution High resolution: 0.2 in [0.51 cm] High speed (3,000 ft/h]: 1.5 in [3.81 cm]

Accuracy Internal radius: ±0.04 in [±1 mm] Casing thickness: ±4%

Depth of investigation Thickness of casing

Mud type or weight limitations Oil-base mud: No solids Water-base mud: Solids content < 5%




UCI Imager



Casing size—min.† 4½ in [11.43 cm]

Casing size—max.† 13⅜ in [33.97 cm]

Outside diameter USRS-AB: 3.41 in [8.66 cm] USRS-A: 3.56 in [9.04 cm] USRS-B: 4.65 in [11.81 cm] USRS-C: 6.69 in [16.99 cm] USRS-D: 8.66 in [22.00 cm]

Length Without sub: 19.73 ft [6.01 m]

Weight Without sub: 333 lbm [151 kg]

Tension 40,000 lbf [177,930 N]

Compression 4,000 lbf [17,790 N] † Minimum and maximum casing sizes depend on the sub used.



PS Platform Multifinger Imaging ToolThe PS Platform Multifinger Imaging Tool (PMIT) is a multifinger caliper tool that makes highly accurate radial measurements of the inside diameter of tubing and casing strings. The tool is available in three sizes to address a wide range of through-tubing and cas-ing size applications.

The tool deploys an array of hard-surfaced fingers, which accu-rately monitor the inner pipe wall. Eccentricity effects are minimized by equal azimuthal spacing of the fingers and a special processing algorithm. The PMIT-B and PMIT-C tools incor-porate powerful motorized centraliz-ers to ensure effective centering force even in highly deviated intervals. The centralizers are equipped with rollers to prevent casing and tubing damage. The inclinometer in the tool provides information on well deviation and tool rotation. The PMIT-C tool can be fit-ted with special extended fingers for logging large-diameter casings. The PMIT-A is similarly fitted with special extended fingers for logging casing through tubing. All versions of the PMIT can be run in either real-time or memory mode.

Applications■ Identification and quantification

of corrosion damage■ Identification of scale, wax,

and solids accumulation■ Monitoring of anticorrosion

systems■ Location of mechanical damage■ Evaluation of corrosion increase

through periodic logs■ Determination of absolute inside

diameterPMIT-A

PMIT-C

PMIT-B




PMIT-A PMIT-B PMIT-C

Output Internal casing image from multiple internal radius measurements

Internal casing image from multiple internal radius measurements

Internal casing image from multiple internal radius measurements

Logging speed, ft/h [m/h] Standard: 1,800 [549] Max.: 6,000 [1,829]

Standard: 1,800 [549] Max.: 6,000 [1,829]

Standard: 1,800 [549] Max.: 6,000 [1,829]

Minimum measurable casing ID, in [cm]

Standard or extended fingers: 2 [5.08] 3 [7.62] Standard fingers: 5 [12.7] Extended fingers: 8 [20.32]

Maximum measurable casing ID, in [cm]

Standard fingers: 4.5 [11.43] Extended fingers: 7 [17.78]

7 [17.78] Standard fingers: 10 [25.4] Extended fingers: 13 [33.02]

Vertical resolution at 1,800 ft/h [529 m/h], in [mm]

0.082 [2.1] 0.11 [2.8] 0.167 [4.24]

Radial resolution, in [mm] Standard fingers: 0.004 [0.10] Extended fingers: 0.007 [0.18]

0.005 [0.13] Standard fingers: 0.007 [0.18] Extended fingers: 0.009 [0.23]

Accuracy, in [mm] Standard fingers: ±0.030 [±0.76] Extended fingers: ±0.042 [±1.07]

±0.030 [±0.76] Standard fingers: ±0.030 [±0.76] Extended fingers: ±0.050 [±1.3]

Relative bearing accuracy, ° ±5 ±5 ±5

Deviation accuracy at up to 70° deviation, °

±5 ±5 ±5

Depth of investigation Casing inside surface Casing inside surface Casing inside surface

Borehole fluid limitations None None None

Combinability Real time: combinable with all PS Platform platform tools Memory mode: stand alone

Real time: combinable with all PS Platform platform tools Memory mode: stand alone

Real time: combinable with all PS Platform platform tools Memory mode: stand alone Bottom-only tool Extra centralizers required for casing larger than 9⅝ in

Special applications H₂S service H₂S service H₂S service


PMIT-A PMIT-B PMIT-C

Temperature rating, degF [degC] 302 [150] 302 [150] PMIT-CA: 302 [150] PMIT-CB: 350 [177]

Pressure rating, psi [MPa] 15,000 [103] 15,000 [103] PMIT-CA: 15,000 [103] PMIT-CB: 20,000 [138]

Outside diameter, in [cm] Standard or extended fingers: 1.6875 [4.29]

2.75 [6.99] Standard fingers: 4 [10.16] Extended fingers: 5.5 [13.97]

Fingers 24 40 60

Fingertip radius, in [mm] 0.06 [1.5] 0.05 [1.27] 0.06 [1.52]

Finger width, in [mm] 0.063 [1.6] 0.063 [1.6] 0.063 [1.6]

Length, ft [m] 11.88 [3.62] (with centralizers) 8.86 [2.70] 10.34 [3.15]

Weight, lbm [kg] 56.5 [26] (with centralizers) 87.4 [40] 120 [54]

Tensile strength, lbf [N] 10,000 [44,480] 10,000 [44,480] 10,000 [44,480]

Compressive strength, N [lbf] 1,850 [8,230] 2,500 [11,120] 2,500 [11,120]


Production Logging Services


The Flow Scanner horizontal and deviated well production logging system deploys multiple minispin-ners and arrays of electrical and opti-cal probes across the vertical axis of the wellbore, regardless of hole deviation, to produce real-time mul-tiphase velocity and holdup profiles. Unlike conventional production log-ging tools, which are designed with a central, single spinner for use in vertical or nearly vertical wells, the Flow Scanner system provides a complete flow analysis of complex downhole environments, including highly deviated wells.

As the tool is run eccentralized, against the wellbore wall, the innovative electrical probes of the Flow Scanner system distinguish water and hydrocarbon holdups. The optical probes differentiate gas from liquid holdups to enable the three-phase measurement. All measurements are made simultaneously in the same vertical depth interval. The holdup profiles are combined with the multiphase velocity profile calculated from the measured phase velocities to determine relative volumetric flow rates in real time.

Applications■ Multiphase flow profiling in

nonvertical wells■ Identification of fluid and gas

entry in multiphase wells and of liquid entry in gas wells

■ Detection of fluid recirculation■ Stand-alone, real-time, three-

phase flow interpretation

Wireline Services Catalog ■ Production Logging Services 195

Flow Scanner Horizontal and Deviated Well

Production Logging System




Flow Scanner System

Output Oil, gas, and water holdups; oil, gas, and water velocities; relative bearing; caliper

Logging speed† 1,800, 3,600, 5,400, and 7,200 ft/h [549, 1,097, 1,646, and 2,195 m/h]

Range of measurement Borehole coverage: 95% in 6-in- [15.24-cm-] ID casing

Vertical resolution Not applicable

Accuracy Three-phase holdup: ±10% Velocity: ±10%

Depth of investigation Within the wellbore

Mud type or weight limitations Min. salinity for electrical probe measurement: 1,000 ppm at 212 degF [100 degC]

Combinability Combinable with PS Platform platform and most cased hole tools

Special applications H₂S service † In situ spinner calibration requires passes recorded at different logging speeds.


Flow Scanner System



Borehole size—min. 2⅞ in [7.30 cm]†


Outside diameter 1.6875 in [4.29 cm] High-temperature (>302 degF [>150 degC]): 2.25 in [5.72 cm]

Length Flow Scanner system tool: 11.6 ft [3.54 m] With basic measurement sonde, swivel, and head: 26.2 ft [7.99 m]


Max. tension 10,000 lbf [44,480 N]

Max. compression 1,000 lbf [4,450 N] † Min. restriction is 1.813 in [4.61 cm].


Production Logging Services 197

The integrated PS Platform produc-tion services platform performs in vertical, horizontal, or any angle of bore-hole deviation to provide three-phase flow profiles and production monitoring or diagnostic information. Measurement capability is in both real-time and memory modes.

Three-phase flow profiles and res-ervoir monitoring information are pro-vided by the following sensors in the PS Platform platform toolstring:■ Platform Basic Measurement

Sonde (PBMS) houses the gamma ray and casing collar locator for correlation and also measures well pressure and temperature.

■ Flow-Caliper Imaging Sonde (PFCS) measures the average fluid veloc-ity, water and hydrocarbon hold-ups, and bubble counts from four independent electrical probes. The bubble count image is used to iden-tify the first fluid entry. This com-pact sonde—measuring only 5.2 ft [1.58 m] long—provides an inte-grated set of measurements for flow rate evaluation. The position of the sensors (only 1.3 ft [40 cm] from the bottom of the toolstring) enables accurate measurement even when logging wells with a small sump. The PFCS is also self-centering and has several spinner and caliper set-tings that are easily changed at the wellsite to adapt to the range of tubular and hole sizes to be tra-versed during a survey. The tips of the centralizer and caliper arm can be equipped with either skids or rollers for smooth conveyance in both open and cased holes. Spinner blades are available in different sizes to log the normal range of casing and borehole sizes. The centralizer and caliper arm provides an x-y measurement of

casing, tubing, or openhole diam-eter with a resolution of 0.04 in [1.0 mm]. This level of sensitivity enables the examination of corro-sion or defects such as splits or separation in tubing and casing with one trip into the wellbore.

■ Gradiomanometer specific gravity profile tool (PGMS) measures the average density of the wellbore fluid, from which the water, oil, and gas holdups are derived. An accelerome-ter measurement provides deviation correction for the measured fluid density.

■ GHOST gas holdup optical sensor tool uses four optical probes to mea-sure gas and liquid holdups. The certainty of the three-phase flow rate determination and accuracy of the final calculation are ensured by the clear discrimination between liquid and gas that GHOST tool mea-surements provide.

■ FloView holdup measurement tool incorporates four electrical probes that can be used to measure water and hydrocarbon holdups and bubble counts in conjunction with the PFCS electrical probes for greater borehole coverage. This additional information is especially useful in horizontal wells, where flow profiles are essential for understanding surface production.

■ FloView Plus holdup measurement for highly deviated and horizontal wells adds a FloView tool with the electrical probes angularly offset with respect to the primary FloView tool in the toolstring. The FloView Plus tool combination of two FloView tools provides even better radial res-olution that is particularly useful in horizontal or highly deviated wells where segregated flow is suspected.

PS Platform Production Services Platform

FloView andFloView Plus

GHOST-A

PGMS

PILS-A

PBMS

PFCS



■ PS Platform Inline Spinner (PILS) is an optional component for measuring bidirectional fluid velocity inside the tubing or as a backup spinner, nor-mally in higher flow rates.

■ UNIGAGE pressure gauge system (PUCS) provides an optional high-res-olution pressure measurement. This additional measurement capability is typically used to make transient mea-surements for reservoir characteriza-tion and monitoring.

■ SCMT slim cement mapping tool can be run in conjunction with the PS Platform platform for cement bond and Variable Density logs in casing. A radial cement map is also available in surface-readout mode.


PS Platform Production Logging Platform

Output Flow rate, fluid density, pressure, temperature, water holdup, gas holdup, caliper, relative bearing, tool acceleration With SCMT: CBL, VDL, surface-readout radial cement map

Logging speed Stationary to variable based on the application

Range of measurement See individual sensor listing

Accuracy See individual sensor listing

Depth of investigation Wellbore measurements

Mud type or weight limitations Relatively clean fluids

Combinability Combinable with SCMT tool and PS Platform Multifinger Imaging Tool (PMIT)

Special applications Conveyance on drillpipe, tubing, coiled tubing, or slickline


PS Platform Production Logging Platform

Temperature rating 302 degF [150 degC] PILS: 350 degF [177 degC] High-temperature† and memory (only PBMS, PFCS, and PGMS sensors): 374 degF [190 degC] High-temperature† and surface readout (only PBMS, PFCS, and PGMS sensors): 392 degF [200 degC]

Pressure rating Sapphire gauge: 10,000 psi [69 MPa] CQG and high-pressure Sapphire gauges: 15,000 psi [103 MPa]

Borehole size—min.‡ 2⅜ in [6.03 cm]

Borehole size—max. PFCS caliper: 11 in [27.94 cm] Other sensors: No limit

Outside diameter Without rollers: 1.6875 in [4.29 cm] With rollers: 2.125 in [5.40 cm] High temperature: 2.06 in [5.23 cm]

Length§ PBMS: 8.27 ft [2.52 m] PFCS: 5.14 ft [1.57 m] PGMS: 4.8 ft [1.46 m] GHOST tool: 7.1 ft [2.16 m] FloView tool: 6.8 ft [2.07 m] PILS: 3.1 ft [0.94 m] UNIGAGE gauge: 4.2 ft [1.28 m]

Weight§ PBMS: 38.3 lbm [17.4 kg] PFCS: 19.7 lbm [9.0 kg] PGMS: 29.5 lbm [13.4 kg] GHOST tool: 57.7 lbm [26.2 kg] FloView tool: 16 lbm [7.3 kg] PILS: 12.5 lbm [5.7 kg] UNIGAGE gauge: 33 lbm [15 kg]

† High-temperature tools include the High-Temperature Basic Measurement Sonde (HBMS) and the High-Temperature Gradio flowmeter tool (HGFT). These two components provide the same measurements as the PBMS, PGMS, and PFCS.

