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HalliburtonLogging and Perforating

Capabilitiesfor

High-Pressure, High-TemperatureWells and Slim Holes

HalliburtonLogging and Perforating

Capabilitiesfor

High-Pressure, High-TemperatureWells and Slim Holes

Halliburton Energy ServicesHouston

© 1995 by Halliburton Energy Services. All rights reserved.Printed in the United States of America

Halliburton Energy Services Publication EL-1088

Sales of Halliburton products and services will be in accord solely with the terms and conditionscontained in the contract between Halliburton and the customer that is applicable to the sale.

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Contents

INTRODUCTION 1

SECTION 1 Openhole Logging 3The HEAT Suite Logging System 3

Cablehead Tension Load Cell 3Hostile Telemetry Assembly (HETS) 4Hostile Powered Decentralizer (HPDC) 4Centralizers and Flex Joints 4Hostile Four Arm Caliper (HECT) 4Hostile Dual Induction (HDIL) 5Hostile Full Wave Sonic (HFWS) 5Hostile Spectral Density (HSDL) 5Hostile Dual Spaced Neutron (HDSN) 5Hostile Natural Gamma Ray (HNGR) 5Hostile Dipmeter (HEDT) 6

Circumferential Acoustic Scanning Tool (CAST) 6Toolpusher Logging (TPL) 6Coiled-Tubing Conveyed Logging 6

SECTION 2 HEAT Suite Log Examples 21Comparison of HEAT and Standard Logs 21Triple-Combo Log and Analysis 21Sonic Log and IWC Analysis 21

Instantaneous Transmissivity 22Instantaneous Phase 22Instantaneous Frequency 22Data and Analysis Examples 22

SECTION 3 Environmental Effects on HEAT Suite Responses 29

SECTION 4 Cased-Hole Logging 77Gamma-Neutron-CCL (GNST and HGNC) 77Cement Bond/Micro-Seismogram® Logging (HFWS) 77Production Logging (PL) 78

Hydro (HYD) 78Fluid Density (FDT) 78Gradiomanometer 78Fullbore Gas Holdup (GHT) 78Continuous Flowmeter (FMC) 79Pressure (SPT and CQPT) 79Temperature (TLT) 79Borehole Audio Tracer (BATS) 79

Casing Inspection 79

SECTION 5 Cased-Hole Mechanical and Related Services 91Explosive Services 91

Jet Cutters 91Drill-Collar Severing Tools (DCST) 91Perforating Systems 91Junk Shots 92Magnetic Orienting Device (MOD) 92Slimhole Hostile Gamma Perforator (HGPS) 92

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Chemical Cutters 92Free-Point and Back-Off Tools 92Bridge Plugs 92

Through-Tubing Bridge Plugs 92Cast-Iron Bridge Plugs 92

SECTION 6 Radius-of-Borehole-Curvature Limitations on Downhole Tools 101

INDEX 107

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TABLESTable 1.1—HEAT Suite Specifications 4Table 5.1—Specifications for Jet Tubing Cutters 93Table 5.2—Specifications for Jet Drillpipe Cutters 93Table 5.3—Specifications for Drill-Collar Severing Tools 93Table 5.4—Specifications for Strip-Carrier and Wire-Carrier Through-Tubing Capsule Guns 94Table 5.5—Specifications for Scalloped Hollow-Carrier Tubing Guns 94Table 5.6—Specifications for Ported Hollow-Carrier Casing Guns 94Table 5.7—Specifications for Scalloped Hollow-Carrier Casing Guns 95Table 5.8—Chemical Cutters Used in Tubulars With OD 4-1/2 Inches or Less 96Table 5.9—Elite Magna-Range Bridge Plugs 97

FIGURES

Specifications: Openhole Logging Tools

Figure 1.1—Typical HEAT Suite Configurations 7Figure 1.2—Hostile Environment Telemetry (HETS-A) 8Figure 1.3—Hostile Powered Decentralizer Caliper (HPDC-A) 9Figure 1.4—Hostile Environment Caliper Tool (HECT-A) 10Figure 1.5—Hostile Dual Induction (HDIL-A) 11Figure 1.6—Hostile Full Wave Sonic (HFWS-A), Long-Spaced Operation, Sonic Full Waveform 12Figure 1.7—Hostile Full Wave Sonic (HFWS-A), Long-Spaced Operation, Sonic Real-Time Slowness 13Figure 1.8—Hostile Spectral Density (HSDL-A), With In-Line Pad 14Figure 1.9—Hostile Spectral Density (HSDL-A), With Extendable Pad 15Figure 1.10—Hostile Dual Spaced Neutron (HDSN-A) 16Figure 1.11—Hostile Natural Gamma Ray (HNGR-A) 17Figure 1.12—Hostile Environment Dipmeter Tool (HEDT-A) 18Figure 1.13—Circumferential Acoustic Scanning Tool (CAST-A), DITS Version 19

Examples: HEAT Suite LogsFigure 2.1—Comparison of HEAT and Standard Logs 23Figure 2.2—HEAT Triple-Combo Log 24Figure 2.3—Analysis of HEAT Triple-Combo Log 25Figure 2.4—HEAT Full Wave Sonic Log 26Figure 2.5—Instantaneous Waveform Characteristics Log 27

Charts: HEAT Suite InterpretationFigure 3.1—Hostile Dual Induction - Short Normal: Short Normal Borehole Correction 31Figure 3.2—Hostile Dual Induction: Deep and Medium Induction Borehole Corrections 33Figure 3.3—Hostile Dual Induction: Deep and Medium Induction Bed Thickness Corrections

(Rs = 1 & 2 ohm·m) 35Figure 3.4—Hostile Dual Induction: Deep and Medium Induction Bed Thickness Corrections

(Rs = 4 & 10 ohm·m) 36Figure 3.5—Hostile Dual Induction - Short Normal: Invasion Corrections (Rxo/Rm = 20, 4-inch borehole) 37Figure 3.6—Hostile Dual Induction - Short Normal: Invasion Corrections (Rxo/Rm = 100, 4-inch borehole) 39Figure 3.7—Hostile Dual Induction - Short Normal: Invasion Corrections (Rxo/Rm = 20, 6-inch borehole) 40Figure 3.8—Hostile Dual Induction - Short Normal: Invasion Corrections (Rxo/Rm = 100, 6-inch borehole) 41Figure 3.9—Hostile Dual Induction - Short Normal: Invasion Corrections (Rxo/Rm = 20, 8-inch borehole) 42Figure 3.10—Hostile Dual Induction - Short Normal: Invasion Corrections (Rxo/Rm = 100, 8-inch borehole) 43Figure 3.11—Hostile Spectral Density: Borehole Curvature Corrections 45Figure 3.12—Hostile Dual Spaced Neutron: Openhole Environmental Corrections (Borehole) 47

Tables and Figures

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Figure 3.13—Hostile Dual Spaced Neutron: Openhole Environmental Corrections (Standoff and Formation Salinity) 49

Figure 3.14—Hostile Dual Spaced Neutron: Cased Hole Environmental Corrections (Borehole) 51Figure 3.15—Hostile Dual Spaced Neutron: Cased Hole Environmental Corrections

(Standoff and Formation Salinity) 53Figure 3.16—Porosity Determination: Neutron Limestone Porosity versus Porosity 55Figure 3.17—Porosity-Mineralogy Crossplot: Bulk Density versus Neutron Porosity (Fluid Density = 0.85 g/cc) 57Figure 3.18—Porosity-Mineralogy Crossplot: Bulk Density versus Neutron Porosity (Fluid Density = 1.00 g/cc) 58Figure 3.19—Porosity-Mineralogy Crossplot: Bulk Density versus Neutron Porosity (Fluid Density = 1.15 g/cc) 59Figure 3.20—Porosity-Mineralogy Crossplot: Bulk Density versus Sonic (Oil-Based Fluid) 61Figure 3.21—Porosity-Mineralogy Crossplot: Bulk Density versus Sonic (Fresh Water) 62Figure 3.22—Porosity-Mineralogy Crossplot: Bulk Density versus Sonic (Salt Water) 63Figure 3.23—Porosity-Mineralogy Crossplot: Sonic versus Neutron Porosity (Fresh Water) 65Figure 3.24—Mineral Identification Plot: ρmaa

Determination 67Figure 3.25—Mineral Identification Plot: ∆tmaa

Determination 69Figure 3.26—Mineral Identification Plot: Umaa

Determination 71Figure 3.27—Mineral Identification Plot: ρmaa

versus ∆tmaa73

Figure 3.28—Mineral Identification Plot: ρmaaversus Umaa

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Specifications: Cased-Hole Logging ToolsFigure 4.1—Hostile Gamma Neutron CCL (HGNC-A) 80Figure 4.2—Gamma Neutron Slim Tool (GNST-A) 81Figure 4.3—Hostile Full Wave Sonic (HFWS-A), Cement Bond 82Figure 4.4—Hydro (HYD-FC), MUX 83Figure 4.5—Fluid Density (FDT-EC), MUX 84Figure 4.6—Fullbore Gas Holdup (GHT) 85Figure 4.7—Continuous Flowmeter (FMS-HC), MUX 86Figure 4.8—Stack Pressure Tool (SPT-CC), MUX 87Figure 4.9—Compensated Quartz Pressure Tool (CQPT-A), MUX 88Figure 4.10—Temperature Logging Tool (TLT-IC) 89Figure 4.11—Borehole Audio Tracer Survey (BATS) 90

Specifications: Cased-Hole Mechanical ServicesFigure 5.1—Time-Temperature Effect on Explosives 97Figure 5.2—Hostile Gamma Perforator (HGPS-A), Slim Version 98Figure 5.3—Free-Point and Back-Off Tool (Dia-Log), 1.625-inch 99

Charts: Minimum Radius of Borehole CurvatureFigure 6.1—Radius of Curvature Limitations on Tool Length 101Figure 6.2—Minimum Radius of Borehole Curvature Determination (Tool Diameter = 2.75 inches) 103Figure 6.3—Minimum Radius of Borehole Curvature Determination (Tool Diameter = 3.5 inches) 104Figure 6.4—Minimum Radius of Borehole Curvature Determination (Tool Diameter = 1.4375 inches) 105Figure 6.5—Minimum Radius of Borehole Curvature Determination (Tool Diameter = 1.6875 inches) 106

1

Introduction

Providing services in high-pressure, high-temperature wells and in slimholes presents a special challenge to wireline service companies. Inparticular, the companies must produce small-diameter logging toolsthat can make measurements as accurately and reliably as the tools'

standard-sized counterparts, sometimes under extremely harsh downholeconditions. Furthermore, perforating assemblies must use special explosives thatcan withstand both high temperatures and high pressures and still operateeffectively to produce optimum perforation characteristics.

Halliburton has developed equipment for providing a complete line of wirelineservices in both open and cased wells that are at high temperature and highpressure or that have small-diameter bores. The following sections in thisbooklet give an overview of these services, present detailed tool specifications,and furnish environmental correction charts used for log interpretation.Additional information and literature are available through Halliburton salesrepresentatives and local offices.

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LOGGING AND PERFORATING CAPABILITIES FOR HIGH-PRESSURE, HIGH-TEMPERATURE WELLS AND SLIM HOLES

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Section 1OpenholeLogging

THE HEAT SUITE LOGGING SYSTEMThe HEAT Suite comprises six logginginstruments, a cablehead-tension loadcell, and associated centralizer, decentral-izer, flex-joint, and telemetry assemblies.The logging instruments include FourArm Caliper, Dual Induction, FullWave Sonic, Spectral Density, DualSpaced Neutron, and Natural GammaRay devices. A Hostile EnvironmentFour Arm Dipmeter is available for usein 6-inch and larger boreholes.

Each HEAT tool contains an internaltemperature sensor that provides qualitycontrol data related to operationalcharacteristics and tool electronics.Such information is usually criticalonly in very hot well conditions—inparticular, when temperatures over aprolonged period are near the 500˚Flimit of the toolstring.

Cablehead Tension Load CellIn all wells, but particularly in slim holes,erratic tool movement resulting fromborehole and formation conditions can cause tool sticking. Thus, erratictool movement must be identified toaccurately determine depth. When theHEAT Suite is run, downhole tensionand compression in the tool are measuredwith the downhole Load Cell and areplotted on the log along with surfacecable tension to give information about tool drag. The Load Cell alsocontains a temperature sensor thatprovides a continuous measurement ofborehole temperature.

Halliburton's HostileEnvironment ApplicationsTools system (the HEATSuite) was the first set of

combinable, high-quality, small-diametertools capable of comprehensive formationevaluation in harsh environments. HEATSuite tools are digital and are smallerthan standard logging tools—2-3/4- to3-1/2-inch OD for HEAT Suite versus3-5/8- to 4-1/2-inch OD for standardtools. The HEAT Suite's small ODmakes it possible to design a thoroughformation evaluation program for holesas small as 3-1/2 inches. With temper-ature and pressure ratings of 500˚F (for6 hours) and 25,000 psi, respectively(Table 1.1), HEAT tools are built tohandle the severe conditions encounteredin deep and hot hydrocarbon-bearingformations. HEAT tools can becombined in almost any configuration(Figure 1.1) to suit the boreholegeometry and formation evaluationrequirements of each job.

Halliburton also has a dipmeter that israted to 450˚F and an acoustic imagingtool that can operate in holes as smallas 4-1/2 inches. The dipmeter is a four-arm device, whereas the imaging tool isan armless sonde that contains a singlerotating transducer for scanning theborehole wall.

In horizontal and deviated wells,Halliburton's Toolpusher system usesjointed tubing or drillpipe to transportwireline tools through the wellbore.The system can be deployed in openand cased wells and has been designedto operate with standard and slimholetools. In extended-reach and high-deviation operations, Halliburton canalso use coiled tubing to transportwireline tools through cased wells andnonrugose open holes.

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Table 1.1 — HEAT Suite Specifications

Tool Temperature Rating(°F)

Pressure Rating(psi)

Length(ft)

OD(inches)

31.7

13

15.3

30.22

11.55

8.54

9.2

Dual Induction

Spectral Density (In-Line Pad)

Dual Spaced Neutron

Full Wave Sonic

Gamma Ray

Four Arm Caliper

Powered Decentralizer

2-3/4

2-3/4

2-3/4

2-3/4

2-3/4

2-3/4

2-3/4

25,000

25,000

25,000

25,000

25,000

25,000

25,000

500

500

500

500

500

500

500

Hostile Telemetry Assembly (HETS)The Hostile Telemetry assembly (Figure 1.2) is one ofthe main components in the HEAT Digital InteractiveTelemetry system described below. It routes real-timeoperator commands from the surface to the downholetools and transmits measured parameters and tool statusindicators back to the surface computer.

The HEAT Digital Interactive Telemetry system has beenspecially designed to provide efficient, high-rate, distortion-corrected data transmission. The system overcomes thenarrow bandwidth restrictions that are inherent in wirelinelogging cables and that could otherwise limit data-trans-mission rates. The system also minimizes the high, variablesignal distortion that arises from elevated and changingtemperatures and that can seriously affect data reliability.System features include (1) a downhole telemetrytransmitter that generates a multilevel signal and (2) anadaptive equalizer in the uphole receiver that is continuallyoptimized to correct for the changing signal distortion.

Hostile Powered Decentralizer (HPDC)A Hostile Powered Decentralizer (Figure 1.3 ) is used withthe Hostile Dual Spaced Neutron tool to obtain accurateporosity data without the need for a bulky mechanicaldecentralizer such as that found on standard neutron loggingtools. The main decentralizing arm provides a boreholecaliper measurement used in correcting neutron porosityfor hole size. The diametrically opposed secondary armfurnishes indications of rugosity and washouts and makesa standoff measurement for correcting neutron porositywhen borehole conditions are such that the neutron toolcannot be effectively placed against the formation.

Centralizers and Flex JointsIn-line centralizers can be run on both the Full Wave Sonicand Dual Induction tools to provide the proper centraliza-tion needed to obtain the highest quality logging data. Adouble flex joint is available with the HEAT Suite, allowingHEAT services to be run in high-angle and horizontal wells.This permits eccentering Dual Spaced Neutron andSpectral Density tools when they are run in combinationwith other tools that require centering or can be runcentered, such as the Full Wave Sonic and Dual Induction.

Hostile Four Arm Caliper (HECT)Each arm of the Hostile Four Arm Caliper tool (Figure 1.4 )is independent of the other three arms—the arms are notmechanically paired or ganged as in tools of earlier design.This design allows the tool to provide a more accuratehole-size measurement and give a better description of theborehole's cross-sectional geometry. The tool incorporatesa positive-close feature that keeps the arms closed if electricalpower to the tool is interrupted. This feature preventsaccidental extension of the arms and also ensures positivearm closure so that the tool is "slick" should overshotfishing operations be necessary.

The tool measures borehole diameters from 3.5 to 12 inches.The tool's two diametrically opposed arm-pairs measuretwo borehole diameters that are presented on the log andthat can be used to determine borehole ovality. Other logcurves include average caliper, differential caliper, boreholevolume, and annular volume, the latter two of which areuseful in planning cement jobs.

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SECTION 1: OPENHOLE LOGGING

Hostile Dual Induction (HDIL)The Hostile Dual Induction tool (Figure 1.5) uses conven-tional 6FF40 deep and 8FF34 medium coil arrays. Thelog includes deep induction resistivity, medium inductionresistivity, and 16-inch short-normal resistivity curves.The availability of three resistivity curves permits invasionanalysis and the determination of true formation resistivity.

Tool design was optimized to provide the best possibleresistivity profile in common hostile-environment mudsystems. The coil arrays are pressure balanced to eliminatehydraulic pressure effects, and algorithms can be appliedto acquired data to sharpen the vertical resolution of theinduction measurements.

