Form Eval Complete 2013 14

Institute of Petroleum Engineering

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Formation Evaluation

1 INTRODUCTION TO OPENHOLE LOGGING

2 ROCK AND FLUID PROPERTIES

3 SUMMARY OF PROCEDURES

4 LOG MEASUREMENTS AND TOOLS

5 INTERPRETATION OF POROSITY

6 LITHOLOGY AND POROSITY IN COMPLEX FORMATIONS

7 SATURATION DETERMINATION

8 INTERPRETATION CHARTS CHAPTER

9 EXAM AND MODEL SOLUTION

10 TUTORIAL

Formation Evaluation Petroleum Engineering


Self Potential Resistivity

Oil

Introduction To Openhole Logging O N E

1 INTRODUCTION

2 HISTORY

3 WIRELINE LOGGING3.1 Logging While Drilling (LWD)3.2 Measurement While Drilling (MWD)

4 LOG DATA ACQUISITION

5 DATA PROCESSING

6 DATA TRANSMISSION

7 LOG RUNS

8 LOG PRESENTATIONS


C O N T E N T S


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LEARNING OBJECTIVES

Having worked through this chapter the Student will be able to:

• Describevariousloggingtechniquesincludingwirelinelogging,logging whiledrilling(LWD)andmeasurementwhiledrilling(MWD).

• Describelogheadersandproceduresinvolvedinaloggingoperation.

• Describeprinciplesofloggingmeasurements,depthcorrelationand interpretationprocess.

Formation EvaluationPetroleum Engineering

2

1 INTRODUCTION

Electricalwellloggingwasintroducedtotheoilindustryoverhalfacenturyago.Sincethattime,manyadditionalandimprovedloggingdeviceshavebeendevelopedandputintogeneraluse.

Asthescienceofwellloggingadvanced,theartofinterpretingthedataalsoadvanced.Today,thedetailedanalysisofacarefullychosensuiteofwirelineservicesprovidesamethodofderivingor inferringaccuratevalues for thehydrocarbonandwatersaturation’s,theporosity,thepermeabilityindex,andthelithologyofthereservoirrock. Hundreds of technical papers have been written describing the various loggingmethods,theirapplication,andtheirinterpretation.Thisabundanceofliteratureisoverwhelmingincontentandfrequentlyunavailabletotheaveragewellloguser. This document therefore presents a review of these well logging methods andinterpretation techniques. The various openhole services offered by wirelineloggingcontractorsarediscussedinsomedetail, togetherwithessentialmethodsofinterpretationandbasicapplications.Thediscussioniskeptasbriefandclearaspossible,withaminimumofderivationalmathematics.

2 HISTORY

The first electrical logwas recorded in 1927 in a well in the small oil field ofPechelbronn,inAlsace,aprovinceofnorth-easternFrance.Thislog,asinglegraphoftheelectricalresistivityoftherockformationscutbytheborehole,wasrecordedby the “station”method. Thedownholemeasurement instrument (called sonde)wasstoppedatperiodic intervals in theborehole,measurementsweremade,andthecalculatedresistivitywashand-plottedonagraph.Thisprocedurewascarriedonfromstationtostationuntiltheentirelogwasrecorded.Sincetheresistivityoftheformationwasadirectindicationofthefluidcontainedintheporespaceoftheformation,thislogwasusedtodetectthepresenceofhydrocarbonsintheformation. In 1929, electrical resistivity logging was introduced on a commercial basis inVenezuela, theUnitedStates,andRussia,andsoonafterwards in theDutchEastIndies.Theusefulnessoftheresistivitymeasurementforwelltowellcorrelationpurposesandforidentificationofpotentialhydrocarbon-bearingstratawasquicklyrecognisedbytheoilindustry. In1931thespontaneouspotential(SP)measurementwasincludedwiththeresistivitycurveontheelectricallog.Inthesameyear,theSchlumbergerbrothers,MarcelandConrad,perfectedamethodofcontinuousrecordingandthefirstpenrecorderwasdeveloped. The photographic-film recorderwas introduced in 1936. By then, the electricallogconsistedofthe SP curve and short normal, long normal, and long lateral resistivity curves.Thiscombinationwaspredominantinloggingactivityfrom1936tothelate1950’s.Afterabout1946,thesecurveswererecordedsimultaneously.

Institute of Petroleum Engineering, Heriot-Watt University 3


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Thedevelopmentofadipmeter logbeganintheearly1930’swiththeanisotropydipmetertool.Thethree-armdipmeterdevice,withanassociatedphotoclinometer,wasintroducedin1943;itpermittedboththedirectionandangleoftheformationdiptobedetermined.EacharmcontainedanSPsensor.In1946,theSPsensorswerereplacedbyshort resistivity devices;thismadedipmeasurementspossibleinwellswheretheSPhadlittlecorrelatabledetail. The first continuously recording electrical dipmeter sonde, which used threemicroresistivity arrays and contained a fluxgate compass, followed in the mid-1950’s.Sincethen,numerousdevelopmentshavefurtherrefinedthemeasurementofformationdip.Today,afour-armdipmetertoolrecords10microresistivitycurvessimultaneously, and a triaxial accelerometer and magnetometers provide highlyaccurateinformationontooldeviationandazimuth.Theprocessingofthesedataintoformationdipinformationisnowdoneexclusivelywithelectroniccomputers. The gamma ray (GR) and neutron toolsrepresentedthefirstuseofradioactivepropertiesinwellloggingandthefirstuseofdownholeelectronics.UnlikeSPandresistivity tools, they are able to log formations through steel casing, aswell asinair-orgas-filledholesorinoil-basedmuds.TheneutronlogwasdescribedbyPontecorvoin1941. IncombinationwiththeGRlog,aneutronlogenhanceslithologicalinterpretationsandwell-to-wellstratigraphiccorrelations.Afterabout1949,attentionwasgiventotheneutronlogasaporosityindicator.However,theearlyneutronlogsweregreatlyinfluencedbytheboreholeenvironment.ItwasnotuntiltheintroductionoftheSNP sidewall neutron porositytoolin1962andtheCNL* compensated neutron tool in1970thattheneutrongainedacceptanceasaporositymeasurement.TheDualPorosityneutrontoolcombinesthosetwoneutronmeasurementsintoasingletool. Earlyattemptsatporositydeterminationemployedmicroresistivitymeasurements.TheMicrologtool,introducedintheearly1950’s,usesaminiaturelineararrayofthreeelectrodesimbeddedinthefaceofaninsulatingpad,whichisappliedtotheboreholewall.Aboreholecalliperisprovidedbythearmcarryingtheelectrodepadandanoppositebackuparm. The microlog recording is also useful to delineate permeable beds, and othermicroresistivitydeviceshelpestablishtheresistivityprofilefromtheinvadedzoneneartheboreholetothenon-invadedvirginformation.TheMicrolaterologtoolwasdevelopedforsaltmudsin1953.TheMicroProximitylogandMicroSFL*loghavefollowed.

In1951,thelaterologtool,thefirstfocuseddeep-investigatingresistivitydevice,wasintroduced.Itusesafocusingsystemtoconstrainthesurveyingcurrent(emittedfromacentralelectrode)tosubstantiallyahorizontaldiscforsomedistancefromthesonde.Focusedresistivitylogsarewelladaptedforinvestigationofthinbedsdrilledwithlow-resistivitymuds. Thelaterologdevicequicklysupplantedconventionalresistivitylogsinsaltmudsandhighlyresistiveformations.


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Overtheyears,severallaterologtoolsweredevelopedandusedcommercially.Today,theDLL*duallaterologtool,whichconsistsofdeeplaterologandshallowlaterologmeasurements,isthestandard.ItisusuallyrunwithaMicroSFLdeviceaswell. Infreshwatermuds,theoriginalelectricalloghasbeenreplacedbytheinductionlog.Theinductionlogwasdevelopedin1949,asanoutgrowthofwartimeworkwithminedetectors,foruseinoil-basedmud.However,itssuperiorityovertheelectricalloginfreshwatermudswassoonrecognised. By1956,afive-coilinductiondevicewascombinedwiththeSPcurveanda16-in.normaltomaketheinduction-electricaltool,In1959,thefive-coildevicewasreplacedbyonewithasix-coilarraywithdeeperinvestigation. TheDIL*dualinductionlog,introducedin1963,isnowthestandard.Itconsistsofdeepinduction,mediuminduction,andshallowresistivity-measurements.Theshallowresistivity-measuringdeviceisnowafocusedresistivitydevice—aLaterolog8onthe1963toolandanSFLdeviceoncurrenttools.Anewdualinductionlog,thePhasor*induction,providesimprovedthin-bedresponse,deeperdepthofinvestigation,andgreaterdynamicresistivityrange. Sincethe1930’s,loggingcableshavebeenusedtolowergeophonesintowellstomeasurelong-intervalacoustictraveltimesfromsoundsourcesatthesurface. Inthelate1950’s, thesonicloggainedacceptanceasareliableporositylog; itsmeasurementrespondsprimarilytoporosityandisessentiallyindependentofsaturation. Thesoniclog,coupledwiththefocusedresistivitylogs—laterologandinduction—madepossiblemodernformationevaluationfromwelllogs.Thesoniclogprovidedameasurement of porosity; the focused resistivity logs, ameasurement of trueresistivityofthenon-invadedvirginformation. SubsequentimprovementsinsonicloggingincludedtheBHCboreholecompensatedsonic,theLSS*long-spacedsonic,andtheArray-sonic*tools.Thelattertoolspermittherecordingoftheentiresonicwavetrain.Fromananalysisofthewavetrain,theshearandStoneleytransittimescanbeextractedaswellasthecompressionaltransittime. Theloggingofformationbulkdensity,anothermeasurementprimarilydependentonformationporosity,wascommerciallyintroducedintheearly1960’s.

AnFDC*compensatedformationdensitylog,whichcompensatedforthemudcake,quicklyfollowedin1964.In1981,theLitho-Density*logprovidedanimprovedbulkdensitymeasurementandalithology-sensitivephotoelectricabsorptioncrosssectionmeasurement. Therecoveryofphysicalrocksamplesandformationfluidsampleswithwirelinetoolsalsohasarichhistory.Sidewallcoring,usingahollow,cylindrical“bullet”shotintotheformationandretrievedbypullingitout,hasexistedsince1937.Obviously,thistechniquehasundergonecontinuousimprovementovertheone-halfcenturysinceitsintroduction.Forveryhardrocks,downholemechanicalcoringtoolsexistthatactuallydrillouttherocksamples.



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In1957,aformationtesterwasintroduced.Itrecoveredasampleoftheformationfluidsandtheporepressurewasmeasuredduringthesamplingprocess.The FIT formation interval testerandtheRFT*repeatformationtesterhavefollowed.Theoldertoolscouldmakeonlyonepressuremeasurementandrecoveronlyonefluidsamplepertripintothewell;theRFTtoolcanmakeanunlimitednumberofpressuremeasurementsandrecovertwofluidsamplespertrip. Tohandlethoseformationsinwhichtheformationwaterisfresh,orvariesinsalinity,orinwhichthesalinityisunknown,dielectricmeasurementshavebeendeveloped.TheEPT*electromagneticpropagationlogwasintroducedin1978;theDPT*deeppropagationlog,in1985. Theprecedinghistoricalsketchhasnot,byanymeans,coveredallthemeasurementsnowmadewithwirelinewellloggingdevices.Otherloggingmeasurementsincludenuclearmagneticresonance,nuclearspectrometry(bothnaturalandinduced),andnumerouscasedholeparameters.

3 WIRELINE LOGGING

Wirelineelectricalloggingisdonefromaloggingtruck,sometimesreferredtoasa“mobilelaboratory”(Figure1).

Self Potential Resistivity

Oil

Figure 1Wirelineelectricallogging.

Wirelinelogsaremadeusinghighlyspecializedequipmententirelyseparatefromthatusedfordrilling.Onshore,amotorizedloggingtruckisusedwhichbringsitsarrayofsurfacerecorders,computersandaloggingdrumandcabletothedrillsite.Offshore,thesameequipmentisinstalledinasmallcabinleftpermanentlyontherig.Bothtruckandcabinuseavarietyofinterchangeableloggingtools,whichareloweredintothewellontheloggingcable.


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Torunwirelinelogs,theholeiscleanedandstabilizedandthedrillingequipmentextracted.Thefirstloggingtoolstringisthenattachedtotheloggingcable(wireline)andloweredintotheholetoitsmaximumdrilleddepth.Mostlogsarerunwhilepullingthetoolupfromthebottomofthehole.Thecableattachedtothetoolactsbothasasupportforthetoolandasacanalfordatatransmission.Theoutsideconsistsofgalvanizedsteel,whiletheelectricalconductorsareinsulatedintheinterior.Thecableiswoundaroundamotorizeddrumontowhichitisguidedmanuallyduringlogging. Thedrumwillpull thecableatspeedsofbetween300m/h(1000ft/h)and1800m/h(6000ft/h),i.e.0.3to1.8km/h,dependingonthetoolused.Asthecableispulledin,sothedepthoftheworkingtoolischecked.Loggingcableshavemagneticmarkerssetatregularintervals(e.g.100ftor25m)alongtheirlengthanddepthsarecheckedmechanically,butapparentdepthsmustbecorrectedforcabletensionandelasticity.

Becauserigtimeisexpensiveandholesmustbeloggedimmediately,modernloggingtoolsaremulti-function.Theymaybeupto28m(90ft)inlength,butstillhaveanoveralldiameterofonly3-4in(althoughnew,shortertoolsarebeingprepared).TheSchlumbergerISFsonictool,forexample,of3indiameter,is55.5ft(16.9m)longandgivesasimultaneousmeasurementofgammarayorcaliper,SP,deepresistivity(conductivity),shallowresistivityandsonicvelocity.Thecomplexityofsuchtoolsrequirestheuseofthesurfacecomputer,notonlytorecordbutalsotomemorizeandtodepth-matchthevariousreadings.Thegamma-raysensor,forexample,isnotatthesamedepthastheresistivitysensorssoatanyoneinstant,differentformationsarebeingsampledalongthetool.Thesurfacecomputerthereforememorizesthereadings,compensatesfordepthortimelagandgivesadepth-matchedoutput.

Mostmodernlogsarerecordeddigitally.Thesamplingratewillnormallybeonceevery15cm(6in),althoughforsomespecializedlogsitwillbeaslowas2.5mm(0.1in).Anaveragewellofsay2000mwillthereforebesampledover12,000timesforeachindividuallog,andforasuiteof8orsotypicallogs,itwillbesampledover100,000times(althoughforsomenew,specialisedtools,thiscanbethesamplingratepermetre).Attypicalloggingspeeds,datatransmissionrateswillvaryfrom0.05kilobitspersecondforsimplerlogstoover200kilobitspersecondforthenewcomplexlogs.Thehugeamountofdatarepresentingeachloggingrunisfedintothecomputerofthesurfaceunit. Thereisgenerallyaninstantaneousdisplayforqualitycontrolandafullprint-outimmediatelythelogisfinished,buttherawdataarestoredonmagnetictapeforfutureprocessingandediting.

Despitetheuseofthecombinedtools,therecordingofafullsetoflogsstillrequiresseveraldifferenttooldescents.Whileaquick,shallowloggingjobmayonlytake3-4hours,adeep-hole,fullsetmaytake2-3days,eachtooltakingperhaps4-5hourstocomplete.

Well depths aremeasuredwith a calibratedmeasuringwheel system. Logs arenormallyrecordedduringtheascentfromthewelltoassureatautcableandbetterdepthcontrol. Thesurface instrumentationprovides theelectricalpower to thedownhole tools.Moreimportantly,thesurfaceinstrumentationreceivesthesignalsfromthedownholetools,processesand/oranalysesthosesignals,andrespondsaccordingly.



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Thedesiredsignalsareoutputtomagnetictapeindigitalformandtoacathode-raytubeandphotographicfilminanalyticalform. Thephotographicfilmisprocessedontheunit,andpaperprintsaremadefromthefilm.Thiscontinuousrecordingofthedownholemeasurementsignalsisreferredto as the log.

3.1 Logging While Drilling (LWD)Logging While Drilling (LWD) technique was introduced to provide similarinformationtowirelinelogging.However,asopposedtowirelineloggingwheretoolstringisloweredintothewellattheendofawirelinecableaftertheholeisdrilled,thesensorsinLWDareintegratedintodrillcollars(DC’s)andthemeasurementsaremadewhilethewellisbeingdrilled.LWDtoolsprovidedeviationandloggingoptionsinhigh-anglewells.Howevertheirgreatestadvantageistherealtimedataacquisitionatsurfacewhichsavesconsiderableloggingtimetothecompaniestoallowthemmakeimportantfielddevelopmentdecisionsmuchearlier.

EarlyLWDtechnologywasoftenconsideredtobeinferiortowirelineastheformerwasnotcapableofamorediverserangeofmeasurements.ThisisbecauseLWDtoolshavetobeveryrobustandstrongtohandlethetorque,compression,extension,andvibrationofdrilling,andcertaintools(iesonicetc)areexpensiveanddifficulttodeveloptohandlethiskindoftreatment.HoweverrecentdevelopmentsinLWDtoolshaveprogressedtothestagewheremostoftheconventionalwirelineloggingtools canpotentiallybe replacedbyaLWDequivalent.Someof the advantagesLWDtoolsoffer,whichjustifiestheiradditionalcostsandcomplicationsfordrilling,includethefollowing.

• Pre-invasionprofilesanddatapriortotheholewashingout(orifthereisariskoflosingthehole)isobtained.

• Realtimedataisobtainedforsteeringawelle.g.• Dataisobtainedinsituationswherewirelineacquisitionisdifficult(e.g.in

horizontalwells).

SomeoftheLWDtoolsthatarecurrentlyinuseincludethefollowing:

GR:naturalgammarayemissionfromtheformationDensity:formationdensityasmeasuredbygammarayComptonscatteringeffectandphotoelectriceffect(Pe)measurements.Neutron:formationporosityderivedfromthecollisionsofneutronswithhydrogenatomsintheformation.Sonic:thetransittimeofcompressional(P)wavesintheformationrockmatrix.Resistivity:theshallow,mediumanddeepinductionresistivitymeasurements.