‡ Min. tubing size § The high-temperature tool (including all sensors) has a length of 23.94 ft [7.30 m] and a weight of 190.2 lbm [86.3 kg].


Applications■ Three-phase production logging

– Vertical, deviated, and horizontal wells

– Combined with perforating for immediate flow rate analysis

– Stimulation evaluation– Multirate production logging

■ Depth correlation■ Reservoir and production

monitoring■ Time-lapse monitoring■ Transient analysis■ Short periods of multilayer testing■ Cement bond evaluation


PS Platform Production Logging Component Measurement SpecificationsPBMS PFCS PGMS GHOST Tool

Output Pressure (Sapphire or CQG gauge), temperature, gamma ray, CCL

Fluid velocity, water holdup, relative bearing, x-y dual caliper

Fluid density, acceleration, deviation

Gas holdup, relative bearing, average caliper

Logging speed Based on application Based on application Based on application Based on application

Range of measurement Sapphire gauge: 1,000 to 10,000 psi [6.9 to 69 MPa] High-pressure Sapphire gauge: 1,000 to 15,000 psi [6.9 to 103 MPa] CQG gauge: 14.5 to 15,000 psi [0.1 to 103 MPa] Temperature: Ambient to 302 degF [150 degC]

Spinner: 0.5 to 200 rps Caliper: 2 to 11 in [5.08 to 27.94 cm] (diameter)

0 to 2.0 g/cm3 Gas holdup: 0 to 100% Caliper: 2 to 9 in [5.08 to 22.86 cm]

Vertical resolution Point of measurement Point of measurement 15 in [38.10 cm] Point of measurement

Accuracy Sapphire gauge: ±6 psi [±41,370 Pa] (accuracy), 0.1 psi [689 Pa] at 1-s gate time (resolution) High-pressure Sapphire gauge: ±13 psi [±89,632 Pa] (accuracy), 0.2 psi [1,379 Pa] at 1-s gate time (resolution) CQG gauge: ±(1 psi [6,894 Pa] + 0.01% of reading) (accuracy), 0.01 psi [69 Pa] at 1-s gate time (resolution) Temperature: ±1.8 degF [±1 degC] (accuracy), 0.01 degF [0.005 degC] (resolution)

Water holdup (Hw): ±5%, ±2% for Hw > 90%, ±10% in oil-continuous phase Relative bearing: ±6° Caliper: ±0.2 in [±5.1 mm]

±0.04 g/cm3 (accuracy), 0.002 g/cm3 (resolution)

Gas holdup: ±5% without probe protector, ±7% with probe protector, ±1% for 2% < gas holdup (Hg) < 98% Relative bearing: ±6° Caliper: ±0.25 in [±6.3 mm]

Combinability Combinable with SCMT tool and PMIT

Special applications Exceeds NACE MR0175 standard for H₂S resistance

PS Platform Production Logging Component Measurement SpecificationsFloView Tool PILS UNIGAGE Gauge

Output Water holdup, relative bearing, average caliper

Fluid velocity Pressure (quartz crystal gauge)

Logging speed Based on application Based on application Based on application

Range of measurement Caliper: 2 to 9 in [5.08 to 22.86 cm] Spinner: 0.5 to 100 rps 15 to 15,000 psi [0.1 to 103 MPa]

Accuracy Water holdup: ±5%, ±2% for Hw > 90%, 10% in oil-continuous phase Relative bearing: ±6° Caliper: ±0.25 in [±6.3 mm]

– ±1 psi [6,894 Pa] ± 0.01% full scale (accuracy), ±0.01 psi [±69 MPa] (resolution)

Combinability Combinable with SCMT tool and PMIT Combinable with SCMT tool and PMIT Combinable with SCMT tool and PMIT

Special applications Exceeds NACE MR0175 standard for H₂S resistance

Exceeds NACE MR0175 standard for H₂S resistance

Exceeds NACE MR0175 standard for H₂S resistance


The RSTPro reservoir saturation tool is compatible with the surface-readout version of the PS Platform production logging platform. Only the pro duction logging capabilities of the RSTPro tool are discussed in this section.

The primary use of the RSTPro tool is formation evaluation behind casing. The RSTPro tool provides measure-ments of the formation capture cross section (sigma), porosity, and carbon and oxygen in one trip in the well-bore. This data combination is useful for water saturation evaluation in old wells in which modern openhole logs have not been run.

WFL water flow log from the RSTPro reservoir saturation toolThe WFL water flow log is used to locate and evaluate axial water migration behind pipe, measure the velocity of water flow in both production wells and water injection wells, and collect critical data on internal or behind-pipe crossflow between zones.

The RSTPro tool can be configured for WFL flow measurement of both upward and downward flow, inside casing and behind pipe. This adapt-ability enables the diagnosis of any flow condition. The tool measures the phase velocity of water. In a producing well it measures the velocity of water independent of other produced fluids; however, the accuracy of the water velocity measurement is decreased if the ratio of the volume of water to other produced fluids is low. The phase velocity inside casing can be converted to a quantitative measurement of pro-duction or injection (i.e., barrels per day or cubic meters per day).

Applications■ Detection and quantification of

water flowing in cement channels■ Identification of water flow in the

annulus between tubing and casing■ Independent measurement

of water velocity in casing


RSTPro Reservoir Saturation Tool

RST-C RST-D


RSTPro Tool for WFL Water Flow Log

Output Velocity of water flowing inside the borehole or outside the casing

Logging speed Stationary measurements

Range of measurement 3 to 210 ft/min [0.9 to 64 m/min] for 4.9-in [12.45-cm] ID casing

Vertical resolution Depends on water velocity

Accuracy ±5%

Depth of investigation For flow behind casing: 6 in [15.24 cm]


Combinability Combinable with additional gamma ray sensor, PS Platform platform tools (only surface readout), and CPLT tool

Special applications Inverted RSTPro tool measures downward flow inside the borehole or outside the casing H₂S service


RSTPro tool with silica activationThe RSTPro reservoir saturation tool with silica activation can be run with the surface-readout version of the PS Platform platform to provide infor mation for evaluating the quality of gravel-pack placement before placing the well on production. The gamma ray detectors use the nuclear reaction response of silica to neutron

bombardment to identify the location of gravel-pack sand behind the screen. If holes or gaps are found in the pack placement, a remedy can be applied inexpensively during this phase of the completion. If the gravel-pack sand was not placed behind the screen to the proper height, the job can continue until it is. A second pass of the RSTPro tool with silica activation can then verify proper placement for a successful job.

Applications■ Proper placement of gravel-pack

sand■ Identification of holes or gaps

in the sand pack■ Efficient pack correction



RSTPro Tool with Silica Activation

Output Silica-activated gamma ray curve, images of sand placement and deficiencies


Vertical resolution �15 in [�38 cm]

Depth of investigation �10 in [�25 cm]


Combinability Combinable with PS Platform platform (only surface readout), CPLT tool, gamma ray



RST-C RST-D

Temperature rating 302 degF [150 degC] With flask: 400 degF [204 degC]

302 degF [150 degC] With flask: 400 degF [204 degC]


15,000 psi [103 MPa] With flask: 20,000 psi [138 MPa]

Borehole size—min. 113⁄16 in [4.60 cm] 3 in [7.62 cm]

Borehole size—max. 9⅝ in [24.45 cm] 9⅝ in [24.45 cm]


Length 23.0 ft [7.01 m] 22.2 ft [6.76 m]





The CPLT combinable production logging tool provides a production profile for a producing wellbore. The profile includes measurements of the flow rate, fluid density, temperature, and in situ pressure in the wellbore. A three-arm caliper can be included

when the CPLT toolstring is run in open hole. Other uses of the CPLT tool include monitoring the profile of injection fluids into an injection well and determining the existence of fluid channeling behind casing.


CPLT Combinable Production Logging Tool


CPLT Tool

Output Flow rate, fluid density, temperature, pressure, caliper

Logging speed Stationary to variable based on application

Range of measurement Spinner: 0.5 to 100 rps Density: 0 to 2 g/cm3 Temperature: –13 to 350 degF [–25 to 177 degC] Pressure: 0 to 10,000 psi [0 to 69 MPa] Caliper: 2 to 18 in [5.08 to 45.72 cm]

Vertical resolution Spinner, temperature, pressure, and caliper: Point of measurement Density: 15 in [38.10 cm]

Accuracy Spinner: ±0.1 rps Density: ±0.04 g/cm3 (accuracy), 0.004 g/cm3 (resolution) Temperature: ±1.8 degF [±1 degC] (accuracy), 0.011 degF [0.006 degC] (resolution) Pressure: ±10 psi [±0.07 MPa] (accuracy), 0.1 psi [689 Pa] (resolution)

Depth of investigation Borehole measurement only


Combinability Combinable with most production logging services



CPLT Tool



Borehole size—min. 125⁄32-in [4.52-cm] seating nipple


Outside diameter With Continuous Flowmeter Sonde CFS-H: 1.6875 in [4.29 cm] With CFS-J: 2.125 in [5.40 cm] With CFS-K: 2.875 in [7.30 cm]

Length Basic tool body: 15.2 ft [4.6 m]

Weight Basic tool body: 75 lbm [34 kg]

Tension 10,000 lbf [44,480 N]



The Combinable Gamma Ray Sonde (CGRS) performs both through-tubing and -casing gamma ray correlation. The result is accurate posi tioning of various production logging tools on depth with openhole logs. The CGRS is also used as a third gamma ray detector in combination with the RSTPro reservoir saturation tool to detect high-velocity water movement.

Application■ Accurate depth correlation


Combinable Gamma Ray Sonde


CGRS

Output Gamma ray activity

Logging speed Up to 3,600 ft/h [1,097 m/h]

Range of measurement 0 to 2,000 gAPI


Accuracy ±5%



Combinability Combinable with CPLT tool, RSTPro tool



CGRS



Borehole size—min. 113⁄16 in [4.60 cm]





Tension 10,000 lbf [44,480 N]



The Phase Velocity Sonde (PVS) is a production logging tool used in con-junction with the RSTPro reservoir saturation tool to measure the veloc-ity of two separate phases (water and oil) in a flowing horizontal or highly deviated well. A chemical marker with a high thermal neutron absorption cross section (sigma) that is mis-cible only with the phase of interest is injected into the borehole. The passage of the marker downstream is detected by the borehole sigma measurement of the RSTPro tool. The PVS is capable of measuring upflow or downflow depending on where it is placed in the toolstring with respect to the RSTPro tool. The fluid velocity

is determined from the ejection-to-detector distance and travel time. These data are essential for determi-nation of the volume of water, oil, or both fluids flowing in the wellbore. This provides a basis for determining the flowing profile of a well at down-hole conditions in comparison with individual-fluid production at surface conditions. The PVS main module can be combined with an auxiliary mod-ule to provide an additional chemical marker reservoir for long jobs.

Application■ Downhole measurement of a PVL

phase velocity log


Phase Velocity Sonde


PVS

Output PVL phase velocity log


Range of measurement Phase velocity: 4 to 500 ft/min [1.2 to 152 m/min]

Vertical resolution Depends on ejector–detector spacing

Accuracy ±5%

Depth of investigation Borehole

Mud type or weight limitations Produced or injected fluids

Combinability PS Platform production services platform (only surface readout)




PVS


Pressure rating 5,000, 10,000, or 15,000 psi [34, 69, or 103 MPa]

Borehole size—min. 2⅜ in [6.03 cm]†



Length Main and auxiliary modules: 22.39 ft [6.82 m] Main module: 12.9 ft [3.93 m] Optional auxiliary module: 9.44 ft [2.88 m]

Weight Main module: 57.7 lbm [26.2 kg] Auxiliary module: 45.5 lbm [20.6 kg]

Tension 5,000-psi [34-MPa] rating: 12,650 lbf [56,270 N] 10,000-psi [69-MPa] rating: 19,350 lbf [86,070 N] 15,000-psi [103-MPa] rating: 26,000 lbf [115,650 N]


Marker fluid ejection Reservoir volume: 400 cm3 (main), 400 cm3 (auxiliary) Ejection volume: 10 cm3 ± 1 cm3 (standard), 15 cm3 ± 1.5 cm3 (optional) Ejection duration: 250 ms (max.) Ejection recycle time for metering piston: �1 min

† Min. tubing size


The FloView tool is used to determine the percentage of the heavy phase, normally water, in the flow stream downhole. The tool also measures the bubble count of the light phase, either gas or oil, in the flow stream. This measurement is used to calculate the velocity of the light phase, if in bubble form, at the point of measurement (i.e., the intrinsic velocity) and is independent of the velocity measured by propeller flowmeters.