Hostile Full Wave Sonic (HFWS)As with the full-sized, industry-standard Full Wave Sonictool, the Hostile Full Wave Sonic tool (Figures 1.6 and 1.7)can be used in both open holes and cased wells. The HostileFull Wave Sonic tool utilizes a long-spaced transmitter-to-receiver configuration to provide real-time sonic wave-forms and compressional and shear slowness measurements(∆tc and ∆ts , respectively). Because of its short receiver-to-receiver spacings, this tool has excellent bed-resolutioncharacteristics, having the capability to delineate beds asthin as 6 inches. As with the standard full-sized tool, theslimhole version is fully digital and has selectable optionsfor downhole gain to be fixed or automatically controlled.

The Hostile Full Wave Sonic data have a broad range ofapplications that include the determination of formationporosity, formation permeability (from Stoneley waves),rock mechanical properties, and borehole stability. Thesonic data are also used for gas detection, natural fractureanalysis, hydraulic fracture design, seismic calibration,and amplitude versus offset (AVO) analysis.

Hostile Spectral Density (HSDL)The Hostile Spectral Density tool (Figures 1.8 and 1.9)furnishes complete spectral density information: bulkdensity, photoelectric factor (Pe ), and associated corrections.Density and photoelectric data are used to determineformation porosity and lithology and, when used withother porosity devices such as the Hostile Dual SpacedNeutron, to estimate shale volume and indicate thepresence of gas. The tool is available in a 2-3/4-inch in-line-pad configuration and a 3-1/2-inch extendable-padconfiguration. The extendable-pad design is preferred inmost conditions, especially in rugose boreholes, because itprovides the more positive pad contact needed to obtain

good log data. The in-line pad should only be used whenclearance becomes critical (that is, when bit size is lessthan 4-1/2 inches) or when borehole conditions warrantthe use of "slick body" tools. When the in-line pad isselected, the in-line Powered Decentralizer is used topress the toolstring against the borehole wall.

For the Hostile Density tool, an entirely new method wasdevised for obtaining bulk density, photoelectric factor,and various corrections. The procedure has proven sosuccessful that it is now being used for standard-sized tools.Instead of the traditional spine-and-ribs processing forcomputing density from near- and far-detector count-ratedata, a four-dimensional technique is used to determinethe density and Pe of the formation and mudcake withoutthe assumption of any correlations among these variables.Besides yielding density, the calculations provide informa-tion for compensating the Pe measurement and computinguseful quality indicators. Among the quality indicators area two-component density correction (which can be reducedto a single value similar to the traditional correction) andan estimate of the standoff or mudcake thickness.

Hostile Dual Spaced Neutron (HDSN)The Hostile Dual Spaced Neutron tool (Figure 1.10 ) canbe deployed in both open holes and cased wells and iscommonly run with the Powered Decentralizer. Asmentioned earlier, this decentralizer provides necessarytool eccentering and furnishes a continuous standoffmeasurement that helps improve porosity calculations,especially over rugose intervals. Additionally, caliper datafrom the decentralizer are used to correct porosity for holesize. The He3 detectors in the tool have been speciallydesigned to minimize the effects of elevated temperatureon observed count rates and computed porosity. TheHostile Dual Spaced Neutron tool has been extensivelycharacterized in test pits, and a full set of correction chartsare included in Section 3 of this publication. Neutronmeasurements are used to determine formation porosityand can be used with density measurements to identifylithology and to indicate the presence of gas.

Hostile Natural Gamma Ray (HNGR)As a standard operating procedure, the Hostile NaturalGamma Ray tool (Figure 1.11 ) is run in combinationwith all other HEAT Suite services. The tool can be runin both open holes and cased wells. Gamma-ray measure-ments are used for geologic correlation, depth control,and shale volume computation.

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* A mark of Halliburton

Hostile Dipmeter (HEDT)The Hostile Dipmeter (Figure 1.12) is a four-arm, 5-inch-OD device rated to 450˚F and 22,500 psi. It can bedeployed in holes as small as 6 inches. An innovative paddesign allows the tool to obtain reliable measurements inany type of borehole fluid, including oil-based mud.

Halliburton furnishes both wellsite computer processingand extensive computer center analysis of dipmeter data.State-of-the-art global mapping techniques are availablethrough Halliburton's SHIVA program, and resistivityimaging can be provided with Halliburton RESMAPprocessing. Results are available in many formats, includingconventional tadpole (arrow), polar, and statistical plotsand tabular listings. Besides the traditional application ofdetermining formation dip, dipmeter data can be used forhigh-resolution shale discrimination (LARA program)and to help deconvolve logging data for thin-bed analysis.

CIRCUMFERENTIAL ACOUSTICSCANNING TOOL (CAST™*)The CAST tool (Figure 1.13 ) is an ultrasonic scanningdevice that uses a single, rotating transducer to image thecomplete circumference of the wellbore. The circumferentialscanning rate can be set at 200, 300, 400, or 500 shots perrevolution, depending on hole size, with a vertical samplingrate of 40, 60, 90, or 120 revolutions per foot. Interchange-able transducer heads of different ODs adapt the tool tospecific wellbore conditions, such as fluid weight and type.The tool is capable of recording high-quality images inboreholes as small as 4-1/4 inches and is rated at 375˚Fand 20,000 psi.

The CAST transducer generates acoustic signals that reflectoff the borehole wall and return to the transducer. Basicprocessing of the returned signals determines time-of-flight and amplitude from which very detailed images areproduced. Image processing and enhancement softwareaid in analyzing structural and stratigraphic features,delineating thin beds, identifying natural fractures, andproviding borehole breakout data to define the directionof least principle stress. With information from the CASTtool's acoustic-travel-time caliper and optional navigationpackage, CAST logs can be used to calculate formationdip angle and azimuth.

TOOLPUSHER LOGGING (TPL)The Toolpusher system uses drillpipe or jointed tubing totransport wireline logging devices through the well. It wasdesigned for deviated and horizontal wells and can be usedin both open and cased holes. Standard wireline tools areattached to the drillpipe or tubing. To supply power andtelemetry to the tools, the wireline is pumped down thetubulars and is attached to the top of the logging string viaa wet-connector system. With flexible joints between thetools, toolstrings can traverse holes deviating as much as 30˚per 100 ft and having radius of curvature as small as 250 ft.

In wells where temperature or pressure is excessive, HEATSuite tools can be run on the Toolpusher system. Holesize must be 4-3/4 inches or larger.

COILED-TUBING-CONVEYED LOGGINGFor rigless operations in highly deviated and horizontalwellbores, hostile environment and conventional tools canbe run on coiled tubing. This method of tool deploymentis limited to cased wells and nonrugose open holes. Theflexibility of the coiled tubing and special flex joints betweentool components allow the downhole assembly to negotiatesmall-radius deviations. In extended reach operations,rollers on the toolstring or on the tools themselves facilitatetransport. Swivel joints, weights, and fins allow logging toolsand perforating guns to be oriented for top performance.

To save rig-up time, the wireline is threaded through thetubing before the tubing is transported to the wellsite. Atthe wellsite, the tools can be quickly attached to the wirelineand tubing at the surface and then conveyed through thewell with the motive power of the tubing injector assembly.

The design of the coiled-tubing-conveyed system permitscirculation at almost anytime during wireline operations.Such circulation provides clean fluids for better toolperformance and can contribute to more reliable tooloperation by helping control borehole temperature.

Coiled tubing is available in ODs ranging from 1-1/4- to3-inches. Limitations on the well's diameter, deviation, andradius of curvature depend on the size of the wireline tools.

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Figure 1.1

Typical HEAT Suite Configurations


8

Figure 1.2

TOOL: Hostile Environment Telemetry (HETS-A)

GENERIC TYPE: Tool Telemetry

GROUP: Instrumentation

DIMENSIONS AND RATINGSMax Temp: 500°F (6 hr)

Max OD: 2.75 in

Length: 11.5 ft

Max Press: 25,000 psi

Max Hole*: 12 in

Min Hole*: 3.5 in

Weight: 122 lb

*In cased holes, the Min Csg/Tbg ID is 3.25 inches and the Max Csg/Tbg IDis 12 inches

BOREHOLE CONDITIONSBorehole Fluids: Salt ■ Fresh ■ Oil ■ Air ■

Tool Positioning: Centralized ■ Eccentralized ■

Recommended Logging Speed: na

HARDWARE CHARACTERISTICSSource Type: None

Sensor Spacings: na

Sensor Type: None

Firing Rate: na

Sampling rate: 4 or 10 Samples per ft

No. of Windows: na

Combinability: HDIL, HSDL, HDSN, HNGR, HFWS, HECT

Full Spectrum: na

MEASUREMENTPrinciple: Digital Interactive Telemetry

Vertical Resolution: na

Range: na

Depth of Investigation: na

Primary Curves: na

Sensitivity: na

Accuracy: na

Secondary Curves: na

CALIBRATIONPrimary: None

Wellsite Verifier: None

Secondary: None

Sample Size: 3 or 1.2 in

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9

Figure 1.3

TOOL: Hostile Powered Decentralizer Caliper (HPDC-A)

GENERIC TYPE: Decentralizer

GROUP: Powered Decentralizer


Max OD: 2.75 in

Length: 9.2 ft


Max Hole: 12 in

Min Hole: 3.5 in

Weight: 145 lb



Recommended Logging Speed: 60 ft/min

HARDWARE CHARACTERISTICSDecentralizing Arm Force: 80 lb

Source Type: None

Washout Arm Force: 10 lb

Sensor Type: Point contact on two independent mechanical arms

Sensor Spacings: na

Sampling Rate: 4 or 10 Samples per ft

Combinability: HDIL, HSDL, HDSN, HNGR

MEASUREMENTPrinciple: Spring linkage

Vertical Resolution (90%): na

Washout Arm Range: 0 - 4 in

Depth of Investigation (50%): 0

Primary Curves: Caliper, Standoff

Sensitivity: na

Accuracy: na


CALIBRATIONPrimary: Metal Ring

Wellsite Verifier: Metal Ring

Secondary: Metal Ring

Firing Rate: Continuous

Decentralizing Arm Range: 0 - 12 in

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Figure 1.4

TOOL: Hostile Environment Caliper Tool (HECT-A)

GENERIC TYPE: Caliper

GROUP: Caliper


Max OD: 2.75 in

Length: 8.54 ft


Max Hole: 12 in

Min Hole: 3.5 in

Weight: 121 lb





Sensor Spacings: na

Sensor Type: Point contact on four independent mechanical arms



Full Spectrum: na

Combinability: HDIL, HSDL, HDSN, HFWS, HNGR

MEASUREMENTPrinciple: Four independent arms

Depth of Investigation (50%): 0

Vertical Resolution (90%): na

Sensitivity: na

Secondary Curves: Average caliper, Differential caliper,Borehole volume, Annular volume

Accuracy: ± 0.125 in

Primary Curves: 4 radii, 2 diameters

CALIBRATIONPrimary: 2.65-, 6.1-, and 10.1-inch concentric ring fixture

Wellsite Verifier: 6.1-inch concentric ring fixture

Secondary: 2.65-, 6.1-, and 10.1-inch concentric ring fixture

No. of Windows: na

Range: 4 - 12 in

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11

Figure 1.5

TOOL: Hostile Dual Induction (HDIL-A)

GENERIC TYPE: Dual Induction

GROUP: Macroresistivity


Max OD: 2.75 in

Length*: 31.7 ft


Max Hole: 12 in

Min Hole: 3.5 in

Weight: 260 lb

*The HDIL must be run with the Isolation Subassembly. The Isolationsubassembly is 23 inches (1.91 ft) long and is located between the cable headand the telemetry section.




HARDWARE CHARACTERISTICSSource Type: 20-kHz Coil Arrays

Sensor Spacings: 6FF40, 8FF34, 16 in

Sensor Type: Coil Arrays



Full Spectrum: na

Combinability: HDSN, HSDL, HNGR, HFWS

MEASUREMENT

Range

Principle

Vertical Resolution

Accuracy, Low

Depth of Investigation (50%)

Sensitivity

Accuracy, High

CALIBRATIONPrimary: Precision conductive loop, Sonde error offset, Precision resistor

Wellsite Verifier: Internal instrument reference signal

Secondary: Precision conductive loop, Sonde error offset, Precision resistor

No. of Windows: na

Primary Curves: ILd, ILm, Short Normal

Secondary Curves: SP

Short NormalInductionInduction

16 in54 in60 in

20 in30 in65 in

0.002 ohm·m1 mmho1 mmho

± 4%± 4%± 4%

0.2 to 2,000 ohm·m

± 1 mmho + Sonde Error

ShallowMediumDeep

IsolationSubassembly

InstrumentSection

SondeAssembly

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Figure 1.6

TOOL: Hostile Full Wave Sonic (HFWS-A), Long-Spaced Operation

GENERIC TYPE: Sonic Full Waveform

GROUP: Sonic


Max OD: 2.75 in

Length*: 30.22 ft


Max Hole: 12 in

Min Hole: 4 in

Weight: 340 lb




HARDWARE CHARACTERISTICSSource Type: Two 17-kHz piezoelectric

Sensor Spacings: 3, 5 ft (both inactive); 8, 8.5, 9, 9.5 ft (all active)

Sensor Type: Six piezoelectric

Firing Rate: 2.5/s for near source (Far source is inactive.)

Digitizing Interval: 6 µs/sample

Measurement Bandwidth: 1.5 to 30 kHz

Combinability: HDSN, HNGR, HSDL, HECT, HDIL

MEASUREMENTPrinciple: Full waveform recording of sonic signal

Depth of Investigation (50%): ~ 1 ft

Vertical Resolution (90%): ~ 0.5 ft

Sensitivity: na

Primary Curves: Waveform, ∆tc (Compressional Slowness),∆tc (Shear Slowness)

Accuracy: ± 1.0 µs

CALIBRATIONPrimary: Internal quartz clock

Wellsite Verifier: Casing for 57-µs slowness check

Secondary: None

Samples per Sensor: 1,024

Range: 40 to 190 µs/ft

*Add 3.5 ft for each in-line centralizer (usually two).

Secondary Curves: Quality, tc , ∆tSt (Stoneley Slowness)

UpperElectronics

LowerElectronics

Transmitter 1Transmitter 2

Receiver 1

Receiver 2

Receiver 3Receiver 4Receiver 5Receiver 6

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13

Figure 1.7

TOOL: Hostile Full Wave Sonic (HFWS-A), Long-Spaced Operation

GENERIC TYPE: Sonic Real-Time Slowness

GROUP: Sonic

MEASUREMENTPrinciple: Total sonic travel time

Depth of Investigation (50%): ~ 1 ft

Vertical Resolution (90%): ~ 0.5 ft

Sensitivity: na

Secondary Curves: Quality, tc , (MSG® or XY display)

Accuracy: ± 1.0 µs

Primary Curves: ∆tc (Compressional Slowness)

CALIBRATIONPrimary: Internal quartz clock

Wellsite Verifier: Casing for 57-µs slowness check

Secondary: None

Range: 40 to 190 µs/ft


Max OD: 2.75 in

Length*: 30.22 ft


Max Hole: 12 in

Min Hole: 3.5 in

Weight: 340 lb




*Add 3.5 ft for each in-line centralizer (usually two).

HARDWARE CHARACTERISTICSSource Type: Two 17-kHz piezoelectric

Sensor Spacings: 3, 5 ft (both inactive); 8, 8.5, 9, 9.5 ft (all active)


Firing Rate: 2.5/s for each source (400-ms firing cycle, with Source 1 firing at 0 ms and Source 2 at 100 ms)

Samples per Sensor: 1,024 (1,000 samples for MSG® service)

Measurement Bandwidth: 5 to 30 kHz


Combinability: HDSN, HNGR, HSDL, HECT, HDIL

UpperElectronics

LowerElectronics


Receiver 1

Receiver 2


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Figure 1.8

TOOL: Hostile Spectral Density (HSDL-A), With In-Line Pad

GENERIC TYPE: Gamma-Gamma Spectral Density

GROUP: Induced Radioactivity


Max OD: 2.75 in

Length: 13 ft


Max Hole: 12 in

Min Hole: 3.5 in

Weight: 176 lb




HARDWARE CHARACTERISTICSSource Type: 1.5-Ci Cesium-137

Sensor Spacings: Proprietary

Sensor Type: Two Nal(TI) scintillometers



Combinability: HNGR, HDIL, HDSN, HFWS, HECT, HPDC

MEASUREMENT

Principle

Depth ofInvestigation (50%)

VerticalResolution (90%)

Precision (1 SD)

Primary Curves: RHOB, DRHOP, DRHOM, Pec

Secondary Curves: GR, Caliper, Window 1-8 counts

CALIBRATIONPrimary: Halliburton calibration blocks of known mineralogy and density

Wellsite Verifier: Passive verifier

Secondary: Aluminum and magnesium blocks

No. of Windows: 8

Range

Gamma backscatter

Pe

(High Resolution)PeBulk Density

(Medium)

33 in (standard)5.5 in (enhanced)

0 - 50 - 51.0 - 3.1 gm/cc

0.330.100.45%

0.5 in0.5 in1.5 in

2 in4 in

In-Line PadAssembly

InstrumentSection

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Figure 1.9

TOOL: Hostile Spectral Density (HSDL-A), With Extendable Pad

GENERIC TYPE: Gamma-Gamma Spectral Density



Max OD: 3.50 in

Length: 23.8 ft


Max Hole: 12 in

Min Hole: 4.5 in

Weight: 456 lb




HARDWARE CHARACTERISTICSSource Type: 1.5-Ci Cesium-137


Sensor Type: Two Nal(TI) scintillometers



Combinability: HNGR, HDIL, HDSN, HFWS, HECT

MEASUREMENT

Principle



Precision (1 SD)

Primary Curves: RHOB, DRHOP, DRHOM, Pec

Secondary Curves: GR, Caliper, Window 1-8 counts

CALIBRATIONPrimary: Halliburton calibration blocks of known mineralogy and density

Wellsite Verifier: Passive verifier

Secondary: Aluminum and magnesium blocks

No. of Windows: 8

Range

Gamma backscatter

Pe

(High Resolution)PeBulk Density

(Medium)

33 in (standard)5.5 in (enhanced)

0 - 50 - 51.0 - 3.1 gm/cc

0.330.100.45%

0.5 in0.5 in1.5 in

2 in4 in

PadAssembly

InstrumentSection

MandrelAssembly

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Figure 1.10

TOOL: Hostile Dual Spaced Neutron (HDSN-A)

GENERIC TYPE: Neutron—Thermal Neutron



Max OD: 2.75 in

Length*: 15.3 ft


Max Hole**: 12 in

Min Hole**: 3.5 in

Weight*: 179 lb

*The length and weight include the HGNI instrument section, which is required torun the HDSN. Add 7.04 ft when run with the in-line, bowspring decentralizer.