Tools like nuclear magnetic resonance (NMR) and shear sonic are still underdevelopmentforLWDmode.Furthermorethingslikesidewallcoringandseismicarenotevenwithinthescope(atpresent)ofLWD.NodoubtLWDhaseateninwirelineovertheyearsandwillcontinuetodoso.Ideallywirelinewouldbereplacedbecauseitusesseveraldaysofrigtime.


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3.2 Measurement While Drilling (MWD) MWDtechnologywasfirstintroducedin1980’stoprovideinformationonwellboredirectionalsurveysandotherdrillingrelatedinformationinreal-timeduringdrilling.LikeLWD,MWDsystemswerebasedonmudtelemetrywherepressurevariationsinthemudpulseexercisedbythetoolweresensedbyacomputeronsurface.Thistechniquedoesnotallowaveryhighbandwidthtelemetrypathandsometimesthedataisrecordeddownholeandretrievedwhenthedrillstringisremovedfromthehole.Themudtelemetrymethodprovidesabandwidthofmuchlessthan100bitspersecond.Sincedrillingthroughrockisafairlyslowprocessanddatacompressiontechniquesmeanthatthisisanamplebandwidthforreal-timedeliveryofcriticalinformation.

Generally,MWDtoolsuseaccelerometersandmagnetometerswhichmeasurethetoolorientationwithrespecttotheearth'sgravitationalandmagneticfieldsandthisdataisthenconvertedintowellboreinclinationanddirectionbyasurfacesystem.BothLWDandMWDaresometimesconsideredassynonymousandamoreappropriatetermfortheseiscalledformationevaluationwhiledrilling(FEWD).

4 LOG DATA ACQUISITION

Wireline-loggingtechnologyisbeingchangedbytherapidadvancementsindigitalelectronicsanddata-handlingmethods.Thesenewconceptshavechangedourthinkingaboutexistingloggingtechniquesandremouldedourideasaboutthedirectionoffuturedevelopments. Basic loggingmeasurementsmay contain large amounts of information. In thepast, some of this data was not recorded because of the lack of high data-ratesensorsandelectronicsdownhole,theinabilitytotransmitthedataupthecable,andinabilitytorecorditintheloggingunit.Similarly,thoselimitationshavepreventedordelayedtheintroductionofsomenewloggingmeasurementsandtools. Withdigitaltelemetry,therehasbeenatremendousincreaseinthedataratethatcanbehandledbytheloggingcable.Digitalrecordingtechniqueswithintheloggingunitprovideasubstantialincreaseinrecordingcapability.Theuseofdigitisedsignalsalsofacilitatesthetransmissionoflogsignalsbyradio,satellite,ortelephonelinetocomputingcentresorbaseoffices. In Table 1 the data rate for one of the older tool systems, the induction-soniccombination,iscontrastedwiththedata-ratetransmissionrequirementsforsomeofthenewertools.Itillustratesthetremendousincreaseinthedataratethatcannowbehandledbythenewerdownholesensors,bytheloggingcable,andbythesurfaceinstrumentationasaresultofdigitaltechniques.



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ISF Induction-Sonic 200 Bits/Borehole Ft

High-Resolution Dipmeter 10 Dip Channels 25,000 Bits/Borehole Ft Array Sonic Full Waveform 60,000 Bits/Borehole Ft Inelastic Spectroscopy Energy Spectrum 20,000 Bits/Second Well Seismic Tool 5-Second Wavetrain 80,000 Bits/Second

Table 1Dataratetransmissionrequirementsofsomewellloggingtools.

5 DATA PROCESSING

Signalprocessingcanbeperformedatatleastthreelevels:downholeinthetool,upholeinthetruck,andatacentralcomputingcentre.Wheretheprocessingisdonedependsonwherethedesiredresultscanmostefficientlybeproduced,wheretheextractedinformationisfirstneeded,wherethebackgroundexpertiseexists,orwheretechnologicalconsiderationsdictate. Whereitseemsdesirable,theloggingtoolisdesignedsothatthedataareprocesseddownholeandtheprocessedsignalistransmittedtothesurface.Thisisthecasewhenlittlefutureuseisenvisionedfortherawdataorwhentheamountofrawdataprecludesitstransmission.Inmostcases,however,itisdesirabletobringmeasuredrawdatatothesurfaceforrecordingandprocessing.Theoriginaldataarethusavailableforanyfurtherprocessingordisplaypurposesandarepermanentlypreservedforfutureuse. Awellsitedigitalcomputersystem,calledtheCSU*unit, isnowstandardonallSchlumbergerunitsthroughouttheworld.Thesystemprovidesthecapabilitytohandlelargeamountsofdata.Itovercomesmanyofthepastlimitationsofcombinationloggingsystems(thestackingorcombinationofmanymeasurementsensorsintoasingleloggingtoolstring).Italsoexpeditesfieldoperations.Toolcalibrationisperformedmuchmorequicklyandaccurately,andtooloperationismoreefficientlyandeffectivelycontrolled. TheCSU system provides the obvious potential forwellsite processing of data.Processingofsonicwaveformsforcompressionalandshearvelocitiesisalreadybeingdone,asistheprocessingofnuclearenergyspectraforelementalcompositionand,then,chemicalcomposition.MoresophisticateddeconvolutionandsignalfilteringschemesarepracticalwiththeCSUsystem.


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NearlyallthecommonloginterpretationmodelsandequationsareexecutableontheCSUunit.Althoughnotquiteassophisticatedastheloginterpretationprogramsavailable in computingcentres, thewellsite interpretationprograms significantlyexceedwhatcanbedonemanually.Wellsiteprogramsexisttodetermineporosityandsaturationinsimpleandcomplexlithology,toidentifylithology,tocalculateformationdip,tocalculatepermeability,andtodeterminemanymorepetrophysicalparameters.Inaddition,data(whetherrecorded,processed,orcomputed)canbereformattedintheformmostappropriatefortheuser. Thecomputingcentreoffersamorepowerfulcomputer,expertloganalysts,moretime,andtheintegrationofmoredata.Schlumbergercomputingcentresarelocatedinmajoroilcentresthroughouttheworld.TheyprovidemoresophisticatedsignalprocessingandformationanalysisthanthewellsiteCSUsystem.Evaluationprogramsrangeinscopefromsingle-wellevaluationprogramstoaseriesofspecialapplicationproducts to reservoir description services that evaluate entire fields. Statisticaltechniquescanbeemployedmoreextensively,bothintheselectionofparametersandintheactualcomputations. Logprocessingseemstobemovingmoreandmoretowardintegratedtreatmentofalllogmeasurementssimultaneously.

Programsarebeingdesignedtorecognisethatthelogparametersofagivenvolumeofrockareinterrelatedinpredictableways,andtheserelationshipsaregivenattentionduringprocessing.Newprogramscannowusedatafrommoresources,suchascores,pressureandproductiontesting,andreservoirmodelling.

6 DATA TRANSMISSION

TheCSUsystemisabletotransmitlogswithasuitablecommunicationlink.ThereceivingstationcanbeanotherCSUsystem,atransmissionterminal,oracentralcomputingcentre.Datacanbeeditedorreformattedbeforetransmissiontoreducethetransmissiontimeortotailorthedatatotherecipient.Built-inchecksonthetransmissionqualityensurethereliabilityofthetransmittedinformation.

With theLOGNET*communications network, graphic data or log tapes canbetransmittedviasatellitefromthewellsitetomultiplelocations. ThisserviceisavailableinthecontinentalU.S.andCanada,onshoreandoffshore.Virtuallyanytelephoneisapossiblereceivingstation.

AsmalltransportablecommunicationsantennaatthewellsitepermitstransmissionofthewelllogdataviasatellitetoaSchlumbergercomputingcentreandthenbytelephonetotheclient’sofficeorhome.Sincethesystemistwoway,offsetlogsorcomputedlogscanbetransmittedbacktothewellsite.Thesystemalsoprovidesnormaltwo-wayvoicecommunication.Thereareseveralreceivingstationoptions:

AstandarddigitalFAXmachinewillreceiveloggraphicdatadirectlyattheoffice.



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APilot50*portabletelecopierpluggedintoastandardtelephoneoutletattheofficeorathomeallowsclientstotakeadvantageofthe24hourservice.

APilot100*logstationcanbeinstalledintheclient’sofficetoreceivetapeandloggraphicsandtomakemultiplecopiesoftheloggraphics.Sincethisstationisautomatic,itcanreceivedataunattended.

AnELITE1000*workstationcanbeinstalledintheclient’sofficetoreceivedatafromtheLOGNETcommunicationsnetwork.AcompletelibraryofenvironmentalcorrectionsaswellastheentirerangeofSchlumbergeradvancedanswerproductsareavailablewiththisnewworkstation.

APilot2000*computercentre,staffedwithaSchlumbergerloganalystandlogdataprocessor,canbeinstalledintheclientofficeforon-sitecomputerinterpretationofwelllogdata.ThiscentrehasaccesstoallthestandardSchlumbergerloginterpretationprograms.

Alldataareencryptedtoprovidesecuritywhiletransmittingovertheairwaves.

Other local transmission systems exist elsewhere in the world using telephone,radio,and/orsatellitecommunications.Insomeinstances,transmissionfromthewellsiteispossible.Inothers,transmissionmustoriginatefromamorepermanentcommunicationstation.Withsomepreplanning,itispossibletotransmitlogdatafromnearlyanypointintheworldtoanother.

7 LOG RUNS

Whenalogismadeitissaidtobe‘run’.Alogrunistypicallymadeattheendofeachdrillingphase,i.e.attheendofthedrillingandbeforecasingisputinthehole.Eachspecificlogrunisnumbered,beingcountedfromthefirsttimethattheparticularlogisrecorded.Run2oftheISFSonic,forexample,maycoverthesamedepthintervalasaFormationDensityLogRun1.InthiscaseitmeansthatoverthefirstintervaloftheISFSonic,(i.e.Run1),therewasnoFormationDensitylogrecorded.

Typically,throughanywell,morelogsarerunoverintervalscontainingreservoirsorwithshows,thanoverapparentlyuninterestingzones.Thechoiceoflogsdependsonwhatitishopedtofind.Loggingcosting5-10%oftotalwellcostsisexpensive,sothatincheap,onshorewells,inknownterrain,aminimumsetisrun.Offshore,whereeverythingisexpensive,fullsetsoflogsaregenerallyrun,evenifhydrocarbonsarenotfound,aseachwellrepresentshard-gainedinformation.Cuttingdownonwelllogsisprobablyafalseeconomy,butitcanbeforgivenwhenpricesareconsidered.

8 LOG PRESENTATIONS

AstandardAPI(AmericanPetroleumInstitute)logformatexists(Figure2a-d).Theoveralllogwidthis8.25in(21cm),withthreetracksof2.5in(6.4cm),tracks1and2beingseparatedbyacolumnof0.75in(1.9cm)inwhichthedepthsareprinted.Therearevariouscombinationsofgrid.Track1isalwayslinear,withtenstandard


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divisionsof0.25in(0.64cm).Tracks2and3mayhavea4cyclelogarithmicscale,alinearscaleof20standarddivisions,orahybridoflogarithmicscaleintrack2andlinearscaleintrack3.

TRACK 1 TRACK 2 TRACK 3

LINEAR

LOGARITHMIC

LOGARITHMIC LINEAR

SPLIT

2600

2700

2800

Figure 2aStandardlogpresentationformats.



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Spontaneous Potential

Caliper - Gamma Ray

SP (MV)-180.0 20.00

DEPTH


SPONTANEOUS POTENTIALMILLIVOLTS

10+-

DEPTH

TRACK 1

CALIPER

GAMMA RAY

TRACK 2 TRACK 3

DIAM. IN INCHES188

100

API UNITS

0D

EPTH


Figure 2bPresentationofSPandGRlogheadingsusedforcleanformationdetermination.

Induction

DEPTH


ILD(Ωm)2000.0.2000

2000.0.2000

2000.0.2000

ILM(Ωm)

SFLU(Ωm)

Rxo

RILM

RT

Figure 2cTheinductionlogheadingandschematicoftheformation,withthreezonescorrespondingapproximatelytothesimultaneouselectricalmeasurementsofdifferent

depthsofinvestigation.


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Neutron - Density

Sonic

NPHI (SS) -0.150

-0.1500.4500

-0.1500.4500DPHI (SSI)

DEPTH


50

MICROSECONDS PER FOOT∆T

150

DEPTH


POROSITY INDEX %

CORRECTION

INTERVAL TRANSIT TIME

01530

55 MATRIXCOMPENSATED FORMATION DENSITY POROSITY

COMPENSATED NEUTRON POROSITY

FIELD PRINT SECTION

4560

01530

+ .250- .25

GRAMS CC

Use this scale when correctioncurve is presented in Track 3

4560

DEPTH


Figure 2d Logheadingsforthreeporositydevices.Thetoptwocorrespondtotwopossibleformatsforsimultaneousdensityandneutronlogs.Thebottomisthesoniclogformat.

Thesearetheclassicpresentationswhich,inthepast,usuallyprevailed.Withtheadventofdigitisedlogs,non-standardformatsarebecomingmorecommon,especiallyoncomputerplaybacks.

Ontheoldanalogloggingsystems,thechoiceofverticalordepthscaleswaslimitedtotwoof1:1000,1:500,1:200,1:100,1:40and1:20.Fromthese,themostfrequentscalecombinationswere1:500(1cm=5m)forrésuméorcorrelationlogsand1:200(1cm=2m)fordetailedreservoirpresentation.

TheAmericanareawasanexception,wheretheavailablescaleswere1:200,1:600,1:240and1:48.Fromthesethecommonly-chosenscaleswere1:600(1in=100feet)forrésuméandcorrelationlogs,and1:240(5in=100feet)fordetail.

Thesescalesstilldominateindustrydocuments,butasaresultofmoderncomputerstorageotherscalesarebecomingmorecommon.Especiallyusefultothegeologistarethereducedscalesof1:2000(1cm=20m)and1:5000(1cm=50m).Infactanyconvenientscalecannowbeproducedeasilybythecomputer,whereasinthepastscalechangescouldonlybemadebyunsatisfactoryphotographicmethods.



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Onefinalaspectoftheloggridtonotearemarkerswhichindicaterealtimeduringlogging.OnSchlumbergerlogs,timeisindicatedbythedashedgridmarginsonthefieldprints.Eachdashrepresentsoneminute,regardlessoflogscale.Othercompaniesuseticksorspikesonthegridforthesamepurpose.Timemarkersallowadirectcontrolofloggingspeedand,indirectly,logquality.

Everyloggridisprecededbyacomprehensivelogheading.Itcoversallaspectswhichallowtheproperinterpretationofthelogand,inaddition,identificationofthewell,rig,loggerandloggingunit.Thelogheadingillustrated(Figure3)isbutoneexample,eachcompanyhavingitsownformat.

Figure 3Asamplelogheadingfortheduallaterolog.

On the log tail is found a repetition of some of the log-head data, simply forconvenience.Calibrationdataarealsoaddedtothelogtail,asareshort,doubled-uporrepeatsectionswhichactassamplesforempiricalqualitycontrol.


16


X5

Pres

sure

Temperature

% Liquid

Gas

(Gas)Black

Oil Volatile

Oil Gas

Condensate Gas

TM2

75

100

50

25201510

50 Single Phase Region

Single Phase Region(Liquid)Single Phase Region

Two Phase Region

CP

Where:

Pb = Bubble point pressure at indicated temperature

Pm = Maximum pressure at which two phases can coexist

Tm = Maximum temperature at which two phases can coexist

C = Critical conditions

X5 = Cricondentherm

Bubble Point Line

Dew Point Line

Pm

PbA

BC

Y1

Y2

1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

01.00.90.80.70.60.50.40.30.20.10

SW, Water Saturation, Fraction

Rel

ativ

e P

erm

eabi

lity

k ro

k rw

Rock and Fluid Properties T W O

22/10/13


C O N T E N T S


1 INTRODUCTION

2 ROCK CLASSIFICATION SYSTEM

3 POROSITY3.1 Primary Porosity3.2 Secondary Porosity

4 SATURATION

5 PERMEABILITY5.1 Darcy's Law5.2 Effective Permeability5.3 Relative Permeability

6 CAPILLARY PRESSURE

7 FLUID PROPERTIES

8 WATER SALINITY

9 DETERMINATION OF FORMATION TEMPERATURE

22/10/13


2

LEARNING OBJECTIVES


• Distinguishbetweenthemainrelevantrocktypesandfluidproperties(singlephaseandmixedphase).

• Define the terms primary porosity, secondary porosity, fluid saturation,permeability(effectiveandrelative)andDarcy'sLaw.

• Describethetermscapillarypressure,watersalinityandformationtemperature.



1 INTRODUCTION

Theresponsetomeasurementsmadewithpetrophysicalloggingtoolswilldependontheformationbeinginvestigated.

Thefirststepintheinterpretationoftheloggingdataistodeterminethetypeofrockwhich isbeing logged.Thenextstep is todetermine theporosity,saturation,andpermeabilityoftherocks.

Rocksareclassifiedinaveryspecificwayforthepurposesofwellloginterpretation.Evaluation of reservoir rocks or potential reservoir rocks requires basically threepiecesofdata:

• Porosity - thecapacityoftherocktocontainfluids;• Saturation - therelativeamountsofthesefluids;and• Permeability - theabilityofthefluidstoflowthroughtherocktothewell

bore.Separationofthehydrocarbonsintoeithergasoroil isoflessersignificance.

2 ROCK CLASSIFICATION SYSTEM

Thisclassificationsystemusesapseudo-rockchemistryclassification.Themethodisveryusefulsincemanyoftheresponsesfromwellloggingtoolsreflectphysicalandchemicalpropertiesoftherocks.Howevertheclassificationsystem,basedonchemistry,mustbeclearlydefinedsothatitcanberelatedtothegeologicaldescriptionoftherocks.Thisclassificationisusedextensivelyintheevaluationoflogsandinparticularinthechartsusedforinterpretation.