Applications■ Accurate water holdup■ First oil-entry detection

– From bubble count– Works at high water cut

■ First water-entry detection for water shutoff (at low water cut)

■ Caliper measurement■ Differentiation of fresh and

injected waters


FloView Holdup Measurement Tool


FloView Tool

Output Bubble count, water holdup, caliper

Logging speed Stationary to variable based on application

Range of measurement Caliper: 2 to 9 in [5.08 to 22.86 cm]

Vertical resolution Point of measurement

Accuracy Water holdup (Hw): ±5% (±2% for Hw > 90%)† Relative oil flow rate: ±20%

Depth of investigation Borehole measurement

Mud type or weight limitations Min. salinity of all wellbore fluids: 2,000 ppm at 77 degF [25 degC] 1,000 ppm at 212 degF [100 degC] 700 ppm at 302 degF [150 degC]

Combinability Gamma ray, CPLT tool

Special applications H₂S service † Valid for bubble size greater than 0.08 in [2 mm] and deviation less than 30°


FloView Tool


Pressure rating DEFT-A and DEFT-AB: 15,000 psi [103 MPa] DEFT-B: 10,000 psi [69 MPa]




Length DEFT-A and DEFT-AB: 6.75 ft [2.06 m] DEFT-B: 6.08 ft [1.85 m]


Tension 10,000 lbf [44,480 N]



The Multiple-Isotope Spectroscopy Tool (MIST) discriminates between isotopes that emit gamma rays to provide a clear analysis of multistage stimulation at the wellsite. The tool detects gamma ray energies through 14 energy windows that range from 180 to 3,000 keV. The related counts and energy levels are integrated by the wellsite computer and used to identify the source isotope. Isotope identification by the MIST log is virtually immediate. Using laboratory-derived standard spectra, the detector also discriminates between isotopes in the formation and isotopes in the wellbore.

Because the MIST tool discrim-inates between radioisotopes, it is used to track downhole processes that

can be tagged with different isotopes. An important example is formation fracture evaluation. If the pad fluid and each proppant stage are tagged with different isotopes, a single wire-line run can log both the extent of the fracture and the degree of proppant placement. The real-time availability of the MIST log at the wellsite means that the evaluation is conducted immediately.

Applications■ Single-pass analysis of multiple

fracture jobs■ Background-corrected analysis

of multiple fracture jobs


Multiple-Isotope Spectroscopy Tool


MIST

Output Elemental spectra from individual tracer isotopes





Combinability Gamma ray, CCL, CPLT tool


MIST-A MIST-B



Borehole size—min. 2¾ in [6.98 cm] 3 in [7.62 cm]

Borehole size—max. 12 in [30.48 cm] 12 in [30.48 cm]

Outside diameter 1.6875 in [4.29 cm] 2 in [5.08 cm]

Length 14.3 ft [4.36 m] 14.3 ft [4.36 m]





Perforating Services and Accessories


SPAN Rock* stressed-rock perforating analysis is used to specify the optimal gun system and charges to deliver the best productivity from a completion. Simple yet comprehensive modeling guides the user down a logical path for perforation design and the prediction of well productivity. Input parameters include casing, cement, and rock prop-erties; wellbore geometry (orientation and accommodating up to five concen-tric casing strings); and completion fluid characteristics. These are matched with performance and positioning data for the gun system and charge to predict perforating performance. Skin can be analyzed solely as perforation skin or as the total skin effect.

The resulting accurate prediction of downhole shaped charge penetration by SPAN Rock analysis is based on a unique model built from length measurements of thousands of shaped charge perforation tunnels in stressed rock. Whereas conventional API RP 19B performance testing shoots shaped charges into rock samples or concrete at surface conditions, the SPAN Rock

data are measured using pressure vessels to confine rock at reservoir stress conditions. Strong to weak rocks, sandstones and carbonates, high- and low-stress conditions, and different sizes and generations of shaped charges have been tested to ensure that the broadest possible range of conditions is quantified.

PowerJet Nova extradeep penetrating shaped chargesRecent stressed-rock research has acquired test data at extreme values of rock strength for the development of PowerJet Nova* extradeep pene-trating shaped charges, the deepest penetrating charge in the industry. The PowerJet Nova family of shaped

Wireline Services Catalog ■ Perforating Services and Accessories 211

SPAN Rock Stressed-Rock Perforating Analysis

and Schlumberger Premium Charges

PowerJet Nova Shaped Charge Performance Summary

Gun Size, in

Shot Density, spf, and Phasing, °

PowerJet Nova Charge

Max. Explosive Load, g

Entrance Hole, in

Stressed-Rock Penetration, in

Stressed-Rock Penetration Improvement†, %

Max. Diameter, in

Shot in Liquid

Shot in Gas

2 6, 60 2006‡ 7.3 0.23 11.5 21.1 2.29 2.31

2.5 6, 60 2506‡ 14 0.33 13.8 25.3 2.78 –

2.88 6, 60 2906‡ 16.9 0.38 15.4 26.7 3.16 3.32

3.125 6, 60 3106‡ 25.9 0.37 16.8 25.9 3.57 –

3.375 6, 60 3406‡ 19.9 0.40 17.2 19.9 3.66 3.73

4.5 12, 135/45 4512§ 20.5 0.36 8.6 26.5 4.91 ††

4.5 5, 72 4505§ 45 0.40 13.1 41.0 4.74 ††

7 12, 135/45 4505§ 45 0.41 12.7 44.7 7.28 ††

† Improvement over previous-generation equivalent deep penetrating shaped charge ‡ Penetration in Berea sandstone with 8,200-psi uniaxial compressive strength, 5,000-psi axial and radial confining pressure, and 0-psi pore pressure § Penetration in Crab Orchard sandstone with 22,094-psi uniaxial compressive strength, 5,000-psi confining pressure, and 0-psi pore pressure †† Not rated for gas



charges is exclusively designed to pen-etrate reservoir rock and is the first shaped charge in the industry that has been extensively tested in this environ-ment. API RP 19B Section 1 perfor-mance data and stressed-rock testing document the significant penetration increases delivered by PowerJet Nova shaped charges. This performance translates into up to 50% more forma-tion contact for more effective stimula-tion treatments, increased drainage contact, and greater productivity.

PowerJet Nova charges are avail-able for the PURE* clean perforations system for clean perforations as well as the current wireline and TCP gun systems, with conveyance on wireline, slickline, TCP, coiled tubing, tractor, and permanent completions.

PowerJet Omega deep penetrating perforating shaped chargePowerJet Omega* shaped charges increase penetration depth on average by 20% compared with the performance of previous-generation shaped charges. With performance verified through API RP 19B, this deeper penetration trans-lates to increased well productivity or injectivity. Because PowerJet Omega shaped charges maintain deep pen-etration at high shot density, more natural fractures can be intersected.

The PowerJet Omega shaped charge is used with the PURE clean perforations system and is available for 2- to 7-in HSD high shot density perforating gun systems.

PFrac Nova perforating charge for optimizing stimulation treatmentThe PFrac Nova* charges are the lat-est generation of PFrac* perforating charges. PFrac Nova charges are ideal for hydraulic fracturing operations in unconventional reservoirs, improving perforation tunnel geometry for the subsequent application of treatments and delivering premium penetration in tight formations. Perforation per-formance has been verified through stressed-rock test shots.

PowerFlow slug-free big hole shaped chargePowerFlow* slug-free big hole shaped charges are designed deliver the largest possible area open to flow. Perforating debris can be further limited by employing INsidr* perforating shock and debris reduction technology, which restricts the charge case from breaking when the gun is fired. This debris is too large to exit the gun body, which is highly practical for perforating operations in horizontal or highly deviated wells.

Applications■ Production or injection wells■ Damaged formations■ Formations requiring reservoir

stimulation■ Stressed rocks■ All phases: oil, water, gas


The explosives used for well perforating are designed mainly for different ranges of well temperatures. Cyclo trimethylene trinitramine (RDX) explosives are used for standard applications, whereas hexanitrostilbene (HNS) explosives may be used in environments up to 500 degF [260 degC]. The temperature rating of an explosive is also dependent on the time of exposure to that temperature. Explosives must be selected on the basis of the well temperature and the expected duration of exposure.

Perforating Services and Accessories 213

Perforating Explosives

Time, h

Temperature,degF

Temperature,degC

700

600

500

400

300

200

100

371

315

260

204

149

93

371 10 100 1,000 10,000

90 days

HMX

RDX

SX2

HNS

Contact your Schlumberger representative for high-temperature and long-duration operations falling in the shaded area. Exceeding the temperature rating leads to reduced performance followed by burning (all explosives) and possible autodetonation (RDX and HMX explosives).

Temperature Rating of Explosive SystemsHollow Carrier Systems Only


Modern perforating technology has evolved from simple holes in the cas-ing to engineered, objective-oriented services adapted to achieve sophisti-cated and versatile completion designs. Perforating is now used to optimize per-manent completions, temporary com-pletions such as DSTs, and workovers. Along with services such as hydrau-lic fracturing, sand management, extended-reach and horizontal wells, completion fluids engineering, and well testing, perforating has become indis-pensable for improving productivity.

Gun systems and charges must meet the demand for the increased hole size and penetration required to opti-mize productivity. The key to improved perforating performance is synergy between the gun and charge designs. Schlumberger provides a wide range of perforating charges, gun systems, and detonating techniques to address a comprehensive range of applications.

Gun and charge performance in the downhole environment is critical to the success of well completion. Schlumberger perforation equipment is qualified to American Petroleum Institute (API) Recommended Prac-tice (RP) 19B Section 1.

Capsule gun systemsCapsule guns are exposed gun systems, with the individual charges packed into pressure-tight capsules that are exposed to the well environment. Capsule guns are typically used in through-tubing perforation applications.

The two types of capsule gun sys-tems are expendable (the charges and mounting assembly are left as debris after firing) and retrievable (debris is left, but the mounting is recovered for use where debris is a concern). The latter design is also called semiex-pendable. Some capsule gun systems

have a selectivity option that allows shooting more than one zone per run. Deployment is on electric wireline cable, although some systems can also be run on slickline.

Enerjet expendable strip gun systemThe Enerjet* expendable strip gun sys-tem provides deep penetrating charges in either nonphased or various phasing configurations. The gun systems are available as retrievable or expendable and in sizes from 1.63 to 2.5 in [4.14 to 6.35 cm].

Pivot Gun through-tubing perforating gun systemThe high-performance Pivot Gun* wireline through-tubing gun systems are ideal for workover reperforating or shooting past deep formation damage. The running-in-hole gun diameter is only 111⁄16 in [4.29 cm], but once the gun is below the tubing, the charges are rotated outward to produce an effective gun diameter of 3.79 in [9.63 cm]. The penetration produced by the Pivot Gun system is deeper than that of other similar-sized guns.

An important Pivot Gun feature is its Safe Arming/Deployment Verifi-cation Circuit. This circuit prevents the gun from being armed and fired until the charges are fully rotated outward from the gun carrier by the deployment head and rods. Another key feature is that an unfired deployed gun can be retrieved. The charges rotate back into the carrier as the gun enters the tubing muleshoe (wireline reentry guide).


Gun Systems and Charges

Enerjet

Pivot Gun


PowerSpiral spiral-phased capsule perforating systemThe PowerSpiral* spiral-phased perforating system is a retrievable capsule perforating gun designed for through-tubing wireline operations. It is available in 111⁄16-, 21⁄8-, and 2½-in [4.29-, 5.40-, and 6.35-cm] sizes. The technological breakthrough provided by the PowerSpiral guns is a shock-absorbing material between the charges. This material attenuates shock

waves during the detonation, which reduces charge-to-charge interference and also minimizes shock waves in the wellbore. This reduction is significant because it increases the performance of shots across the wellbore. With features including multiple phasing, high shot density, and use of PowerJet* deep penetrating shaped charges, the PowerSpiral system generates perforations capable of the highest well productivity for its size.

Applications■ Through-tubing perforation■ Deep penetration■ Rigless perforation or reperforation


Capsule (Exposed) Guns Performance and Mechanical Dana SummaryGun Size, in

Exposed Gun System Shot Density, spf

Phasing, °

Charge API RP 19B Section 1 Temperature Rating for 1 h, degF

Maximum Explosive Load, g

Maximum Pressure Rating, psi

Minimum Restriction, in

Debris Fill per Charge in 41⁄2-, 5-, and 7-in Casing, in

Maximum Gun Length, ft

Penetration, in

Entrance Hole, in

Area Open to Flow, in2/ft

111⁄16-in PowerPivot* 4 180 PP, HMX 28.4 0.35 – 365 22 12,000 1.78 0.85/0.48/0.33 15

111⁄16-in Retrievable Power Enerjet

6 0 PE, HMX 21.6 0.2 – 365 8 20,000 1.78 0.13/0.08/0.06 50

111⁄16-in Biphased Retrievable Power Enerjet

6 ±45 Ph PE, HMX 14.6 0.26 – 365 8 20,000 1.78 0.16/0.10/0.07 35

111⁄16-in PowerSpiral 7.5 45 PowerSpiral EJ, HMX 19.5 0.22 – 365 8 20,000 1.78 0.15/0.09/0.07 30

21⁄8-in PowerSpiral 6 45 PowerSpiral EJ, HMX 27.2 0.32 – 365 14.5 15,000 2.25 0.18/0.14/0.07 30

21⁄8-in Triphased Expendable Big Hole

6 0, ±45 EJ BH, HMX 8.1 0.47 1.04 330 15 15,000 2.25 0.23/0.15/0.10 30

21⁄2-in PowerSpiral 5 45 PowerSpiral EJ, HMX 36.6 0.39 – 365 25.6 15,000 2.62 0.65/0.47/0.28 30Notes: Every attempt has been made to verify the accuracy of the data tabulated; contact your Schlumberger representative for further information.Other shot densities and phasings are available; Schlumberger also custom designs perforation systems to meet specific needs.Blue type identifies API 19B Registered Perforation Systems; unofficial API data is listed for the other systems.