**In cased holes, the Min Csg/Tbg ID is 3.25 inches and the Max Csg/Tbg ID is 12 inches.




HARDWARE CHARACTERISTICSSource Type: 19-Ci Americium-Beryllium


Sensor Type: Two He-3 Proportional Counters



Full Spectrum: na

Combinability: HNGR, HDIL, HSDL, HFWS, HECT

MEASUREMENTPrinciple: Neutron—Thermal Neutron

Depth of Investigation (50%): 6 in

Vertical Resolution (90%): 36 in (standard), 10 in (enhanced)

Precision, Low (1 SD): 3 ± 0.1 p.u.

Primary Curves: Neutron Limestone Porosity,Near-to-Far Detector Count-Rate Ratio

Precision, High (1 SD): 30 ± 0.6 p.u.

CALIBRATIONPrimary: API pits in Houston

Wellsite Verifier: Dual-Cavity block

Secondary: Vertical water bath or horizontal water tank

No. of Windows: 1

Range: 2 - 100 p.u.

Secondary Curves: Near- and Far-Detector Count Rates

HGNIInstrumentSection

Far-SpaceDetector

HDSNInstrumentSection

Near-SpaceDetector

NeutronSource

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Figure 1.11

TOOL: Hostile Natural Gamma Ray (HNGR-A)

GENERIC TYPE: Gamma Ray

GROUP: Natural Gamma Radioactivity


Max OD: 2.75 in

Length*: 11.55 ft


Max Hole**: 24 in

Min Hole**: 3.5 in

Weight*: 146 lb

*The length and weight include the HGNI instrument section, which is required torun the HNGR.

**In cased holes, the Min Csg/Tbg ID is 3.25 inches and the Max Csg/Tbg ID is 24 inches.





Sensor Spacings: na

Sensor Type: Nal(TI) scintillator



Full Spectrum: 60 keV - 3 MeV

Combinability: HDIL, HSDL, HDSN, HFWS, HECT

MEASUREMENTPrinciple: Natural Gamma

Depth of Investigation (50%): 4 in (90%: 11 in)

Vertical Resolution (90%): 18 - 36 in (standard), 12 in (enhanced)

Precision (1 SD): ± 4

Primary Curves: GR

Accuracy: 5 API


Wellsite Verifier: Thorium verifier

Secondary: Thorium verifier

No. of Windows: 1

Range: 0 - 1,000 API

HNGRInstrumentSection

HGNIInstrumentSection

Secondary Curves:

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Figure 1.12

TOOL: Hostile Environment Dipmeter Tool (HEDT-A)

GENERIC TYPE: Dipmeter

GROUP: Dipmeter

InstrumentSection

MandrelAssembly

DIMENSIONS AND RATINGSMax Temp: 450 °F

Max OD*: 5 in

Length**: 20.9 ft


Max Hole: 20 in

Min Hole: 6 in

Weight**: 470 lb

*The maximum OD is 5.25 inches when adapted for use in oil-based muds.**The length and weight are for the HEDT-A only. The HEDT-A must be run with

the HDTU (telemetry) and HGRT (gamma). The total length for the HEDT-A,HDTU, and HGRT string is 41.56 feet.




HARDWARE CHARACTERISTICSSource Type: 400 Hz

Sensor Spacings: Coplanar

Sensor Type (Water-Based Mud): Four pad-mounted current electrodes(Oil-Based Mud): Eight pad-mounted current electrodes (two per pad)


Sampling Rate: 120 Samples per ft, per pad

No. of Windows: na

Combinability: HDTU, HGRT

Sampling Size: 0.1 in

MEASUREMENT

Range

Principle


Accuracy


Sensitivity

CALIBRATIONPrimary: Navigation - vendor specification

Wellsite Verifier: Pad test - manual rotation

Secondary: Navigation - orientation test stand

Primary Curves: PDD 1-4, AZI, HAZI, DEV, ROT

*Water-based mud: Hot body conductivity; Oil-based mud: Micronormal

*

nanana

FormationDependent

0 - 360°

DeviationAzimuthResistivity

Navigation

0.2 - 5,000 ohm·m

Rotation

0 - 360°0 - 360°

0.25 in

nanana

0.1°0.1°0.1°na

± 2°± 2°± 2°na

Secondary Curves: Dip Angle, Dip AZI, Borehole Inclination, CAL 1and 3, CAL 2 and 4

Full Spectrum: na

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Figure 1.13

TOOL: Circumferential Acoustic Scanning Tool (CAST-A), DITS Version

GENERIC TYPE: Borehole Televiewer

GROUP: Sonic Imaging

ToolElectronics

ScannerAssembly

DIMENSIONS AND RATINGSMax Temp: 375°F

Max OD: 3.625 in

Length**: 12.68 ft


Max Hole*: 17 in

Min Hole*: 4.5 in

Weight: 251 lb

Commonly run with two slip-on centralizers*In cased holes, the Min Csg/Tbg ID is 4.25 inches and the Max Csg/Tbg ID

is 17 inches.**Length does not include scanning head. Add 3.8 inches for the

3.62-inch-diameter head, 3.75 inches for the 4.37-inch-diameter head,and 4.8 inches for the 6- and 8-inch-diameter heads.




HARDWARE CHARACTERISTICSSource Type: 380-kHz piezoelectric on rotating head

Firing Rate (shot/s): Circumferential Sampling Rate times Motor Speed*

Sensor Type: Source also serves as sensor

Circumferential Firing Rate: 200, 300, 400, or 500 shots per single rotation of the head

Combinability: DITS-combinable (requires 306 words per frame)

*Operator-controlled motor speed

Vertical Sampling Rate: 40, 60, 90, or 120 rotations per foot

MEASUREMENT

Range: 16 gray shades

Principle: Ultrasonic pulse echo and time of flight

Vertical Resolution (90%): ~0.25 in

Accuracy: ± 5%

Depth of Investigation (50%): Borehole surface

Sensitivity: 1 mv, 0.1 µs

CALIBRATIONPrimary: Uncalibrated

Wellsite Verifier: na

Secondary: na

Secondary Curves: Azimuth

Sensor Spacings: na

Primary Curves: Average Reflected Amplitude,Average Time of Flight, Acoustic Image

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20

21

conditions were challenging: well depthwas in excess of 16,000 ft, temperaturewas above 430˚F, and mud weight wasmore than 18 lb/gal. Because the mudwas oil based, no shallow resistivitymeasurement was made over the intervalshown, which was composed primarilyof sand and shale. The density, densitycorrection, and Pe curves were generatedfrom raw density data with the algorithmsdeveloped especially for the HEATdensity tool. In the interval from aboutXY527 to about XY590, the low gamma,high resistivities, and moderate porositiesindicate potential hydrocarbons. Thispotential was confirmed by analysis ofthe data with a standard Halliburtonprogram, the results of which are shownin Figure 2.3. Fluid analysis was limitedto oil and water saturation because ofthe absence of a shallow resistivitymeasurement.

SONIC LOG AND IWCANALYSISHFWS tools can provide high-qualitydata for advanced acoustic evaluation.The data can be processed to yieldInstantaneous Waveform Characteristics(IWC) logs. IWC logs allow the user tobetter evaluate changes in the complexacoustic signal caused by the absorptionor dispersion effects of geologicaldiscontinuities such as fractures andfaults, as well as thin beds. To assist inthis evaluation, IWC processing yieldsseparate transmissivity, phase, andfrequency displays of the acoustic datafrom the HFWS tool. A special color-coding scheme helps identify formationeffects on HFWS acoustic signals.

Section 2HEAT SuiteLogExamplesT

he examples that followillustrate the validity ofHEAT logs and some of thebasic applications of those

logs in formation evaluation.

COMPARISON OF HEATAND STANDARD LOGSFigure 2.1 compares gamma-ray andinduction curves from HEAT andconventional logs and shows that theresponses of HEAT tools are nearlyidentical to the responses of theirstandard-sized counterparts. The HEATcurves (red) have been depth-shifted by2 ft to better differentiate them from theconventional curves (blue). The HDILand DIL induction curves represent rawdata (that is, no borehole or bed correc-tions have been applied) and exhibit ahigh degree of correlation in each pair(medium-resistivity pair and deep-resistivity pair). It should be noted thatthe scale used for recording calipermeasurements ranges from 6 to 26inches. Even where the borehole iswashed out up to almost 13 inches, thereis excellent agreement between the HDILand DIL curves. The two gamma-raycurves may exhibit slightly more diver-gence from one another than do theresistivity curves because of the statisticalnature of gamma-ray measurements.

TRIPLE-COMBO LOG ANDANALYSISFigure 2.2 is part of a triple-combo logproduced with HEAT induction,density, and neutron tools. Logging

22

Instantaneous TransmissivityThe instantaneous magnitude of amplitude, defined asthe envelope of a complex acoustic response to a forma-tion, is the portion of the signal emitted by the HFWStool that is transmitted through a short section of theformation to reach the receiver. Different colors areassigned to different decibel ranges, with the color codingbeing referenced to the maximum value of transmissivityfound in the section being processed.

Instantaneous PhaseThe instantaneous phase emphasizes the continuity ofacoustic events through the formation. The phase displaycan reveal formation boundaries and their apparent dips,geological discontinuities such as faults and fractures, andbroken or hydrofractured formations. These featuresappear on the display as oblique events, phase-line splits,and irregular patterns.

The phase angles at 180˚ and -180˚ are assigned the samecolor, and to emphasize the continuity of events, the anglesbetween these two values are assigned colors of the availablespectrum. The light colors assigned to the phase anglesaround 0˚ form the background on which the phase anglesnear 180˚ appear as black lines.

Instantaneous FrequencyThe instantaneous frequency is sensitive to formationabsorption and dispersion effects, to scattering caused bystructural irregularities, and to transitional acousticimpedance changes. This frequency characteristic is aneffective indicator of fractured zones. The frequency iscolor-coded in equal steps over the available colors. Bluecolors are used for the low frequencies, and red hues forthe high frequencies.

Data and Analysis ExamplesThe HFWS log contained in Figure 2.4 was run for fracturedetection in a 4-1/2-inch hole down to a depth of morethan 20,000 ft. Some of the log curves cease at XY737,which is casing bottom. The interval shown is a low-porosity dolomitic limestone that produced hydrocarbonsfrom fractures higher in the structure. The full waveformdisplay shows the true relative amplitude of the acousticwaves.

Data from Figure 2.17 were processed to yield the IWClog of Figure 2.5 . On all three displays, casing arrivals areindicated by the high frequencies at the beginning of thewaveforms. On the transmissivity display, the high energiesof the waveforms in the Stoneley region are indicated bythe two reddish bands that extend vertically over the open-hole section. Because of the denseness of the formation,compressional arrivals are very weak and can hardly berecognized on the transmissivity display but are somewhatrecognizable on the phase display. On the phase display,fractures would be indicated by the attenuation of theshear and Stoneley waves and by phase shifts; however,no such characteristics are present on the log. This wellproved to be unproductive and was abandoned.


23

SECTION 2: HEAT SUITE LOG EXAMPLES

Comparison of HEAT and Standard Logs

Figure 2.1

Note: The HEAT curves (red) have been depth-shifted by 2 ft to better differentiate them fromthe conventional curves (blue).

24


HEAT Triple-Combo Log

Figure 2.2

25


Analysis of HEAT Triple-Combo Log

Figure 2.3

26


HEAT Full Wave Sonic Log

Figure 2.4

27


Instantaneous Waveform Characteristics LogGenerated From HEAT Full Wave Sonic Data

Figure 2.5


28

29

Section 3EnvironmentalEffects onHEAT SuiteResponses

Designing small-diameter,hostile environment toolsis a particularly formidabletask because such tools

require critical components such as coils,detectors, and acoustic transducers thatnot only must be smaller than theirstandard-sized counterparts, but mustalso operate effectively under higher andbroader temperature and pressure ranges.Halliburton has met these challengesand with the HEAT Suite can obtainhighly accurate logs under the some ofthe most adverse downhole conditionspossible. The logs give reliable data forcomprehensive formation evaluationand can be easily correlated with logsrun with standard-sized tools.

HEAT Suite logs require the same typeof corrections as logs from standard-sizedtools. Before detailed analysis, log datashould be corrected for environmentaleffects on tool response. The followingcharts (Figures 3.1 to 3.28) are used tomake corrections for borehole effects,invasion, lithology, bed thickness, andother factors. Examples are presented thatexplain how to use each type of chart.As with logs from standard-sized tools,particular attention should be paid tomaking borehole corrections whenborehole diameter is much larger thanlogging-tool diameter. (In small-diameter wells, borehole-fluid effectsare minimal because the annular spacebetween the tool and the borehole wallis small.) The continuous standoffmeasurement made by the PoweredDecentralizer greatly aids in makingsome of these corrections, especially toneutron porosity.


30

Chart: Figure 3.1 (Hostile Dual Induction (HDIL) Borehole Correction: Short Normal)

Applications: Correction of Short Normal resistivity for borehole effects

Nomenclature: RSN ........................Short Normal resistivityRDFLcor

....................Short Normal resistivity corrected for borehole effectsRm .........................mud resistivity at formation temperaturedh ..........................borehole diameter

Given: RSN = 31 ohm·mRm = 0.91 ohm·mdh = 11 inStandoff = 0.0 in

Find: RSNcor

Procedure: Since the standoff is 0.0 in, use the center chart. To determine the point on the RSN––––Rm

axis at which toenter the chart, calculate

RSN––––Rm

= 31 ohm·m

= 34.07

Project vertically into the chart and use the dh = 10 in and dh = 12 in curves to estimate where theprojection would intersect a dh = 11 in curve. From that intersection point, project horizontally to

the RSNcor axis and there estimate

RSNcor to be 1.38. Calculate

RSNcor=

RSNcor ·RSN = 1.38·31 ohm·m = 42.78 ohm·m

Answer: RSNcor= 42.78 ohm·m

– – – – – – – – – – – – – – – –0.91 ohm·m

– – – – – – –RSN

– – – – – – –RSN

– – – – – – –RSN

31

dh

dh

dh

0.0 in (0.0 mm) Standoff

Tool is Centered

1.5 in (38 mm) Standoff

3.0

2.0

1.0

3.0

2.0

1.0

1 10 100 1,000RSN /Rm

3.0

2.0

1.0

1 10 100 1,000RSN/Rm

1 10 100 1,000RSN/Rm

SECTION 3: ENVIRONMENTAL EFFECTS ON HEAT SUITE RESPONSES

Hostile Dual Induction – Short Normal (HDIL)Short Normal Borehole Correction

Figure 3.1


32

Chart: Figure 3.2 (Hostile Dual Induction Borehole Corrections:Deep and Medium Induction)

Applications: Correction of Hostile Dual Induction deep and medium resistivities for borehole effects

Nomenclature: RHID .......................Hostile Dual Induction deep resistivity RHIDcor

....................Hostile Dual Induction deep resistivity corrected for borehole effectsRm .........................mud resistivity at formation temperatureGh-HID ....................Hostile Dual Induction deep resistivity borehole geometrical factorsh-HID .....................Hostile Dual Induction deep conductivity borehole signaldh ..........................borehole diameter

Given: RHID = 13 ohm·mRm = 0.25 ohm·mdh = 11 inStandoff = 1.5 in

Find: RHIDcor

Procedure: Enter the chart at 11.0 in on the Borehole Diameter axis. Project vertically to the 1.5-in DeepInduction Standoff curve, then horizontally to the Borehole Geometrical Factor axis. There, estimateGh-HID to be 0.0001.

To calculate sh-HID, use

sh-HID = Gh × 1000

sh-HID = 0.0001 × 1000

= 0.40

Then to calculate RHIDcor, use

RHIDcor=

1000 (1−Gh-HID)

RHIDcor=

1000 (1−0.0001)= 13.07 ohm·m

Answer: RHIDcor= 13.07 ohm·m

Notes: After determining Gh - H I D from the chart, you can calculate RH I Dc o rdirectly from the following

equation:

RHIDcor=

Rm·RHID (1−Gh-HID)

With this equation, it is not necessary to determine sh-HID from the chart.

You can correct the Hostile Dual Induction medium resistivity with procedures and equationsanalogous to those used above for the deep resistivity.

– – – – – – – – – – – – – –Rm

– – – – – – – – — — – – – – — – –1000 − sh-HID

– – – – – –RHID

– – – – – – – – – — — – – – – –0.25

– – – – – – – – — — – – — — – — — — — — — — – – — – –1000 − 0.40 mmho/m– – – — — — – – – –

13 ohm·m

– – – – – – – – — — — — – – — – –Rm−RHID·Gh-HID

33

Gh, Borehole Geometrical Factor

Gh, Borehole Geometrical Factor


Hostile Dual Induction – Short Normal (HDIL)Deep and Medium Induction

Figure 3.2


34

Chart: Figure 3.3 (Hostile Dual Induction (HDIL) Bed Thickness Corrections:Deep and Medium)

Applications: Correction of Hostile Dual Induction deep and medium resistivities for bed thickness

Nomenclature: RHID .......................Hostile Dual Induction deep resistivityRHIDcor

....................Hostile Dual Induction deep resistivity corrected for shoulder bed effectsRS ..........................shoulder bed resistivityh............................thickness of bed in which HID measurement to be corrected was made

Given: RHID = 10.25 ohm·m (corrected for borehole effects)RS = 1.2 ohm·m (from Hostile Dual Induction deep resistivity in shoulder bed)h = 13 ft

Find: RHIDcor

Procedure: Since RS = 1.2 ohm·m ≈ 1 ohm·m, use the upper left chart. Enter the chart at 13 ft on the BedThickness axis. Project vertically into the chart and use the RHID = 10 ohm·m and RHID = 15 ohm·mcurves to estimate where the projection would intersect a RHID = 10.25 ohm·m curve. From thatintersection point, project horizontally to the RHIDcor

axis, there estimating RHIDcorto be 21.5 ohm·m.