Thisclassificationsystemisbasedonthefollowingcategoriesofrocks:

• Sandstones–SiO2;• Limestones–CaCO3;• Dolomite–CaCO3MgCO3;• NaCl,Anhydrite,Gypsum,Clay

Onthisrockchemistrybasis,sandstones are SiO2.Therefore,anythingthatisSiO2 showsuponwelllogsassandstone.Sincetheclassificationisonapurelychemicalbasisandnotonagrainsizebasis,siltisconsideredasaverysmallgrainedsandstone.Chertisalsoclassifiedasasandstonealthoughthecrystalstructureisdifferentitlookslikesandstoneonwelllogs.

Limestoneiscalciumcarbonate(CaCO3).Sincechalkresultsinthesameresponseonlogsascalciumcarbonate,itisclassifiedasalimestone.

Dolomite (CaCO3MgCO3) differs strongly from limestoneonwell log readings.Physically, dolomite differs from limestone significantly in density, hardness andotherproperties.

22/10/13


4

NaCl, Anhydrite, Gypsum and Clay are relatively common rocks, but differsignificantlyfromsandstone,limestoneanddolomite.Haliteiscommontablesalt,(NaCl)andwillrecordasNaCl.Anhydriteiscalciumsulphateandalthoughgypsumiscalciumsulphatepluscrystallinewater,thewateringypsumcreatesalargedifferencebetweenthetwologresponses.

Theonlyapparentmaverickinthesystemisshale,whichinrealityisclay,andisclassifiedasclay.Forgeneralusage,thereisnoneedtodifferentiatebetweenthevariousclaymineralswhichmakeupshalesaslongascleanshalesareconsideredasbeingclay.

Afewrocktypeshavebeenomittedbuttheseomissionsarenotconsideredserious.Forexample,aconglomerateisnothingmorethanagrainsizevariationofsandstone,limestoneswithregular,sphericalgrainsarenotclassifiedassandstonesbutaslimestone.

3 POROSITY

Theporosityofarockisthepercentageofrockgrossrockvolumethatisnotmadeupofmatrixmaterial.Porositycanhoweverbesubdividedintoprimaryandsecondaryporosity.

3.1PrimaryPorosityPrimaryPorosity,usuallyrelatedtogranular,istheporositydevelopedbytheoriginalsedimentationprocessbywhichtherockwascreated.Forallpracticalpurposes,porosityisthenon-solidpartoftherock,filledwithfluids.Porosityisreferredtointermsofpercentages,whileincalculationsitisalwaysanumberlessthanone.Porosity,bydefinition,isthevolumeofthenon-solidpartoftherock(thatfilledwithfluids)dividedbythebulkvolume.

Bulk VolumeRepresentation

Grain VolumeRepresentation

Pore VolumeRepresentation

= +

Figure 1Diagramandequationofporosity.



Porosity Void volumeBulk volume

P

= x

orosity = Bulk v

100

oolume - Grain volumeBulk volume

x

Porosity pore v

100

=oolume

void volume+grain volume× 100

Figure 2 Columnstackingofrockgrains-Porosity=47.6%.

Figure 3Closepackingofrockgrains-Porosity=25.9%.

Toacquirea feel for thevaluesofporositygenerallyencountered, assumesomemarbles,allthesamesize,arestackedontopofeachotherincolumns.Calculationswillshowaporosityof47.6%(Figure2).Sphericalsandgrains1/10thesizeofthemarblesstackedoneontopoftheotherwillhavethesameporosity,47.6%.Ifthesamemarblesarepackedintheclosestpossiblearrangementinwhichtheuppermarblesitsinthevalleybetweenthefourlowermarbles,eachtouching,theporosityisreducedto25.9%(Figure3).Again,changingthesizeofthemarbleswillnotchangetheporosityaslongasallthemarblesarethesamesize.

Thehighestporositynormallyanticipatedis47.6%.Amoreprobableporosityisinthemid-twenties.Inreality,porosity’sgreaterthan40%arerare.Thesemaybefoundinsurfacesandsthatareneithercompactednorconsolidate.Porosityreductionoccurswithdistributionofgrainsizessothatsmallergrainsfitbetweenlargergrains(Figure4).Also,non-sphericalshapesfittogetherbetter.Thisisclosertotherealsituation.Thenormalrangeofporosityingranularsystemsisfrom10%-35%withtheactualcompleterangebeingfrom3%to40%.

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6

Ingeneral,porositiestendtobelowerindeeperandolderrocks.Thisdecreaseinporosityisdueprimarilytooverburden,time,stressesontherock,andcementation.Therearemanyexceptionstothisgeneraltrendwhennormaloverburdenconditionsdonotprevail.Shalesfollowverymuchthesameporosity/depthtrendassandstonesexceptthatporositiesarenormallylowerinshales.Forexample,inarecentmudtheporositymeasuresabout40%.Itdecreasesrapidlywithdepthandoverburdenpressureuntil,atabout10,000feetdepth,normalporositiesarelessthan5%.ThisistypicalofTertiaryshales,witholdershalesbeingconsiderablymorecompactedandthus lower inporosity. Shalesareessentiallyplasticandthereforecompressmoreeasilythansands.Thesebasictrendsofporosityversusdeptharenotreallynoticeableincarbonates,whichtendtobepseudo-plasticandcompressconsiderablymorethansands.

Pore Space

Figure 4Impactofsortingonporosity.

3.2SecondaryPorositySecondaryPorosityiscreatedbyprocesseswhichoccurafterdeposition.Anexampleof secondary porosity can be found in limestones orDolomiteswhich has beendissolvedbygroundwaters, aprocesswhichcreatesvugsorcaverns (Figure5).Fracturing and dolomitizationalsocreatesecondaryporosity.Dolomitizationistheresultoftheshrinkingofsolidvolumeasthematerialtransformsfromlimestonetodolomite.Inmostcases,secondaryporosityresultsinmuchhigherpermeabilitythanprimarygranularporosity.



Figure 5 Secondary Porosity in Limestone.

4 SATURATION

Saturationofanygivenfluidinaporespaceistheratioofthevolumeofthefluidtothetotalporespacevolume.Forexample,awatersaturationof10%meansthat1/10oftheporespaceisfilledwithwater.

Whereporosityisthecapacitytoholdfluids,saturationisthepercentageorfractionofthistotalcapacitythatactuallyholdsanyparticularfluid.Porosity,hydrocarbonsaturation,thethicknessofthereservoirrockandthearealextentofthereservoirrockallcontributetothetotalhydrocarbonsinplace(Figures6and7).Theseestablishtheeconomicpotentialofanygivenreservoir.

Oil Water

Figure 6Reservoirrock-saturationwithdifferentfluids(oilandwater).

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8

Oil Water Gas

Figure 7Reservoirrock-saturationwithdifferentfluids(oil,waterandgas).

Ofthetotalvolume(barrelsormillionsofcubicfeet)ofgaspresentinareservoir,the percentage that is produced depends on the recovery factor. This recoveryfactor,normallydeterminedbyexperience,istypicallyinthe20%-50%range.Theproducedoilmustbeabletopayforthecostofdrillingandcasingthewellandothermiscellaneousexpenses,aswellassupplyaprofit.

5 PERMEABILITY

Permeabilityreferstotheeasewithwhichfluidsflowthroughaformation.Itisnotsufficienttohaveoilorgasinaformation,thehydrocarbonsmustbeabletoflowfromthereservoirintothewellboreinordertoberecoveredatthesurface.Permeabilityisaphysicalcharacteristicofanygivenrock.Generally,permeabilityismeasuredbyflowingfluidsthroughtherockunderknownconditions.Todeterminethepermeabilityofarockformation,severalfactorsmustbeknown:thesizeandshapeoftheformation;itsfluidproperties;pressureexertedonthefluid;andtheamountoffluidflow.Thegreaterthepressureexertedonthefluid,thehighertheflowrate.Themoreviscousthefluid,themoredifficultitistopushitthroughrock.Forexample,itisalotmoredifficulttopushhoneythrougharockthantopushairthroughit.

5.1D'Arcy'sLawPermeabilityisameasureoftheabilityofporousmaterialtotransmitfluid.TheunitofmeasurementistheDarcy,namedaftertheFrenchhydrologistwhoinvestigatedflowofwaterthroughfilterbedsinordertodesignthepublicdrinkingfountainsofthecityofDijonintheyear1856.

However,Henrid'Arcywasusingcleanwaterinhisexperiments.Subsequently,itwasHenriPoiseuilles,whonotedthatviscositywasalsoinverselyproportionaltotheflow-rate.Henceitwasessentialtoincludeatermforviscosity,m incentipoise,intheDarcyequation.

Q =

k A ∆P µ



Onedarcyisdefinedasthatpermeabilitythatwillpermitafluidofonecentipoiseviscositytoflowatarateofonecubiccentimetrepersecondthroughacross-sectionalareaof1squarecentimetrewhenthepressuregradientisoneatmospherepercentimetre.

where:

Q = flowrateoffluid(cm3/sec) k = permeability(Darcy) A = cross-sectionalarea(cm2) DP = pressurechange(atmospheres) l = length(cm)

Inpracticalunits,oneDarcypermeabilitywillyieldaflowofapproximatelyonebarrel/dayofonecentipoiseoilthroughonefootofformationthicknessinawellborewhenthepressuredifferentialisaboutonepsi.

Darcy'sLawisusedtodeterminepermeability,whichisaconstantwhenthefollowingboundaryconditionsaremet:

1 Linear-laminarflow 2 Noreactionbetweenfluidandrock 3 Onephasepresentat100percentpore-spacesaturation 4 Incompressible

Because of the relatively high value of the base-unit, the millidarcy mD, (onethousandth,1/1000,ofaDarcy)iscommonlyinuseinreservoirdescription.TheDarcyhasaSIequivalentinthemm2.Formationpermeabilitiestypicallyvaryfromafractiontomorethan10,000millidarcies.

Permeabilitiesnormallyencounteredinreservoirrocksarefromlessthanonemillidarcytoabout50,000millidarcies.Thepermeabilityofanyrockisgovernedprimarilybythesizeofthepores.Thelargertheporesize,thehigherthepermeability.Forexample,onefour-inchdiameterpipewillhaveahigherpermeabilitythanabundleofquarter-inchdiameterpipeswiththesameflowcrosssectionalarea.Thetortuosity ofthepaththefluidtakesgoingfromoneendoftherocktotheotheralsodeterminespermeability.Thisisduetothefluidflowingaroundallthesandgrainsratherthaninastraightlinefromoneendofthecoretotheother.

Insandstones,controllingfactorsonpermeability include thepercentageofclay,grainsize,sorting, thepresencecementsandfractures.Thegammaraylogoftencorrelateswiththeamountofclay,whilsttheporositylogsoftenpin-pointcemented(lowpermeability)zones.

Althoughtheremaybeacorrelationbetweenincreasingpermeabilitywithincreasingporosity,thisdoesnotnecessarilyholdforanygivensituation.Anexamplecanbefoundintheearlierdiscussionsinwhichthesandgrainswerestackedoneontopoftheotherandhadaporosityof47.6%.Ifthesandgrainsarelarge,theporediametersarelargeandthepermeabilityisveryhigh.

22/10/13


10

Reducethesizeofthesandgrainsbyafactorof100andthepermeabilityisconsiderablysmallerbecausethediametersoftheporesareconsiderablysmaller.Further,smallerporesmeanlargersurfaceareasaroundthem,andthereforemoreresistancetoflow(lowerpermeability).Anotherexampleisinvuggytyperocksinwhichtheporesareoftenlargeandpermeability’sveryhigheventhoughtheporositymaybeonly5%-10%.

Thepermeabilityoffractureshasbeenshowntobealmostapurefunctionofthewidthofthefracture.Aroughrelationshipforpermeabilityversuswidthoffracturecanbeshownas:

k=54,000,000xWidth

Therefore,afracture.001inchesinwidthhasapermeabilityof54,000millidarcies.

Theveryhighpermeabilitycreatedbyaverysmallfractureisthereasonthatfracturessignificantly affectproductioncapabilities in reservoirs. One small fracture in areservoirwillresultintheproductionofmostofthefluidsfromthefractureareaasthefractureactslikeapipelinethroughtheformation.Equivalently,ifaformationisfracturedwhiledrilling,thehighpermeabilityofthefractureresultsinthehighflowofdrillingfluidsintotheformation.

Whenonlyonefluidispresentintheporesthepermeabilityoftheformationiscalledtheabsolutepermeability.

5.2EffectivePermeabilityTheeffectivepermeabilitytoanygivenfluidinarockreferstopermeabilitywhenmorethanonefluidispresent.Effectivepermeabilityislessthanabsolutepermeabilitybecausethepresenceofasecondfluidreducestheeffectiveporediameteravailableforfluidflow.

Inthecaseofareservoirwhereonlywaterispresent,thepermeabilitymeasuredwillbeabsolute.Inthecasewhereoilandwaterarepresentandtheoilisflowing,theeffectivepermeabilityoftheoilwillbelessthanabsolutepermeability.Thisisduetothewaterreducingtheeffectivediametersoftheporesthroughwhichtheoilisflowing.

5.3RelativePermeabilityRelativepermeability is the ratioofeffectivepermeabilityofa specificfluid toabsolutepermeability.Relativepermeabilitycurvesreflectthecapacityoftherocktoproducegivenfluidsbyshowingthepermeabilityofthosefluidsasafunctionofsaturation(Figure8).Thus,inatypicalrelativepermeabilitycurve,itwillbeseenthatatlowwatersaturationsonlyoilwillflow.Asthewatersaturationincreases,therelativepermeabilityofoildecreasesuntilsomecriticallevelisreached,atwhichpointbothoilandwaterflow.Theoilflowcontinuestodecreaseandthewaterflowtoincreaseaswatersaturationincreases.Atsomelevelofwatersaturation,theoilnolongerflowsandonlywaterflows.Beyondthispoint,aswatersaturationincreases,theflowofwaterwithinthecorecontinuestoincrease.



1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

01.00.90.80.70.60.50.40.30.20.10

SW, Water Saturation, Fraction

Rel

ativ

e P

erm

eabi

lity

k ro

k rw

Figure 8DiagramofRelativePermeability.

In either case, the amount of fluid flowing is not a direct effect of the relativepermeabilityasdifferentfluidshavedifferentviscosities.Forexample,ifgasandoilhaveequalrelativepermeabilities,moregasthanoilwillflowwithintherockbecauseofthedramaticdifferenceinviscosity.

6 CAPILLARY PRESSURE

Reservoirrocksarecomposedofmanycapillariesofvaryingsizes.Capillarypressureisthephenomenonbywhichwateroranywettingliquidisdrawnupintoacapillary.Thesmallerthecapillary,thehighertheliquidrises.

Duetothevarietyofcapillarydiameters,thewatersaturationexistingwithinarockabovethewatertablevaries(Figure9).Thepermeabilityofarockisdeterminedbythesizeofthecapillariesintherock.Thesecapillariesalsodefinetheirreduciblewatersaturation,whichisthewatersaturationthatexistsabovethetransitionzone.Thetransitionzoneisthezonewhichdisplaysachangeinthewatersaturationwithheight.

Mostoftenitisconsideredtheregioninwhichbothwaterandoil(orgas)flow.Themoresmallcapillariesthereare,thehigherthewatersaturation,andthelongerthetransitionfromirreduciblewatersaturationtoallwater.Thelargertheporespaces,thefewerthesmallcapillaries,thetransitionzoneisshorter.

22/10/13


12

Oil

Sand Grain

Pc

Water

WOC

FWL0% Water Saturation 100%

Transition Zone

hDt

h

Figure 9CapillaryPressureandSaturation.

7 FLUID PROPERTIES

Hydrocarbonsexistingwithin reservoirsarecombinationsofcompoundssuchasmethane,propane,butaneandpentane.Intheoilbusiness,oilandgasarereferredtoasiftheyareseparateanddistinguishableitems.Theyareproducedeitherasliquidorgasatsurfacetemperatureandpressure.Thecutbetweenliquidandgasoftendependsonthemethodofseparationusedatthewellsite.

In the reservoir,oil andgasarenotdistinguishableas separateentitiesbut are asystem.Onewaytodefinethissystemiswithapressure-temperature(P,T)diagramwhichdescribestheconditionsofthematerialinthereservoiratanygivenpressureortemperature(Figure10).Forexample,thehydrocarbonsexistingunderthepressureandtemperaturethatwouldputtheminthe“A”partoftheP,Tdiagramareundersaturatedoils,(liquid).Thoseexistinginthe“B”areaaregases.Thehydrocarbonfluidsintheenvelope“C”existasbothoil(liquid)andgas.Thelocationwithin“C”determinesthevolumetricratiobetweengasandoil.Everyparticularoilorhydrocarbonsystemhasitsownpressure/temperaturephasediagram.Thecompositionofthehydrocarbondeterminestheshapeandlocationofthetwo-phaseenvelope.



X5

Pres

sure

Temperature

% Liquid

Gas

(Gas)Black

Oil Volatile

Oil Gas

Condensate Gas

TM2

75

100

50

25201510

50 Single Phase Region

Single Phase Region(Liquid)Single Phase Region

Two Phase Region

CP

Where:

Pb = Bubble point pressure at indicated temperature

Pm = Maximum pressure at which two phases can coexist

Tm = Maximum temperature at which two phases can coexist

C = Critical conditions

X5 = Cricondentherm

Bubble Point Line

Dew Point Line

Pm

PbA

BC

Y1

Y2

Figure 10PhaseBehaviourofFluid.

Whereatwophasesystemexists,afreegasandafreeliquidphase,thetwoareincontactbutnotnecessarilyinadispersedcondition.Inthisstate,theoilsarecalledsaturated.Thatis,theyhaveinsolutionallthegastheycanholdatthatparticularpressureandtemperature,andoftenexistasanoilfieldwithagascap.ThesizeofthegascapisdependentuponitslocationintheP,Tenvelope.Forexample,ifitwasonthe75%line,oilvolumewouldbe75%andgasvolume25%ofthereservoir.Itshouldbenotedthatthereisnodistinctbarrierbetween“A”and“B”.Theareathatseparates“A”and“B”ismiscibleinthesensethatitisimpossibletotellwhenthematerialgoesfromliquidtogas;withinthisregionarethecondensatereservoirs.