Hollow carrier perforating gun systemsHollow carrier gun systems are engi-neered systems in which the shaped charges are housed in a pressure-tight steel tube and are not exposed to well fluids. For gun ODs of 2½ in and larger, hollow carrier guns perform better than exposed guns because they can use larger charges (deep penetrating, big hole, and good hole), optimized phas-ing, and increased shot density. Hollow carrier guns are also used when debris is unacceptable and in hostile condi-tions that preclude the use of exposed guns. These guns are typically wireline conveyed and can be fired selectively.

HSD high shot density perforating gun systemThe HSD high shot density perforating gun system features increased shot density, optimal phasing patterns, and the largest high-performance charges available for natural, stimulated, or sand control completions. Available in sizes ranging from 1.56 to 7 in [3.96 to 17.78 cm] for application in all casing sizes, HSD guns use expendable, retrievable carriers, and they run on wireline, slickline, tubing, or coiled tubing. Multiple guns can be aligned with alignment intercarriers.

The high shot densities range from 4 spf for the 1.56-in gun up to 27 spf for the 7-in guns. The helical shot pat-tern available in all gun sizes provides the smallest vertical spacing between shots and optimizes the phasing pattern for maximizing productiv-ity and retaining casing strength. Shot spacing can be varied on request.

Applications■ Deep penetrating perforations■ Big hole perforating■ Sand control■ Perforating for fracturing

Fractal multistage stimulation perforating systemThe Fractal* perforating system reen-gineers the conventional perforating gun to create a fit-for-purpose modu-lar design that significantly improves the safety, reliability, and efficiency of multistage perforating operations. The Fractal system is available in multiple gun sizes and lengths, from 1 to 5 ft [0.3 to 1.5 m] with up to 40 guns in a single descent.

Electrically prewired at the manu-facturing center, the Fractal perfo-rating system requires only minimal assembly on location. All components, including either an RF-safe or conven-tional initiation system, are supplied in plug-and-play subassemblies.

Because the disposable Fractal system incorporates pressure barriers integrated with the electrical connec-tions, it does not require redressable intergun adapters—every perforat-ing run uses new components, which reduces rig-up height while improving efficiency and reliability.

Applications■ Multistage fracture stimulation■ Coalbed methane (CBM) wells■ Limited-entry acid stimulation

Frac Gun multistage fracture stimulation perforating gun systemThe Frac Gun* perforating system is engineered for slimhole casing opera-tions in wells requiring fracture stimu-lation. The 2-in [5.08-cm] Frac Gun system also has applications in com-pletions where downhole restrictions limit gun size, including through tub-ing, dual completion, monobore, and extended reach. The 3.12-in [7.93-cm] Frac Gun system has additional appli-cations in sand control operations and CBM wells.

Fracture stimulation requires 60° (or 120°) phased guns that produce a large entrance hole size. To best execute fracture designs, the Frac Gun system can be loaded with either the big hole or deep penetrating charges used with HSD high shot density gun systems. The guns are conveyed with wireline or slickline. The gun intercarriers feature a push-in connector, allowing faster operation than comparable systems. The plug and shoot adapter of the 3.12-in Frac Gun system makes it possible to set a plug and shoot multiple guns in the same descent.

Applications■ Wells requiring fracture stimulation■ 2-in Frac Gun system: completions

with downhole restrictions■ 3.12-in Frac Gun system: sand

control operations■ 3.12-in Frac Gun system: CBM wells




High Shot Density Perforating Systems Performance and Mechanical Data SummaryGun Size, in

Shot Density, spf

Phasing, ° Charge API RP 19B Section 1 Weight of Loaded 20-ft Gun in Air (without adapters), lbm

Maximum Diameter Including Burrs, Shot in Liquid, in

Maximum Diameter Including Burrs, Shot in Gas, in

Penetration, in

Entrance Hole, in


Deep Penetration Shaped Charges

1.56-in HSD 6 60 PowerJet 1606, HMX 11.3 0.17 3.5 76 1.72 1.752-in HSD 6 60 PowerJet Omega 2006, HMX 21.8 0.22 7.3 123 2.29 2.312-in HSD 6 60 PowerJet 2006, HNS 15.3 0.22 8 123 2.16 2.212-in HSD 6 60 PowerJet 2006, HMX 18.7 0.23 6.5 123 2.16 2.2121⁄4-in HSD 6 60 PowerJet 2306, HMX 17.7 0.3 8.7 155 2.46 2.4821⁄4-in HSD 6 60 PowerJet 2306, HNS 15.7 0.27 9.5 155 2.46 2.4821⁄2-in HSD 6 60 PowerJet Omega 2506, HMX 30.6 0.32 12 171 2.78 – 21⁄2-in HSD 6 60 PowerJet 2506, HNS 16.7 0.3 13.5 174 2.66 2.7521⁄2-in HSD 6 60 PowerJet 2506, HMX 24.4 0.31 10.5 176 2.66 2.7527⁄8-in HSD 6 60 PowerJet Omega 2906, HMX 36.0 0.34 16 246 3.16 3.3227⁄8-in HSD 6 60 PowerJet Omega 2906, HNS 24.3 0.31 17.6 249 3.16 3.3227⁄8-in HSD 6 60 PowerJet 2906, HMX 25.3 0.38 15 245 2.98 3.0827⁄8-in HSD 6 60 PowerJet 2906, HNS 21.0 0.31 19.5 239 2.96 3.0831⁄8-in HSD 6 60 PowerJet Omega 3106, HMX 36.9 0.34 20 301 3.57 – 31⁄8-in Frac Gun 6 60 PowerJet Omega 3104, HMX 37.5 0.38 17.9 280 3.50 – 33⁄8-in HSD† 6 60 PowerJet 3406, HMX 36.5 0.37 22.7 334 3.66 – 33⁄8-in HSD† 6 60 PowerJet 3406, HNS 28.8 0.31 25 335 3.66 – 33⁄8-in OrientXact* ‡ 5 ±10 PowerJet OX 3505, HMX 37.7 0.34 22.5 564 na 3.7831⁄2-in HSD 6 72 PowerJet Omega 3506, HMX 44.2 0.44 27 370 3.72 – 31⁄2-in HSD 6 72 PowerJet Omega 3506, HNS 33.7 0.32 28 374 3.72 – 4-in HSD 5 72 PowerJet Omega 4005, HMX 51.7 0.48 38.8 496 4.44 –4-in HSD 5 0/180 PowerJet 4006, HMX 36.5 0.46 26.0 425 na 4.3741⁄2-in HSD§ 5 72 PowerJet Omega 4505, HMX 59.2 0.43 38.8 504 4.74 – 41⁄2-in HSD§ 5 72 PowerJet 4505, HMX 46.4 0.47 38.6 504 4.74 – 41⁄2-in HSD§ 12 135/45 PowerJet Omega 4512, HMX 34.0 0.35 22 495 4.91 – 41⁄2-in HSD§ 12 135/45 PowerJet 4512, HMX 30.2 0.34 22 495 4.91 – 41⁄2-in OrientXact†† 4 ±10 PowerJet OX 4504, HMX 43.8 0.29 38.8 568 4.74 4.774.72-in HSD 5 72 PowerJet Omega 4705, HNS 44.4 0.36 38.8 606 4.95 5.164.72-in HSD 5 72 PowerJet 4505, HMX 48.3 0.51 38.6 606 4.95 5.164.72-in HSD 5 72 PowerJet 4505, HNS 34.4 0.4 38 623 4.95 5.164.72-in HSD 12 135/45 PowerJet 4512, HNS 22.8 0.31 22.5 610 4.99 5.164.72-in HSD 21 120/60 PowerJet 4521, HMX 21.0 0.32 15 665 4.93 – 7-in HSD 12 135/45 PowerJet Omega 4505, HMX 62.0 0.46 38.8 1,168 7.28 –7-in HSD 12 135/45 PowerJet 4505, HMX 43.6 0.44 38.6 1,169 7.05 –7-in HSD 27 120/60 PowerJet Omega 7027, HMX 35.5 0.29 20 1,110 7.05 –

Notes: Every attempt has been made to verify the accuracy of the data tabulated; contact your Schlumberger representative for further information. Other shot densities and phasings are available; Schlumberger also custom designs perforation systems to meet specific needs.

na = not availableBlue type identifies API 19B Registered Perforation Systems; unofficial API data is listed for the other systems.

† Available in 33⁄8-, 31⁄2-, and 3.67-in perforating systems ‡ Available in 31⁄2-in perforating systems § Available in 41⁄2-, 45⁄8-, 4.72-, and 5-in perforating systems †† Available in 4.72-in perforating systems rated for high pressure



Performance and Mechanical Data SummaryGun Size, in

Shot Density, spf

Phasing, °

Charge API RP 19B Section 1 Maximum Explosive Load, g

Weight of Loaded 20-ft Gun in Air (without adapters), lbm



Penetration, in

Entrance Hole, in

Area Open to Flow, in2/ft

Big Entrance Hole Shaped Charges

2-in HSD 6 60 PowerFlow 2006, HMX 4.5 0.45 0.95 6.4 119 2.16 2.2121⁄4-in HSD 6 60 PowerFlow 2306, HMX 4.8 0.52 1.27 – 149 2.46 2.48

21⁄2-in HSD 6 60 PowerFlow 2506, HMX 5.2 0.64 1.93 11.2 151 2.66 2.75 27⁄8-in HSD 6 60 38C CleanPACK*, HMX 6.6 0.7 2.31 15 231 3.09 3.227⁄8-in HSD 6 60 38C CleanPACK, RDX 8.4 0.62 1.18 15 231 3.09 3.231⁄8-in HSD 10 135/45 PowerFlow 3412, HMX 4.7 0.67 3.53 14.2 259 3.34 – 33⁄8-in HSD† 12 135/45 PowerFlow 3412, HMX 4.5 0.64 3.86 14.2 339 3.52 3.584-in HSD 5 120 PowerFlow 5008, RDX 6.3 0.95 3.55 30 414 4.19 – 41⁄2-in HSD 6 120 PowerFlow 5008, RDX 6 0.93 4.08 30 437 4.74 – 45⁄8-in HSD Bigshot 21* ‡ 21 120/60 PowerFlow 4621, RDX 5.9 0.83 11.3 19 555 4.82 – 45⁄8-in HSD Bigshot 21‡ 21 120/60 PowerFlow 4621, HMX 6.1 0.83 11.3 19.4 555 4.82 – 4.72-in HSD Bigshot 21‡ 21 120/60 PowerFlow 4621, RDX 5.4 0.73 8.8 19 596 na – 4.72-in HSD Bigshot 21 21 120/60 PowerFlow 4721 Zinc, RDX 5.4 0.73 8.79 19 596 4.82 – 4.72-in HP HSD§ 20 120/60 PowerFlow 4621 Extreme, HMX 5.38 0.60 5.65 18 778 4.90 –65⁄8-in HP HSD†† 18 120/60 PowerFlow Max* 6618, HMX 7 0.94 12.5 38.8 1,606 6.94 – 65⁄8-in HP HSD††,‡‡ 18 120/60 PowerFlow Max 6618, HMX 6.2 0.86 10.5 38.8 1,606 6.94 –65⁄8-in HP HSD 18 120/60 PowerFlow Max 6618, HMX 7.8 0.96 13 38.8 1,352 6.89 –65⁄8-in HP HSD‡‡ 18 120/60 PowerFlow Max 6618, HMX 7.3 0.9 11.5 38.8 1,352 6.89 –65⁄8-in HP HSD‡ 18 120/60 CleanPack Max* 6618, HMX 7.4 0.87 10.7 37.8 1,290 6.87 –65⁄8-in HP HSD‡‡ 18 120/60 CleanPack Max 6618, HMX 6.5 0.73 7.5 37.8 1,290 6.87 –65⁄8-in HP HSD 18 120/60 PowerFlow 6618, HMX 6.8 0.91 11.7 34 1,426 6.73 –7-in HSD 18 120/60 PowerFlow 7018, RDX 7.4 1.15 18.7 45 1,236 7.13 –7-in HSD 18 120/60 PowerFlow 7018, HMX 7.1 1.14 18.53 49.5 1,236 7.13 –7-in HSD 14 140/20 58C UltraPack, RDX 12.2 0.95 9.92 61 1,234 7.27 –7-in HSD 12 135/45 64C CleanPACK, RDX 10.1 1.13 11.41 59 1,184 7.75 –7-in HP HSD§§ 18 120/60 PowerFlow 6618, HMX 6.0 0.66 6.16 34 1,441 7.10 –7-in HP HSD†† 18 120/60 PowerFlow Max 6618, HMX 7.8 0.93 12.22 38.8 1,735 7.20 –