Answer: RHIDcor= 21.5 ohm·m

Notes: You can correct the Hostile Dual Induction medium resistivity with procedures analogous to thoseused above for the deep resistivity. Use the lower charts.

35

0 4 8 12 16 20 24 28h, Bed Thickness (ft)

HIM, Rs = 1 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

60

5040

30

20

15

10

8

6

4

2

1

0.5

0.3

0.2

RHID

60

5040

30

20

15

10

8

6

4

2

1

0.5

0.3

0.2

RHID

6050

40

30

20

15

108

6

4

2

1

0.5

0.3

0.2R HIM

708090100

60

50

40

30

20

15

108

6

4

2

1

0.5

0.3

0.2

R HIM

708090100




HIM, R s = 2 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8

HID, Rs = 1 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8

HID, R s = 2 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8


Hostile Dual Induction – Bed Thickness CorrectionsRs = 1 & 2 ohm·m Deep and Medium Induction

Figure 3.3

36

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

200

100

50

20

10

5

2

1.0

0.5

0.2

0.1

80

70

40

30

20

15

108

6

4

2

1

0.5

0.3

0.2

RHID

6050

40

30

20

15

108

6

4

2

1

0.5

0.3

0.2

RHID

6050

40

30

20

15

108

6

4

2

1

0.5

0.3

0.2RHIM

708090100

605040

30

20

15

108

6

4

2

1

0.5

0.3

0.2

RHIM

708090100

50

60708090 100


HID, Rs = 4 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8


HID, R s = 10 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8


HIM, Rs = 4 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8


HIM, R s = 10 ohm•mh, Bed Thickness (m)

0 1 2 3 4 5 6 7 8


Hostile Dual Induction – Bed Thickness CorrectionsRs = 4 & 10 ohm·m Deep and Medium Induction

Figure 3.4

37


Hostile Dual Induction – Short Normal Invasion CorrectionsRxo/Rm = 20

4-inch (102-mm) Borehole

Figure 3.5


38

Chart: Figure 3.6 (Hostile Dual Induction (HDIL) Invasion Corrections: Rxo/Rm = 100)

Applications: Determination of true formation resistivity, flushed zone resistivity, and diameter of invasion

Nomenclature: RHID .......................Hostile Dual Induction deep resistivityRHIM ......................Hostile Dual Induction medium resistivityRSN ........................Short Normal Log resistivityRt...........................true formation resistivityRxo.........................flushed zone resistivityRm .........................mud resistivity at formation temperaturedi ...........................diameter of invasiondh ..........................diameter of borehole

Given: RHID = 15 ohm·m (corrected for borehole effects and bed thickness)RHIM = 22 ohm·m (corrected for borehole effects and bed thickness)RSN = 105 ohm·m (corrected for borehole effects)Rxo = 139 ohm·m (from a very shallow resistivity device)Rm = 1.5 ohm·mdh = 4.0 in

Find: Rt , Rxo , and di

Procedure: To determine the appropriateness of using this chart, first note that dh = 4 in.

Then use the Rxo value from the very shallow resistivity device to calculate Rxo––––Rm

:

Rxo––––Rm

= 139 ohm·m

= 92.67 ≈ 100

Thus, it is appropriate to use this chart.

For use in the chart, calculate

—RR

HIM–——–HID

= 22 ohm·m

= 1.467 and —RR

SN–——–HID

= 105 ohm·m

= 7

Starting at 1.467 on the —RR

HIM–——–HID

axis, project vertically into the chart. Starting at 7 on the —RR

SN–——–HID

axis,

project horizontally into the chart. Note the point of intersection of the two projections.

Use the intersection point to interpolate between the —R

Rt–——HID

= 0.9 and —R

Rt–——HID

= 0.95 curves (solid,

vertically oriented curves) and estimate —R

Rt–——HID

to be 0.925. Calculate

Rt = —R

Rt–——HID

· RHID = 0.925 · 15 ohm·m = 13.88 ohm·m

Use the intersection point again to interpolate between the Rxo–––––Rt

= 10 and Rxo–––––Rt

= 15 curves (solid,

horizontally oriented curves) and estimate Rxo–––––Rt

to be 11.5. Calculate

Rxo = Rxo–––––Rt

· Rt = 11.5 · 13.88 ohm·m = 159.62 ohm·m

Use the intersection point once more, this time to interpolate between the di = 40 in and di = 50 incurves (dashed, vertically oriented curves) and estimate di to be 45 in.

Answer: Rt = 13.88 ohm·m, Rxo = 159.62 ohm·m, and di = 45 in.

– – – – – – – – – – – – – –1.5 ohm·m

– – – – – – – – – – – – – –1.5 ohm·m

– – – – – – – – – – – – – –1.5 ohm·m

39

di

1.5

2

3

5

7

15

20

25

30

Rxo/Rt

10

Rt/RHID

1.0

.98.95 .9

.7

.8

.6

Thick BedsSkin Effect CorrectedNo Transition ZoneNo AnnulusBorehole Effect Corrected

.9 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6RHIM /RHID

30

10

9

8

7

6

5

4

3

2

1

20




Figure 3.6

40

di

Rxo/Rt

1.5

2

3

5

7

10

15

20

25

30

Rt /RHID

1.0

.98.95 .9

.8.7

.6

.9 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6RHIM/RHID

20

10

9

8

7

6

5

4

3

2

1





Figure 3.7

41

di

1.5

2

3

5

7

15

20

25

30

Rxo /Rt

10

Rt/RHID

1.0.98

.95 .9.7

.8

.6

.9 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6RHIM /RHID

30

10

9

8

7

6

5

4

3

2

1

20




Figure 3.8

42




Figure 3.9

43

di

Rxo/Rt

1.5

2

3

5

7

10

15

20

25

30

Rt/RHID

1.0

.98

.95.9

.8.7

.6

.9 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.5RHIM/RHID

20

10

9

8

7

6

5

4

3

2

1





Figure 3.10


44

Chart: Figure 3.11 Density - Borehole Curvature Corrections: Hostile Spectral Density Log (HSDL)

Applications: Correction of Hostile Spectral Density bulk density for borehole curvature

Nomenclature: ρm..........................mud weightdh ..........................borehole diameterρLOG.......................formation bulk density read from logρb ..........................formation bulk density

Given: ρm = 14 lb/galdh = 4.75 inρLOG = 2.6 g/cc

Find: ρb

Procedure: Since ρm = 14 lb/gal, use the middle chart on the right. Enter the chart at 4.75 inches on the BoreholeDiameter axis. Project vertically to the ρL O G = 2.6 g/cc curve, then horizontally to HSDL Correction axis.From that axis, estimate the needed correction to be about 0.002 g/cc. Calculate

ρb = ρLOG + HSDL Correction = 2.6 g/cc + 0.002 g/cc = 2.602 g/cc

Answer: ρb = 2.602 g/cc

45

* Not valid for hematite weighted fluid

ρLOG(g/cc)

3.0

2.6

2.2

1.8

0.02

0.01

0.00

-0.014 6 8 10 12 14 16 18 20

dh, Borehole Diameter (in)

dh, Borehole Diameter (mm)100 150 200 250 300 350 400 450 500

ρm = 8.35 lb/gal (1000 kg/m3)fresh water

ρLOG(g/cc)

3.0

2.6

2.2

1.8

0.02

0.01

0.00

-0.01

ρm = 10 lb/gal (1198 kg/m3)

ρLOG(g/cc)

3.0

2.6

2.2

1.8

ρLOG(g/cc)

3.0

2.6

2.2

1.8

ρLOG(g/cc)

3.0

2.6

2.2

1.8

ρLOG(g/cc)

3.0

2.6

2.2

1.8

0.02

0.01

0.00

-0.01

ρm = 12 lb/gal* (1438 kg/m3)

0.02

0.01

0.00

-0.01

ρm = 16 lb/gal* (1917 kg/m3)

0.02

0.01

0.00

-0.01

ρm = 14 lb/gal* (1678 kg/m3)

0.02

0.01

0.00

-0.01

ρm = 18 lb/gal* (2157 kg/m3)

4 6 8 10 12 14 16 18 20dh, Borehole Diameter (in)











Density – Borehole Curvature CorrectionsHostile Spectral Density Log

HSDL

Figure 3.11


46

Chart: Figure 3.12 (Openhole Environmental Corrections: HDSN)Figure 3.13 (Tool Standoff and Formation Salinity Environmental Corrections:HDSN)

Applications: Correction of HDSN porosity for borehole, standoff, and formation salinity effects

Nomenclature: φNLS .......................formation porosity from neutron measurement with limestone matrix assumptionφNLS* ......................φNLS corrected for borehole and standoff effectsφNLScor

....................φNLS corrected for borehole, standoff, and formation salinity effectsφNQ ........................formation porosity from neutron measurement with quartz matrix assumption,

and corrected for borehole and standoff effectsφNQcor

.....................φNQ corrected for borehole, standoff, and formation salinity effectsΣma ........................formation matrix thermal neutron capture cross sectiondh ..........................borehole diameterhmc ........................mudcake thicknessCh ..........................borehole fluid salinityρm..........................mud densityTh ..........................borehole temperaturePh ..........................borehole pressuretso ..........................tool standoffCfm ........................formation fluid salinity in zone of investigation∆φx.........................porosity correction for factor x, where x may be dh (borehole diameter),

hmc (mudcake thickness), Ch (borehole fluid salinity), ρm (mud density), Th (borehole temperature), Ph (borehole pressure), tso (tool standoff), or Cfm (formation fluid salinity in zone of investigation)

Given: Neutron log was run in open hole and was not caliper-corrected.Mineralogy is quartz.Σma = 4.6 c.u.φNLS = 32%dh = 10.5 inhmc = 0.5 inCh = 100 kppm NaClρm = 10 lb/gal (natural mud)Th = 125oFPh = 2,500 psitso = 0.5 inCfm = 150 kppm NaCl

Find: φNLScor

Procedure: On Chart Figure 3.12 construct a vertical line segment connecting the 32% porosity point at the topand the bottom of the Open Hole Borehole Diameter block.

On the Open Hole Borehole Diameter block, estimate the location of the 10.5-in Borehole Diameterline. From the intersection of this line with the previously constructed vertical segment, follow thetrend of the adjacent curves to the 8-in reference line. From there, project to the bottom of theblock. Using the distance between the projection and the vertical segment, estimate ∆φdh

to be-3.0%.

Construct a vertical line segment connecting the borehole-diameter-corrected porosity point of 29%at the top of the Mudcake Thickness block and the 29% porosity point at the bottom of the BoreholePressure block.

Following procedures analogous to those used in finding the borehole diameter correction, use theremaining five blocks in Chart Figure 3.12 to estimate ∆φhmc

= -0.5%, ∆φCh= 0.80%, ∆φρm

= 0.6%,∆φTh

= 1.5%, and ∆φPh= -0.3%.

47

Neutron Log Porosity (%) (Apparent Limestone)0 10 20 30 40 50

2016

1285

0 10 20 30 40 50

0 10 20 30 40 50

Enter Here If Caliper Correction Has Been Applied

1.0

0.5

0.0

250200150100

500

14

12

10

8

16141210

8

400

300200

100

201510

50

0 10 20 30 40 50Neutron Log Porosity (%) (Apparent Limestone)

508406305203127

25.0

12.5

0.0

250200150100500

1.61.4

1.21.0

1.81.61.41.21.0

10

138

20015010050

1209060300


Openhole Environmental CorrectionsHostile Dual Spaced Neutron

HDSN

Figure 3.12


48

Proceed to Chart Figure 3.13. On the dh = 10.5-in Open Hole Borehole Standoff block, construct avertical line segment connecting the 29% porosity points at the top and bottom of the block. Fromthe intersection of the 0.5-in Open Hole Borehole Standoff line with the previously constructedvertical segment, follow the trend of the adjacent curves until reaching a point at the bottom of theblock. From the distance between this point and the vertical segment, estimate ∆φtso

to be -3.0%.

To calculate φNLS , use

φNLS = φNLS + ∆φdh+ ∆φhmc

+ ∆φCh+ ∆φρm

+ ∆φTh+ ∆φPh

+ ∆φtso

Thus, φNLS* = 32% + (-3.0%) + (-0.5%) + (0.80%) + (0.6%) + (1.5%) + (-0.3%) + (-3.0%) = 28.1%.

Before correcting for formationsalinity, you must convert φN L S * t oequivalent neutron quartz porosity,i.e., φNQ. To do this, enter Figure 3.16at 28.1% on the Neutron LimestonePorosity axis, project vertically untilintersecting the Σma = 4.6 c.u. Quartzcurve, then horizontally to thePorosity axis. There, estimate φN Q to be35.2%.

To correct for formation salinity,return to Figure 3.13. On the QuartzFormation Salinity Block, construct avertical line segment connecting the35.2% porosity points at the top andbottom of the b lock. From theintersection of the 150-kppm line withthis vertical segment, follow the trendof the curves down to a point at thebottom of the block. Using the distancebetween the point and the verticalsegment, estimate ∆φCfm

to be -1.0%.

To calculate φNQcor, use

φNQcor= φNQ + ∆φCfm

Thus, φNQcor= 35.2% + (-1.0%) = 34.2%.

You obtain φNLScorby converting φNQcor

to equivalent neutron limestone porosity. To do this, return toFigure 3.16. Enter the chart at 34.2% on the Porosity axis, project horizontally to the Σm a= 4.6 c.u. c u r v e ,then vertically down to the Neutron Limestone Porosity axis. There estimate φNLScor

to be 27.2%.

Answer: φNLScor= 27.2%.

45

40

35

30

25

20

15

10

5

0

-5-5 0 5 10 15 20 25 30 35 40 45

φ NLS, Neutron Limestone Porosity (%)

49

Openhole Standoff Correction ChartsNeutron Log Porosity (%) (Apparent Limestone)

0 10 20 30 40 50


Formation Salinity Correction ChartsNeutron Log Porosity (%) (Appropriate Matrix)

0 10 20 30 40 50

0 10 20 30 40 50Neutron Log Porosity (%) (Appropriate Matrix)

1.5

1.0

0.5

0.0

36

24

12

0

dh = 10.5 in

dh = 8.0 in

dh = 6.5 in

dh = 4.5 in

1.5

1.0

0.5

0.0

2.52.01.51.00.50.0

3.0

2.0

1.0

0.0

dh = 114 mm

36

24

12

0

dh = 165 mm

dh = 203 mm

dh = 267 mm

6050403020100

80

60

40

20

0

250200150100500250200150100500250200150100500

250200150100500

Calcite

250200150100500

250200150100500

Quartz

Dolomite


Tool Standoff and Formation Salinity Environmental CorrectionsHostile Dual Spaced Neutron

Figure 3.13


50

Chart: Figure 3.14 (Cased Hole Environmental Corrections: HDSN)Figure 3.15 (Tool Standoff and Formation Salinity Environmental

Corrections: HDSN)

Applications: Correction of HDSN porosity for borehole effects

Nomenclature: φNLS .......................formation porosity from neutron measurement with limestone matrix assumptionφNLS* ......................φNLS corrected for borehole and standoff effectsφNLScor

....................φNLS corrected for borehole, standoff, and formation salinity effectsφNQ ........................formation porosity from neutron measurement with quartz matrix assumption

and corrected for borehole and standoff effectsφNQcor

.....................φNQ corrected for borehole, standoff, and formation salinity effectsΣma ........................formation matrix thermal neutron capture cross sectiondh ..........................borehole diameterhcsg ........................casing thicknesshcmt .......................cement thicknessCh ..........................borehole fluid salinityρm..........................mud densityTh ..........................borehole temperaturePh ..........................borehole pressuretso ..........................tool standoffCfm ........................formation fluid salinity in zone of investigation∆φx.........................porosity correction for factor x, where x may be dh (borehole diameter), hc s g

(casing thickness), hcmt (cement thickness), Ch (borehole fluid salinity), ρm (muddensity), Th (borehole temperature), Ph (borehole pressure), tso (tool standoff), orCfm (formation fluid salinity in zone of investigation)

Given: Neutron log was run in cased hole and was not corrected for borehole diameter, casing thickness, orcement thickness.Mineralogy is quartz.Σma = 4.6 c.u.φNLS = 24.5%dh = 10.5 in (open hole)hcsg = 0.4 inhcmt = 1 inCh = 150 kppm NaClρm = 10 lb/gal (natural mud)Th = 150°FPh = 2,500 psitso = 0.25 inCfm = 100 kppm NaCl

Find: φNLScor

Procedure: On Figure 3.14 construct a vertical line segment connecting the 24.5% porosity point at the top andthe bottom of the Borehole Diameter block.

On the Borehole Diameter block, estimate the location of the 10.5-in Borehole Diameter line. Fromthe intersection of this line with the previously constructed vertical segment, follow the trend of theadjacent curves to the 8-in reference line. From there, project to the bottom of the block. Using thedistance between the projection and the vertical segment, estimate ∆φdh

to be -2.5%.

Construct a vertical line segment connecting the borehole diameter corrected porosity point of 22%at the top of the Casing Thickness block and the 22% porosity point at the bottom of the BoreholePressure block.