Everyparticularhydrocarbon systemhas itsownP,Tphasediagram. WhatwillhappenduringthelifeoftheoilorgasfieldcanbedeterminedfromtheP,Tdiagram.Forexample,assumethepressure/temperatureissuchthattheoilfieldisproducedataconstanttemperatureconditionwherejustthepressureisreduced.Aspressuredrops,thefluideventuallyreachesthebubblepointlinewhichseparates“A”from“C”.Havingoncecrossedthebubblepointline,thereservoirthendevelopslargerandlargeramountsofgasorinmanycases,developsagascap.

Agascapdevelopsonlywhentheverticalpermeabilityinthereservoirislargeenoughtoallowthegastomoveupward.Thispresumesthesystemisclosedandthereisnowaterencroachment. If thereservoir is initiallyat“Y1”on thischartand thepressuredrops,asshowngoingfrom“Y1”to“Y2”,thereservoirfluidschangefromasinglephasetoatwo-phaseliquidandgas,andthentoasinglegasphase.Thisisaretrogradecondensationsysteminwhichyoufirstdeveloptheliquidswithinthereservoirasthepressuredrops.Asthepressurecontinuestodrop,thereservoirfluidbecomesasinglephasegasandendsupagasfield.

Anoilbeingproducedfromthereservoirtothesurfacehasbothpressureandtemperaturereduction,andwillchangefromaliquidtoacombinationofgasandliquid.

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14

ThephenomenaoccurringisverymuchliketheCokebottlephenomena.Asthewellisagitated(thepressuredropped),thegascomesoutofsolution.ACokebottlethathasbeenagitated,whenyoutakethetopoff,blowsCokeeverywhere.ThegasintheCokeiscomingoutofsolutionandrepresentsthedrivingforcethatpushedtheCokeoutofthebottle.Anoilfieldisessentiallytheequivalentwiththenaturalgasforcingtheoiloutoftheformation.

8 WATER SALINITY

Thewatersinreservoirsintheearthvaryfromfreshtosaltsaturatedsolutions.Nearthesurface,watersaregenerallyveryfreshwithlowsodiumchlorideconcentrations.Deeper,thewaterstendtobecomesaltieruntilsomemaximumconcentrationoccursandthewateroftenbecomesfresher.

Thesalinityofthewaterisaresultnotonlyofitsverticalpositionintheearth,butalsotheageoftherocksandthephysicalpositionoftherocksrelativetosurfaceoutcrops.Salinitiesusedaregenerallyinpartspermillionbyweight.Intheloggingbusiness,sodiumchlorideconcentrationsgenerallyareused.Atnormalroomtemperatures,250,000ppm(partspermillion)isasaturatedsolution,whileathighertemperaturesthesaturationpointforwatersishigher.Forexample,at300degreesC,a300,000ppmsodiumchloridesolutionissaturated.

9 DETERMINATION OF FORMATION TEMPERATURE

Itisoftennecessarytoknowtheresistivityofformationwatersandthedrillingmudatthedepthofsomeformationofinterest.Theresistivityofaqueoussolutionsisafunctionoftemperature.Itisthusnecessarytobeabletodeterminetheapproximatetemperatureinawellboreatanygivendepth.

Thelogicisverystraightforward.Ameansurfacetemperaturecanbeobtainedorestimatedforanygivenlocation.Amaximumreadingthermometerisrunwiththelogginginstrumentandthetemperaturereportedonthelogheading.Thismaximumtemperaturereadingisassumedtobeobtainedattotaldepthorthemaximumdepthatwhichtheloggingtoolstopped.Thetemperaturebetweenthesurfaceandthedepthatwhichthemaximumtemperatureisrecordedisassumedtochangelinearly.Theassumptionthatthegeothermalgradient(therateatwhichtemperatureincreaseswithincreaseddepth)islinearisagoodapproximation.

Sometimesthemaximumtemperatureintheboreholeislessthantheactualformationtemperatureduetothecoolingeffectofcirculatingmudwhiledrillingthehole.Ifthisisaproblem,multiplerunswiththemaximumreadingthermometershouldbemadetodetermineastabilisedtemperature.Thenormalapproachistoassumebottomholetemperatureandformationtemperatureareequal.


FORMATION

Shale

Gas

Gas

Gas

Gas

Water

Water

Shale

Shale

Sand

Shaley Sand Grading to Shale

Sand(Uncompacted)

Sand(Uncompacted)

Sand(Compacted)

Sand(Compacted)

SATURATION GR ρ ∆t φn

Summary of Procedures Used in Interpretation T H R E E

Sandstone

20

10

00

30

20

10

30

0

20

10

30

Limestone

Dolomite

2.1

0.10.3

0.50.70.8

B

A

2.3

2.5

2.7

2.90 10 20 30

rb

rh

fN

22/10/13

1 INTRODUCTION

2 CORRELATE AND DEPTH MATCH LOGS

3 INTERPRET LITHOLOGY

4 IDENTIFICATION OF PERMEABLE AND NON-PERMEABLE ZONES FROM LOGS

5 DETERMINE AND DIVIDE THE FORMATIONS INTO WATER BEARING AND HYDROCARBON BEARING ZONES

6 DETERMINE THE POROSITY OF THE ZONES OF INTEREST

7 DETERMINATION OF SATURATION


C O N T E N T S


22/10/13

LEARNING OBJECTIVES


• Describe in general terms how to interpret logs, lithology, permeable and non-permeable zones, and water bearing and hydrocarbon bearing zones.

• Describe which logs can be used to determine porosity and water saturation.

• Correlate and depth match marker beds using the gamma ray log.


2

1 INTRODUCTION

The objective of well logging is to determine the properties of the rocks which are potential sources of hydrocarbons. The logs are used to determine specifically :

• Lithology of Formation • Porosity• Fluid Content• Saturation

The interpretation process can be summarised into the following headings:

• Correlate and depth match Logs• Interpret Lithology• Identify the permeable and non-permeable beds on the logs • Determine and Divide the beds into zones consisting of water bearing and

hydrocarbon bearing zones• Determine the porosity of the zones of interest• Determine the hydrocarbon saturation of the zones of interest

2 CORRELATE AND DEPTH MATCH LOGS

The suite of logs which have been produced must be correlated, to ensure that the petrophysical measurements made in a particular formation by the sondes are all represented at the same depth. This is necessary because the sondes are stacked upon each other in a particular logging tool and only a certain number of sondes can be run in any particular tool. Hence the sondes are making the measurements at different points in time as the tool is being extracted from the well. If the sondes were all at the same depth, at the same time, when making the measurements then correlation would not be necessary.

The correlation of logs is usually performed on the basis of the Gamma Ray Log, since the gamma ray log is generally run with each logging tool run in hole and measurements made by the sondes on a particular logging tool are depth matched automatically. This means that all log measurements are automatically aligned with the Gamma Ray log and therefore depth correlation of the Gamma Ray log from one logging tool with the Gamma Ray log from another tool will ensure that all logs on both tools are depth correlated.



22/10/13

The procedure is as follows (Figure 1) :

Marker

Flow Unit 1

Flow Unit 2

Charts continue for wells 3 & 4

Figure 1

a. Place the logging suites side by side.b. Identify a distinct marker bed on the Gamma Ray log of each suite of logsc. Shift the suites of logs up or down until the marker beds are aligned in terms

of depth

All of the logs will now be aligned with respect to depth and the measurements from each tool at any particular depth can be assumed to represent the properties of the same formation.


4

3 INTERPRET LITHOLOGY

The lithology of the formations which have been drilled through is not always immediately obvious from the logs which have been run. However in virtually all exploration and appraisal wells the interpretation of the lithology will be supported by evidence which is derived from drilled cuttings by the mudlogging engineer or wellsite geologist and analysis of cores which have been cut and retrieved from the well. In addition to the lithological description derived from the above, the mudlogger or geologist will also provide an interpretation of the depth at which the formation horizons were penetrated. In the case of development wells the regional geology should be reasonably well defined.

As discussed in Chapter 2, rocks are classified on the basis of a system associated with the chemistry of the rocks. The reason for this is that the measurements made by the logging tools can be calibrated in terms of the properties (e.g. density) of these specific minerals and therefore that these minerals can be clearly identified when encountered. If the formation is made up of one mineral then a particular log measurement may be used to identify that mineral and therefore infer the rock type (lithology). However, if the formation is made up of a mixture of known minerals then it is necessary to use a combination of logs to obtain a good indication of the mineralogical content and therefore lithology of the formation. The composition of the rock can be inferred by crossplotting combinations of the Density, Neutron and Acoustic log data. Figure 2 shows an example of a Neutron Porosity versus Bulk Density crossplot. The utility of this approach depends on the complexity of the rock as well as the number of porosity logs run. This technique of crossplotting porosity logs to identify the lithology is described in Chapter 6. This technique can also be used to define the porosity of the formation and presence of gas. This will be discussed in the section on porosity determination below.



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Sandstone

20

10

00

30

20

10

30

0

20

10

30

Limestone

Dolomite

2.1

0.10.3

0.50.70.8

B

A

2.3

2.5

2.7

2.90 10 20 30

rb

rh

fN

Figure 2 Neutron Porosity versus Bulk Density crossplot for determining lithology.

4 IDENTIFICATION OF PERMEABLE AND NON-PERMEABLE ZONES FROM LOGS

The permeable zones on a suite of logs can be identified by referring to the GR, SP and resistivity logs. The Gamma Ray log is generally used as a depth reference tool and the Gamma Ray sonde is therefore run with all logging tools. It is however primarily used from an interpretation viewpoint to differentiate between shales and other formation types. Since shales generally have a very low permeability (very common caprocks) the Gamma Ray log response can be used in a qualitative way to identify non-permeable zones. The technique for identifying permeable zones on an SP log is provided in Section 4 of Chapter 4. A comparison of the resistivity readings from the flushed zone, shallow and deep into the reservoir (Figure 3) will give some indication of the depth of penetration of the borehole fluid and therefore the permeability of the formation.


6

Uninvaded zone (UZ)

Transition zone (TZ)Flushed zone (FZ)

Mudcake (MC)Borehole (BH)

RmRmc Rxo Rtr Rt

BH MCFZ TZ UZFresh mud

Salty mud

Fresh water formation

Fresh water formation

Salty water formation

Salty water formation

FZ

FZ

TZ

TZ

UZ

UZ

R

R

S M D

SMD

Resistivity responses will be the same as above with higher seperation among S, M, D for fresh water formation and a lower seperation among D,M,S for salty water formation.

Shallow, Medium and Deep resistivities versus depth of investigation.

Figure 3 Invasion and Resistivity Profiles in terms of shallow, medium and deep curves.



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5 DETERMINE AND DIVIDE THE FORMATIONS INTO WATER BEARING AND HYDROCARBON BEARING ZONES

The nature of the fluids in the permeable formations is determined by analysis of the porosity and resistivity logs. It is possible to differentiate between gas and liquid with the porosity logs but it is not possible to differentiate between water and oil from these logs. The characteristics of the log measurements made by porosity tools in gas bearing and non-gas bearing formations is shown in Figure 4. The rationale for these log responses is explained in Chapter 5.

FORMATION

Shale

Gas

Gas

Gas

Gas

Water

Water

Shale

Shale

Sand

Shaley Sand Grading to Shale

Sand(Uncompacted)

Sand(Uncompacted)

Sand(Compacted)

Sand(Compacted)

SATURATION GR ρ ∆t φn

Figure 4 Formation gas influence on porosity logs.

The resistivity logs can only be used to differentiate between hydrocarbons and water. This is because the conductivity of gas and oil will be similar whereas the resistivity of (salt) water and hydrocarbons will be significantly different. The interpretation of the response of the resistivity tools in water and hydrocarbon and water-bearing formations relies on an appreciation of the changes in resistivity that occur in the region close to the wellbore of a permeable zone (Figure 3).

When a permeable zone is penetrated by the drillbit the drilling mud will try to penetrate the permeable formation. If the size of the pores in the formation are smaller than the solids in the drilling fluid then the solids will be trapped on the surface of the wellbore and the fluid in the drilling mud will pass through the solids into the formation.

When invasion occurs, the wellbore is coated with a thin film of solids known as the “filter cake” and the formation next to the wellbore is “flushed” by the mud filtrate moving into the formation and is therefore known as the “flushed zone”. The hydrocarbon saturation in the flushed zone is a minimum and all of the formation water is removed.


8

The formations deeper into the formation are affected progressively less than the flushed zone until at some radial depth into the formation the fluids in the pore space are undisturbed. In a hydrocarbon bearing formation the hydrocarbon saturation is reduced in the flushed zone and increases in the transition zone until the original saturation is reached in the undisturbed zone. In a water bearing formation the water saturation in the zone between the flushed zone and the undisturbed zone would not change but the salinity and therefore the resistivity may. These changes in saturation and resistivity create resistivity profiles which can be used to identify the water bearing and hydrocarbon bearing formations.

When using freshwater mud, the resistivity of the mud filtrate is higher than that of the formation water and therefore in a water bearing zone the resistivity of the flushed zone is high and the resistivity readings decrease with movement out into the undisturbed zone. In a hydrocarbon bearing formation the resistivity of the zone behind the flushed zone may be higher or lower than the flushed zone depending on the water saturation and resistivity of the formation water. The resistivity profiles and relative readings which would be expected from the shallow (S), medium (M) and deep (D) reading resistivity logs for each of the above conditions are shown in Figure 5.

D M SFresh Mud

Resi

stiv

ity,

RRe

sist

ivit

y, R

R

S M DR

R0

Rt

Fresh Mud System

Salt Mud System

Salt Water Zone

Figure 5 Resistivity profiles from shallow, medium and deep resistivity logs in fresh and salt mud systems.

When using a salt water mud the flushed zone has a lower or similar resistivity than the undisturbed zone if the undisturbed zone contains high resistivity water. The undisturbed zone will have higher resistivity if the formation contains hydrocarbons.

6 DETERMINE THE POROSITY OF THE ZONES OF INTEREST

Rock porosity is generally determined from the measurements from one, or a combination of, the following logs:

• Acoustic log, • Density log and/or • Neutron log.



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The measurements of the neutron, density, and sonic logs depend not only on porosity (f) but also on the formation lithology, on the fluid in the pores, and, in some instances, on the geometry of the pore structure. When the lithology and, therefore, the matrix parameters (tma, rma, fma) are known, correct porosity values can be derived from any one of these logs, appropriately corrected for environmental effects, in clean water-filled formations. This procedure is described in Chapter 5.

Accurate porosity determination is more difficult when the matrix lithology is unknown or consists of two or more minerals in unknown proportions. Determination is further complicated when the response of the pore fluids in the portion of the formation investigated by the tool differs appreciably from that of water. In particular, light hydrocarbons (gas) can significantly influence the response of all three porosity logs. Even the nature of type of pore structure affects the tool response. The neutron and density logs respond to total porosity - that is, the sum of the primary (intergranular or intercrystalline) porosity and the secondary (vugs, fissures, fractures) porosity. The sonic logs, however, tend to respond only to evenly distributed primary porosity. When any of these complicating situations exists the porosity of the rock can only be determined by crossplotting the measurements from two different log types. In other words the porosity cannot be determined from a single porosity log. The way in which the porosity can be determined in these situations will be described in Chapter 6.

7 DETERMINATION OF SATURATION

The electrical resistivity of a formation is a very good indicator of the fluid in the pore space of that formation. Neither oil nor gas conducts electrical current but water does. It is very rare however for a formation to contain no water at all and there is generally some level of water saturation of the pore space, Sw in all formations. If Sw is the fraction of the pore volume occupied by formation water then (1-Sw) is the fraction of the pore volume occupied by hydrocarbons.

The proportion of water and therefore hydrocarbons in the pore space of formations is generally determined from the levels of resistivity of the formations in question. The resistivity of the formation is however also a function of a number of other variables such as porosity and the salinity of the water in the pore space.

There are a number of techniques available to determine the water saturation of a formation and therefore the hydrocarbon saturation and these are presented in Chapter 7. However the most commonly used techniques and the ones that will be examined in this course are the following:

• Direct application of the Humble Formula• Resistivity vs. Porosity Crossplotting (Hingle Plot)• Rwa Comparison• Flushed Zone Resistivity Ratio Method


10

Cor

rela

te a

ndD

epth

Mat

ch L

ogs

Inte

rpre

tLi

thol

ogy

Iden

tify

Perm

eabl

e B

eds

Zone

Log

s as

Wat

er o

r Hyd

roca

rbon

Bed

sC

alcu

late

Satu

ratio

n, S

wC

alcu

late

Po

rosi

ty,

Flow

char

t 1Lo

g In

terp

reta

tion

Flow

char

tO

verv

iew



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Cor

rela

te a

ndD

epth

Mat

ch L

ogs

Inte

rpre

tLi

thol

ogy

Iden

tify

Perm

eabl

e B

eds

Cle

an S

and

Soni

c Lo

g

Wyl

lie E

quat

ion

Empi

rical

Equ

atio

n

Con

side

rSh

ales

Car

bona

tes

Unc

ompa

cted

San

dPr

essu

re

Con

side

rH

ydro

carb

ons

Shal

esC

arbo

nate

sPr

essu

re

Con

side

rH

ydro

carb

ons

Shal

esC

arbo

nate

s

Den

sity

Log

Neu

tron

Log

Lim

esto

ne

Flow

char

t 2Lo

g In

terp

reta

tion

Flow

char

t - P

oros

ityM

onom

iner

al L

ithol

ogy


12

Hum

ble

Equa

tion

Con

side

rSh

ales

Car

bona

tes

Unc

ompa

cted

San

dPr

essu

re

Con

side

rH

ydro

carb

ons

Shal

esC

arbo

nate

sPr

essu

re

R wa t

o R w

Com

paris

onTe

chni

que

Res

istiv

ity R

atio

Met

hods

Flus

hed

Zone

Inva

ded

Zone

RXO

/Rt

Dis

pers

ed S

hale

Tota

l Sha

le

Loga

rithm

icO

verla

ysR

es. v

s f

Cro

sspl

otM

icro

Res

. vs

fC

ross

plot

Shal

y Fo

rmat

ion

Mod

els

Lam

inat

ed S

hale

Dis

pers

ed S

hale

Tota

l Sha

le

Det

erm

ine

Poro

sity

Det

erm

ine

Satu

ratio

n

Flow

char

t 3Lo

g In

terp

reta

tion

Flow

char

t-Sa

tura

tion

Inte

rpre

tatio

nC

orre

late

and

Dep

th M

atch

Log

s

Inte

rpre

tLi

thol

ogy

Iden

tify

Perm

eabl

e B

eds



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14


Log Measurements and Tools F O U R

Caliper(Diam. in.)