Notes: Every attempt has been made to verify the accuracy of the data tabulated; contact your Schlumberger representative for further information. Other shot densities and phasings are available; Schlumberger also custom designs perforation systems to meet specific needs.

na = not available HP = high pressure Blue type identifies API 19B Registered Perforation Systems; unofficial API data is listed for the other systems. † Available in 33⁄8-, 31⁄2-, and 3.67-in perforating systems‡ Available in 45⁄8- and 4.72-in perforating systems

§ 7.0-in 38-lbm/ft Q125 heavy-wall casing †† INsidr technology for gun shock control and low-debris applications ‡‡ 97⁄8-in 62.8-lbm/ft Q125 heavy-wall casing

§§ 101⁄8-in 79.22-lbm/ft Q125 heavy-wall casing

Performance and Mechanical Data Summary

Gun Size, in

Shot Density, spf

Phasing, ° Charge API RP 19B Section 1 Weight of Loaded 20-ft Gun in Air (without adapters), lbm



Penetration, in

Entrance Hole, in


Good Hole Shaped Charges

2-in HSD 6 60 UltraJet* 2006, RDX 14.7 0.28 6.5 123 2.17 2.23

2-in HSD 6 60 HyperJet* 2006, RDX 9.6 0.33 6.5 122 2.16 2.21

21⁄2-in HSD 6 60 HyperJet 2506, RDX 13.1 0.43 10.5 176 2.66 2.75

27⁄8-in HSD 6 60 UltraJet 2906, HMX 22.1 0.36 15 245 2.98 3.08

27⁄8-in HSD 6 60 HyperJet 2906, RDX 15.0 0.39 15 245 2.98 3.08

31⁄8-in Frac Gun 6 60 PFrac Omega* 3106, RDX 32.7 0.40 22.5 280 3.50 –

31⁄8-in Frac Gun 6 60 PFrac 3106, RDX 24.9 0.44 22.5 280 3.50 –

31⁄8-in HSD 6 60 34JL UltraJet, HMX 24.0 0.41 22.7 286 3.57 –

31⁄8-in HSD 4 90 UltraPack* 3106, RDX 16.2 0.4 9.2 185 3.14 3.22

33⁄8-in HSD† 6 60 UltraJet 3406, HMX 31.4 0.44 22.7 335 3.66 3.7

33⁄8-in HSD† 6 60 HyperJet 3406, RDX 22.5 0.49 22.7 335 3.66 3.7

4-in HSD 4 90 UltraPack 4004, RDX 18.7 0.43 12.4 265 4.09 4.37

41⁄2-in HSD‡ 5 72 UltraJet 4505, HMX 42.6 0.46 38.3 485 4.74 –

41⁄2-in HSD‡ 5 72 HyperJet 4505, RDX 37.0 0.57 38.8 487 4.74 –

5-in HSD 8 135/45 UltraJet 5008, RDX 20.2 0.54 24 620 5.19 5.22

7-in HSD 12 135/45 UltraJet 4505, HMX 39.9 0.45 38.3 1,123 7.05 –

7-in HSD 12 135/45 HyperJet 4505, RDX 37.0 0.57 37 1,128 7.05 – Notes: Every attempt has been made to verify the accuracy of the data tabulated; contact your Schlumberger representative for further information. Other shot densities and phasings are available; Schlumberger also custom designs perforation systems to meet specific needs.

Blue type identifies API 19B Registered Perforation Systems; unofficial API data is listed for the other systems. † Available in 33⁄8-, 31⁄2-, and 3.67-in perforating systems ‡ Available in 41⁄2-, 45⁄8-, and 4.72-in systems


The job design basis of the PURE clean perforations system for clean perforations minimizes or eliminates perforation damage by optimizing the well’s dynamic underbalance, which is the transient underbalance that occurs immediately after creation of the perforation cavity. Whereas conventional perforating design fails to account for the dynamic period immediately following detonation, the PURE system incorporates consideration of the gun design and completion characteristics unique to the job to achieve and control the desired condition of dynamic underbalance at the time the guns fire. Dynamic underbalance cleans perf o rations much more effectively than conventional underbalanced or overbalanced perforating methods. The PURE system also accounts for impacts on perforation tunnel permeability from the time of perforating until either injection or production begins. The resulting clean, permeable perforations enable better injectivity or productivity than in wells completed with traditional techniques.

The PURE clean perforations sys-tem uses the Schlumberger premier family of PowerJet deep penetrating shaped charge technology, including the newest PowerJet Nova extradeep penetrating shaped charge, which is

the deepest penetrating charge in the industry. Exclusively designed to penetrate reservoir rock, PowerJet Nova charges deliver significant pen-etration increases that translate into up to 50% more formation contact than the performance of previous-generation deep penetrating shaped charges. The result is superior pen-etration performance and minimized charge debris exiting the gun.

Additional PURE system features are independent placement of the charge, flexible loading options, and size range from 2 to 7 in [5.08 to 17.78 cm].

Applications■ Perforated completions in consoli-

dated reservoirs with permeability greater than 0.5 mD or reservoir pressure greater than 1,200 psi [8,270 kPa].

■ Operational efficiency through less underbalance required and reduced wellbore shock

■ Potential elimination of the need for secondary perforation cleanup operations


PURE Clean Perforations System



PURE Clean Perforations System Mechanical Data Summary

Outside Diameter 2 in [5.08 cm] 2½ in [6.35 cm] 2⅞ in [7.30 cm] 3⅜ in [8.57 cm] 3½ in [8.89 cm] 4½ in [11.43 cm] 4½ in [11.43 cm] 7 in [17.78 cm]

Shot density 5.5 spf, 60º 5.5 spf, 60º 5.5 spf, 60º 5.5 spf, 60º 5.5 spf, 72º 11.5 spf, 135º/45º 4.5 spf, 72º 11.5 spf, 135/45º

Shot spacing 2 in 2 in 2 in 2 in 2 in 1 in 2 in 1 in

Temperature rating 400 degF [204 degC] 400 degF [204 degC] 400 degF [204 degC] 400 degF [204 degC] 400 degF [204 degC] 400 degF [204 degC] 400 degF [204 degC] 400 degF [204 degC]

Pressure rating 20,000 psi 25,000 psi 25,000 psi 20,000 psi 25,000 psi 12,000 psi 12,000 psi 10,000 psi

Min. casing size 2⅞ in 3½ 4½ in 4½ in 5 in 6⅝ in 6⅝ in 9⅝ in

Max. diameter including burrs† 2.26 in 2.59–2.78 in 3.07 in 3.75 in 3.72 in 4.87 in 4.83 in 7.28 in

Interval missed between guns 13 in 12.5 in 12 in 12 in 12 in 12 in 12 in 12 in

Weight of loaded 20-ft gun in air 119 lbm 179 lbm 237 lbm 332 lbm 292 lbm 501 lbm 446 lbm 1,245 lbm

Max. tensile load 63,000 lbf 81,000 lbf 105,000 lbf 150,000 lbf 200,000 lbf 150,000 lbf 150,000 lbf 500,000 lbf † Shot in liquid

PURE Clean Perforations System Performance Summary†

Gun Shot Density, spf Phasing, °

Charge Penetration, in Entrance Hole, in

2-in PURE 5.5, 60 PowerJet 18.6 0.20

2-in PURE 5.5, 60 PowerJet Omega 21.8 0.22

2½-in PURE 5.5. 60 PowerJet 18.7 0.34

2½-in PURE 5.5, 60 PowerJet Omega 30.6 0.32

2⅞-in PURE 5.5, 60 PowerJet 25.3 0.38

2⅞-in PURE 5.5, 60 PowerJet Omega 36.0 0.34

3⅜-in PURE 5.5, 60 PowerJet 36.5 0.37


4½-in PURE 11.5, 135/45 PowerJet 30.2 0.34

4½-in PURE 11.5, 135/45 PowerJet Omega 34.0 0.35

4½-in PURE 4.5, 72 PowerJet 46.4 0.47


7-in PURE 11.5, 135/45 PowerJet 43.6 0.44

7-in PURE 11.5, 135/45 PowerJet Omega 53.2 0.43 † Unofficial API RP 43 5th edition or API 19B Section 1; area open to flow available on request, specific per job design


The majority of wireline-conveyed perforating operations are performed using standard detonators that employ primary high explosives. This situation necessitates following rigorous safety policies and procedures to ensure that stray electrical effects caused by radio signals, electric arc welding operations, or cathodic protection systems do not accidentally set off the detonator. In environments where it is not feasible to eliminate all sources of interference, detonation systems that incorporate additional safety features are required.

Secure2 RF-safe electronic detonatorThe Secure2* RF-safe electronic deto-nator uses exploding foil initiator (EFI) technology to provide industry-leading safety and reliability during perforat-ing operations.

As the fourth generation of S.A.F.E.* slapper-actuated firing equipment ini-tiators, which have been in use world-

wide since 1988, this latest iteration provides a step change in performance reliability. The reliability of the Secure2 detonator is comparable with that of a traditional resistor-based detona-tor, with an efficiency of 99.82%, while maintaining the safety benefits of a high-power initiator. The Secure2 deto-nator is radio frequency (RF) safe, with certification by an independent third-party assessor, which improves over-all operational efficiency by allowing radio transmitters to stay on and critical wellsite operations, such as helicopters, boats, cathodic protection, and welding in appropriate locations, to continue during the perforating operation.

No primary explosives are used within the Secure2 detonator, which reduces sensitivity to shock and burn detonation.

Secure2 detonators are available for hollow carrier and exposed gun sys-tems, plug setting, and pipe recovery applications.

S.A.F.E. slapper-actuated firing equipmentS.A.F.E. equipment’s detonating sys-tem is RF safe for electric potential differences created by RF radiation, impressed current for cathodic protec-tion, and welding in appropriate loca-tions. The technology eliminates the need to shut down radio communica-tion and other vital rig equipment dur-ing perforating jobs.

The EFI detonating mechanism used in S.A.F.E. equipment has proved resistant to stray voltages because it requires a high current for detonation. The S.A.F.E. equipment contains no primary high explosives.

When shooting power is applied, a section of metal foil is instantly vaporized, which causes a neighboring (secondary) high-explosives pellet to detonate and shear a small aluminum flyer. The flyer travels across a fluid desensitization gap in the EFI housing and strikes a booster that initiates the detonation of the gun.

Applications■ Hollow carrier and exposed

perforating gun systems■ Punchers■ Plug setting■ Pipe recovery


Detonation Systems

Wireline input

Detonating cord

EFI Electronics

Secondary explosive pellet

Aluminum flyerBooster


Secure2 Detonator

High-Temperature Secure2 Detonator

Exposed Secure2 Detonator

Secure2 Detonator Igniter

Temperature rating† 340 degF [171 degC] 400 degF [204 degC] 340 degF [171 degC] 340 degF [171 degC]

Pressure rating na na 15,000 psi [103 MPa] na

Fluid desensitization Yes Yes No na

Combinability Hollow carrier guns, puncher, cutter, severing tools

Hollow carrier guns, puncher, cutter, colliding tools

Exposed guns, backoff, string shot

Plug setting

Special applications UN classification code: 1.4S UN classification code: 1.4S UN classification code: 1.4B UN classification code: 1.4S na = not applicable † For 1 h



ASFS Addressable-Switch Firing System

The ASFS* addressable-switch firing system is run within explosive devices. The system is a series of microproces-sors attached to the initiators. Digital communication is used to operation-ally check and arm the switches. Each microprocessor has a unique address to individually identify the associated explosive device.

All circuits, gun wiring, and connections can be checked at surface with the Integrated Perforating Device Tester (IPDT); while running in hole, checking is done with the perforation acquisition system. Positive shot indication is achieved through the switch requerying feature. In the case of a misfire or failed pressure switch, that explosive device can be skipped over. For critical operations, backup devices can be run as a contingency.

Available for all hollow carrier per-forating gun systems and explosive plug-setting systems, the ASFS system is compatible with conventional and Secure2 detonators. Up to 40 guns per descent can be run to efficiently perforate long intervals or multiple stages in one trip.

Applications■ Selective perforating■ Multistage perforating■ Tractor-conveyed perforating■ Pumpdown perforating■ Combined plug setting

and perforating

Addressable arming protection switch

Addressable switch

Addressable switch

Plug-and-shoot addressable switch


ASFS System



Casing collar locatorThe casing collar locator (CCL) is the universal positioning device used to correlate between cased hole services (e.g., gamma ray–CCL to perforating–CCL or other cased hole ser vices that do not necessarily require a gamma ray for correlation). The CCL run in com-bination with a cased hole gamma ray establishes the link between the open-hole gamma ray measurement and the cased hole CCL.

The magnetic field of the perma-nent magnets in the CCL tool becomes distorted as the device passes a cas-ing collar. The distortion is amplified within the tool and sent up hole as a

pulse that is recorded in conjunction with the gamma ray. The dual record-ing establishes the position of the cas-ing collar with reference to the casing gamma ray log to the SP or gamma ray of an openhole log.

CCL tools are available in a wide range of sizes and specifications to address different casing and tubing sizes, well pressure and temperature conditions, and logging cables as well as combinability with other services.