Follow analogous procedures using the remaining six blocks in Chart Figure 3.14 to estimate∆φhcsg

= -0.75%, ∆φhcmt= 0.9%, ∆φch

= 1.0%, ∆φρm= 0.4%, ∆φTh

= 2.0%, ∆φPh= -0.2%.

51

Enter Here If Casing and Cement Thickness Corrections Have Been Applied In Real Time


250200150100

500

14

12

10

8

161412108

400

300

200100

201510

50


250200150100500

1.61.4

1.21.0

1.81.61.41.21.0

10

138

20015010050

1209060300



Enter Here If Borehole Diameter Correction Has Been Applied

201612

85

0.5

0.4

0.3

0.2

3.0

2.0

1.0

0.0

508406305203127

121086

75

50

25

0


Cased Hole Environmental CorrectionsHostile Dual Spaced Neutron

HDSN

Figure 3.14


52

To determine the tool standoff correction, proceed to Figure 3.15. On the dh = 10.5-in BoreholeStandoff block, construct a vertical line segment connecting the 22% porosity points at the top andbottom of the block. From the intersection of the 0.25-in Borehole Standoff line with the previouslyconstructed vertical segment, follow the trend of the adjacent curves until reaching a point at thebottom of the block. From the distance between this point and the vertical segment, estimate ∆φtsoto be -1.75%.

To calculate φNLS , use

φNLS = φNLS + ∆φdh+ ∆φhcsg

+ ∆φhcmt+ ∆φCh

+ ∆φρm+ ∆φTh

+ ∆φPh+ ∆φtso

Thus, φNLS=24.5%+(-2.5%)+(-0.75%)+(0.9%)+(1.0%)+(0.4%)+(2.0%)+(-0.2%)+(-1.75%)=23.6%.

Before correcting for formationsalinity, you must convert φN L S t oequivalent neutron quartz porosity,i.e., φNQ. To do this, enter Figure 3.16at 23.6% on the Neutron LimestonePorosity axis, project vertically untilintersecting the Σm a = 4.6 c.u. Quartzcurve, then horizontally to thePorosity axis. There, estimate φN Q to be30.4%.

To correct for formation salinity, useFigure 3.15. On the Quartz FormationSalinity Block, construct a vertical linesegment connecting the 30.4%porosity points at the top and bottomof the block. From the intersection ofthe 100-kppm line with this verticalsegment, follow the trend of thecurves down to a point at the bottomof the block. Using the distancebetween the point and the verticalsegment, estimate ∆φCfm

to be -1.0%.

To calculate φNQcor, use

φNQcor= φNQ + ∆φCfm

Thus, φNQcor= 30.4% + (-1.0%) = 29.4%.

You obtain φNLScorby converting φNQcor

to equivalent neutron limestone porosity. To do this, return toFigure 3.16. Enter the chart at 29.4% on the Porosity axis, project horizontally to the Σm a = 4.6 c.u. c u r v e ,then vertically down to the Neutron Limestone Porosity axis. There, estimate φNLScor

to be 22.7%

Answer: φNLScor= 22.7%.

45

40

35

30

25

20

15

10

5

0

-5-5 0 5 10 15 20 25 30 35 40 45

φ NLS, Neutron Limestone Porosity (%)

53

Cased Hole Standoff Correction ChartsNeutron Log Porosity (%) (Apparent Limestone)

0 10 20 30 40 50


Formation Salinity Correction ChartsNeutron Log Porosity (%) (Appropriate Matrix)

0 10 20 30 40 50

0 10 20 30 40 50Neutron Log Porosity (%) (Appropriate Matrix)

1.5

1.0

0.5

0.0

36

24

12

0

dh = 10.5 in

dh = 8.0 in

dh = 6.5 in

dh = 4.5 in

1.5

1.0

0.5

0.0

2.5

2.0

1.51.0

0.5

0.0

3.0

2.0

1.0

0.0

dh = 114 mm

36

24

12

0

dh = 165 mm

dh = 203 mm

dh = 267 mm

6050403020100

80

60

40

20

0

250200

15010050

0250200150

10050

0250

200150

100500

250200

150100

500

Calcite

250200

150100

500

250200

150100

500

Quartz

Dolomite


Tool Standoff and Formation Salinity Environmental CorrectionsHostile Dual Spaced Neutron

Figure 3.15


54

Chart: Figure 3.16 (Porosity Determination: Neutron Limestone Porosityversus Porosity (HDSN))

Applications: Determination of formation porosity from HDSN porosity measurement based on a limestone matrixand from knowledge of formation thermal neutron capture cross section

Nomenclature: φ ............................formation porosityφNLS .......................formation porosity from neutron measurement with limestone matrix assumption

(corrected for environmental effects)Σma ........................formation matrix thermal neutron capture cross section

Given: Lithology is sandstone.φNLS = 20% (from HDSN log)Σma = 10 c.u. (typical of common sandstones)

Find: φ

Procedure: Enter the chart on the Neutron Limestone Porosity axis at φN L S = 20%. Project vertically to theSANDSTONE curve labeled Σma = 10.0 c.u., then horizontally to the Porosity axis. There, estimate φ tobe 24.8%.

Answer: φ = 24.8%

55


Porosity DeterminationNeutron Limestone Porosity versus Porosity

HDSN

Figure 3.16


56

Chart: Figure 3.17 (Porosity-Mineralogy Crossplot: Bulk (Log) Densityversus Neutron Porosity (HDSN), Fluid Density = 0.85 g/cc)

Applications: Determination of porosity and mineralogy mix from density and neutron logs

Nomenclature: φNLS. . . . . . . . . . . . . . . . . . . . . . . .formation porosity from neutron measurement made assuming a limestone matrixρb ..........................formation bulk densityρf ...........................formation fluid density in zone of investigationΣQ..........................quartz matrix thermal neutron capture cross sectionΣC ..........................calcite matrix thermal neutron capture cross sectionΣD ..........................dolomite matrix thermal neutron capture cross sectionfDN.........................formation porosity from combined neutron and density data

Given: Borehole fluid is oil-based mud.φNLS = 17% (from HDSN log that has been environmently corrected)ρb = 2.34 g/cc (from density log corrected for borehole effects)ρf = 0.85 g/cc (Estimated. This is a reasonable value for pore fluids near the wellbore when oil-based

muds are used)ΣQ = 4.6 c.u.ΣC = 7.1 c.u.ΣD = 4.7 c.u.

Find: φDN and formation mineralogy mix

Procedure: From φN L S = 17% on the Neutron Limestone Porosity axis, project vertically into the chart. From ρb = 2.34g/cc on the Bulk Density axis, project horizontally into the chart. Note that the point of intersectionof the two projections (later called the plotted point) lies between the Quartz and Calcite curves onthe chart as well as between the Quartz and Dolomite curves. Thus, the constituent minerals can bequartz and calcite, or quartz and dolomite.

To determine the porosity and mineralogy mix if the constituent minerals are quartz and calcite,construct a line segment containing the plotted point and connecting points of equal porosity on theQuartz and Calcite curves. This line segment should connect the 19% porosity points on the twocurves, indicating that φDN = 19%. By using the plotted point to proportion the segment, you canestimate that the matrix contains about 35% quartz and 65% calcite, with calcite having the higherpercentage since the plotted point is closer to the Calcite curve.

To determine the porosity and mineralogy mix if the constituent minerals are quartz and dolomite,construct a line segment containing the plotted point and connecting points of equal porosity on theQuartz and Dolomite curves. This line segment should connect the 20% porosity points on the twocurves, indicating that φDN = 20%. By using the plotted point to proportion the segment, you canestimate that the matrix contains about 70% quartz and 30% dolomite, with quartz having thehigher percentage since the plotted point is closer to the Quartz curve.

Answer: If the constituent minerals are quartz and calcite, then φD N = 19% and the mineralogy mix isapproximately 35% quartz and 65% calcite. If the constituent minerals are quartz and dolomite,then φDN = 20% and the mineralogy mix is approximately 70% quartz and 30% dolomite.

Notes: As long as the rock matrix is composed of two of the three common minerals quartz, calcite, anddolomite, the crossplotted porosity is relatively insensitive to the mineralogy mix. To resolveambiguities regarding which minerals are present (e.g., quartz and calcite versus quartz anddolomite), you can use a Mineral Identification Plot.

Individual crossplots of two porosity logs define the mineralogy percentage mix for two knownminerals. Three minerals require three porosity logs. More minerals require more measurements.

57


Porosity – Mineralogy CrossplotBulk (Log) Density versus Neutron Porosity

HDSNFluid Density = 0.85 g/cc (850 kg/m3)

Figure 3.17

58




Figure 3.18

59




Figure 3.19


60

Chart: Figure 3.20 (Porosity-Mineralogy Crossplot: Bulk (Log) Density versus Sonic)

Applications: Determination of porosity and mineralogy mix from density and sonic logs

Nomenclature: ∆tc .........................sonic compressional interval transit time in formation∆tf. . . . . . . . . . . . . . . . . . . . . . . . . .sonic compressional interval transit time in formation fluid in zone of investigationρb ..........................formation bulk densityρf ...........................formation fluid density in zone of investigationφSD.........................formation porosity from combined sonic and density data

Given: Borehole fluid is oil-based mud.∆tc = 82 µs/ft∆tf = 245 µs/ft (Estimated. This is a reasonable value for pore fluids near the wellbore when oil-b a s e d

muds are used.)ρb = 2.22 g/cc (from density log corrected for borehole effects)ρf = 0.85 g/cc (Estimated. This is a reasonable value for pore fluids near the wellbore when oil-based

muds are used.)

Find: Empirical φSD and formation mineralogy mix

Procedure: From ∆tc = 82 µs/ft on the Interval Transit Time axis, project vertically into the chart. From ρb = 2.22g/cc on the Bulk Density axis, project horizontally into the chart. Note that the point of intersectionof the two projections (later called the plotted point) lies between the empirical Calcite and Quartzcurves as well as between the empirical Calcite and Dolomite curves. Thus, the constituent mineralscan be calcite and quartz, or calcite and dolomite.

To determine the porosity and mineralogy mix if the constituent minerals are calcite and quartz,construct a line segment containing the plotted point and connecting points of equal porosity on theempirical Calcite and Quartz curves. This line segment should connect the 26% porosity points onthe two curves, indicating that φS D = 26%. By using the plotted point to proportion the segment, youcan estimate that the matrix contains about 75% calcite and 25% quartz, with calcite having thehigher percentage since the plotted point is closer to the empirical Calcite curve.

To determine the porosity and mineralogy mix if the constituent minerals are calcite and dolomite,construct a line segment containing the plotted point and connecting points of equal porosity on theempirical Calcite and Dolomite curves. This line segment should connect the 27.6% porosity pointson the two curves, indicating that φS D = 27.6%. By using the plotted point to proportion thesegment, you can estimate that the matrix contains about 85% calcite and 15% dolomite, withcalcite having the higher percentage since the plotted point is closer to the empirical Calcite curve.

Answer: If the constituent minerals are calcite and quartz, then empirically φSD = 26.0% and the mineralogymix is approximately 75% calcite and 25% quartz. If the constituent minerals are calcite anddolomite, then empirically φSD = 27.6% and the mineralogy mix is approximately 85% calcite and15% dolomite.

Notes: As long as the rock matrix is composed of two of the three common minerals quartz, calcite, anddolomite, the crossplotted porosity is relatively insensitive to the mineralogy mix. To resolveambiguities regarding which minerals are present (e.g., calcite and quartz versus calcite anddolomite), you can use a Mineral Identification Plot.


Reference: Wyllie, M.R.J., “Elastic Wave Velocities in Heterogenous and Porous Media,” Geophysics, Vol. 21,1956, p. 41.

Krief, M., Garat, J., Stellingwerff, J., and Ventre, J.: “A Petrophysical Interpretation Using theVelocities of P and S Waves (Full-Waveform Sonic),” presented at the 12th International FormationEvaluation Symposium, Paris, France, Oct. 24-27, 1989, paper HH.

61

1.9

40 50 60 70 80 90 100 110 120∆tc, Interval Transit Time (µs/ft)

ρf = 0.85 g/cc (850 kg/m3)∆tf = 245 µs/ft (804 µs/m)

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Halite

Anhydrite

∆tc, Interval Transit Time (µs/m)150 200 250 300 350

Time AverageEmpirical


Porosity – Mineralogy CrossplotBulk (Log) Density versus Sonic

Oil-Based Fluid

Figure 3.20

62

1.9



2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Halite

Anhydrite





Fresh Water

Figure 3.21

63

1.9



2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Halite

Anhydrite





Salt Water

Figure 3.22


64

Chart: Figure 3.23 (Porosity-Mineralogy Crossplots:Sonic versus Neutron Porosity (HDSN))

Applications: Determination of porosity and mineralogy mix from sonic and neutron logs

Nomenclature: ∆tc .........................sonic compressional interval transit time in formation φNLScor∆tf. . . . . . . . . . . . . . . . . . . . . . . . . .sonic compressional interval transit time in formation fluid in zone of investigationφNLS .......................formation porosity from neutron measurement with limestone matrix assumptionφSN.........................formation porosity from combined sonic and neutron logs

Given: Borehole fluid is fresh mud.∆tc = 74 µs/ft∆tf = 189 µs/ft (Estimated. This is a reasonable value for pore fluids near the wellbore when fresh

muds are used.)φNLS = 21% (from HDSN log that has been environmentally corrected)

Find: Empirical φSN and formation mineralogy mix

Procedure: From φNLS = 21% on the Neutron Limestone Porosity axis, project vertically into the chart. From ∆tc=74 µs/ft on the Interval Transit Time axis, project horizontally into the chart. Note that the point ofintersection of the two projections (later called the plotted point) lies between the empirical Quartzand Calcite curves on the chart as well as between the empirical Quartz and Dolomite curves. Thus,the constituent minerals can be quartz and calcite, or quartz and dolomite.

To determine the porosity and mineralogy mix if the constituent minerals are quartz and calcite,construct a line segment containing the plotted point and connecting points of equal porosity on theempirical Quartz and Calcite curves. This line segment should connect the 22.8% porosity points onthe two curves, indicating that φSN = 22.8%. By using the plotted point to proportion the segment,you can estimate that the matrix contains about 30% quartz and 70% calcite, with calcite having thehigher percentage since the plotted point is closer to the empirical Calcite curve.

To determine the porosity and mineralogy mix if the constituent minerals are quartz and dolomite,construct a line segment containing the plotted point and connecting points of equal porosity on theempirical Quartz and Dolomite curves. This line segment should connect the 22.8% porosity pointson the two curves, indicating that φS N = 22.8%. By using the plotted point to proportion thesegment, you can estimate that the matrix contains about 55% quartz and 45% dolomite, withquartz having the higher percentage since the plotted point is closer to the empirical Quartz curve.

Answer: If the constituent minerals are quartz and calcite, then φS N = 22.8% and the mineralogy mix isapproximately 30% quartz and 70% calcite. If the constituent minerals are quartz and dolomite,then φSN = 22.8% and the mineralogy mix is approximately 55% quartz and 45% dolomite.

Notes: As long as the rock matrix is composed of two of the three common minerals quartz, calcite, anddolomite, the crossplotted porosity is relatively insensitive to the mineralogy mix. To resolveambiguities regarding which minerals are present (e.g., quartz and calcite versus quartz anddolomite), you can use a Mineral Identification Plot.




65

120

∆tf = 189 µs/ft (620 µs/m)

110

100

90

80

70

60

50

40-5 0 5 10 15 20 25 30 35 40 45

φNLS, Neutron Limestone Porosity (%)

380

360

340

320

300

280

260

240

220

200

180

160

140



Porosity – Mineralogy CrossplotSonic versus Neutron Porosity (HDSN)

Fresh Water

Figure 3.23


66

Chart: Figure 3.24 (Mineral Identification Plot - maaDetermination)

Applications: Determination of apparent formation matrix density

Nomenclature: ρb ..........................formation bulk densityρmaa

.......................apparent formation matrix densityφNLS .......................formation porosity from neutron measurement with limestone matrix assumption

Given: ρb = 2.34 g/cc (from density log corrected for borehole effects)φNLS = 17% (from HDSN log corrected for borehole effects)

Find: ρmaa

Procedure: From φNLS = 17% on the Neutron Limestone Porosity axis, project vertically into the chart. From ρb =2.34 g/cc on the Bulk Density axis, project horizontally into the chart. The point of intersection of thetwo projections lies between the ρmaa

= 2.66 g/cc and ρmaa= 2.68 g/cc curves. Use the intersection

point to interpolate between the two curves and estimate ρmaato be 2.675 g/cc.

Answer: ρmaa= 2.675 g/cc

Notes: You enter the value of ρmaathat you determine from this chart into Figure 3.27 or Figure 3.28.

67


Mineral Identification Plot

maaDetermination

HDSN

Figure 3.24


68

Chart: Figure 3.25 (Mineral Identification Plot - tmaaDetermination)

Applications: Determination of apparent sonic compressional interval transit time in formation matrix

Nomenclature: ∆tc .........................sonic compressional interval transit time in formation∆tf. . . . . . . . . . . . . . . . . . . . . . . . . .sonic compressional interval transit time in formation fluid in zone of investigation∆tmaa

.....................apparent sonic compressional interval transit time of formation matrixφNLS .......................formation porosity from neutron measurement with limestone matrix assumption

Given: Borehole fluid is fresh mud.∆tc = 74.0 µs/ft∆tf = 189 µs/ft (Estimated. This is a reasonable value for pore fluids near the wellbore when fresh

muds are used.)φNLS = 17% (from HDSN log corrected for borehole effects)

Find: ∆tmaa

Procedure: From φNLS = 17% on the Neutron Limestone Porosity axis, project vertically into the chart. From ∆tc=74.0 µs/ft on the Interval Transit Time axis, project horizontally into the chart. The point ofintersection of the two projections would lie approximately on a ∆tmaa

= 52.5 µs/ft curve if such acurve were displayed. Thus, estimate ∆tmaa

to be 52.5 µs/ft.