SP

10-ft - 12-ftLSS

20+_ mV

Interval Transit Time (µs/ft)Depth 250

3100

3200

8600

8700

2212 50150

3-ft - 5-ft BHC

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1 INTRODUCTION

2 BOREHOLE ENVIRONMENT

3 GAMMA RAYS AND GAMMA RAY TOOLS3.1 Gamma Ray Logging Tool3.2 Spectral Gamma Ray (SGR)Tools

4 SPONTANEOUS POTENTIAL MEASUREMENTS AND SP TOOL

5 ACOUSTIC TOOLS5.1 Propagation of Sound5.2 Borehole Compensated Sonic (BHC)

Tools5.3 Long-spaced Sonic (LSS) Tools5.4 Array Sonic Tools5.5 Dipole Shear Sonic Imager (DSI)

6 DENSITY LOGGING TOOLS6.1 Compensated Formation Density Tools6.2 The Litho Density Tools6.3 Triple Detector Lithology Density Tool

(TLD)

7 NEUTRON LOGGING TOOLS7.1 GNT Tools7.2 The SNP Tool7.3 The CNL Tool

8 NUCLEAR MAGNETIC RESONANCE (NMR) TOOL

9 RESISTIVITY TOOLS9.1 Resistivity of the in the formation9.2 Conventional Electrical Tools9.3 Focused Electrode Logs9.4 Induction Logging Tools9.5 Environmental Factors on Induction

Logging Tools9.6 Microresistivity Devices

APPENDIX

SUMMARIES OF SELECTED PASSIVE AND ACTIVE TOOLS

1 PASSIVE TOOLS

2 ACTIVE TOOLS

SUMMARY TABLES OF TOOLS AND MEASUREMENTS

LIST OF INTERPRETATION CHARTS FOR CHAPTER 4


C O N T E N T S


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LEARNING OBJECTIVES


• Describetheboreholeenvironment,theinvasionprocessandtheimpactof variousfactors(washouts,mudcakeetc)ontheboreholesize.

• DescribethenaturalGRandSGRloggingsondes,andthebehaviourofGR log in a sand-shale sequence.

• DescribetheoccurrenceofSpontaneousPotentialintheboreholeandhow thesepotentialsarepickedupbyanSPtool.

• Describetheoperatingprinciplesofvariousacousticloggingtoolsandtheir porositydetermination,andvariousotherapplicationsofacousticwaves.

• Describethemodeofoperationofadensityloggingtoolandtheadvantages of the Litho-Density tool over the FDC tool.

• Describe the various types of Neutron Logging tools and their porosity determination.

• DescribetheoperatingprincipleoftheNMRtoolsandtheiruseinpermeability determination

• Describe the operation of the conventional resistivity; focused electrode; inductionandmicroresistivity logging toolsand theirapplications,and the effect of various factors on induction logging tools.


2

1 INTRODUCTION

This chapter will explain the operating principles and applications of the majority of openhole wireline logging tools. The petrophysical properties of the formations such asporosity,claycontent,hydrocarbonsaturationandpermeabilityareinferredfromspecificmeasurementsmadeontherocks.Thetoolsusedtomakethesemeasurements,andthepropertieswhichcanbeinferredorquantifiedfromthesemeasurementswillbepresentedinthischapter.

2. BOREHOLE ENVIRONMENT

Borehole SizeTheboreholesizedependsonthesizeofthedrillbitused.Theinitialdrillingisbegunwitharelativelylargediameterdrillbit.Afterthefirstdrillingphase,acasinghavinga slightly smaller diameter of the drilled hole is placed inside the hole. Cement is injectedbetweenthesteelcasingandtheformationwallinordertokeepthesteelpipeinplace.Aseconddrillbitofarelativelysmallerdiameterislowereddownthesteelpipeforfurtherdrillingoftheborehole.Theresultingbottomholediametervarieswithintheoilindustryanditcanbeasnarrowas5inches(“slimhole”devicesarerequiredtologthesesmallerdiameterboreholes).

Thedrilledboreholeisloggedusingatoolstringcomprisingvarioustools.Thecallipertool is often used as part of the tool string to measure the internal diameter of the borehole.Thetoolalsoprovidesinformationaboutholequality/condition.Calliperswithfourormorearmsareusedtoprofiletheboreholeshape.Theboreholeusuallymaintains its diameter (gauge) in hard formations. However soft formations are pronetocrumbleorcollapseintotheborehole(washout).Thecalliperlogmeasuresa largerholediameter inwashout sectionsof theborehole and this is shownby‘overgauge’holeinFigure1.Ontheotherhand,excessivemudcakecanbuildupacrossapermeableformation.Filtercakebuildupisusuallyslowandappearsasan‘undergauge’holeonthecalliperlog.Sometools(likedensity)requireacallipertopressitspadagainsttheboreholewall.

The Drilling MudDrillingmudsareusedtohelpremovecuttingsfromthewellbore,tolubricatethedrillbitanddrillstring,tocoolthedrillbitandtocreateaboreholepressureasadirectresultoftheweightofthemudcolumn.Thehigherboreholepressurecounterbalancesporepressuresinthedrilledformationtoavoidanyblowouts.Thedrillingmudinsome cases is also used to transmit signals from logging tools at in situ downhole on to the surface.

Drillingmuds aremadeupof oil,water or amixtureof both.Freshwatermudsthat have a liquid phase of water are generally lightly treated and contain small concentrations of salt. They include spud muds (use appropriate concentrations of commercial clays) and natural muds (use native drilled solids). Saltwater muds on theotherhandcontainsignificantamountofconstituents(normallymorethan10,000mg/Lofchloride).Examplesofsaltwaterfluidsincludebrakishwaterandseawaterwhichalsousevariouscommercialandformationclaysforfluidlosscontrol(causticsodaisoftenusedforviscositychange).Saltwatermudsareusedprimarilybecauseoftheconvenienceofmake-upwateroffshore.



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Variousloggingtoolsgetaffectedbythecharacteristicsofthedrillingmudused.Theselectionoftheappropriatedrillingmudneedstobeconsidereddependingonthetypeoflogsruninthatwellbore.Forexample,bariteisusedasanadditiveformudweightcontrol.Howeverthedensitylogwillgetaffectedbythepresenceofbariteduetoitshigherbulkdensity.Therearearangeofotheradditivesusedindrillingmuds(e.g.walnut,calciteetc.)forviscositychange,mudlighteningor toreducecirculation losses and these often have no adverse effect on log responses.

Permeable Layer

Borehole size

Washout“Moderate Over guage”

In Guage Hole

Underguage“Filter Cake”

Washout beyond reach of calliper “Serious out of guage”

Figure 1OvergaugeandUndergaugeholesasaresultofformationwashoutandmudcakebuildupintheborehole

The Invasion ProcessDuring the drilling of the well the hydrostatic pressure of the mud column is usually greaterthantheporepressureoftheformations.Thispreventsthefluidsfromtheformationsflowing into thewell. Theresultantpressuredifferentialbetween themudcolumnandformationforcesmudfiltrateintothepermeableformation,andthesolidparticlesofthemudaredepositedontheboreholewallwheretheyformamudcake.Themudcakebuild-upismosteffectiveinhighpermeableformations.Itusuallyhasaverylowpermeability(oftheorderof10-2-10-4mD)and,oncedeveloped,considerablyreducestherateoffurthermudfiltrateinvasion(Figure2).


4

Normallythemudcakehasmuchhigherresistancethantheformationsuchthattheexcesspressurecreatedinthelatterisnegligible.Oncethemudcakepermeabilitydropsverylow(normallybelow1mD),thisconditionnolongerholdsandtheformationnexttotheboreholemaybecomesupercharged.Thesimilarphenomenonoccursinlowpermeabilityformationswherefiltrateinvasion(inpressurecommunicationwithmud column) continues for a long period and which is why supercharging occurs.

Uninvaded zone (UZ)

Transition zone (TZ)Flushed zone (FZ)

Mudcake (MC)Borehole (BH)

RmRmc Rxo Rtr Rt

BH MCFZ TZ UZ

Figure 2 Invasionofthedrillingfluidintotheformation

Veryclose to theboreholemostof theoriginal formationwaterandsomeof thehydrocarbonsmaybeflushedawaybythefiltrate(Figure2a).Thiszoneisreferredtoastheflushedzone.Itcontains,iftheflushingiscomplete,onlymudfiltrate;iftheformationwasoriginallyhydrocarbonbearing,onlyresidualhydrocarbons.Oil-basedmudinvasiongivesadditionalchallenges,notleastforitstendencytogravitysegregation in the formation.

Furtheroutfromtheborehole,thedisplacementoftheformationfluidsbythemudfiltrateislessandlesscomplete,resultinginatransitionfrommudfiltratesaturationtooriginalformationwatersaturation.Thiszoneisreferredtoasthetransitionorinvadedzone.Theextentordepthoftheflushedandtransitionzonesdependsonmany parameters such as:



22/10/13

• Typeandcharacteristicsofthedrillingmud • Theformationporosity • Theformationpermeability • Thepressuredifferential,and • Thetimesincetheformationwasfirstdrilled

Flus

hed

zone

Uni

nvad

ed z

one

Tran

sitio

n zo

ne

OilZone

Water Zone

Bed

Thic

knes

s h

Ro

1

Rw

Rw

Sw

Rt

Hole Diameter dh

Rmc

Mud Cake

RmMud

Rxo

1

Rmf

Rmf

Sxo

Rxo

Figure 2aInvasionofthedrillingfluidintotheformation.

Generally,thelowertheformationporosity,thedeepertheinvasion.Theundisturbedformation beyond the transition zone is referred to as the uninvaded, virgin, oruncontaminatedzone.Infracturedformationsthemudfiltrateinvadeseasilyintothefractures,butitmaypenetrateverylittleintotheunfracturedblocksoflow-permeabilitymatrix.Therefore,onlyasmallportionofthetotaloriginalformationfluids(formationwaterand,ifpresent,hydrocarbons)isdisplacedbythefiltrate-evenveryclosetotheborehole.Inthiscase,notrueflushedzoneexists.

Borehole Environment and Log InterpretationClearlyinspectionofthecalliper(relativetobitsize)isthefirststeptologinterpretation.Consideration to the typeofmudandlikely invasionprofile isalsoan importantearly step.

3 GAMMA RAYS AND GAMMA RAY TOOLS

3.1 Gamma Ray Logging ToolThe Gamma Ray tool is a passive logging tool. It records the naturally occurring radiationofgammaraysfromtheformation.Gammaraysareburstsofhigh-energy


6

electromagneticwavesthatareemittedspontaneouslybysomeradioactiveelements.Nearlyallthegammaradiationencounteredintheearthisemittedbytheradioactivepotassium isotopewhich has an atomicweight 40 (K40), and by the radioactiveelements of the uranium and thorium series.

Thenumberofemittedgammaraysandtheirenergiesaredistinctiveofeachelement.Figure 3showstheenergiesofthegammaraysemittedbypotassium(K40) and the uraniumandthoriumseries.Potassium(K40) emits gamma rays of a single energy at1.46MeV,whereastheuraniumandthoriumseriesemitgammaraysofvariousenergies.

1.46

2.62

1.76

0 0.5 1 1.5 2 2.5 3

Potassium

Thorium Series

Uranium-Radium Series

Gamma Ray Energy (MeV)

Prob

abilit

y of

Em

issi

on p

er D

isin

tegr

atio

n

Figure 3 Gamma Ray Emmission Spectra of Radioactive Minerals.

Inpassingthroughmatter,gammarayscollidewith,andarescatteredby,theatomsoftheformationmaterial.Duringthisscatteringprocess,knownasCompton-scattering,the gamma rays lose energy with each collision. After the gamma ray has lost enough energy,itisabsorbedbyanatomoftheformationknownasPhotoelectricEffect.Thus,naturalgammaraysaregraduallyabsorbedandtheirenergyreducedastheypassthroughtheformation.Therateofabsorptionvarieswithformationdensity.Twoformationshavingthesameamountofradioactivematerialperunitvolume,buthavingdifferentdensities,willshowdifferentradioactivitylevelswiththelessdenseformationsappearingtobeslightlymoreradioactive.ThemeasurementsrecordedbytheGRloggingtool,afterappropriatecorrectionsfortheboreholesizeetc.areproportional to the weight concentrations of the radioactive material in the formation:

GR = ρi Vi Ai∑ρb

(1)



22/10/13

where,ri arethedensitiesoftheradioactiveminerals,Vi arethebulkvolumefactorsofthemineralsAi areproportionalityfactorscorrespondingtotheradioactivityofthemineral,

and

rbisthebulkdensityoftheformation.

Insedimentaryformations,thedepthofinvestigationoftheGRloggingtoolisabout1ft.The GR sonde contains a detector to measure the gamma radiation originating in the volume of formation near the sonde. Scintillation counters are now generally usedforthismeasurement.Theyaremuchmoreefficientthanthe Geiger-Mueller counters usedinthepast.Becauseoftheirhigherefficiency,ascintillationcounterneedsonlybeafewinchesinlength,therefore,gooddefinitionoftheGammaraysemittedbytheformationisobtained.TheGRlogmaybe,andusuallyis,runincombinationwithmostotherloggingtoolsandcasedholeproductionservices.

TheprimarycalibrationstandardforGRtoolsistheAPItestfacilityinHouston.AfieldcalibrationstandardisusedtonormaliseeachtooltotheAPIstandardandthelogsarecalibratedinAPIunits.TheradioactivitiesinsedimentaryformationsgenerallyrangefromafewAPIunitsinanhydriteorsaltto200ormoreinshales.

Prior to theAPI calibration procedure, GR logs were scaled in micrograms ofradium-equivalent per ton of formation. Conversions from these units to API units areshowninTable1.

API UnitsEquipment Old Unit Per Old Unit

GNT - F or -G Gamma Ray 1 μgm Ra-eq/ton 16.5GNT-J, -K Gamma Ray, GLD-K 1 μgm Ra-eq/ton 11.7

Table 1 ConversionfromoldunitstoAPIunitsforSchlumbergergammaraylogs.

Thetotalgammaraymeasurementobtainedfromtheformationisoftenusedtoderivea shale volume since naturally occurring radioactive elements tend to have greater concentrationsinshalesthanincleansandstones.Forthis,thegammarayshaleindexiscalculatedfirstusingtheequation:

IGR = (GR – GRcl)/(GRsh - GRcl) (2)

Thevaluecanthenbeinsertedinarelevantchart(fromSchlumbergere.g.)tocalculatethevolumeofshale.However,careshouldbetakensincethismethodcanonlybeusedinasimplesandstone-shaleformation.SignificanterrorscanoccurinVshcalculationwhen radioactive elements (uranium or potasium salts e.g.) are present in the sand or if shale has very low concentration of radioactive elements.


8

3.2 Spectral Gamma Ray (SGR)ToolsThe Spectral Gamma Ray Tools provides quantitative lithological and mineralogical information in sands and shales. The tool measures gamma ray spectra and resolves this into themost commonly found and naturally occurring potassium, thoriumand uranium contributions and their concentrations.These data are then used todistinguishdifferenttypesofclayse.g.aroundthewellbore.Theordinarygammaraytoolrecordsonlythetotalradiationsandthereforecannotdistinguishbetweenradioactive elements.

Physical PrincipleMost of the gamma ray radiation in the earth originates from the decay of three radioactive isotopes:

potassium 40 (K40),withahalf-lifeof1.3x109years;

uranium 238 (U238),withahalf-lifeof4.4x109years;and

thorium 232 (Th232),withahalf-lifeof1.4x1010 years.

Potassium40decaysdirectlytostableargon40withtheemissionofa1.46-MeVgammaray.However,uranium238andthorium232decaysequentiallythroughalongsequenceofvariousdaughterisotopesbeforearrivingatstableleadisotopes.Asaresult,gammaraysofmanydifferentenergiesareemittedandfairlycomplexenergyspectraareobtained,asshowninFigure 3.Thecharacteristicpeaksinthethoriumseriesat2.62MeVandtheuraniumseriesat1.76MeVarecausedbythedecayofthallium208andbismuth214,respectively.

Itisgenerallyassumedthatformationsareinsecularequilibrium.Thismeansthatthe daughter isotopes decay at the same rate as they are produced from the parent isotope. This means that the relative proportions of parent and daughter elements in aparticularseriesremainfairlyconstantso,bylookingatthegammaraypopulationinaparticularpartofthespectrumitispossibletoinfertheThoriumpopulationatanyotherpoint.Inthisway,theamountofparentisotopepresentcanbedetermined.

Oncetheparentisotopepopulationisknown,theamountofnonradioactiveisotopecanalsobefound.Theratioofpotassium40tototalpotassiumisverystableandconstantontheearthwhile,apartfromthorium232,thethoriumisotopesareveryrareandsocanbeneglected.Therelativeproportionsoftheuraniumisotopesdependsomewhatontheirenvironment,andthereisalsoagradualchangebecauseoftheirdifferenthalf-lives.Atpresent,theratioofuranium238touranium235isabout137.

NGS Natural Gamma Ray Spectrometry Tool The NGS tool uses a sodium iodide scintillation detector contained in a pressure housingwhich,duringlogging,isheldagainsttheboreholewallbyabowspring.

Gammaraysemittedbytheformationrarelyreachthedetectordirectly.Instead,theyarescatteredandloseenergythroughthreepossibleinteractionswiththeformation;Compton scattering, the photoelectric effect,andpair production. Because of these interactionsandtheresponseofthesodiumiodidescintillationdetector,theoriginalspectra of Figure 3 are degraded to the rather smeared spectra shown in Figure 4.



22/10/13

K40

K

W1 W2 W3 W4 W5

U Th

Bi214

Th + U + K

Energy (MeV)

Schlumberger

x 10Scale

Ti208

dNdE

Figure 4Potassium,Thorium,andUraniumresponsecurves.