Application■ Correlation of cased hole logs

to perforating or other cased hole services


Perforating Accessories

CCL-AG


CCL

Output Casing and tubing collar location


Combinability Requires monocable, coaxial cable, or hepta-cable Combinable with perforating guns of different sizes, plug and packer setting tools, cutters, punchers, cased hole logging tools



CCL



Borehole size—min. 1½ in [3.81 cm]


Outside diameter 1.375 to 3.375 in [3.49 to 8.57 cm]

Length 1.48 to 3.5 ft [0.45 to 1.07 m]

Weight 6 to 81.5 lbm [2.7 kg to 37 kg]



UPCT

CCL

Gammaray detector

UPCT universal perforating and correlation toolThe UPCT* universal perforating and correlation tool is a gamma ray–CCL depth correlation tool for perforating operations shooting any type of detonator, including radio frequency– (RF-) safe detonator systems on both polarities (addressable switch). The depth correlation provided by the 1.6875-in [4.29-cm] UPCT tool enables precise positioning of perforating guns and other through-tubing explosive devices. The rugged design and robust electronics of the UPCT tool enable running it on the same string as the perforating guns without requiring a shock absorber sub.

Applications■ Gamma ray–CCL correlation

– During perforating runs for single-trip efficiency

– Through tubing– In tubing and casing– At extreme depth and

temperature conditions


UPCT Tool

Output Formation gamma ray, casing and tubing collar location


Combinability Combinable with all detonator types and perforating guns without requiring a shock absorber sub

Special applications H₂S service Shock qualified to 5,000-g pyro


UPCT Tool

Temperature rating 350 degF [177 degC] 1-h excursion: 374 degF [190 degC] With flask: 500 degF [260 degC]


Borehole size—min. 1.6875-in tool: 1.82 in [4.62 cm] Flasked 2.125-in tool: 2.25 in [5.72 cm]


Outside diameter 1.6875 in [4.29 cm] With flask: 2.125 in [5.40 cm]

Length Without gun: 4.5 ft [1.37 m] With flask: 5.94 ft [1.81 m]

Weight 46 lbm [20.9 kg]


PGGT powered gun gamma toolThe PGGT powered gun gamma tool records naturally occurring gamma rays in the formations near the wellbore. This nuclear measurement indicates the radioactive content of the formations. Effective in any environment, the PGGT tool is the standard device for the correlation of cased hole logs with openhole logs. Perforating guns, tubing punchers, plugs and packers, and core guns can be correlated by using gamma ray, CCL, or both techniques simultaneously.

Applications■ Accurate positioning of tubing-

conveyed perforating (TCP) guns■ Correlation of perforating guns,

plugs, and packers in wells without previously recorded cased hole logs

■ Correlation of perforating guns, plugs, and packers in wells with uniform casing joints

■ Correlation of plugs and packers in large casing sizes, which may cause the CCL to be centralized and ineffective

■ Added assurance for correlating critical perforating or plug and packer jobs

■ Reliable openhole gamma ray correlation for core guns

■ Correlation services in casing where CCL signals cannot be detected


Measurement SpecificationsPGGT Tool

Output Naturally occurring gamma ray, casing collar locator


Range of measurement 0 to 400 gAPI


Accuracy ±5%



Combinability CST chronological sample taker, casing guns, plugs, packers


Mechanical SpecificationsPGGT-DA PGGT-DC



Borehole size—min. 4⅜ in [11.11 cm] 4⅛ in [10.47 cm]

Borehole size—max. No limit No limit


Length 5.83 ft [1.78 m] 5.83 ft [1.78 m]



WPP wireline perforating platformThe WPP* wireline perforating platform integrates a rugged arsenal of sensors and actuators for optimizing well productivity while perforating. Use of the WPP platform maximizes flexibility in positioning perforating guns and enables real-time monitoring of results. Safer, more reliable perforating results from intelligent control of the downhole power supply.

Oriented perforating using the WPP platform provides single-trip convey-ance and orientation of perforating guns on wireline, coiled tubing, or a tractor system through tubing into vertical or deviated wells. The motor system of the WPP platform rotates the guns into firing position relative to the preferred fracture plane to optimize hydraulic fracturing operations.

The completion imaging configura-tion of the WPP platform is used to shoot through a tubing string in a multiple completion without hitting parallel strings. This “mapper” con-figuration of the WPP platform detects multiple completion strings to gen-erate a metal-proximity profile that guides selective shooting of multiple guns, which provides perforation and production access to reservoirs that would otherwise require a costly and time-consuming workover.

Borehole temperature and pressure data can be acquired by the WPP plat-form before, during, and after perforat-ing. Interpretation of these real-time data can provide a good indication of the formation pressure and res-ervoir parameters (permeability and skin effect) to guide operations. Data acquisition is not interrupted by deto-nator initiation. Up to 20 guns can be connected to the bottom of the tool for selective firing through the use of addressable-switch technology.

Applications■ Hydraulic fracturing■ Sand prevention■ Multiple completion string

detection■ Establishment of over- or under-

balance before perforating■ Temperature survey■ Measurement of formation pressure

buildup or drawdown





WPP Platform

Output Casing and tubing collar location, inclination or relative bearing, orientation of perforating guns, downhole shot indication Optional: gamma ray, borehole temperature, borehole pressure, completion imaging

Logging speed Stationary measurement


Combinability Combinable with telemetry system of the PS Platform production services platform


WPP Platform





Outside diameter 1.6875 in [4.29 cm] With gyroscope carrier: 1.75 in [4.44 cm]

Length Oriented perforating: 24.0 ft [7.31 m] (not including gun and gamma ray tool) Completion mapper: 22.0 ft [6.70 m] (not including gamma ray tool) Pressure and temperature measurement: 15.0 ft [4.57 m] (not including gun and gamma ray tool)

Weight WPP platform: 166.3 lbm [75.4 kg] Oriented perforating: 159.3 lbm [72.2 kg] Completion mapper: 140.3 lbm [63.6 kg] Pressure and temperature measurement: 85 lbm [38 kg]

Tension Perforating and imaging: 14,200 lbf [63,160 N] Measurement: 39,000 lbf [173,480 N]


Wireline Oriented Perforating ToolThe gyroscope-oriented Wireline Oriented Perforating Tool (WOPT) is used for wireline-conveyed, azimuth-oriented perforating in near-vertical wells. The WOPT enables perforating the preferred facture plane (PFP), which improves hydraulic fracture treatments as well as assists sanding prevention in weak but con solidated formations. From the perspective of rock mechanics, a fracture propagates in the direction of the maximum hori-zontal stress regardless of perforation orientation, which causes the fracture fluid to travel around the casing before it flows into the direction of propaga-tion. Perforating in the direction of the maximum shear stress plane (i.e., the PFP) allows the fracture fluid to flow directly into the fracture propagation.

By orienting the perforations toward the PFP, the fracturing job needs less breakout pressure. This results in lower surface pressures and the pumping fluid can be more viscous. It also helps prevent sand production by creating less turbulent flow along the perforation tunnels.

Applications■ Fracture plane perforating■ Minimized fracture pressure■ Minimized sand production■ Directional cement squeeze■ Setting whipstocks■ Perforating adjacent well (from

relief well) for well control■ Oriented core sampling with the

CST chronological sample taker■ Relief well perforating



WOPT

Output Azimuthal perforating direction


Range of measurement Indexing at 5° increments

Accuracy ±3°

Depth of investigation Borehole positioning device


Combinability 3⅛-, 3⅜-, 3½-, 3.67-, 4-, 4½-, 4.72-, and 5-in [7.93-, 8.57-, 8.89-, 9.32-, 10.16-, 11.43-, 11.99-, and 12.70-cm] HSD high shot density perforating gun systems


WOPT






Length Variable based on configuration

Weight Variable based on configuration


Through-tubing perforating positioning devices are used to position through-tubing perforating guns below the end of the tubing in the casing across a zone of interest.

Magnetic Positioning DeviceThe Magnetic Positioning Device (MPD) has a strong permanent mag-net oriented in the same plane as the zero-phased tubing gun. In a verti-cal wellbore, the magnet positions the gun charges to the face of the casing wall. This position produces maximum hole size and formation penetration. In deviated wells the magnet posi-tions the charges to the low side of the wellbore to prevent orientation of the gun to the high side of the casing. High-side (across-casing) perforating severely restricts the hole size in the casing and formation penetration.

Applications■ Increased well productivity■ Maximum casing hole size■ Maximum formation penetration

Spring Positioning DeviceThe Spring Positioning Device (SPD) forces the through-tubing gun to the casing wall in vertical wells. The loca-tion of the spring on the opposite side of the gun charges (zero phasing) maximizes the casing hole size and formation penetration.

Applications■ Increased well productivity■ Maximum casing hole size■ Maximum formation penetration


Through-Tubing Perforating Positioning Devices

SPD-A

MPD


MPD SPD



Borehole size—min. 113⁄16 in [4.60 cm] 113⁄16 in [4.60 cm]

Borehole size—max. No limit 7 in [17.78 cm]

Outside diameter 1.375 to 2 in [3.49 to 5.08 cm] 1.6875 to 2.875 in [4.29 to 7.30 cm]

Length 1.46 to 1.77 ft [0.44 to 0.54 m] 2.36 to 3.3 ft [0.72 to 1.00 m]

Weight 7 to 22 lbm [3 to 10 kg] 10 to 32 lbm [4.5 to 14 kg]


The Wireline Perforating Anchor Tool (WPAT) is used for perforating monobore wells under very high under-balance pressure. This method of anchoring wireline-conveyed guns is a practical, reliable, and economical technique for completing monobore wells. The WPAT makes perforating with very high underbalance possible by eliminating gun movement during perforating. Higher underbalance improves perforation cleanup, resulting in greater well productivity.

The WPAT positively anchors guns from below by using three circumferentially distributed slips. With an electrical command from the surface, the slips are anchored in the casing before the gun is fired. The profile of the slips is carefully crafted to prevent both movement when set and damage to the tubing. After a preprogrammed time interval, which can be from 5 min to 1 h, the slips are automatically released and retracted.

The tool is designed to work in 27⁄8- and 3½-in casing. The anchor-ing mechanism withstands force to 17,000 lbf [75,620 N] in an upward or downward direction. The high rate of flow during perforation cleanup causes the holding capacity to increase as the amount of force acting on the gun string increases. The WPAT prevents the guns from jumping, which in turn helps to prevent inadvertent breaking of the wireline cable head weakpoint.

Applications■ Underbalanced perforation

in small casing sizes■ Memory gauges run below perfor-

ating guns for the determination of crossflow or depletion

■ Enhanced cleanup because the well can be flowed immediately after perforating underbalanced


Wireline Perforating Anchor Tool


WPAT-A WPAT-B



Casing size—max. ID 2.58 in [6.55 cm] 3.04 in [7.72 cm]

Casing size—OD 2⅞ in [7.30 cm] 3.5 in [8.89 cm]


Length 9.2 ft [2.80 m] 9.3 ft [2.83 m]



Cutters and colliding tools are designed to sever downhole tubulars and completion components in a variety of environments.

The two types of cutting technolo-gies are as follows:■ Explosive jet cutters make precise

cuts with minimal swelling by using a radial shaped charge that creates a 360° high-pressure jet.

■ Chemical cutters use heat and abra-sion generated by a chemical reac-tion to cleanly cut tubulars.

Both technologies cleanly and efficiently cut coiled tubing, tubing, casing, drillpipe, and completion components, which enables conducting single-trip dressing and fishing operations.

Colliding tools use a high explosive load to create a radial jet by colliding two opposing ballistic shock waves. They are specifically designed for severing heavyweight drill pipe and drill collars.

Cutters and colliding tools are avail-able for the entire range of downhole tubulars. For more information, con-tact your Schlumberger representative.

Applications■ Coiled tubing, tubing, casing, drill-

pipe, and completion components

■ Burr- and flare-free cutting with chemical cutters

■ Colliding tool for heavy drillpipe or drilling collars

PowerCutter precision tubular cutterThe PowerCutter* precision tubular cutter employs a unique liner material and design to deliver industry-leading cut quality, comparable to that of a chemical cutter but without the need for hazardous chemicals. Operation is simple, reliable, and efficient with no anchoring required. No anchoring reduces the likelihood of the tool becoming stuck after the cutting operation is performed.

The PowerCutter precision tubular cutter is combinable with the RF-safe Secure2 electronic detonator for additional operational safety and efficiency.