Answer: ∆tmaa= 52.5 µs/ft

Notes: You enter the value of ∆tmaathat you determine from this chart into Figure 3.27.



69

140

-5 0 5 15 15 20 25 30 35 40 45φNLS, Neutron Limestone Porosity (%)

∆tf = 189 µs/ft (620 µs/m)

130

120

110

100

90

80

70

60

50

40

∆tmaa

440

420

400

380

360

340

320

300

280

260

240

220

200

180

160

140


Mineral Identification Plottmaa

Determination

HDSN

Figure 3.25


70

Chart: Figure 3.26 (Mineral Identification Plot - UmaaDetermination)

Applications: Determination of apparent matrix volumetric photoelectric factor

Nomenclature: φNLS .......................formation porosity from neutron measurement with limestone matrix assumptionρb ..........................formation bulk densityρf ...........................formation fluid density in zone of investigationPem ........................modified photoelectric factorUm .........................volumetric modified photoelectric factorUmaa

......................apparent matrix volumetric photoelectric factorφta..........................apparent total formation porosity

Given: Borehole fluid is fresh mud.φNLS = 17% (from HDSN log corrected for borehole effects)ρb = 2.34 g/cc (from density log corrected for borehole effects)ρf = 1.00 (Estimated. This is a reasonable value for pore fluids near the wellbore when fresh mudsare used.)Pem = 2.41

Find: Umaa

Procedure: Use φN L S = 17% and ρb = 2.34 g/cc in Figure 3.18 to determine that φt a = 19.2%. (Refer to the exampleaccompanying Figure 3.17 for the procedure to use.)

To determine the point at which to enter the Um axis on the chart, use the nomograph below thechart. Construct a line segment through ρb = 2.34 g/cc on the ρb leg and through Pem = 2.41 on thePe m leg. Extend the segment to intersect the Um axis of the chart. The segment intersects the Um a x i sat Um = 5.69.

From Um = 5.69 on the Um axis, project vertically into the chart. From φta = 19.2% on the φta axis,project horizontally into the chart. The point of intersection of the two projections lies on the Umaa= 7.0 curve. Thus, estimate Umaa

to be 7.0.

Answer: Umaa= 7.0

Notes: You enter the value of Umaathat you determine from this chart into Figure 3.28.

71

3.0 2.9 2.8 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2.0

50

3 4 5 6 7 8 9 10 20Um, Volumetric Modified Photoelectric Factor

45

40

35

30

25

20

15

10

5

0

Umaa

-5

1 2 3 4 5 6 7 8 9 10Pem, Modified Photoelectric Factor

ρb, Bulk (Log) Density (g/cc or 1000 kg/m3)


Mineral Identification PlotUmaa

Determination

Figure 3.26


72

Chart: Figure 3.27 (Mineral Identification Plot (MIP-1) - maaversus tmaa

)

Applications: Determination of formation mineralogy from the apparent density and apparent soniccompressional interval transit time of the formation matrix

Nomenclature: ρmaa.......................apparent formation matrix density

∆tmaa.....................apparent sonic compressional interval transit time in formation matrix

Given: ρmaa= 2.675 g/cc

∆tmaa= 52.5 µs/ft

Find: Formation mineralogy

Procedure: From ∆tmaa= 52.5 µs/ft on the ∆tmaa

axis, project vertically into the chart. From ρmaa= 2.675 g/cc on

the ρmaaaxis, project horizontally into the chart. The intersection of the two projections is located

between the quartz and dolomite points on the chart. Assuming that the formation is shale-free, theposition of the intersection point indicates that the formation mineralogy is approximately 60%quartz and 40% calcite.

Answer: The formation matrix is comprised of approximately 60% quartz and 40% calcite.

Notes: If you know that the rock matrix is comprised of any three minerals shown on Figure 3.27, then youcan construct a proportionality triangle to determine the percentages of each mineral.

73

Anhydrite

Langbeinite

Orthoclase

Halite

Albite

Muscovite

Calcite

Quartz

Dolomite

2.4

35 40 45 50 55 60 65 70 75

∆tmaa, Apparent Matrix Transit Time (µs/ft)

2.5

2.6

2.7

2.8

2.9

3.0

3.1

2.0

2.160 70

∆tmaa, Apparent Matrix Transit Time (µs/m)

120 140 160 180 200 220 240


Mineral Identification Plot (MIP – 1)

maaversus tmaa

HDSN

Figure 3.27


74

Chart: Figure 3.28 (Mineral Identification Plot (MIP-2) - maaversus Umaa

)

Applications: Determination of formation mineralogy from the apparent density of the formation matrix andfrom the apparent matrix volumetric photoelectric factor.

Nomenclature: ρmaa.......................apparent formation matrix density

Umaa......................apparent matrix volumetric photoelectric factor

Given: ρmaa= 2.675 g/cc

Umaa= 7.0

Find: Formation mineralogy

Procedure: From ρmaa= 2.675 g/cc on the ρmaa

axis, project horizontally into the chart. From Umaa= 7.0 on the

Umaaaxis, project vertically into the chart. The intersection of the two projections is located near the

quartz point on the chart. Thus, the formation mineralogy is most likely to be predominantly quartz.

If you assume the formation to be composed of only the primary minerals quartz, calcite, anddolomite, you can estimate the percentage of each by using the triangular figure in the chart. Thepreviously found point of intersection of the projections into the chart lies between the 60% and80% Quartz lines (the diagonally oriented lines running lower-left to upper-right) in the triangle.From the position of the point between those two lines, you can estimate that the formationcontains about 72% quartz. The intersection point also lies between the 20% and 40% Calcite lines(the diagonally oriented lines running upper-left to lower-right). From the point’s position betweenthe Calcite lines, estimate that the formation contains about 21% calcite. Finally, the point liesbetween the 0% and 20% dolomite lines (the approximately horizontally oriented lines). From thepoint’s position between the Dolomite lines, estimate that the formation contains about 7%dolomite.

Answer: The formation is predominantly quartz. If you assume that the formation contains only quartz,calcite, and dolomite, then the mineralogy is approximatley 72% quartz, 21% calcite, and 7%dolomite.

Notes: You can select any three minerals to form a proportionality triangle such as the one shown in thechart.

75

Langbeinite

Calcite

Quartz

Dolomite

2.4

3 4 5 6 7 8 9 10 11 12 13 14 15 16 17Umaa

, Apparent Matrix Volumetric Photoelectric Factor

2.5

2.6

2.7

2.8

2.9

3.0

3.1

2.0

2.112 13 14 15 16 17

Orthoclase

Sulphur

Halite

Muscovite

Anhydrite


Mineral Identification Plot (MIP – 2)

maaversus UmaaHDSN

Figure 3.28


76

77

CEMENT BOND/MICRO-SEISMOGRAM ®*LOGGING (HFWS)To obtain cement bond logs under harshwell conditions, the Hostile Full WaveSonic Tool is run in a short-spacedconfiguration (Figure 4.3 ). Data areobtained at conventional 3- and 5-fttransmitter-to-receiver spacings. Thetransmitter is pulsed to produce acousticenergy that travels through boreholefluid, casing, cement, and formationbefore reaching the receivers. Theacoustic energy is attenuated in all thematerials through which it propagates,but the attenuation is severe at thecasing-cement and cement-formationinterfaces when bonding between theadjacent materials is poor. Analysis of therecorded acoustic information, whichcan be displayed in several log formats,can reveal the effectiveness of cementingoperations. The logs show areas wherethere is free pipe, where there is goodbond to the pipe but not to the forma-tion, and where there is good bond tothe pipe and to the formation. Whencement properties are known, the logscan also indicate intervals over whichthere is partial bond or channeling.

On cement bond logs, a pipe amplitudecurve is generated from data recorded atthe 3-ft receiver. This curve displays theamplitude of acoustic signals that havetraveled only through the borehole fluidand casing. Signal amplitude is relatedto signal attenuation: High amplitudesindicate low attenuation; low amplitudesindicate high attenuation.

Section 4Cased-HoleLoggingT

he HEAT sonic, neutron, andgamma-ray tools described inSection 1 of this publicationcan all operate in cased holes.

In addition, Halliburton has other loggingtools that can run in small-diameter tub-ulars under hostile conditions. Includedare gamma-neutron-CCL, cementbond, and production logging tools.

GAMMA-NEUTRON-CCL(GNST AND HGNC)Halliburton's gamma-neutron-CCLservices provide precision cased-holemeasurements in hostile environmentsand slim boreholes. On the resultingcombination logs, the gamma-ray curvesare used to verify depth, correlateformations, and calculate shale volume.The curves from the single-detectorneutron devices are used for the samepurposes as the gamma-ray curves andalso serve to identify gas zones and, intime-lapse logging, to monitor gas/liquidcontacts. Casing collar locator (CCL)curves are usually used with gamma orneutron logs for depth correlation.

The 1-11/16-inch Hostile GammaNeutron CCL tool (Figure 4.1 ) comple-ments the openhole HEAT Suite toolsby being able to make through-tubingcorrelation measurements underextreme temperatures and pressures. The1-7/16-inch Gamma Neutron Slimtool (Figure 4.2 ) furnishes precisioncorrelation in gas- or liquid-filled wellsand is ideal for use in wells that havesmall restrictions.

* A registered mark of Halliburton


78

Full acoustic wavetrain data recorded at the 5-ft receivercan be displayed on the log in several ways. An XYdisplay presents amplitude information for the entireacoustic wavetrain at selected depth intervals; it is asinusoidal-type display. An XZ, or Micro-Seismogram®,display, presents the entire acoustic wavetrain in the formof light and dark streaks of varying intensities thatrepresent the amplitudes of the half cycles comprising thewavetrain. A combination of the XY and XZ displays,referred to as the XYZ log, also can be generated. While acement bond log is being run, the logging presentationcan be switched between the XY, XZ, and XYZ formats.

It should be noted that when the cement bond with thecasing and with the formation is good, the Hostile FullWave Sonic tool can be run in a long-spaced configurationto evaluate the formation behind casing. Both compres-sional and shear slowness (∆tc and ∆ts ) can be measured,and most of the openhole applications of sonic data—including determining formation porosity, detecting forma-tion gas, analyzing natural fractures, and obtaining datafor hydraulic fracture design—are valid also in cased wells.

PRODUCTION LOGGING (PL)Production Logging (PL) services furnish quick and accurateinformation about downhole fluid flow. Fluid sources andsinks can be located, fluid types can be identified, and fluidflow rates measured. Halliburton's PL tools provide reliableresults in both single-phase and multiphase flow, even indeviated wells. PL flow profiles aid in studying reservoirproduction, monitoring injection operations, diagnosingtubular problems, detecting crossflow between zones, andmodeling reservoir characteristics. The PL data mayindicate a need for production enhancement operations, inwhich case PL tools can be used to monitor and evaluatethese operations.

The conventional PL toolstring consists of Hydro (fluiddielectric), Fluid Density, Continuous Flowmeter (spinner),Temperature, Pressure, Gamma Ray, and Collar Locatortools. These tools are rated to 375˚F and 18,000 psi andeach has 1-7/16-inch OD. A Gradiomanometer and aBorehole Audio Tracer tool are also available.

Hydro (HYD)The Hydro tool (Figure 4.4 )—also known as the fluiddielectric, capacitance, or watercut tool—is sensitive to thedielectric constant of the flowing stream. Wellbore fluidsflow through a tool chamber that acts as a capacitor in anoscillator circuit. The capacitance varies with changes in

the dielectric constants of the fluids flowing through thechamber and causes a change in the oscillator frequency.Low frequencies correspond to high-dielectric-constantfluids (water), and high frequencies correspond to low-dielectric-constant fluids (hydrocarbons). Consequently,the Hydro tool can differentiate between water andhydrocarbons, but the frequency differences between thetwo hydrocarbon phases (oil and gas) are small and maybe indistinguishable. The tool is calibrated so that waterholdup can be calculated from the oscillator frequency.

Fluid Density (FDT)The Fluid Density tool (Figure 4.5) is used to determinethe density of the flowstream. Wellbore fluid flows througha tool chamber that has a gamma-ray source at one end anda gamma-ray detector at the other end. The attenuationof gamma rays in the chamber depends upon the densityof the wellbore fluid there: the denser the wellbore fluid,the fewer gamma rays that reach the detector. Thus, lowdetector count rates correspond to high fluid density, andhigh detector count rates correspond to low fluid density.The tool is calibrated so that fluid density can be calculatedfrom the detector count rate and displayed on the log.Light-phase and heavy-phase holdups (the cross-sectionalareas of the casing occupied by the light and heavy phases,respectively) can be calculated from the fluid densityshown on the log, provided the density of each individualphase is known.

GradiomanometerGradiomanometers are also used to determine fluid density.These tools contain a fluid-filled float system. The pressuredifference between two points in the system is measuredand used to determine a pressure gradient, which in turnis converted to fluid density. Gradiomanometer measure-ments must be corrected for hole inclination; measurementswith the Fluid Density tool do not require such a correction.Gradiomanometers are not recommended for high-angleor horizontal wells.

Fullbore Gas Holdup (GHT)The Fullbore Gas Holdup tool (Figure 4.6) measures thegas holdup of the flowstream. The tool contains a gamma-ray source and a gamma-ray detector located a shortdistance from the source and separated from the source byshielding material. The measurement consists of countingthe gamma rays backscattered from the wellbore fluid to thedetector, the count rate being inversely proportional to thegas holdup. The measurement is insensitive to the

79

composition of the liquid phase (oil, salt water, or freshwater), to the material outside casing, to casing thickness,and to the volume-distribution of the gas. Themeasurement is suitable for use in highly deviated wells,where the gas may be separated from the liquid phases, aswell as in vertical wells where the gas may be uniformlymixed with the liquids.

Continuous Flowmeter (FMC)Continuous flowmeters (Figure 4.7) contain a helicalimpeller, or spinner, of diameter slightly less than that of thetool case. They are designed for use in wells with moderateto high flow rates and in wells containing small-diametercasing. These devices evaluate flow velocities in both tubingand casing. Since the mass of the impeller is very small, thetool has excellent resolution and a low threshold velocity.

Pressure (SPT and CQPT)Halliburton uses strain gauges and quartz transducers inits PL Pressure tools (Figure 4.8 and 4.9). Strain gaugesrespond more quickly to pressure changes, so are generallyused when real-time pressure measurements are needed.Quartz transducers have higher accuracy and thus can givesuperior data for analyzing drawdowns and buildups. Whenheld stationary in the wellbore, the Pressure tool measurespressure as a function of time. The resulting data areanalyzed to obtain the reservoir's permeability and skindamage. These measurements are made as the well is beingshut in, particularly during the afterflow, wellbore storage,and buildup phases.

Temperature (TLT)Temperature tools (Figure 4.10 ) use a resistance thermo-meter to measure wellbore temperature. A resistive elementthat is part of an electrical circuit is exposed to wellborefluids: changes in fluid temperature cause changes in theelement's resistance. Fluid entering the wellbore, or fluidsleaving the wellbore and accumulating in the regionsurrounding the well, can alter the normal temperaturegradient in the well. Such temperature-gradient anomaliesserve to identify producing zones, locate zones acceptingfluid in injection wells, and detect channeling from aboveor below.

Borehole Audio Tracer (BATS)The Borehole Audio Tracer tool (Figure 4.11 ) senses noisecreated by fluid movement in and around the borehole.The 1-11/16-inch tool is rated at 392˚F and 15,000 psi.To eliminate noises that would occur as a result of toolmotion, the tool is held stationary while measurementsare being made.

The logging system records the maximum noise amplitudein each of four frequency ranges extending from 200 Hz,600 Hz, 1,000 Hz, and 2,000 Hz up to the maximumfrequency to which the tool is sensitive. Amplitudes areplotted versus depth, and points in corresponding frequencyranges are joined to produce a four-curve log. The log isused to locate fluid flow, to assist in identifying fluid type,and to give information about the type of passage throughwhich the fluids are flowing. The data can also be used toindicate sand movement.

CASING INSPECTIONThe CAST tool described earlier can provide detailedimages for determining casing condition. CAST imagescan verify perforation location and reveal damage such asparting and splitting. CAST tools can be used in tubularswith OD as small as 4-1/2 inches.