Thehigh-energypartofthedetectedspectrumisdividedintothreeenergywindows,W3,W4,andW5, eachcoveringacharacteristicpeakof the three radioactivityseries(Figure4).Knowingtheresponseofthetoolandthenumberofcountsineachwindow,itispossibletodeterminetheamountsofthorium232,uranium238,andpotassium40intheformation.Therearerelativelyfewcountsinthehigh-energyrangewherepeakdiscrimination isbest. Thereforemeasurementsare subject tolargestatisticalvariations,evenatlowloggingspeeds.Byincludingacontributionfromthehighcountrate,low-energypartofthespectrum(WindowsW1andW2),thesehigh statisticalvariations in thehigh-energywindowscanbe reducedbyafactorof1.5to2.Thestatisticsarefurtherreducedbyanotherfactorof1.5to2byusingafilteringtechniquethatcomparesthecountsataparticulardepthwiththeprevious values in such a way that spurious changes are eliminated while the effects offormationchangesareretained.Normally,onlythefinalfiltereddataarepresentedonfilm,buttheunfilteredrawdataarealwaysrecorded.

4 SPONTANEOUS POTENTIAL MEASUREMENTS AND SP TOOL

The Spontaneous potential (SP) tool is the second of the passive logging tools It recordstheelectricalpotential(voltage)producedbytheinteractionofformationconnatewater,conductivedrillingfluidandcertainion-selectiverocks(shale).

Tworesearchers,MounceandRustusedasimpleexperimenttoprovethattwowatersofdifferentsalinities,togetherwithshaleandapermeableinertmembranebetweenthetwofluids,createsabatteryandcurrentflowsinthecell.Thecurrentflowsfromthe fresh to the salty water and then through the shale. Removal of the shale stops thecurrentflow.Interchangingthetwoliquidsreversesthedirectionofcurrentflow.Thiscellprovesverysimilartoconditionsexistingintheboreholewherethedrillingmud salinity is different from the formation water salinity.


10

The Spontaneous Potential (SP) tool measures the naturally occurring potentials in thewellboreasafunctionofdepth.Thetoolinvolvesasinglemovingelectrodeintheboreholeandareferenceelectrode,usuallylocatedatthesurfaceinthemudpitorsomeothersuitablelocation.ThemeasuredSPisthevoltageobservedintheboreholecausedbythepotentialdropasthecurrentsflowthroughthemud.Thepotentialdropgenerallyislargerintheboreholethanintheshale,orpermeableformation.

Electrochemical Component of the SPConsiderapermeableformationwiththickshalebedsaboveandbelow.Assumethatthetwoelectrolytes(mudfiltrateandinterstitialformationwater)containsodiumchloride (NaCl) only. Because of the layered clay structure and the charges on the layers,shalesarepermeabletotheNa+cationsbutimpervioustotheCl- anions. Only the Na+cations(positivecharges)areabletomovethroughtheshalefromthemore concentrated to the less concentrated NaCl solution. This movement of charged ionsisanelectriccurrent,andtheforcecausingthemtomoveconstitutesapotentialacrosstheshalecalledmembranepotential.

The curved arrow in the upper half of Figure 5showsthedirectionofcurrentflowcorresponding to the passage of Na+ ions through the adjacent shale from the more salineformationwaterinthebedtothelesssalinemud.

CMud

InsulatingPlug

MudCake

InvadedZone

Static SPDiagram

Static SP Diagram - Potential in mud when SPcurrents are prevented from flowingSP Log - Potential in mud when SPcurrents are flowing

A A

C

C C

BB

BB

Shale

Shale

Sand

C

A A

C

C C

BB

BB

Shale

Shale

Sand

Ec

Static SPDiagram

SP Curve

Figure 5SchematicRepresentationofPotentialandCurrentDistributioninandaroundapermeablebed.



22/10/13

Another component of the electrochemical potential is produced at the edge of the invadedzone,wherethemudfiltrateandformationwaterareindirectcontact.HereNa+ and Cl ions can diffuse (move) from either solution to the other. Since Cl- ions haveagreatermobilitythanNa+ions,thenetresultofthisiondiffusionisaflowofnegative charges (Cl- ions) from the more concentrated to the less concentrated solution. Thisisequivalenttoaconventionalcurrentflowintheoppositedirection,indicatedbythestraightArrowAintheupperhalfofFigure 5.Thecurrentflowingacrossthejunctionbetweensolutionsofdifferentsalinityisproducedbyanelectromagneticforce (emf) called liquid-junction potential. The magnitude of the liquid-junction potentialisonlyaboutone-fifththemembranepotential.

Ifthepermeableformationisnotshaly,thetotalelectrochemicalemf,Ec,correspondingtothesetwophenomena,isequalto

Ec =−K logawamf

, (3)

where aw and amf are the chemical activities of the two solutions (formation water andmudfiltrate)atformationtemperature; Kisacoefficientproportionaltotheabsolutetemperature,and,forNaClformationwaterandmudfiltrate,isequalto71at 25° C (77° F). The chemical activity of a solution is roughly proportional to its saltcontent(i.e.,toitsconductivity).IfthesolutionscontainsubstantialamountsofsaltsotherthanNaCl,thevalueofKat77°Fmaydifferfrom71.

The activities aw and amf are inversely proportional to the resistivities of the formation waterandmudfiltraterespectively.Equation(3)canthereforeberewrittenas:

Ec =−K log

RmfeqRweq

If the permeable formation contains some shale or dispersed clay, the totalelectrochemicalemfand,hence,theSPdeflectionswillbereducedsincetheclayinthepermeableformationproducesanelectrochemicalmembraneofoppositepolaritytothatoftheadjacentshalebed.

Electrokinetic Component of the SPAnelectrokineticpotential,Ek(alsoknownas streaming potential or electrofiltration potential)isproducedwhenanelectrolyteflowsthroughapermeable,non-metallic,porousmedium. Themagnitudeof the electrokineticpotential is determinedbyseveralfactors,amongwhicharethedifferentialpressureproducingtheflowandthe resistivity of the electrolyte.

Intheborehole,anelectrokineticemf,Ekmc,isproducedbytheflowofmudfiltratethroughthemudcakedepositedontheboreholewalloppositepermeableformations.Inpractice,littleornoelectrokineticemfisactuallygeneratedacrossthepermeableformationitself.Thisisbecausepracticallyallthedifferentialpressurebetweentheboreholeandundisturbedvirginformationisexpendedacross thelesspermeablemudcake.Anyremainingdifferentialpressureacrosstheformationisnormallynotgreatenoughtoproduceanyappreciableelectrokineticemf.


12

Anelectrokineticemf,Eksh,may,however,beproducedacrosstheshale,sinceitmayhavesufficientpermeabilitytopermitatinyamountoffiltrationflowfromthemud.

Eachoftheseelectrokineticemf’scontributestoamorenegativeSPreadingoppositethepermeablebedandoppositetheshale,respectively.ThenetcontributiontotheSPdeflection(measuredfromtheshaleline)is,therefore,thedifferencebetweenthecontributionsofthemudcakeandtheshaleelectrokineticeffects.Inpractice,theseelectrokineticemf’saresimilarinmagnitude,andthenetelectrokineticcontributiontotheSPdeflectionisthereforeusuallysmall,normallyregardedasnegligible.Thisisparticularlytrueiftheformationwaterisrathersaline(resistivitylessthan0.1ohm-m)and the differential pressure has a normal value of only a few hundred psi or less.

Itis,however,possibleforelectrokineticeffectstobecomemoreimportantincasesofunusuallylargepressuredifferentials(e.g.,indepletedformationsoflowpressureorwhenveryheavydrillingmudsareused).Inthesecases,theelectrokineticemf’smaybequitesignificantandthemudcakeandshaleelectrokineticeffectsmaynotcancel each other.

Importantelectrokineticeffectsmayalsobeseeninverylow-permeabilityformations(lessthanafewmillidarcies)inwhichanappreciablepartofthepressuredifferentialisappliedacrosstheformationitself.Ifformationpermeabilityissolowthatlittleornomudcakeisformed,mostofthepressuredifferentialbetweentheformationpore pressure and hydrostatic head of the mud column is applied to the formation. If theformationwater isbrackish, if themudisresistive,andif theformationiscleanandhassomeporosity,theelectrokineticeffectmaybequitelarge,sometimesexceeding-200mV.

Theseinfrequenteffectsaredifficulttodetect,butconditionsfavouringtheirexistenceshouldalertustothepossibilityofalargeelectrokineticpotential.WhenasignificantelectrokineticpotentialexiststheSPdeflectioncannotbeusedtocalculateareliablevalueofformationwaterresistivity,Rw.

Spontaneous Potential LogThe spontaneous potential log is a relative measurement of the DC voltage in the borehole with no zero being recorded. Readings opposite shales are relativelyconstantandarereferredtoas“theshalebaseline”.OppositepermeableformationstheSPcurvetypicallyshowsexcursionstotheleft(negativepolarity)ortotheright,depending upon the salinity of the drilling mud and formation waters (Figure 6). The positionoftheshalebaselinehasnorealsignificance.Theloggingengineersetsthepositionandsensitivityonthelogsothatdeflectionsoppositepermeablebedsstaywithinthelimitsoftrack#1onthelog(Figure7).Typically,theshalebaselineissettwochartdivisions(wheretendivisionsmakethetotalwidthofthetrack)fromtherightedgeoftheSPtrack.



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Shal

e Ba

se li

ne

Clean sand

Shale

Rmf = Rw

Rmf > Rw

Rmf < Rw

Figure 6SPcurvebehaviourincleansandandshaleintervalsforvariousformationwaterandmudfiltratesalinities.

SPmV

20 +-

Sand Line

Depths

0.2 1.0 10 1001 1000 2000

Resistivityohms m2/m

Shale Line

Figure 7 Example of SP log in sand-shale sequence.


14

POROSITY LOGGING TOOLS (ACOUSTIC, DENSITY, NEUTRON)

5 ACOUSTIC TOOLS 5.1 Propagation of SoundThepropagationofsoundinaboreholeisacomplexphenomenon.Itisgovernedbythemechanicalpropertiesof:theformation;theboreholefluidcolumn;andthelogging tool itself.

The sound emanated from the transmitter of an acoustic logging tool impinges on the boreholewall.Thisestablishescompressional and shear waveswithintheformation,surfacewavesalongtheboreholewall,and guidedwaveswithinthefluidcolumn. Inthecaseofwelllogging,theboreholewall,formationbedding,boreholerugosity,andfracturescanallrepresentsignificantacousticdiscontinuities.Therefore,thephenomena of wave refraction, reflection, and conversion lead to the presence of manyacousticwavesintheboreholewhenasoniclogisbeingrun.Itisnotsurprising,inviewoftheseconsiderations,thatmanyacousticenergyarrivalsareseenbythereceivers of a sonic logging tool. The more usual energy arrivals are shown in the acoustic waveform displays of (Figure 8). These waveforms were recorded with an array of eight receivers located 8 to 11ft from the transmitter. The various wave packetshavebeenlabelled.Althoughthewavepacketsarenottotallyseparatedintimeatthisspacing,thedistinctchangescorrespondingtotheonsetoftheformationcompressionalandsheararrivalsandtheStoneleyarrivalcanbeobserved.

Compr. Shear StonelyRec 1

Rec 2

Rec 3

Rec 4

Rec 5

Rec 6

Rec 7

Rec 8

Figure 8 Example Waveforms from the eight-receiver Array sonic tool.



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Thefirstarrivalatthereceiverisgenerallythecompressional wave. This wave has travelledfromthetransmittertotheformationasafluidpressurewave,hasbeenrefractedattheboreholewall,hastravelledwithintheformationatthecompressionalwavevelocityof the formation, andhas travelledback to the receiver as afluidpressure wave.

The shear wavehastravelledfromthetransmittertotheformationasafluidpressurewave,hastravelledwithintheformationattheshearwavevelocityoftheformation,andhastravelledbacktothereceiverasafluidpressurewave.

The mud wave (not strongly evident in these wavetrains) has travelled directly from transmitter to receiver in the mud column at the compressional wave velocity of the boreholefluid.

The Stoneley wave has large amplitude and has travelled from transmitter to receiver withavelocitylessthanthatofthecompressionalwavesintheboreholefluid.ThevelocityoftheStoneleywaveisdependentuponthefrequencyofthesoundpulse,holediameter,formationshearvelocity,densitiesoftheformationandfluid,andfluidcompressional wave velocity.

Applications of Acoustic Log

Correlations with t CurveVariationsofvelocityindifferenttypesofrockproduceasoniccurvewithacorrelatablecharacter. Inaddition, theverygoodverticaldefinitionof the sonic logand thereducedholeeffectbecauseofboreholecompensationmakethislogexcellentforcorrelation.Itisveryhelpfulinsomecaseswhereotherlogsgivepoorresults(thickshalesectionsandevaporites).Moreover,sometypesofformations,evaporitesinparticular,canbeeasilyidentifiedfromtheirtvalues.

Shear-Wave InterpretationWith the Dipole Sonic Imager tool (explained later in this chapter) and full-waveform recording,itisnowpossibletoobtainshear-wavetransittimemeasurementsonamoreroutinebasis.Applicationoftheshearwaveinformationevaluationisonlynowbeginningtobeexplored.

Shear-wavetransittimedataareusefulinidentifyingmatrixmineralsandporefluids.Forexample,acrossplotofcompressionaltransittime,tc,andsheartransittime,ts,canbeusedtoidentifythemineralcontentofthevariousrockstraversedbythewellbore.Thetechniqueissimilartootherporositylogcrossplottingtechniques(e.g.,density-neutron,sonic-density,sonic-neutron).

Thereisevidencethattheshear-wavetransittimemaybeusefulforfluididentification.Laboratory observations suggest that light hydrocarbon saturation decreases thevelocityofthecompressionalwave(relativetobrinesaturation)throughtheporousrockandincreasesthevelocityoftheshearwave.


16

Arelationshipbetweenporosityandshearvelocity(orintervaltransittime)hasalsobeennoted.Indeed,thetime-averagerelationship(Equation1,Chapter5)andtheempiricalrelationship(Equation2,Chapter5)thatrelatecompressionaltransittimetoporosityappeartoapplytosheartransittimeaswell.Ofcourse,appropriatematrixandfluidparametersmustbeused.Forshear-wavepropagation,theparametersareapproximately:

Sandstone, tma = 86ms/ftLimestone, tma = 90ms/ftDolomite, tm = 76ms/ftAnhydrite, tm = 100ms/ftWater, tm = 350ms/ft

These values are tentative. Further experience with the shear transit time may lead to somerefinement.Also,thelistingofasheartransittimevalueforwaterissomewhatimaginarysincewaterdoesnotsupportshear-wavepropagation.However,theuseofthelistedvalueforwaterinthetime-averageequationdoesseemtoyieldacceptableporosity values.

5.2 Borehole Compensated Sonic (BHC) ToolsThere are currently four types of sonic tools in use: the BHC borehole compensated sonic tool; the LSS long-spaced sonic tool; the Array-Sonic tool;andtheDipole Shear Sonic Imager(DSI).Althoughtheentiresonicwaveformcannowberecordedwithanyofthesetools,onlytheArray-sonictoolhasbeendesignedtoprovidefull-waveform recording as a standard feature.

Nearly all BHC logs recorded in the past provide only a measurement of formation compressionalintervaltransittime,t.Thisisaccomplishedbyfirstmotiondetectionatthereceiver.Inotherwords,thereceivertriggersonthefirstarrivalofcompressionalenergy.

As shown in Figure 9,theBHCsystemusesonetransmitteraboveandonetransmitterbelowtwopairsofsonicreceivers.Thissondesubstantiallyreducesthespuriouseffectsofhole-sizechangesanderrorsfromsondetilt.Whenoneofthetransmittersispulsed,thetimeelapsedbetweendetectionofthefirstarrivalatthetwocorrespondingreceivers is measured.



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Upper Transmitter

Lower Transmitter

R1

R2

R3

R4

Figure 9SchematicofBHCsonde,showingraypathsforthetwotransmitter-recieversets

The speed of sound in the sonic sonde and in the drilling mud is less than that in the formation.Therefore,thefirstarrivalsofsoundenergyatthereceiverscorrespondtosound-travelpathsintheformationneartheboreholewall.

TheBHCtooltransmittersarepulsedalternately,and t values are read on alternate pairs of receivers. The t values from the two sets of receivers are averaged automatically byacomputeratthesurfaceforboreholecompensation.Thecomputeralsointegratesthetransit-timereadingstoobtaintotaltraveltimes(Figure10).


18

CaliperHole Diam. in.

6 100

32003300

70 4016

BHC Sonic Log2-ft Span

∆t, µs/ft

Total TravelTime ms

Figure 10 Presentation of the sonic log

Sometimes thefirstarrival,althoughstrongenoughto trigger thereceivernearerthetransmitter,maybetooweakbythetimeitreachesthefarreceivertotriggerit.Instead,thefarreceivermaybetriggeredbyadifferent,laterarrivalinthesonicwavetrain,andthetraveltimemeasuredonthispulsecyclewillthenbetoolargeandnotrepresentative of the true compressional wave velocity in the formation. When this occurs,thesoniccurveshowsaveryabruptandlargeexcursiontowardsahighert value.Thisisknownas"cycle skipping".Suchskippingismorelikelytooccurwhen the signal is strongly attenuated by unconsolidated formations, formationfractures,gassaturation,aeratedmuds,orrugoseorenlargedboreholesections.

Inearlystudiesofvelocitylogging,therocksurroundingthewellborewasregardedasaninfinitehomogeneousmediumforthepropagationofsoundwaves.Itisnowapparent that in some shales a lateral velocity gradient exists and that sound wavestravelatlowerspeedsneartheborehole.Atsomegreaterdistancefromtheborehole,they propagate at the true speed of sound in the shale. Similar variations may exist intheradialvelocityprofileinsomeunconsolidatedrocksandinpermafrost.

Inlarge-diameterboreholes,it ispossibletohaveamudwavearrivalatthenearreceiver before the formation signal. This problem is particularly prevalent atshallower depths where sonic logs are often run for seismic purposes.