Applications■ Coiled tubing, tubing, casing, drill-

pipe, and completion components■ Completions under compression

or tension■ High-pressure, high-temperature

wells


Cutters and Colliding Tools

PowerCutter


PowerCutter Precision Tubular Cutter†

Outside diameter 1.68 in [4.29 cm] 2.125 in [5.40 cm] 2.5 in [6.35 cm] 2.75 in [6.99 cm] 3.65 in [9.27 cm] 4.15 in [10.54 cm]


Pressure rating 18,000 psi [124 MPa] 18,000 psi [124 MPa] 18,000 psi [124 MPa] 18,000 psi [124 MPa] 18,000 psi [124 MPa] 18,000 psi [124 MPa]

Tubing size 2⅜ in 2⅞ in 3½ in 3½ in 4½ in 5½ in

Tubing weight with couplings‡ 4.0 to 4.7 lbm/ft 6.4 to 7.90 lbm/ft 9.2 to 10.3 lbm/ft 9.2 to 10.3 lbm/ft 11.6 to 12.6 lbm/ft 17.0 to 26.0 lbm/ft

Tubing swell with burr 2.82 in [7.16 cm] 3.41 in [8.66 cm] 3.90 in [9.91 cm] 3.99 in [10.13 cm] 4.94 in [12.55 cm] 5.87 in [14.91 cm]

Outside diameter before cutting 1.724 in [4.380 cm] 2.139 in [5.433 cm] 2.505 in [6.363 cm] 2.753 in [6.993 cm] 3.655 in [9.284 cm] 4.155 in [10.554 cm]

Outside diameter after cutting 1.693 in [4.300 cm] 2.068 in [5.253 cm] 2.405 in [6.109 cm] 2.657 in [6.749 cm] 3.605 in [9.157 cm] 3.810 in [9.677 cm]

Explosive type, max. weight HMX, 11.2 g HMX, 17.0 g HMX, 28.33 g HMX, 38.0 g HMX, 38.0 g HMX, 109.3 and 76 g † Numerous other sizes are available on request

‡ Grade L80


Punchers are used to make holes in downhole tubulars to establish pressure equalization or circulation between the primary bore and the annulus, without damaging the outer string.

Punchers are selected based on the thickness of the target tubular and the clearance to the outer string.

Special-application punchers, such as chemical punchers, are also available.

Applications■ Pressure equalization between

tubing and annulus■ Establish circulation during

stuck-pipe operations


Punchers


1.56-in HSD High Shot Density Perforating Gun System Puncher

Puncher Charge 1606S Puncher 1606M Puncher 1606L Puncher 1606XL Puncher 1606XXL Puncher

Temperature rating for 1 h 500 degF [260 degC] 500 degF [260 degC] 500 degF [260 degC] 400 degF [204 degC] 400 degF [204 degC]


Tubing size—min. 21⁄16 in 21⁄16 in 21⁄16 in 21⁄16 in 21⁄16 in

Tubing size—max. No limit No limit No limit No limit No limit

Outside diameter 1.56 in [3.96 cm] 1.56 in [3.96 cm] 1.56 in [3.96 cm] 1.56 in [3.96 cm] 1.56 in [3.96 cm]

Explosive type HNS HNS HNS HMX HMX

Wall thickness 0.19–0.375 in [4.83–9.53 mm]

0.375–0.50 in [9.53–12.7 mm]

0.500–0.58 in [12.70–14.73 mm]

0.75 in [19.50 mm]

1.0 in [25.4 mm]

Avg. hole size 0.30–0.21 in [7.62–5.33 mm]

0.25–0.21 in [6.35–5.33 mm]

0.17–0.13 in [4.32–3.30 mm]

0.19 in [4.83 mm]

0.18 in [4.57 mm]

Penetration depth In the outer pipe for all configurations: <0.10 in [<2.54 mm]


Well Intervention Services


ReSOLVE instrumented wireline inter-vention service consists of a modu-lar family of intervention tools that deliver real-time monitoring, dynamic tool control, and verified downhole actuation to set new standards for suc-cess in well intervention operations. Sensors incorporated in the ReSOLVE service tools enable the engineer to monitor tool activity and the prog-ress of downhole operations while responsively controlling the tool for optimal performance. By integrating monitoring and control, ReSOLVE ser-vice eliminates the reliance on esti-mates and assumptions that is typical with conventional “blind” intervention methods. Conveyance is on wireline by gravity or on tractor in highly deviated and horizontal wells.

The four tools of the modular ReSOLVE instrumented service are readily assembled on the basic configu-ration consisting of the telemetry and control modules.

High-force linear actuator toolThe ReSOLVE service combination of the anchor and linear actuator mod-ules reliably applies controlled axial force to well components. The linear actuator tool can be used with either the ReSOLVE service’s universal shift-ing tool (UST) or third-party shifting, pulling, or other interface tools.

The anchor module opens with the industry’s largest reach from the tool OD to the tubing of nearly 2 in [5 cm] diametrically. Although up to 150,000 lbf [667,230 N] of anchoring force is pre-cisely applied, the innovative low-stress anchor grips minimize the impact on the tubing while maximizing traction.

Once anchoring is confirmed to the surface, the linear actuator can be extended or retracted multiple times to apply a large, controlled force of up to 45,000 lbf [200,170 N] to a specific well component. Continuous measurements of displacement and the applied force validate completion of the operation.

Wireline Services Catalog ■ Well Intervention Services 235

ReSOLVE Instrumented Wireline Intervention Service

Hydraulic module Setting module

Anchor module Linear actuator module UST

Tractor Milling module

Milling Tool

Setting Tool

Shifting Tool

Telemetry module Control module


Selective universal shifting toolReSOLVE service’s UST makes mul-tiple shifts in any direction in a single run, whether to a single component or multiple components in multizone completions. The UST is paired with the anchor and linear actuator, for which forces and displacements are measured to confirm that the expected force and distance were achieved.

To engage a selected completion component, the UST radially extends profile keys with a specified preload force. The extended keys remain com-pliant to navigate well geometry. Once the UST is latched into the profile of the component, the anchor secures the tool in the well, and the linear actuator extends or retracts to shift the compo-nent. The keys fully retract to enable the tool to pass restrictions.

Nonexplosive setting toolThe setting tool is hydraulically powered, providing a large force of up to 78,000 lbf [347,000 N] for setting plugs and pack-ers. With real-time confirmation report-ing of the setting force applied and a variable setting speed, the ReSOLVE ser-vice’s setting tool is a reliable, low-risk alternative to the conventional use of explosives to set plugs and packers. Not using explosives provides a significant advantage for operations in locations where explosives security and safety con-cerns can complicate logistics and cause delays. In addition, the setting tool can be performance tested at the surface before deployment, and radio silence is not necessary during operations.

Milling toolThe ReSOLVE service’s milling tool mills through debris and scale build-ups, tubing restrictions, and plugs. The TuffTRAC cased hole services tractor is seamlessly integrated to automatically drive the ReSOLVE system forward and resist rotation while the milling tool’s rotating bit engages the obstruc-tion. Unlike for conventional uninstru-mented milling tools, the engineer is fully informed of the tool’s perfor-mance status through real-time moni-toring while dynamically controlling the bit speed and weight on bit (WOB).

The MillOptimizer* automatic milling system automatically adjusts the WOB to achieve a particular torque. Bit torque is constantly monitored and WOB adjusted by the TuffTRAC tractor to maintain a constant bit speed. With MillOptimizer system’s coordinated control, the trac-tor and milling tool operate as a single intelligent system to maximize milling efficiency and prevent stalling. Any bit stalling is immediately detected by the MillOptimizer system, which automati-cally stops the tool, disengages the scale by reversing the bit and the tractor, and then resumes milling.

The milling tool uses a novel PDC bit designed and manufactured by Lyng Drilling, a Schlumberger company. Optimized for maximum rate of pen-etration (ROP) when milling hard scale buildup, this groundbreaking mill bit achieves the highest rate of scale vol-ume milled within the power limits of electric wireline.

Applications■ Nonexplosive setting of bridge

and tubing plugs, packers, casing patches, and cement retainers

■ High-force axial shifting– Opening and closing of isolation

valves– Shifting sliding sleeves– Pulling retrievable plugs– Fishing operations– Replacing gas lift valves– Safety valve lockout

■ Selective shifting with a high-expansion universal shifting tool– Sliding sleeves in multizone

completions– Mechanically opening isolation

valves– Single-run multiple shifting– Shifting components below

restrictions■ Milling

– Removing scale accumulation in well tubulars

– Milling plugs– Removing tubing restrictions



Well Intervention Services 237


Shifting Setting Milling UST

Output Basic ReSOLVE service configuration: wellbore pressure, wellbore temperature, head tension, casing collar locator, head voltage, DC current, optional gamma ray

Anchor force, linear force, anchor displacement, linear displacement

Setting force Bit torque, WOB, bit speed (rpm), relative bearing (tool orientation)

Key radial force, key radial position

Resolution Basic ReSOLVE service configuration: Wellbore pressure: 17 psi [117 kPa], Wellbore temperature: 0.36 degF [0.2 degC], digital CCL: 0.02 V, head tension: 8 lbf [36 N]

Linear force: 43 lbf [191 N] Linear displacement: 0.005 in [0.127 mm] Anchoring diameter: 0.004 in [0.10 mm] Anchoring force: 60 lbf [267 N]

Setting force: 50 lbf [222 N]

Bit torque: 0.2 ft.lbf [0.27 N.m] Bit speed: 0.5 rpm

Key radial range: 5 lbf [22 N] Key radial position: 0.050 in [1.27 mm]


None None None None

Special applications Complete range of standard brushes, hones, and other accessories and a full set of bits, with custom bits made on request


Shifting Setting Milling UST



20,000 psi [138 MPa] High-pressure version: 30,000 psi [207 MPa]

20,000 psi [138 MPa] 20,000 psi [138 MPa] High-pressure version: 30,000 psi [207 MPa]

Performance limits Anchoring range: 3.13–5.10 in [7.95–12.95 cm] Anchoring range, large-pipe version: 4.63–6.60 in [11.76–16.74 cm] Linear range: 20 in [50.8 cm] Linear force: 45,000 lbf [200,170 N]

Setting range: 11.4 in [28.96 cm] Setting force: 78,000 lbf [346,960 N]

Max. milling torque: 250 ft.lbf [339 N.m] Max. bit speed: 130 rpm

Key opening range: 3.13–5.10 in [7.95–12.95 cm] Key radial force: 700 lbf [133,450 N]

Borehole size—min. 3.2 in [8.13 cm] 4 in [10.16 cm] 3.2 in [8.13 cm]† 3.2 in [8.13 cm]

Borehole size—max. 6.7 in [17.02 cm] –‡ –‡ –‡

Outside diameter 3.125 in [7.94 cm] High-pressure version: 3.625 in [9.21 cm] Large-pipe version: 4.624 in [11.75 cm]

3.625 in [9.21 cm] 3.125 in [7.94 cm] 3.125 in [7.94 cm]

Length 25.0 ft [7.62 m]§ 18.9 ft [5.76 m]§ 8.7 ft [2.65 m]§ 5.5 ft [1.79 m]§

Weight 489 lbm [223 kg] 423 lbm [192 kg] 441 lbm [200 kg]†† 141 lbm [64 kg]

Tension 60,000 lbf [266,890 N] 60,000 lbf [266,890 N] 60,000 lbf [266,890 N] 60,000 lbf [266,890 N]

Compression 20,000 lbf [88,960 N] 20,000 lbf [88,960 N] 20,000 lbf [88,960 N] 20,000 lbf [88,960 N] † Based on current minimum bit size ‡ Configuration dependent § Complete toolstring, without a tractor or logging head †† Minimum with two drives


The Casing Packer Setting Tool (CPST) provides a reliable method of deploying plugs and packers in the wellbore during completion, isolation, or abandonment. The CPST features■ pressure-balanced design (does

not have to overcome well pressure when setting)

■ only one igniter, which incorporates a safety resistor for additional safety

■ spiral pins to prevent tool preset-ting while running in the hole

■ components coated in liquid nitride to improve life expectancy through greater surface hardness and increased corrosion resistance with no surface buildup

■ no special alignment or orientation of components required during assembly or disassembly

■ efficient redressing at the wellsite.

Application■ Setting plugs and packers


Casing Packer Setting Tool


CPST-AA CPST-CC CPST-BC



Casing size—min. 5 in [12.70 cm] 4½ in [11.43 cm] 3½ in [8.89 cm]

Casing size—max. 13⅜ in [33.97 cm] 5½ in [13.97 cm] 5 in [12.70 cm]



Weight 180 lbm [82 kg] 79.5 lbm [36 kg] 81.8 lbm [37 kg]

Bottom thread Sleeve: 3½-in [8.89-cm] 6 Acme Mandrel: 2-in [5.08-cm] 6 Acme

Sleeve: 2½-in [6.35-cm] 6 Acme Mandrel: 1-in [2.54-cm] 8 UN

Sleeve: 2-in [5.08-cm] 10 Stub Acme Mandrel: 11⁄16-in [4.29-cm] 16 UN


The junk basket consists of a wireline feeler and junk catcher. It is run with a gauge ring to determine if the casing ID is sufficient to permit subsequent passage of the completion string, plugs, packers, or other tools. The junk basket also cleans the well of junk.

The housing of the junk basket is fluted to allow wellbore fluid to enter the bottom of the housing and exit through its side as the tool is run.

The gauge ring is screwed on to the mouth of the basket. This position helps to seal the housing bottom as the tool is pulled out of the wellbore. The ring size used depends on the casing size and whether a bridge plug or packer is run. However, the gauge ring OD is always chosen to be slightly larger than subsequent tool runs to ensure that the tools will pass through the casing.