SECTION 4: CASED-HOLE LOGGING


80

Figure 4.1

TOOL: Hostile Gamma Neutron CCL (HGNC-A)


GROUP: Natural and Induced Radioactivity


Max OD: 1.687 in

Length: 8.82 ft


Max Csg/Tbg ID: na

Min Csg/Tbg ID: 2 in

Weight: 48 lb




HARDWARE CHARACTERISTICSSource Type: 5-Ci Americium-Beryllium 241 (neutron)


Sensor Type: Helium-3 (neutron), Nal (TI) (gamma)



Full Spectrum: 60 keV - 3 MeV (gamma)

Combinability: Stand-alone

MEASUREMENT

Principle


Range


Primary Curves: Neutron, GR


Wellsite Verifier: Polyethylene sleeve (neutron), Thorium verifier (gamma)

Secondary: TMD water tank (neutron), Thorium verifier (gamma)

No. of Windows: (gamma)

Secondary Curves: CCL

Precision

Accuracy

Neutron-Thermal Neutron

Neutron Gamma

Natural Gamma Ray

0 - 3,000 cps 0 - 5,000 API

24 - 36 in18 - 36 in (enhanced)

12 in (enhanced)

5 in 4 in (90%: 11 in)

3% 4%

5 API 5 API

CCL

NeutronDetector

Gamma Ray

NeutronSource

wlmv741

small black


81

TOOL: Gamma Neutron Slim Tool (GNST-A)


GROUP: Natural and Induced Radioactivity


Max OD: 1.437 in

Length: 7.91 ft


Max Csg/Tbg ID: na

Min Csg/Tbg ID: 1.875 in

Weight: 33 lb




HARDWARE CHARACTERISTICSSource Type: 5-Ci Americium-Beryllium 241 (neutron)


Sensor Type: Helium-3 (neutron), Nal (TI) (gamma)



Full Spectrum: 60 keV - 3 MeV (gamma)


No. of Windows: 1 (gamma)

MEASUREMENT

Principle


Range


Primary Curves: Neutron, GR


Precision

Accuracy

Neutron-Thermal Neutron

Neutron Gamma

Natural Gamma Ray

0 - 3,000 cps 0 - 5,000 API

24 - 36 in18 - 36 in (enhanced)

12 in (enhanced)

5 in 4 in (90%: 11 in)

3% 4%

5 API 5 API


Wellsite Verifier: Polyethylene sleeve (neutron), Thorium verifier (gamma)

Secondary: TMD water tank (neutron), Thorium verifier (gamma)

CCL

NeutronDetector

Gamma Ray

NeutronSource

Figure 4.2

wlmv741

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82

Figure 4.3

TOOL: Hostile Full Wave Sonic (HFWS-A)

GENERIC TYPE: Cement Bond

GROUP: Cement Evaluation


Max OD: 2.75 in

Length*: 30.22 ft


Max Hole: 12 in

Min Hole: 3.9 in

Weight: 340 lb




HARDWARE CHARACTERISTICSSource Type: Two 17-kHz piezoelectric (one inactive)

Sensor Spacings: 3, 5 ft (both active); 8, 8.5, 9, 9.5 ft (all inactive)


Firing Rate: 200 ms (service dependent)


Measurement Bandwidth: 8 to 30 kHz

Combinability: HDSN, HNGR

MEASUREMENT

Principle


Range


Primary Curves: Waveform or MSG® Display (5-ft), E1 Peak Amplitude (3-ft)

CALIBRATIONPrimary: API CBL Test Facility (Free Pipe and Bond)

Wellsite Verifier: Internal signal

Secondary: Free Pipe

Samples per Sensor: 1,024

Secondary Curves: TT, GR, CCL, Tension

Sensitivity

Accuracy

Sonic waveform attenuation

Neutron Gamma

1000 µs 0 - 100 mV

5 ft

na na

na < 1 mV

na ± 2%

* Add 3.5 ft for each in-line centralizer (usually two).

3 ft

UpperElectronics

LowerElectronics


Receiver 1

Receiver 2


wlmv741

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83

Figure 4.4

TOOL: Hydro (HYD-FC), MUX

GENERIC TYPE: Water Cut

GROUP: Production Logging


Max OD: 1.437 in

Length: 2.5 ft


Max Csg/Tbg ID: na


Weight: 8 lb



Recommended Logging Speed*: 30 ft/min


Sensor Spacings: na

Sensor Type: Fluid capacitance


Sampling Rate: 2, 4, or 10 Samples per ft

Full Spectrum: na

Combinability: PLT, GRT, TLT, FMS, FDT, SPT, CCL, FBT, HPA

MEASUREMENTPrinciple: Water holdup from dielectric constant

Depth of Investigation (50%): na

Resolution: 3% of holdup at stationary reading

Sensitivity: na

Secondary Curves: Frequency

Accuracy: ± 5% of holdup at stationary reading

Primary Curves: CPS, Water Holdup

*Range depends upon fluid distribution

CALIBRATIONPrimary: Water and air

Wellsite Verifier: Water and air

Secondary: Water and air

No. of Windows: na

Range*: 0 - 100% water holdup

*Stationary for holdup calculation

HydroAssembly

wlmv741

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84

Figure 4.5

TOOL: Fluid Density (FDT-EC), MUX

GENERIC TYPE: Fluid Density



Max OD: 1.437 in

Length: 3.26 ft


Max Csg/Tbg ID: na


Weight: 11 lb




HARDWARE CHARACTERISTICSSource Type: 17-mCi Cesium 137


Sensor Type: Geiger-Mueller detector



Full Spectrum: na

Combinability: PLT, GRT, HYD, FMS, TLT, SPT, CCL, FBT, HPA

MEASUREMENTPrinciple: Gamma backscatter


Resolution: 0.01 gm/cc

Sensitivity: na

Primary Curves: Fluid Density, Amplified Fluid Density

Accuracy, Typical: ± 0.02 gm/cc

Accuracy, Maximum: ± 0.03 gm/cc

Secondary Curves: Density Counts




No. of Windows: 1

Range: 1 - 1.5 gm/cc


FluidDensityInstrument

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85

Figure 4.6

TOOL: Fullbore Gas Holdup Tool (GHT)

GENERIC TYPE: Gas Holdup



Max OD: 1.687 in

Length: 2 ft


Max Csg/Tbg ID: na


Weight: 8 lb




HARDWARE CHARACTERISTICSSource Type: 3-mCi Cobalt 57


Sensor Type: Nal Scintillation



Full Spectrum: na

Combinability: PLT, GRT, HYD, FMS, TLT, SPT, CCL, FBF, HPA, FDT

MEASUREMENTPrinciple: Gamma backscatter

Depth of Investigation (50%): Fullbore

Resolution: 2% gas holdup

Sensitivity: na

Primary Curves: Gas Holdup

Accuracy, Typical: ± 2.5% gas holdup

Accuracy, Maximum: ± 4% gas holdup

Secondary Curves: Backscattered Gamma Counts




No. of Windows: 1

Range: 0 - 100% gas holdup


Shield

Detector

Source

wlmv741

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86

Figure 4.7

TOOL: Continuous Flowmeter (FMS-HC), MUX

GENERIC TYPE: Flowmeter/Spinner



Max OD: 1.687 in

Length: 2.33 ft


Max Csg/Tbg ID: na


Weight: 8 lb



Recommended Logging Speed: Dependent on flow rate


Sensor Spacings: na

Sensor Type: Magnetically coupled optics assembly



Combinability: PLT, GRT, FDT, HYD, SPT, TLT, CCL, HPA

MEASUREMENTPrinciple: Spinner/Fluid Velocity


Resolution: < 1 ft/min in water

Sensitivity: 8 pulses/revolution

Primary Curves: Spinner (rev/s)

Accuracy: ± 1 ft/min in water

Threshold Velocity: 3.5 ft/min in water (computed)

Secondary Curves: Fluid Velocity (0 - 100%)

CALIBRATIONPrimary: In-situ well calibration

Wellsite Verifier: CW/CCW verification

Secondary: Flow loop characterization data

Samples per Run: Multiple pass technique

Range: 0 - 1,600 ft/min dynamic in water

FlowmeterAssembly

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87

Figure 4.8

TOOL: Stack Pressure Tool (SPT-CC), MUX

GENERIC TYPE: Pressure



Max OD: 1.437 in

Length: 2.16 ft


Max Csg/Tbg ID: na


Weight: 7 lb





Sensor Spacings: na

Sensor Type: Strain gauge pressure transducer with temperature corrections



Full Spectrum: na

MEASUREMENTPrinciple: Pressure


Resolution: 1 psi

Sensitivity: na

Primary Curves: Pressure, Amplified Pressure,Differential Pressure

Accuracy: ± 15 psi at full scale


CALIBRATIONPrimary: Dead-weight tester and heat box

Wellsite Verifier: Software verification

Secondary: Dead-weight tester and heat box

No. of Windows: na

Range: 100 - 10,000 psi

StackPressureTool

Combinability: PLT, GRT, HYD, TLT, FMS, FDT, CCL, HPA, FBF

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88

Figure 4.9

TOOL: Compensated Quartz Pressure Tool (CQPT-A), MUX

GENERIC TYPE: Pressure



Max OD: 1.687 in

Length: 4.25 ft


Max Csg/Tbg ID: na


Weight: 22 lb



Recommended Logging Speed: Stationary


Sensor Spacings: na

Sensor Type: Quartz pressure transducer with temperature corrections


Sampling Rate: 2 - 3 Samples per second (frequency dependent)

Full Spectrum: 10 - 37.2 kHz

MEASUREMENTPrinciple: Pressure


Resolution: 0.01 psi

Sensitivity: 1.7 Hz/psi

Primary Curves: Pressure, Amplified Pressure,Differential Pressure

Accuracy: ± (1 psi + 0.01% of reading)

Secondary Curves: SIT

CALIBRATIONPrimary: Dead-weight tester and NIST-traceable heat box

Wellsite Verifier: Software verification

Secondary: Secondary pressure standard

Sample Size: One 24-bit pressure word, one 24-bit temperature word

Range: 14.7 - 16,000 psi

InstrumentAssembly

Port BodyAssembly

Combinability: PCU, PFDT, PFST, PGT

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89

Figure 4.10

TOOL: Temperature Logging Tool (TLT-IC), MUX

GENERIC TYPE: Temperature



Max OD: 1.437 in

Length: 1.92 ft


Max Csg/Tbg ID: na


Weight: 7 lb





Sensor Spacings: na

Sensor Type: Platinum RTD



Full Spectrum: na

MEASUREMENTPrinciple: Wellbore temperature


Resolution: 0.02°F

Sensitivity: 50 Hz per °F

Primary Curves: TEMP, DTEMP, Amplified TEMP

Accuracy: ± 3°F (uncorrected), ± 2°F (corrected)


CALIBRATIONPrimary: Heat box/water bath

Wellsite Verifier: Atmospheric check

Secondary: Heat box/water bath

No. of Windows: na

Range: 50 - 375°F

TemperatureLoggingTool

Combinability: PLT, GRT, FMS, FDT, SPT, HYD, CCL, FBF, HPA

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90

Figure 4.11

TOOL: Borehole Audio Tracer Survey (BATS)

GENERIC TYPE: Passive Acoustic



Max OD: 1.687 in

Length: 2.42 ft


Max Csg/Tbg ID: 20 in


Weight: 15 lb



Recommended Logging Speed: Stationary


Sensor Spacings: na

Sensor Type: Piezoelectric hydrophone

Firing Rate: na

Sampling Rate: Continuous (analog)

Full Spectrum: 5 Hz to 10 kHz

MEASUREMENTPrinciple: Acoustic noise


Resolution: na

Sensitivity: na

Primary Curves: 200 Hz, 600 Hz, 1 kHz, 2 kHz

Accuracy: na


CALIBRATIONPrimary: none

Wellsite Verifier: none

Secondary: none

No. of Windows: na

Range: 1 - 2,000 mV

ElectronicSection

HydrophonicSonde

BottomSub


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91

Drill-Collar SeveringTools (DCST)Conventional jet cutters are seldomsuccessful in cutting drill collars becauseof the softness and thickness of collarmetal. The drill-collar severing tool wasdesigned specifically for drill-collarapplications. The tool simultaneouslygenerates two shock waves, one at eachend of the tool. When the two wavesmeet in the borehole near the center ofthe tool, their energies are redirectedoutward toward the inner wall of thedrill collar. The resulting force shears thedrill collar. Drill-collar severing tools areavailable in four sizes: 1-3/8-, 1-3/4-,2-, and 2-5/8-inch OD. As indicated inTable 5.3 , the tools are rated at 20,000psi and 400˚F (with HMX) or 475˚F(with HNS).

Perforating SystemsPerforating systems for slimhole, high-pressure, high-temperature work areavailable in a variety of sizes and types.The systems are based on wire, strip,and hollow carriers and are rated as highas 600˚F and 20,000 psi, dependingupon the explosives used. Tables 5.4through 5.7 list the more commonlyused systems.

Section 5Cased-HoleMechanicalandRelatedServices

Halliburton offers a widevariety of explosive,chemical cutting, andplugback services for

small-diameter, high-pressure, high-temperature cased wells.

EXPLOSIVE SERVICESHalliburton has small-diameter, high-pressure, high-temperature equipmentfor cutting tubing, casing, and drillpipe;severing drill collars; perforating casingand tubing; and performing junk shotservices. Because the tools depend uponexplosives for their operation, the temp-erature limitations of the tools dependupon the temperature limitations ofthe explosives. The explosives mostcommonly used are RDX, HMX, HNS,and PYX. The chart of Figure 5.1 givesthe maximum time that these explosivescan withstand exposure at a given temp-erature and still perform effectively. Inhigh-pressure, high-temperatureapplications, high-temperature explosivesare used not only in the main chargebut also in the detonating cord anddetonator.

Jet CuttersTables 5.1 and 5.2 contain the mostcommonly run small-diameter, high-pressure, high-temperature jet cuttersfor tubing and drillpipe applications.However, other jet cutters can bespecially manufactured to accommodatepractically any size pipe.

92

Junk ShotsJunk shots can be positioned and detonated via wirelineor tubing. They are designed to shoot downward, andnormally only one or two shots are needed to disperse thetoughest downhole junk. Junk shots are available in twosizes: 5-1/4- and 7-3/4-inch OD. Both are rated to 18,000psi and use HMX explosives for applications above 375˚F.

Magnetic Orienting Device (MOD)The Magnetic Orienting Device was developed to prefer-entially perforate selected tubing and/or casing in wellscontaining multiple tubing strings. Using a rotatingpermanent magnet, the MOD tool detects differences inmetal mass in the region surrounding the tool. Toolresponse is based on metal proximity and metal mass. Tokeep constant the proximity effect of the string in which thetool is located, the tool must be centralized in that string.When the tool is centralized, higher metal mass will beindicated in the direction of an additional tubing string.Tool response is relatively unaffected by cement, formation,and borehole fluid. The MOD tool is 1-11/16 inches indiameter and is rated at 350˚F and 18,000 psi.

Slimhole Hostile Gamma Perforator(HGPS)The slimhole Hostile Gamma Perforator (Figure 5.2) isused to correlate perforating-gun depth when casing ortubing collars cannot be reliably detected with a collarlocator. This tool generates a cased-hole gamma-ray log thatis correlated with an openhole gamma-ray log to determinegun depth. The tool has 1-11/16-inch OD and is rated at450˚F and 22,000 psi.

CHEMICAL CUTTERSWhen mechanical efforts to free stuck pipe are unsuccessful,the pipe must be cut and as much pipe salvaged as possible.Jet cutters are the traditional method of cutting pipe andperform best when the pipe is in tension. In instances wherejet cutters are unsuccessful or cannot be used because ofrestrictions or the inability to apply tension (such as betweenpackers), chemical cutters are employed. Chemical cutterseject a circular stream of bromine trifluoride to dissolve thepipe. This stream produces a clean cut that leaves no debrisand requires no further milling before the pipe is retrieved.Chemical cutters are rated to 370˚F and 20,000 psi.Applications are listed in Table 5.8 .

FREE-POINT AND BACK-OFF TOOLSThe free-point tool (Figure 5.3) is a sensitive, highlyaccurate strain gauge device that measures stretch andtorque in a stuck string of drillpipe, tubing, casing, orwashpipe. Free-point measurements determine the lowestdepth at which the pipe can be recovered. Free-point toolsare available in 1-, 1-3/8-, and 1-5/8-inch-OD sizes. Thetools are rated to 400˚F and 20,000 psi.

Back-off services are usually run with the free-point service.Back-off tools use the explosive force of a string of detonatorcord to uncouple the pipestring at the first collar above thestuck point. As the cord is detonated, left-hand torque isapplied to the pipe at the surface.

BRIDGE PLUGSBridge plugs generate a temporary or permanent sealbetween two zones in a well. Halliburton has both basket(through-tubing) and cast-iron bridge plugs.

Through-Tubing Bridge PlugsThrough-tubing bridge plugs offer a fast, easy, and econom-ical way to permanently plug back a well without usingexpensive workover or snubbing services to pull productiontubing. After the plugback assembly is lowered throughtubing into casing, serrated slips anchor the assembly tothe casing and a basket is expanded to form a strong basefor the placement of cement. An internal bypass systemallows fluid to migrate through the plug while cementhardens. The bypass system is closed by a wireline-actuatedmechanical valve. The plugback assemblies are availablein several sizes for use in 4-1/2- to 9-inch-OD casing attemperatures up to 400˚F.

Cast-Iron Bridge PlugsHalliburton's Elite Magna-Range bridge plugs have thesmallest running diameter in the industry. They are ratedat 425˚F and can withstand a 10,000-psi pressure differen-tial. These plugs have three-piece rubber packing elements,can set in P-110 and harder casings, and contain a cast-iron release ring for easy drillout. Table 5.9 lists settingranges for Magna-Range plugs.