22/10/13

Inall thesecases,asonic toolwith longspacing is required toprovideacorrectmeasurementof thevelocity in thenonalteredzone. When the receivers are farenoughfromthetransmitter,thefirstarrivalisnottherefractedraytravellingjustinsidetheboreholewallbutawavepenetratingbeyondtheboreholeintothefasternon-alteredzone. 5.3 Long-spaced Sonic (LSS) ToolsLSS sonic tools,withtransmitter-receiverspacingsof8ftand10ft or10ftand12ft,measuretheintervaltransittimeoftheformationbetterthantheusualBHCsonictool.Thistoolismorelikelytoyieldameasurementfreefromtheeffectsofformationalteration, relaxationdamage (from thedrillingprocess), andenlargedborehole.(Figure11)comparesthetransittimerecordedwithanLSStooltothatfromastandard-spacingtoolinaformationwithalterationoftheboreholewall.


20

Caliper(Diam. in.)

SP

10-ft - 12-ftLSS

20+_ mV

Interval Transit Time (µs/ft)Depth 250

3100

3200

8600

8700

2212 50150

3-ft - 5-ft BHC

Figure 11 Comparison of the LSS and BHC sonic logs in enlarged holes.



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Using the standard BHC system for borehole compensationwith an LSS sondewouldmakethetoolexcessivelylong.Analternatesolutioncalled“depth-derived”boreholecompensationisthereforeused.

The LSS sonde has two transmitters and two receivers arranged as shown in Figure 12.Readingsaretakenattwodifferentdepthpositionsofthesonde:oncewhenthetwo receivers straddle the measure point depth and once when the two transmitters straddle the measure point depth.

T1 R2 = T3

Sequence:

T2 R2 = T4

R1

R2

T1

T2

T1

T2

R1R1

R3

R2

R4

UT

LT

BHC MeasurePoint

(a) Convential BHCMeasurement

(b) Depth-Derived BHC Measurementfor 8-ft - 10-ft Spacing

1,384-86

10ft

8ft

9ft 8in.Later

R2

T1 R1 = T1

Sequence:

T1 R2 = T2

= (T1 - T2) + (T4 - T3)4

Figure 12 Depth Derived compensation for long-spaced sonic tool.

First t reading = T1 gR1 - T1gR2Second t reading = T2gR2 - T1gR2

Thefirsttreadingismemoriseduntilthesondehasreachedthepositiontomakethe second t reading, thenbothareaveraged toobtain theboreholecompensatedmeasurement.

t = memorisedfirst t reading + second t reading 2 x span

wherespanisthedistance(2ft)betweenapairofreceivers.


22

Assumingthetwosondepositiondepthsareaccuratelyknownandthesondetiltingissimilarforthetwopositions,thedepth-derivedboreholecompensatedsystemisequivalent to the standard BHC system. Use of the upper transmitter and receiver yieldsan8ft-10ftsonictmeasurement,anduseofthelowertransmitterandreceiveryieldsa10ft-12ftsonict measurement. 5.4 Array Sonic ToolsThe Array-Sonic tool providesallofthemeasurementsprovidedbytheBHCandLSSlogsand,inaddition,providesseveralotherfeatures.Thetoolcontainstwobroadband(5to18kHz)piezoelectrictransmittersspaced2ftapart.Twopiezoelectricreceivers are located 3 ft and 5 ft from the upper transmitter. These receivers have adualrole.Inopenhole,theyareusedinconjunctionwiththetwotransmitterstomakestandardshort-spaced3ft-5ftand5ft-7ftdepth-derived,borehole-compensatedtlogs.Incasedwells,theyareusedtomakestandard3ftcementbondlogs(CBL)and5-ftVariableDensity* logs (VDL).

TheArray-Sonictool(Figure13)alsocontainsanarrayofeightwidebandpiezoelectricreceivers. The receivers are spaced 6in. apart with the closest receiver 8 ft from the uppertransmitter.Twoofthesereceivers,receivers1and5,spaced2ftapart,canbeusedformakingstandardlong-spaced8ft-10ftand10ft-12ftdepth-derivedborehole-compensatedt logs. Measurementhardwarealsoexists,consistingofacloselyspacedtransmitter-receiverpair,tomakeacontinuousmud t log. Borehole fluidisdrawnthroughthismeasurementsectionasthetoolismovedduringlogging.



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Mud ∆tMeasurementSection

SonicLoggingReceiverSection

SonicLoggingSonde

Eight WidebandCeramic Receivers

Two CeramicReceivers

Two CeramicTransmitters

3.5 ft

8 ft 2 ft

2 ft

3 ft

Figure 13Multi-purposesonicsondeconfiguration.

The eight-array receiver outputs and the two outputs from the sonic sonde are multiplexed with the mud t receiver output and transmitted to the surface in either analogue or digital form. An example of a set of waveforms digitised from the eight-receiver array is shown in (Figure 8).

The array waveforms are processed at the wellsite with the CSU surface instrumentation and array processor or at the computing centre using a true full-waveform technique.

5.5 Dipole Shear Sonic Imager (DSI)The DSI tool incorporates a dipole energy source and a receiver array to provide shear measurements in all formations regardless of the shear velocity values. Monopole sonic toolscanonlydetectshearvelocitiesthatarefasterthantheboreholefluidvelocity,orinotherwordsinhardrocksonly.Dipoletoolsovercomethislimitationoffluidvelocityandmeasureshearwavevelocitiesinbothsoftandhardrockformations.

Ratherthanrecordingjustthecompressionalwavecomponent,awaveform-processingtechniqueisusedinArrayandDSItoolstofindandanalyseallpropagatingwavesin the composite waveform. This slowness-time coherence technique (STC) uses a semblancealgorithm, similar to that employed in seismicprocessing, todetectarrivals that are coherent across the array of receiver waveforms and to estimate their interval transit time.


24

8 Receivers

Dipole-Monopole receivers

Monopole transmitter

Upper dipole transmitter

Lower dipole transmitter

3 TRANSMITTERS

3.5 ft

11.5 ft11 ft

9 ft

Figure 14 Dipole Sonic Imager (DSI).

Applying this semblance algorithm to the waveforms of Figure 8 produces the coherence map shown in Figure 15. Regions of large coherence correspond to the compressional,shear,andStoneleyarrivals. Theapexofeachregiondefinestheslowness of that wave. This process is repeated for each set of array waveforms acquiredbythetoolwhilemovinguptheholeandisusedtoproducealog.Atypicallog determined in this fashion is shown in Figure 16. Compressional transit time, tc : shear transit time, ts ; and Stoneley transit time, tst , are presented. In a slow formation, the tool obtains real-timemeasurementsofcompressional, Stoneley,and mud wave velocities. Shear wave values are then derived from these velocities.



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240

200

160

120

80

40500 1000 1500 2000

Stoneley

Shear

Compressional

2500Time (µS)

Slow

ness

(µS/

ft)

3000 3500 4000 4500

Figure 15 Contour plot of the STC coherence function.

240Slowness (µs/ft)

Dep

th (f

t)

∆tStoneley

∆tshear

∆tcompr

2900

3000

3100

3200

3300

40

Figure 16Logofclassifiedcomponentslowness.

Becauseof thenumberof receivers, the full-wavetrain recording,and thedigitaltransmission,theArrayandDSI-sonictoolscanprovidealargeamountofacousticinformation.


26

6 DENSITY LOGGING TOOLS

Densityloggingtoolscontainaradioactivesourcewhichisappliedtotheboreholewall in a shielded sidewall skid. This source emits medium-energy gamma rays intotheformations.Thesegammaraysmaybethoughtofashigh-velocityparticlesthat collide with the electrons in the formation. At each collision a gamma ray loses some,butnotall,ofitsenergytotheelectron,andthencontinueswithdiminishedenergy.ThistypeofinteractionisknownasCompton scattering. The scattered gammaraysreachingthedetector,atafixeddistancefromthesource,arecountedas an indication of formation density.

E’

E’’

e’

e’’θ

Figure 17 Schematic representation of the Compton Interaction. A gamma ray of energy E" transfers a portion of its energy to an electron e". This results in a gamma ray of

reduced energy E' leaving the site of collision at an angle _ with respect to the direction of theincidentgammaray.Thedisplacedelectronisshownbye'.

ThenumberofCompton-scatteringcollisionsisrelateddirectlytothenumberofelectronsintheformation.Consequently,theresponseofthedensitytoolisdeterminedessentiallybytheelectrondensity(numberofelectronspercubiccentimetre)oftheformation.Electrondensityisinturnrelatedtothetruebulkdensity,whichinturn,depends on: Thedensityoftherockmatrixmaterial;Theformationporosity;andThedensityofthefluidsfillingthepores.

Tominimisetheinfluenceofthemudcolumn,theskid-mountedsourceanddetectorareshielded.Theopeningsoftheshieldsareappliedagainstthewalloftheboreholebyaneccenteringarm(Figure18). Theforceexertedbythearm,andtheplow-shapeddesignoftheskid,allowittocutthroughsoftmudcakes.Anymudcakeormudremainingbetweenthetoolandtheformationis“seen“aspartoftheformationandmustbeaccountedfor.

Acorrectionisneededwhenthecontactbetweentheskidandtheformationsisnotperfect(mudcakeorirregularitiesintheboreholewall).Inunfavourablecasesthiscorrectioncanbefairlylarge.Ifonlyonedetectorisused,thecorrectionisnoteasytodeterminebecauseitdependsonthethickness,theweight,andeventhecompositionofthemudcakeormudinterposedbetweentheskidandtheformations.



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Mudcakermc hmc

,( )

Formation (rb)

Long-Spaced Detector

Short-Spaced Detector

Source

Figure 18 Schematic drawing of the dual spacing Formation Density Logging Device (FDC).

Density logs are primarily used as porosity logs. Other uses include:

Identificationofmineralsinevaporitedeposits,Detectionofgas,Determinationofhydrocarbondensity,Evaluationofshalysandsandcomplexlithologies,Determinationofoil-shaleyield,CalculationofoverburdenpressureandRockmechanicalproperties.

6.1 Compensated Formation Density ToolsIn the compensated formation density tool (FDC),twodetectorsofdifferingspacinganddepthofinvestigationareused,asshownofFigure18.ThechartofFigure19 is a plot of long-spacing versus short-spacing count rates. Points for a given value of rb andvariousmudcakeconditions fallonorveryclose to anaveragecurve.Usingtheseaveragecurvesitispossibletoenterthechartwiththetwocountratesand determine the corrected rb from the plot without any explicit measurement of mudcakedensityorthickness.Thismeasurementtechniqueisreferredtoas“spine and ribs”. The correction is made automatically and the corrected rb and ∆r (the correctionmade)arerecordeddirectlyonthelog(Figure20).Thedistancebetweenthefaceoftheskidandtheextremityoftheeccenteringarmisrecordedasacalliperlog,whichhelpstoassessthequalityofcontactbetweentheskidandtheformation.


28

1/4 in.

1.01.4

1.75

1/2 in. 3/4 in.tmcrmc

rb = 1.9

2.0

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

1/4 in.%

2.02.12.5

33Barite

Mudcake With Barite

MudcakeWithout Barite

Short-Spaced Detector Counting Rate

Long

-Spa

ced

Det

ecto

r Cou

ntin

g R

ate

3966

1/2 in. 3/4 in.tmcrmc

Figure 19"SpineandRibs"plot,showingresponseoftheFDCcountingratestomudcake.



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CaliperHole Diam. in.

API UnitsGamma Ray

6 16

Depths

0 100

Bulk Densityg\cm3

g\cm3Correction

-.25 +250

2.5

Mud Wt. 10 lb/gal

Figure 20 FDC Log Presentation.

6.2 The Litho Density ToolsThe Litho-Density Log is an improved and expanded version of the FDC log. In additiontothebulkdensitymeasurement,thetoolalsomeasuresthephotoelectricabsorptionindexoftheformation,Pe.viaPhotoelectricEffect.Whenthephoton,inthecourseofacollisionwithanelectron,transfersallitsenergytotheelectronintheformofkineticenergy,theelectronisejectedfromitsatomandthephotondisappears.ThegammarayisabsorbedasillustratedinFigure21.


30

Ejected photoelectron

Incidentphoton

Residual Oil Saturation

Formation Water

Mud-cake

Mud

Hole axis

100

Oil

Depth of invasion, di

Borehole wall

0

Mud

Virgin zone

m

Annulus zoneTransition zone

Flushed zone

Depth of invasion

e

Rw

Rmf Filtrate

Water saturation, Sw

Radial distribution of fluids in the formation

RiRxo

Rt

Ran

R

Radial distribution of resistivities

mcR

Figure 21 Schematic of the photoelectric process.

Photoelectricabsorptioncanberelatedtolithology;whereastherb measurement respondsprimarily toporosityandsecondarily torockmatrixandporefluid, thePemeasurementrespondsprimarily to rockmatrix(lithology)andsecondarily toporosityandporefluid.

Inappearanceandoperation,theLitho-DensitytoolissimilartotheFDCtool.Thetoolhasapad,orskid,inwhichthegammaraysourceandtwodetectorsarelocated.Thisskidisheldagainsttheboreholewallbyaspring-activatedbackuparm.Gammarays,emittedbythesourceatanenergyof662keV,arescatteredbytheformationandloseenergyuntilabsorbedthroughphotoelectriceffect. Atafinitedistancefromthesource,suchasthefardetector,theenergyspectrummightlookasillustratedinFigure22. Thenumberofgammaraysinthehigherenergy region (region of Compton scattering) is inversely related only to the electron densityof the formation (i.e., an increase in the formationdensitydecreases thenumberofgammarays).Thenumberofgammaraysinthelowerenergyregion(regionofphotoelectriceffect)isinverselyrelatedtoboththeelectrondensityandthephotoelectricabsorption. Bycomparing thecounts in these tworegions, thephotoelectricabsorptionindexcanbedetermined.



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Region ofPhotolectric Effect

(r and Z Information)Region of

Compton Scattering(r Information Only)

Source Energy662 keV

E(keV)H

(Low Z)(Med Z)(High Z)

cps/keV t mcEffect ofBarite

S

Figure 22VariationsinspectrumforformationwithconstantdensitybutdifferentZ.

The gamma ray spectrum at the near detector is used only to correct the density measurementfromthefardetectorfortheeffectsofmudcakeandboreholerugosity.

6.3 Triple Detector Lithology Density Tool (TLD)Thistoolprovidesinformationonbulkdensity,lithologyandboreholediameter.AswiththeFDCandLDTtools,theTLDtoolemitsgammaraysintotheformationwhich are then detected and counted. The counts are then arranged according to their energy spectrum. The lower energy part of the spectrum corresponds to lithology and isdominatedbyPhotoelectricEffect.ThehigherenergypartcorrespondstodensityandisdominatedbyComptonscattering.Afewercountratesinthelithologywindowwouldmeanthemorephotoelectricabsorptionhastakenplaceandthehighertheatomicnumberoftheformation.Thefewercountratesinthedensitywindowwouldmean more Compton scattering and a denser formation.

Lith

olog

y

Den

sity

Cou

nts

per s

econ

d (c

ps)

Energy (keV)

Figure 23. Schematic of the Triple Detector Lithology Density spectrum.


32

Table2 liststhephotoelectricabsorptioncrosssection,giveninbarnsperatom,forseveralelementsattheincidentgammarayenergylevel.Theatomicnumber,Z,foreachoftheseelementsisalsolisted.Thephotoelectriccrosssectionindex,Pe,inbarnsperelectronisrelatedtoZby:

Pe = Z10

3.6

(5)

Element Photoelectric Cross Section Atomic Number ZeHydrogen 0.00025 1Carbon 0.15898 6Oxygen 0.44784 8Sodium 1.4093 11Magnesium 1.9277 12Aluminium 2.5715 13Silicon 3.3579 14Sulphur 5.4304 16Chlorine 6.7549 17Potassium 10.0810 19Calcium 12.1260 20Titanium 17.0890 22Iron 31.1860 26Copper 46.2000 29Strontium 122.2400 38Zirconium 147.0300 40Barium 493.7200 56

Table 2 Photelectric Cross Sections.



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Table 3 Photelectric Cross Sections.

Foramoleculemadeupofseveralatoms,aphotoelectricabsorptioncrosssectionindex,Pe,maybedeterminedbaseduponatomicfractions.Thus,

Pe = ∑ Ai Zi Pi

∑ Ai Zi

(6)

where Aiisthenumberofeachatominthemolecule.

Table3 gives the Pevalueforseveralreservoirrocks,minerals,andfluidscommonlyencounteredintheoilfield.Fromthislistitisnotreadilyapparentthatthecrosssectionisrelativelyindependentofporosityandthesaturatingfluid.Toverifythisrelativeindependence,expressthephotoelectricabsorptioncrosssectionindexinvolumetric terms rather than in electron terms.


34

Bydefinition:

U = Pe re

Since Pe hastheunitsofbarnsperelectronandretheunitsofelectronspercubiccentimetre,Uhastheunitsofbarnspercubiccentimetre.Thisparameterpermitsthecrosssectionsofthevariousvolumetriccomponentsofaformationtobeaddedinasimpleweightedaveragemanner.Thus,

U = f Uf + (1- f) Uma , (7) whereU,Uf,andUmaarethephotoelectricabsorptioncrosssectionsofthemixture,porefluid,andmatrix,respectively;allareexpressedinbarnspercubiccentimetre.TransformationofthemixtureresponsegivenbyEquation7backintoPe gives the response shown in Chart CP-16 when Peiscrossplottedagainstbulkdensity.

TheLitho-DensitytoolskidanddetectorsystemhavebeendesignedsothatgreatercountingratesareobtainedthanwiththeFDCtoolandresult in lowerstatisticalvariationsandbetterrepeatabilityofthemeasurements.Thegeometryoftheskidhasalsobeenalteredsothatthedensityreadinghasagreaterverticalresolutionthanthat of the FDC measurement. The Pemeasurementexhibitsanevenbetterverticalresolution;thishasapplicationsinidentifyingfracturesandlaminarformations.

Theprocedure formudcakeandborehole rugositycompensationwith theLitho-Densitytooluses“spineandrib”asdonewiththeFDCtool.Becauseofthefixedradiusofcurvatureofthemeasuringdevicesurface,boreholesizealsoinfluencesthemeasurement.Theborehole-sizecorrectionisshowninChart Por-5.

7 NEUTRON LOGGING TOOLS

Neutron logs are used principally for delineation of porous formations and determination of porosity. They respond primarily to the amount of hydrogen in the formation. Thus,incleanformationswhoseporesarefilledwithwateroroil,theneutronlogreflectstheamountofliquidfilledporosity.Gaszonescanoftenbeidentifiedbycomparing the neutron log with another porosity log or a core analysis.