Applications■ Clear casing and tubing of debris■ Prevent bridge plug or packer

sticking ■ Drift the casing ID to ensure the

passage of tools and completion equipment


Gauge Ring and Junk Basket


Gauge Ring and Junk Basket




Casing size—max. 13⅜ in [33.97 cm]

Outside diameter 3 to 4 in [7.62 to 10.16 cm]†

Length 5.83 ft [1.78 m]

Weight Variable† The OD of the junk basket depends on gauge ring used.



PosiSet Mechanical Plugback Tool

The PosiSet* mechanical plugback tool (MPBT) is used in rigless through-tubing recompletions. By using a mast or a crane, recompletions can be accomplished without the cost of a workover rig.

The anchored elastomeric plug of the PosiSet MPBT is run through tub-ing and set in casing to plug off fluid flow in the casing below the plug. The casing seal is similar to that produced by a cast-iron plug, but instead of an explosive charge, a downhole electric motor within the MPBT Setting Unit (MPSU) is used to contract the elas-tomer sealing assembly to form a firm seal against the casing wall. The expan-sion ratio is typically 3:1. An anchoring system keeps the tool in place while cement is placed on top of the plug to a height of 10 ft [3 m] or more to provide additional differential pressure.

The plug is drillable. The small-est plug can withstand 25,000-lbf [111,205-N] force. The largest 95⁄8-in [24.45-cm] plug can withstand 90,000-lbf [400,340-N] force. If the wellbore pressure at setting depth is less than 1,000 psi [7 MPa], a special tool is used to aid the setting process of the plug.

Plugs can be set by the PosiSet MPBT in open hole, across perforations, and at gravel-pack screens.

The Positive Displacement Dump Bailer is used to place the required cement plug on top of the PosiSet plug. Release of a weight bar displaces cement from the bailer sections. The plug can be pressure tested 24 h after the last bailer run, when the cement is at approximately 90% of its ultimate compressive strength. The temperature rating of the Positive Displace ment Dump Bailer is 302 degF [150 degC].

Applications■ Seal off nonproductive zones■ Seal off water-producing zones

below productive zones■ Base for a sand plug■ Low-pressure acid base plug■ Positive depth control plug




MPSU-BA MPSU-CA



Borehole size—min. 4½ in [11.43 cm] 4½ in [11.43 cm]

Borehole size—max. 7⅝ in [19.37 cm] 9⅝ in [24.45 cm]


Length 20.5 ft [6.25 m] 21 ft [6.40 m]


PosiSet MPBT Plug Mechanical Specifications4½-in Casing 5-in Casing 5½-in Casing 7-in Casing 7⅝-in Casing 9⅝-in Casing


Differential pressure rating† 1,000 psi [7 MPa] 1,000 psi [7 MPa] 500 psi [3 MPa] 1,500 psi [10 MPa] 1,000 psi [7 MPa] 500 psi [3 MPa]

Casing size—min. ID 3½ in [8.89 cm] 4 in [10.16 cm] 4½ in [11.43 cm] 5.88 in [14.93 cm] 6½ in [16.51 cm] 8.43 in [21.41 cm]

Casing size—max. ID 4.02 in [10.21 cm] 4.52 in [11.48 cm] 5.02 in [12.75 cm] 6.53 in [16.59 cm] 7.02 in [17.83 cm] 9.01 in [22.88 cm]

Outside diameter 2.125 in [5.40 cm] 1.6875 in [4.29 cm] 1.6875 in [4.29 cm] 2.125 in [5.40 cm] 2.125 in [5.40 cm] 2.625 in [6.67 cm]

Setting time 17 min 17 min 60 min 60 min 60 min 90 min

Remarks Set using either the MPSU-BA or MPSU-CA Must be set using the MPSU-CA

† Pressure ratings are for the plugs only. The desired differential pressure rating is achieved by placing cement (usually 10 ft [3 m]) on top of the plug.


Auxiliary Measurements and Devices


Wireline Services Catalog ■ Auxiliary Measurements and Devices 245

Caliper devices are integral to most stan-dard logging tools because measurement of the borehole axis is an extremely useful parameter for environmental cor-rection, quantitative interpretation, and cement volume calculation.

Caliper logs are recorded from one-, three-, four-, or six-arm devices. If the borehole is uniform and circular, all the calipers read the same value. In an elliptical hole, the single-arm caliper generally lines up with the long axis, and the three-arm caliper indicates a diameter greater than the

short axis but less than the long axis. The four-arm caliper measures both the short and long axes of the hole and provides a more accurate value of borehole volume. Single-arm calipers are typically part of most density and microresistivity tools; four-arm calipers are part of most dipmeter tools. The Mechanical Caliper Device (MCD) is a three-arm caliper tool. The six-arm Environmental Measurement Sonde (EMS) caliper is described subsequently in this chapter.

Applications■ Borehole diameter■ Borehole shape■ Borehole volume■ Environmental correction

to log output

Caliper Log


One-Arm Caliper MCD Three-Arm Caliper Four-Arm Caliper

Output Borehole size Borehole size Borehole size

Logging speed Depends on toolstring Depends on toolstring Depends on toolstring

Range of measurement 4 to 22 in [10.16 to 55.88 cm] 4½ to 16 in [11.43 to 40.64 cm] 4 to 22 in [10.16 to 55.88 cm]

Vertical resolution 6 in [15.24 cm] 6 in [15.24 cm] 6 in [15.24 cm]

Accuracy ±0.25 in [±0.64 cm] ±0.25 in [±0.64 cm] ±0.20 in [±0.51 cm]

Depth of investigation Borehole Borehole Borehole

Mud type or weight limitations None None None

Combinability Combinable with most tools Combinable with most tools Combinable with most tools

Special applications H₂S service H₂S service H₂S service


One-Arm Caliper MCD Three-Arm Caliper Four-Arm Caliper

Temperature rating† 350 degF [177 degC] 350 degF [177 degC] 350 degF [177 degC]


Borehole size—min. 4 in [10.16 cm] 4 in [10.16 cm] 4 in [10.16 cm]

Borehole size—max.‡ 22 in [55.88 cm] 16 in [40.64 cm] 22 in [55.88 cm]

Outside diameter Depends on toolstring 3.375 in [8.57 cm] Depends on toolstring

Length Depends on toolstring 8 ft [2.44 m] Depends on toolstring

Weight Depends on toolstring 155 lbm [70 kg] Depends on toolstring

Tension Depends on toolstring 36,000 lbf [160,140 N] Depends on toolstring

Compression Depends on toolstring 9,900 lbf [44,040 N] Depends on toolstring † Calipers rated to 500 degF [260 degC] are available for high-temperature toolstrings. ‡ Caliper extensions are available for larger borehole sizes.


The Auxiliary Compression Tension Sub (ACTS) measures the tension or compression between the upper and lower heads of the tool in conven-tional wireline logging. When the log-ging equipment is drillpipe conveyed, ACTS monitoring of the downhole compression force is critical for pre-venting damage to the logging tools.

Applications■ Measurement of downhole tension

applied to a logging toolstring■ Measurement of compression

applied to tools during conveyance on TLC tough logging conditions system

■ Determination of stuck cable or toolstring

■ Two ACTS tools in a toolstring to determine which part of the toolstring is stuck

■ Determination of force on the cable head weakpoint to prevent separation of the cable from the cable head during cut-and-thread operations


Auxiliary Compression Tension Sub


ACTS

Output Tension and compression forces

Logging speed No limit

Range of measurement 22,000 lbf [97,860 N]

Accuracy ±3%





ACTS








Tension 22,000 lbf [97,860 N]



The Environmental Measurement Sonde (EMS) significantly enhances the precision of the determination of borehole shape. Six independent caliper measurements are made around the borehole to determine the true ovality of the borehole for stress analysis studies. In addition, the EMS obtains measurements of mud resistivity, mud temperature, and acceleration along the tool axis to support real-time borehole correction of a range of downhole measurements.

The six independent arms of the EMS gauge the borehole cross section with greater precision over a wider range of hole sizes than conventional tools can. Six accurate oval-radius measurements are made, and an ovality algorithm provides detailed information on the borehole geometry for more representative environmental correction of imaging tool measurements, improved borehole stress analysis, and more precise cement volume estimation. The measurement is valid even if the tool is eccentered.

The multiple voltage monitoring electrodes of the EMS resistivity sen-sor provide mud resistivity measure-ments that are both more accurate and more robust than conventionally acquired measurements, even under adverse conditions. For example, good-quality measurements can be made with mudcake on the tool surface and in narrow boreholes.

Because the EMS is combinable with all imaging tools (including the AIT array induction imager tool, ARI azimuthal resistivity imager, and IPL integrated porosity lithology service), environmentally corrected wellsite logs are produced without an extra trip in the borehole.

Applications■ Borehole geometry evaluation■ Accurate determination of

cement volume■ Borehole stress analysis■ Mud resistivity measurement■ Mud temperature and z-axis

acceleration measurement■ Environmental corrections for

other logging tools

Auxiliary Measurements and Devices 247

Environmental Measurement Sonde




EMS

Output Mud resistivity, mud temperature, caliper


Range of measurement Resistivity: 0.01 to 5.0 ohm.m Temperature: 0 to 392 degF [0 to 200 degC] Caliper: 30 in [76.2 cm] (centered), 17 in [43.18 cm] (eccentered)


Accuracy Resistivity: ±10% (from 0.02 to 0.5 ohm.m), ±7% (from 0.5 to 5 ohm.m) Temperature: ±1.8 degF [±1 degC] [1%] (accuracy), 0.18 degF [0.1 degC] (resolution) Caliper: ±0.1 in [±0.25 cm] (accuracy), 0.06 in [0.15 cm] (resolution) Accelerometer: ±1.6 in/s2 [±4 cm/s2] (accuracy), 0.4 in/s2 [±1 cm/s2] (resolution)

Depth of investigation Borehole measurement only




EMS






Length 14.23 ft [4.34 m]


Tension 50,000 lbf [224,110 N]



The FPIT* free-point indicator tool uses a stretch sensor and a torque sensor to accurately determine the free point in stuck drillpipe, drill col-lars, tubing, or casing. Within the elas-tic range of the pipe material, the free section of the pipe deforms linearly when the pipe is subjected to a pull or torsion. The FPIT tool measures the stretch and torque over a fixed distance to calculate the amount of free pipe according to the theoreti-cal deformation. The free portion is conveniently recovered after a backoff shot is fired inside a tool joint that is subjected to left-hand torque. The backoff shot can be combined with FPIT service or performed separately after the free point is determined.

Applications■ Determination of the deepest free

point in a stuck string of pipe■ Backoff of stuck pipe■ Determination of pipe tally■ Effective operation from drillships

and semisubmersibles and in highly deviated wells

Auxiliary Measurements and Devices 249

FPIT Free-Point Indicator Tool


FPIT Tool

Output Free pipe stretch and torque


Range of measurement Stretch: 0.12 to 3.6 in/1,000 ft [10 to 300 USTR] Torque: 0.02 to 0.5 rev/1,000 ft [0.02 to 0.5 c/305 m]

Vertical resolution 7.24 ft [2.21 m] (distance between anchors)

Accuracy ±10% at 350 degF [177 degC]

Depth of investigation Not applicable


Combinability Backoff shot, casing collar locator



FPIT Tool

Temperature rating FPIT-A and FPIT-D: 350 degF [177 degC] FPIT-C: 330 degC [165 degC]


Borehole size—min.† 1½ in [3.81 cm]

Borehole size—max.† 5 in [12.70 cm]


Length 13.92 ft [4.24 m]

Weight 40.75 lbm [18 kg] † For operation in casing sizes up to 95⁄8 in [24.45 cm], the tool OD is increased to 1.875 in [4.76 cm],

for which the minimum hole size is 2 in [5.08 cm].


The CERT* correlated electromag netic retrieval tool is a wireline electro-magnetic fishing tool that retrieves metallic junk in cased or open bore-holes. The CERT tool is 5 times more powerful than a permanent magnet of the same size.

When the power is off, the CERT tool is nonmagnetic and can be transported by helicopter without causing disrup-tion of the navigational instruments. The power remains off until the fishing depth is reached to prevent the collec-tion of unwanted metal and to maintain a clean fishing surface. Once the CERT tool is activated, surface meters reflect contact with the fish and the progress of its return the surface.

The tool is available in four sizes: 111⁄16, 21⁄8, 23⁄4, and 33⁄8 in [4.29, 5.40, 6.99, and 8.57 cm, respectively]. Collar locators and gamma ray devices provide depth control. Nonmagnetic guide shoes are available for 7-, 75⁄8-, and 95⁄8-in casings.

Applications■ Openhole metal retrieval■ Cased hole metal retrieval■ Open, cased, or tubing wellbore

environments


CERT Correlated Electromagnetic Retrieval Tool


CERT Tool

Output Surface indications of retrieval


Range of measurement Lifting capacity up to 1,000 lbf [4,450 N] (depends on area of contact with the fish)

Depth of investigation Borehole service only


Combinability Combinable with gamma ray and CCL tools



CERT Tool





Outside diameter† 111⁄16, 2⅛, 2¾, and 3⅜ in [4.29, 5.40, 6.99, and 8.57 cm]


Weight 50 lbm [22.7 kg] † Ultimate tool size depends on the appropriate gauge rings for the hole size.

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