SECTION 5: CASED-HOLE MECHANICAL AND RELATED SERVICES

93

Table 5.1 — Specifications for Jet Tubing Cutters

Running Diameter(inches)

1-3/8

1-9/16

1-11/16

Recommended Use Temperature/Pressure Rating(°F/psi)

1.9-inch P-105, 0.150-inch wall

2-1/16-inch P-105, 0.156-inch wall

2-3/8-inch P-105, 0.190-inch wall

400/15,000

400/15,000

400/20,000

Table 5.2 — Specifications for Drillpipe Cutters


2-3/8

2-15/16

3-15/16

Recommended Use Temperature/Pressure Rating(°F/psi)

3-1/2-inch drillpipe, 0.449-inch wall



400/16,000

400/16,000

400/12,000

1-23/32

1-13/16

2-1/32

2-3/8-inch P-105, 0.190-inch wall

2-3/8-inch P-105, 0.190-inch wall

2-7/8-inch P-105, 0.217-inch wall

400/20,000

400/20,000

400/20,000

2-1/8

2-1/4

3-19/32

2-7/8-inch Hastelloy, 7.5 lb/ft

2-7/8-inch P-105, 0.217-inch wall

3-1/2-inch P-105, 0.254-inch wall

400/20,000

400/20,000

400/20,000

2.70

2.70

3-1/2-inch P-105, 0.254-inch wall

3-1/2-inch Hastelloy, 9.3 lb/ft

400/20,000

400/20,000

Table 5.3 — Specifications for Drill-Collar Severing Tools


1-3/8

1-3/4

2

Recommended Use Temperature/Pressure Ratings 1

(°F/psi)

2-7/8-inch drillpipe

6-inch drill collars

6-inch drill collars

400/20,000

400/20,000

400/20,000

2-5/8 9-inch drill collars 400/20,000

1 Ratings apply when HMS/HNS/PYX explosives are used.


94

Table 5.5 — Specifications for Scalloped Hollow-Carrier Through-Tubing Guns


Phasing(degrees)

Temperature/Pressure Ratings 1

(°F/psi)

500/30,000

400/20,000

600/20,000

1-9/16

2-3/4

2-3/4

4

6

6

0, 90, or 180

0, 90, or 180

0, 90, or 180

General Purpose

DP2

DP

Shot Density(shots/ft)

Type

1 Ratings apply when HMS/HNS/PYX explosives are used.2 Deep penetrating

Table 5.4 — Specifications for Strip-Carrier and Wire-Carrier Through-Tubing Capsule Guns


Phasing(degrees)


(°F/psi)

400/15,000

400/15,000

400/15,000

400/15,000

400/15,000

1-11/16

2-1/8

2-1/8

1-53/64

2-1/4

4 or 6

4 or 6

4 or 6

4 or 6

4 or 6

0

0

0, 90, 180, or spiral

63 or 116

63 or 116

Strip DP2

Strip DP

Strip DP

Bi-wire

Bi-wire


Type


Table 5.6 — Specifications for Ported Hollow-Carrier Casing Guns


Phasing(degrees)


(°F/psi)

400/20,000

400/20,000

400/20,000

3-1/8

3-1/8

4

4 or 6

4 or 6

4 or 6

120

120

120

DP2

DP

DP


Type



95


Phasing(degrees)


(°F/psi)


Type

Table 5.7 — Specifications for Scalloped Hollow-Carrier Casing Guns

400/15,000

500/15,000

600/15,000

400/22,500

600/22,500

3-1/8

3-1/8

3-1/8

3-3/8

3-3/8

6

6

6

6

6

60

60

60

60

60

DP2

DP

DP

DP

DP

1 Ratings apply when HMS/HNS/PYX explosives are used.2 Deep penetrating3 Big hole

400/22,500

600/22,500

400/20,000

400/19,000

400/19,000

3-3/8

3-3/8

3-3/8

3-3/4

3-3/4

6

6

4

12

12

60

60

90

60

60

BH3

BH

DP

DP

BH

400/17,000

600/17,000

400/15,000

600/15,000

400/15,000

4

4

4-1/2

4-1/2

4-1/2

4

4

12

12

12

90

90

150

150

150

DP

DP

DP

DP

BH

600/15,000

400/13,000

500/13,000

400/13,000

500/13,000

4-1/2

5

5

5

5

12

12

12

12

12

150

60

60

60

60

BH

DP

DP

BH

BH

400/13,000

600/13,000

400/15,000

400/15,000

5

5

6

6

5

5

12

12

60

60

60

60

DP

DP

DP

BH


96

Cutter OD(in.) Nominal Size

(in.)

Table 5.8 — Chemical Cutters Used in Tubulars With ODs of 4-1/2 Inches or Less

1.140.8241.0503/43/4

OD(in.)

ID(in.)

Weight(lb/ft)

Type

Recommended Tubular Use

1.701.0491.31517/8

0.668 to 1.0370.993 to 0.8911.0001Coiled Tubing3/4

0.941 to 1.3281.175 to 1.1411.2501-1/4Coiled Tubing3/4

2.301.3801.6601-1/41-1/8

3.021.2781.6601-1/4Hydril1-1/16

2.751.6101.9001-1/21-1/4

1.426 to 1.9551.405 to 1.3661.5001-1/2Coiled Tubing1-1/8

3.251.7512.0632-1/161-3/8

4.002.0412.3752-3/81-11/16

4.601.9952.3752-3/81-11/16

5.801.8672.3752-3/81-11/16

6.651.8152.3752-3/8Drillpipe1-1/2

6.402.4412.8752-7/82-1/8

7.902.3232.8752-7/82-1/8

8.602.2592.8752-7/82

10.402.1512.8752-7/8Drillpipe1-7/8

7.703.0683.5003-1/22-5/8

9.202.9923.5003-1/22-5/8

10.202.9923.5003-1/22-5/8

12.702.7503.5003-1/22-1/2

13.302.7643.5003-1/2Drillpipe2-1/4

15.502.6023.5003-1/2Drillpipe2-1/4

11.003.4764.00043

11.503.4284.00043

13.403.3404.00043

9.504.0904.5004-1/23-5/8

10.504.0524.5004-1/23-5/8

11.604.0004.5004-1/23-5/8

12.603.9584.5004-1/23-5/8

13.503.9204.5004-1/23-5/8


97

Table 5.9 — Elite Magna-Range Bridge Plugs

1.610

1.905

Plug OD(in.)

1.995

2.441

1.406

1.468

1.750

2.156 2.765 1.906

1 Available by special order

Minimum(in.)

Plug Setting Range

Maximum(in.)

2.375

2.441

2.875

3.000

3.343

3.500

2.187

2.281

2.500

3.187 3.920 2.750

3.437

3.920

3.920

4.154

4.276

4.670

3.000

3.250

3.625

4.154 5.044 4.062

4.950

6.625

6.400

7.921

4.7501

6.125

Time – Temperature Effect on ExplosivesOperational Limits

Figure 5.1


98

Figure 5.2

TOOL: Hostile Gamma Perforator (HGPS-A), Slim Version

GENERIC TYPE: Conventional Gamma Ray

GROUP: Gamma Perforator


Max OD: 1.688 in

Length*: 12.8 ft


Max Csg/Tbg ID: na


Weight: 73 lb




HARDWARE CHARACTERISTICSSource Type: na

Sensor Spacings: na

Sensor Type: Nal(TI) (gamma)


Sampling Rate: Continuous

Full Spectrum: 0 - 3 Mev

MEASUREMENTPrinciple: Natural Gamma

Depth of Investigation (50%): 4 in (90%: 11 in)

Vertical Resolution (90%): 12 in

Precision: ± 4%

Primary Curves: GR

Accuracy: ± 7 API


CALIBRATIONPrimary: Halliburton Test Pits (referenced to API Pits)

Wellsite Verifier: Thorium verifier

Secondary: Thorium verifier

No. of Windows: 1

Range: 0 - 10,000 API

CCL

InstrumentSection

EndSubassembly

Gamma Ray

ShockSubassembly

Combinability: Expendable Hollow Steel Carrier Through-Tubing Guns withOD not exceeding 2.75 in; any Expendable or ExpendableRetrievable Through- Tubing Guns; Wireline Pressure-SettingAssemblies used for setting in-tubing or through-tubingbridge plugs

*Length and weight are given for the tool in standard perforatingconfiguration (with Shock Subassembly). In stand-alone configuration,tool length is 11.57 ft and tool weight is 63 lb.

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99

Figure 5.3

ConductorWeight

Free-PointTool

CCL

Combination SubShooting Adapter

Shooting Rod

TOOL: Combination Free Point—Backoff Tool (Dia-Log), 1.625 inch

GENERIC TYPE: Free Point/Pipe Recovery

GROUP: Fishing


Max OD: 1.625 in

Length*: 24.8 ft


Max Hole: 5.0 in

Min Hole: 1.875 in

Weight**: 80 lb




HARDWARE CHARACTERISTICSSource Type: Oscillator

Sensor Spacings: Single point

Sensor Type: Tuned coil


Sampling Rate: na

Combinability: String shot (limited strength)

MEASUREMENT

Vertical Resolution (90%)

Range

Depth of Investigation (50%)

Accuracy

Sensitivity (Sensor Displacement)

Primary Curves: Pipe Torque, Elongation, Compression

CALIBRATIONPrimary: Electronic adjustment

Wellsite Verifier: Free pipe

Secondary: Free pipe

No. of Windows: na

Principle

*With jar in closed position. Add 5 inches for G-series cablehead adapter.Add 4.5 inches for W-series cablehead adapter.

**Additional conductor weights can be added as needed. Each conductor weightis 60 inches (5 feet) long and weighs 33 pounds.


Pull

Frequency Shift

na

Single Point

na

Torque

0.001 in0.0031 in

± 10%± 10%

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101

Section 6Radius-of-Borehole-CurvatureLimitationsonDownholeTools

The maximum length of arigid downhole tool that canbe run in a deviated well islimited by the radius of

curvature of the well. Clearly, a long,rigid tool cannot negotiate a well withrapidly changing direction. To allowsuch a tool to traverse a deviated well,flex joints can be placed between thesections of the tool.

The maximum length of a rigid tool orrigid tool section that can run in adeviated well is given by

. . . . . . . . . . . . . . . . . . . . . (6.1)

= +( ) − +( )

where lt is the tool or tool section length,rh is the radius of curvature of the well,dh is the borehole diameter, and dt isthe tool diameter (Figure 6.1). Alldimensions must be in the same units.

Conversely, the minimum radius ofcurvature of a well in which a specificrigid tool or rigid tool section can berun is given by

. . . . . . . . . . . . . . . . . . . . . . . . . . (6.2)

Charts such as those in Figures 6.2through 6.5 can be derived from theseequations.

Radius of Curvature

Borehole DiameterTool Diameter

Tool Length

Radius of Curvature Limitations on Tool Length

Figure 6.1

=−( )

+ −

102


Chart: Figure 6.2 Minimum Radius of Borehole Curvature Determination:Tool Diameter = 2.75 in (69.9 mm)

Applications: Determination of minimum radius of borehole curvature in which a tool can run

Nomenclature: dt...........................tool diameter

lt ............................tool length

dh ..........................borehole diameter

rh ...........................minimum radius of borehole curvature

Given: dt = 2.75 in

lt = 15 ft

dh = 4.75 in

Find: rh

Procedure: Enter the chart at 15 ft on the lower Tool Length axis. Project vertically to the 4-3/4-inch BoreholeDiameter curve, then horizontally to the left-hand Minimum Radius of Curvature axis. From that axis,estimate rh to be 168 ft.

Answer: rh = 168 ft

Notes: You can calculate rh from

All variables must be expressed in the same units (e.g., feet).

rh =

It2

2

+ d t2 − dh

2

2 dh − dt( )

103

SECTION 6: RADIUS-OF-BOREHOLE-CURVATURE LIMITATIONS ON DOWNHOLE TOOLS

Minimum Radius of Borehole Curvature DeterminationTool Diameter = 2.75 in (69.9 mm)

Figure 6.2

Borehole Diameter (in)

1 5 10 15 20 25 30Tool Length (ft)

50

40

30

20

0

10

120

110

100

90

80

70

60

400

350

300

250

200

150

100

50

0

Tool Length (m)0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0

104



Figure 6.3

Borehole Diameter (in)

1 5 10 15 20 25Tool Length (ft)

50

40

30

20

0

10

120

110

100

90

80

70

60

400

350

300

250

200

150

100

50

0

Tool Length (m)0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5

105

SECTION 6: RADIUS-OF-BOREHOLE-CURVATURE LIMITATIONS ON DOWNHOLE TOOLS


Figure 6.4

1 2 3 4 5 6 7 8 9 10 11 12Tool Length (ft)

7

6

4

3

0

1

18

16

15

13

12

10

9

60

55

50

40

30

20

15

10

0

Tool Length (m)0.5 1.0 1.5 2.0 2.5 3.0 3.5

45

35

25

5

17

14

11

8

5

2

Tubular OD/ID

106



Figure 6.5

1 2 3 4 5 6 7 8 9 10 11 12Tool Length (ft)

7

6

4

3

0

1

18

16

15

13

12

10

9

60

55

50

40

30

20

15

10

0

Tool Length (m)0.5 1.0 1.5 2.0 2.5 3.0 3.5

45

35

25

5

17

14

11

8

5

2

Tubular OD/ID

107

Index

acoustic scanning tool. See Circumferential AcousticScanning Tool

audio survey. See Borehole Audio Tracerback-off. See free-point and back-offBorehole Audio Tracer

tool description 79tool specifications 90

bridge plugs 92cablehead tension load cell 3caliper. See Hostile Four Arm Calipercased-hole

logging 77mechanical services 91

casing cutter. See jet cuttercasing inspection 79cast-iron bridge plugs. See Elite Magna-Range bridge plugCAST. See Circumferential Acoustic Scanning ToolCBL. See cement bond loggingcement bond logging


centralizers 4chemical cutters

tool descriptions 92tool specifications 96

Circumferential Acoustic Scanning Tooltool description 6, 79tool specifications 19

coiled-tubing-conveyed logging 6Compensated Quartz Pressure Tool


Continuous Flowmetertool description 79tool specifications 86

CQPT. See Compensated Quartz Pressure Toolcutter. See jet cutterDCST. See Drill-Collar Severing Tooldecentralizer. See Hostile Powered Decentralizerdensity. See Hostile Spectral Densitydipmeter. See Hostile DipmeterDrill-Collar Severing Tool


dual induction. See Hostile Dual Inductiondual-spaced neutron. See Hostile Dual Spaced NeutronElite Magna-Range bridge plug


environmental effects on HEAT Suite response 29explosive services 91FDT. See Fluid Densityflex joints 4flowmeter. See Continuous FlowmeterFluid Density

tool description 78

tool specifications 84fluid holdup. See Fullbore Gas Holdup; HydroFMC. See Continuous Flowmeterfour-arm caliper. See Hostile Four Arm Caliperfree-point and back-off


full-waveform sonic. See Hostile Full Wave SonicFullbore Gas Holdup


Gamma Neutron Slimtool description 77tool specifications 81

gamma ray. See Hostile Natural Gamma Raygamma-neutron-CCL. See Hostile Gamma Neutron CCL; Gamma

Neutron Slimgamma-perforator. See Hostile Gamma Perforatorgas holdup. See Fullbore Gas HoldupGHT. See Fullbore Gas HoldupGNST. See gamma-neutron-CCLGradiomanometer 78HDIL. See Hostile Dual InductionHEAT and standard log comparison 21, 23HEAT Suite logging system

description 3log analysis 25, 27log examples 21, 23, 24, 26typical logging configurations 7

HECT. See Hostile Four Arm CaliperHEDT. See Hostile DipmeterHETS. See Hostile Telemetry AssemblyHFWS. See Hostile Full Wave SonicHGNC. See Hostile Gamma Neutron CCLHGPS. See Hostile Gamma PerforatorHMX 91, 97HNGR. See Hostile Natural Gamma RayHNX 91, 97holdup. See Fullbore Gas Holdup; Hydrohollow-carrier perforating gun. See perforating systemsHostile Dipmeter


Hostile Dual Inductioncorrection charts 31, 33, 35, 36, 37, 39, 40, 41, 42, 43correction-chart examples 30, 32, 34, 38logging configuration 7tool description 5tool specifications 11

Hostile Dual Spaced Neutroncorrection charts 47, 49, 51, 53, 55correction-chart examples 46, 50, 54logging configuration 7tool description 5tool specifications 16

108


Hostile Four Arm Calipertool description 4tool specifications 10

Hostile Full Wave Soniclog analysis 21, 22, 27log example 21, 26tool description 5, 77tool specifications 12, 13, 82

Hostile Gamma Neutron CCLtool description 77tool specifications 80

Hostile Gamma Perforatortool description 92tool specifications 98

Hostile Natural Gamma Raylogging configuration 7tool description 5tool specifications 17

Hostile Powered Decentralizerlogging configuration 7tool description 4tool specifications 9

Hostile Spectral Densitycorrection chart 44correction-chart example 45logging configuration 7tool description 5tool specifications 14, 15

Hostile Telemetry Assemblytool description 4tool specifications 8

HPDC. See Hostile Powered DecentralizerHSDL. See Hostile Spectral DensityHSDN. See Hostile Dual Spaced NeutronHYD. See HydroHydro


induction. See Hostile Dual Inductioninstantaneous frequency 22, 27instantaneous phase 22, 27instantaneous transmissivity 22, 27Instantaneous Waveform Characteristics

analysis 21, 22, 27log 21, 27

IWC. See Instantaneous Waveform Characteristicsjet cutter


junk shots 92load cell. See cablehead tension load celllog comparison 21, 23logging

cased-hole 77openhole 3

Magnetic Orienting Device 92

Micro-Seismogram® logging 77mineral identification plots

plot examples 66, 68, 70, 72, 74plots 67, 69, 71, 73, 75

MIP. See mineral identification plotsMOD. See Magnetic Orienting Devicenatural gamma ray. See Hostile Natural Gamma Rayneutron. See Hostile Dual Spaced Neutronopenhole logging 3perforating

systems descriptions 91specifications 94-95

PL. See Production Loggingporosity-mineralogy crossplots

crossplot examples 56, 60, 64crossplots 57, 58, 59, 61, 62, 63, 65

powered decentralizer. See Hostile Powered Decentralizerpressure. See Compensated Quartz Pressure Tool; Stack

Pressure Toolproduction logging 78PYX 91, 97quartz pressure tool. See Compensated Quartz Pressure Toolradius-of-borehole-curvature limitations on downhole tools

chart example 102charts 103, 104, 105, 106equations 101

RDX 91, 97severing tool. See Drill-Collar Severing ToolSlim Hostile Gamma Perforator. See Hostile Gamma

Perforatorsonic. See Hostile Full Wave Sonicspectral density. See Hostile Spectral Densityspinner. See Continuous FlowmeterSPT. See Stack Pressure ToolStack Pressure Tool

tool descriptions 79tool specifications 87

strain-gauge pressure tool. See Stack Pressure Toolstrip-carrier perforating gun. See perforating systemstelemetry assembly. See Hostile Telemetry Assemblytemperature


through-tubing bridge plugs 92time-temperature effect on explosives 97Toolpusher logging 6TPL. See Toolpusher loggingtriple-combo

log 21, 24log analysis 21, 25

tubing cutter. See jet cuttertubing-conveyed logging. See coiled-tubing-conveyed

loggingwater holdup. See Hydrowire-carrier perforating gun. See perforating systems

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