NeutronloggingtoolsincludetheGNTtoolseries(nolongerinuse),theSNPsidewallneutronporositytool(inlimiteduse),andtheCNLtoolseries(whichincludestheCNL compensated neutron and Dual Porosity logs). The current tools use americium-beryllium(AmBe)sourcestoprovideneutronswithinitialenergiesofseveralmillionelectronvolts.Neutronsareelectricallyneutralparticles,eachhavingamassalmostidentical to the mass of a hydrogen atom. These neutrons collide with nuclei of the formationmaterialsinwhatmaybethoughtofaselastic“billiard-ball”collisions.Witheachcollision,theneutronlosessomeofitsenergy.

The amount of energy lost per collision depends on the relative mass of the nucleus with which the neutron collides. The greater energy loss occurs when the neutron strikesanucleusofpracticallyequalmass- i.e.,ahydrogennucleus. Collisionswithheavynucleidonotslowtheneutronverymuch.Thus,theslowingofneutronsdepends largely on the amount of hydrogen in the formation.



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Withinafewmicrosecondstheneutronshavebeenslowedbysuccessivecollisionstothermalvelocities,correspondingtoenergiesofaround0.025eV.Theythendiffuserandomly,withoutlosingmoreenergy,untiltheyarecapturedbythenucleiofatomssuchaschlorine,hydrogen,orsilicon.

Thecapturingnucleusbecomesintenselyexcitedandemitsahigh-energygammarayofcapture.Dependingonthetypeofneutrontool,eitherthesecapturegammaraysortheneutronsthemselvesarecountedbyadetectorinthesonde.

When the hydrogen concentration of the material surrounding the neutron source is large,mostoftheneutronsareslowedandcapturedwithinashortdistanceofthesource.Onthecontrary,ifthehydrogenconcentrationissmall,theneutronstravelfartherfromthesourcebeforebeingcaptured.Accordingly,thecountingrateatthedetectorincreasesfordecreasedhydrogenconcentration,andviceversa.

7.1 GNT ToolsThe GNT tools were nondirectional devices that employed a single detector sensitive tobothhigh-energycapturegammaraysandthermalneutrons.Theycouldberunincasedoruncasedholes.AlthoughtheGNTtoolsrespondedprimarilytoporosity,theirreadingsweregreatlyinfluencedbyfluidsalinity,temperature,pressure,boreholesize,stand-off,mudcake,mudweight,and,incasedholes,bythecasingandcement.

7.2 The SNP ToolIn the SNP tool theneutronsourceanddetectoraremountedonaskid,whichisappliedtotheboreholewall.Theneutrondetectorisaproportionalcounter,shieldedsothatonlyneutronshavingenergiesaboveabout0.4eV(epithermal)aredetected.

The SNP tool has several advantages over the GNT tools:

• Becauseitisasidewalldevice,boreholeeffectsareminimised

• Epithermalneutronsaremeasured,whichminimisestheperturbingeffectsof strongthermalneutronabsorbers(suchaschlorineandboron)intheformation waters and matrix

• Most required corrections are performed automatically in the surface instrumentation

• Itprovidesagoodmeasurementinemptyholes

TheSNPequipmentisdesignedforoperationonlyinopenholes,eitherliquidfilledorempty.Theminimumholediameterinwhichthetoolcanbeusedis5in.Acalipercurve is recorded simultaneously with the SNP neutron data.

7.3 The CNL ToolThe CNL toolisamandrel-typetoolespeciallydesignedforcombinationwithanyof several other tools to provide a simultaneous neutron log. The CNL tool is a dual-spacing,thermalneutron-detectioninstrument.Theratioofcountingratesfromthetwodetectors isprocessedby thesurfaceequipment toproducea linearlyscaledrecording of neutron porosity index. A 16-curie source and longer source-to-detector spacings give the CNL tool a greater radial depth of investigation than that of the


36

SNPtool.Theeffectsofboreholeparametersaregreatlyreducedbytakingtheratiooftwocountingratessimilarlyaffectedbytheseperturbations.TheCNLtoolcanberuninliquid-filledholes,eithercasedoruncased,butcannotbeusedingas-filledholes.

SincethermalneutronsaremeasuredintheCNLtool,theresponseisaffectedbyelements having a high thermal neutron capture cross section. The tool is sensitive toshaleintheformationsinceshalesusuallycontainsmallamountsofboronandother rare earth elements having a particularly high thermal neutron capture cross section.Ifexcessive,thiseffectcanmaskthetoolresponsetogasinshalyformations.

To improve the response to gas and to enhance interpretation in the presence of thermal neutron absorbers, the Dual Porosity tool incorporates two epithermalneutron detectors in addition to the two thermal neutron detectors (Figure 24). Two separateporositymeasurementsareobtained,onefromeachpairofdetectors.Inclean formations the measured porosities generally agree. In shaly formations containingalargenumberofthermalneutronabsorbers,theporositymeasuredbythe epithermal detectors reads lower and agrees more closely with density-derived porosity. A comparison of the two porosity measurements indicates the shale or clay content,ortheformationfluidsalinity.

Thermal Detectors

Source 16 Curie AmBe

EpithermalDetectors

Figure 24CNT-Gtoolconfiguration.



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Atagivensource-detectorspacing,epithermalneutroncountrateisapproximatelyanorderofmagnitudelessthanthatforthermalneutrons.Therefore,tohavereasonableepithermalneutroncountrates,theepithermaldetectorshavebeenplacednearertothe neutron source than the thermal neutron detectors. The thermal neutron-detector configurationduplicatesthatofthestandardCNLtool.

Since the two pairs of detectors are placed at different spacings and neutrons are detectedatdifferentenergylevels,theenvironmentaleffectscanbeexpectedtobesignificantlydifferentonthetwoneutronmeasurements.

If the ratio processing used on the thermal neutron measurement is used for the epithermalmeasurement,thecomputedporosityisquitesensitivetoboreholeeffect.Asaresultofadetailedstudyofdetectorresponsetomanyenvironmentalvariables,andepithermalneutronprocessingtechniquehasbeendevelopedthatusesindividualdetectorcountrates.Themethod,whichisanalogoustothespine-and-ribsanalysisdevelopedfortheFDCtool,greatlyreducesboreholeeffectsontheepithermalneutronporositymeasurement.Theepithermalcountratescanalsobeusedtodetermineneutronporosityinair-filledboreholes.

ThecombinedepithermalandthermalneutronDualPorositymeasurementsprovideimproved porosity determination. Since the epithermal measurement is relatively freeofneutronabsorbereffects,ityieldsimprovedgasdetectioninshalyreservoirs(Figure 25). A comparison of the two neutron responses also provides information onthepresenceofmaterialswithsignificantthermalneutroncapturecrosssections.


38

∅D

∅D

030ρma

ρma

3.02.0

GR

GR

3000

3100

1500 ∅N

∅N(Th)

ρma

Dolomite

Dolomite

∅DGR

Sand

Sand

∅N(Epi)

Figure 25Thermal/Epithermalneutronlogcomparisoninagaszone.

8 NUCLEAR MAGNETIC RESONANCE (NMR) TOOL

NMR (Nuclear Magnetic Resonance) is a relatively new development in petrophysics and is increasinglybeingused inbothdownhole and laboratoryenvironmentbytheoilindustry.Thetoolmakesuseofthegyromagneticpropertyofprotons(e.g.hydrogen nuclei) which behave likemagnets rotating around themselves. Sincehydrogennucleiareabundantlypresentinporespacesinthecompositionofwaterorhydrocarbons,theyalignthemselvesalongthedirectionoftheappliedmagneticfieldbytheNMRtool.Oncethemagneticfieldisremovedtheprotonsrelaxtoastablealignment.Fromthis,theNMRtoolderivesthefollowingtwosignalswhichare then used for NMR interpretation.



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T1 – Longitudinal Relaxation TimeT2 – Transverse Relaxation Time

M

BO

Figure 26 SchematicoftheNMReffectinanappliedmagneticfield.OntheLeft,protonsspinrandomlyintheabsenceofanexternalfield.Ontheright,protonsalignthemselves

withtheexternallyappliedmagneticfield.

AnumberofNMRtoolshavebeen introduced in the logging industry.AfewofthemincludeCombinableMagneticResonance(CMR)bySchlumberger,MRILbyHalliburton,MagneticResonanceExplorer(MREX)byBakerHughes,andMagneticResonanceScanner(MR-Scanner)whichisSchlumberger’snewgenerationwirelineNMR logging tool. Their main use is in the determination of total porosity (occupied bywaterorhydrocarbons),boundfluidporosity,permeability(qualitativeinsight)andviscosity.Thedownsideof these toolsare for thembeingexpensive,havingconsiderablylowerloggingspeeds.

Inthelaboratory,theNMRtoolisusedinSpecialCoreAnalysisforporecharacterisation.There is one advantage over traditionalmercury injectionmethods for pore sizedistributioninthatitdoesn’tusemercurywhichcanbehazardousinthelaboratory.MorerecentstudiesconsidertheroleofNMRinstudiesoffluid(viscosity,heavyoils)androck:fluidproperties(wettability).

Bound Water Free Fluid

Clay bound Capillary bound

0.1 1 10 100 10000.0

0.4

Nor

mal

ised

am

plitu

de

Schematic of a T2 distribution (ms)

Figure 27SchematicofaT2distributiontoidentifyboundandfreefluids.


40

9 RESISTIVITY TOOLS

Theresistivityofaformationisakeyparameterinthedeterminationofhydrocarbonsaturation.Electriccurrentcanonlypassthroughaformationbecauseoftheconductivewateritcontains.Withafewrareexceptions,suchasmetallicsulphideandgraphite,dryrockisagoodelectricalinsulator.Moreover,perfectlydryrocksareveryseldomencountered.Therefore,subsurfaceformationshavefinite,measurableresistivitiesbecauseofthewaterintheirporesorabsorbedintheirinterstitialclay.Theresistivityof a formation depends on:

• Resistivityoftheformationwater

• Amountofwaterpresent

• Porestructuregeometry

9.1 Resistivity of the fluids in the formationTheelectricalresistivityofasubstanceisitsabilitytoimpedetheflowofelectricalcurrentthroughthesubstance.Theunitusedinloggingisohm-meter,usuallywrittenas ohm-m. Electrical conductivity is the reciprocal of resistivity and is expressed inmillimhospermeter(mmho/m).Anelectricalcurrentwillflowonlythroughtheinterstitial water saturating the pore structure of the formation and then only if the interstitial water contains dissolved salts. These salts dissociate into positively charged cationsandnegativelychargedanions.Undertheinfluenceofanelectricalfieldtheseionsmove,carryinganelectricalcurrentthroughthesolution.Otherthingsbeingequal,thegreaterthesaltconcentration,thelowertheresistivityoftheformationwaterand,therefore,oftheformation.Thegreatertheporosityoftheformationand,hence,thegreatertheamountofformationwater,thelowertheresistivity.

Ofalltherockparametersmeasuredbytoday’sloggingtools,resistivityisofparticularimportance. It is the only measurement for which tools having a deep depth of investigation(uptoseveralfeetbeyondtheborehole)exist.Resistivitymeasurementsare essential for saturation determinations - particularly saturation determinations in thevirgin,uninvadedportionofthereservoir(calledtrueresistivity,Rt) Resistivity measurementsarealsousedtodeterminetheresistivityclosetotheborehole(calledflushed-zoneresistivity,Rxo),wheremudfiltratehas largelyreplaced theoriginalporefluids.Resistivitymeasurements,alongwithporosityandwaterresistivity,areusedtoobtainvaluesofwatersaturation.Saturationvaluesfrombothshallowanddeepresistivitymeasurementscanbecomparedtoevaluatetheproducibilityoftheformation.

Manysophisticatedresistivityloggingmethodshavebeendevelopedtomeasuretheresistivityoftheflushedzone,Rxo,andtheresistivityoftheuninvadedvirginzone,Rt.

9.2 Conventional Electrical ToolsIn the conventional resistivity logging tools currents are passed through the formation bymeansofcurrentelectrodesandvoltagesaremeasuredbetweenmeasureelectrodes.These measured voltages provide the resistivity determination for each device. The deep,mediumandshallowresistivitytoolsaregenerallyrunincombination.The



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earliestsuchcombinationwasknownastheconventional electrical survey (ES) andconsistedofanSP,16”,normal,64”normaland18ft8”lateraldevice.

In the normal device(Figure28),acurrentofconstantintensityispassedbetweentwoelectrodes,AandB. Theresultantpotentialdifference ismeasuredbetweentwootherelectrodes,MandN.ElectrodesAandMareonthesonde.BandNare,theoretically,locatedaninfinitedistanceaway.Inpractice,Bisthecablearmor,andNisanelectrodeonthebridle(theinsulation-coveredlowerendofthecable)farremoved from A and M. The distance AM is called the spacing (16-in. spacing for theshortnormal,64-in.spacingforthelongnormal),andthepointofinscriptionforthemeasurementisatO,midwaybetweenAandM.

Meter

B N

M

AOSpacing

Generator

Figure 28NormalDevice-basicarrangement.

Inthebasiclateral device(Figure29),aconstantcurrentispassedbetweenAandB,andthepotentialdifferencebetweenMandN,locatedontwoconcentricsphericalequipotential surfacescentredonA, ismeasured. Thus, thevoltagemeasured isproportionaltothepotentialgradientbetweenMandN.ThepointofinscriptionisatO,midwaybetweenMandN.ThespacingAOis18ft8in.Thesondeusedin practice differs from that shown in Figure 29 in that the positions of the current andmeasuringelectrodesareinterchanged;thisreciprocalsonderecordsthesameresistivityvaluesasthebasicsondedescribedabove.Also,allelectrodesareintheborehole,withNlocated50ft10in.aboveM.


42

Spacing

A

M

NO

B

Meter

Generator

Figure 29LateralDevice-basicarrangement.

Generally,thelongerthespacing,thedeeperthedeviceinvestigatesintotheformation.Thus,oftheESresistivitylogs,the18-ft8-in.lateralhasthedeepestinvestigationandthe16-in.normaltheshallowest.Inpractice,however,theapparentresistivity,Ra,recordedbyeachdeviceisaffectedbytheresistivitiesandgeometricaldimensionsofallmediaaroundthedevice(borehole,invadedanduncontaminatedzones,andadjacentbeds).

9.3 Focused Electrode LogsTheresponsesofconventionalelectricalloggingsystemscanbegreatlyaffectedbytheboreholeandadjacentformations.Theseinfluencesareminimisedbyafamilyofresistivitytoolsthatusesfocusingcurrentstocontrolthepathtakenbythemeasurecurrent. These currents are emitted from special electrodes on the sondes.

The focusing electrode tools include the laterolog and SFL spherically focused devices. These tools are much superior to the ES devices for large Rt/Rm values (saltmudsand/orhighlyresistiveformations)andforlargeresistivitycontrastswithadjacentbeds(Rt/Rs or Rs/Rt).Theyarealsobetterforresolutionofthintomoderatelythickbeds.Focusingelectrodesystemsareavailablewithdeep,medium,andshallowdepths of investigation. Devices using this principle are used to determine Rt and Rxo.



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The deep-reading devices include: The laterolog 7 The laterolog 3 and The deep laterolog of the DLL* dual laterolog tool

Themedium-toshallow-readingdevices,allintegralwithcombinationtools,are: The Laterolog 8 of the DIL dual induction-laterolog tool The shallow laterolog of the DLL tool and The SFL of the ISF and DIL-SFL combinations

Laterologs3,7,and8arenowobsoletebuttheirdesignprincipleswillbediscussedsincemanywellshavebeenloggedwiththesedevicesovertheyears.

Laterolog 7The LL7 devicecomprisesacentreelectrode,A0,andthreepairsofelectrodes:M1 and M2;M’1 and M’2;andA1 and A2(Figure30).Theelectrodesofeachpairaresymmetricallylocated with respect to A0andareelectricallyconnectedtoeachotherbyshort-circuitingwire.Aconstantcurrent,io,isemittedfromA0.Throughbuckingelectrodes,A1 and A2,anadjustablecurrentisemitted;thebuckingcurrentintensityisadjustedautomaticallysothatthetwopairsofmonitoringelectrodes,M1 and M2 and M’1 and M’2,arebroughttothesamepotential.Thepotentialdropismeasuredbetweenoneofthemonitoringelectrodesandanelectrodeatthesurface(i.e.,atinfinity).Withaconstantiocurrent,thispotentialvaries directly with the formation resistivity.

M’2

M’1

A’1

M’O

AO

MO

A1

M1

M2

A1

A2

O1

O2

A1

O1

O2

A2

M’1

M’2

Laterlog 7

Laterlog 3

Spherically Focused Log

io

ia

io

M’2

M’1

A’1

M’O

AO

MO

A1

M1

M2

iaio

Figure 30 Schematics of Focusing Electrode Devices.


44

Since thepotentialdifferencebetween theM1 - M2 pair and the M'1 - M'2 pair is maintainedatzero,nocurrentfromA0isflowingintheholebetweenM1 and M’1 orbetweenM2 and M'2.Therefore,thecurrentfromA0mustpenetratehorizontallyinto the formations.

Figure30showsthedistributionofcurrentlineswhenthesondeisinahomogeneousmedium;the“sheet”ofiocurrentretainsafairlyconstantthicknessuptoadistancefromtheboreholesomewhatgreaterthanthetotallengthA1A2 of the sonde. Experiments have shown that the sheet of iocurrentretainssubstantiallythesameshapeoppositethin resistive beds.The thickness of the io current sheet is approximately 32 in. (distance O1O2onFigure30),andthelengthA1A2ofthesondeis80in.

Laterolog 3TheLL3alsousescurrentsfrombuckingelectrodestofocusthemeasuringcurrentintoahorizontalsheetpenetratingintotheformation(Figure30).Symmetricallyplaced on either side of the central A0 electrode are two very long (about 5-ft)electrodes,A1 and A2,whichareshortedtoeachother.Acurrent,io,flowsfromtheA0electrode,whosepotentialisfixed.FromA1 and A2flowsabuckingcurrent,whichis automatically adjusted to maintain A1 and A2 at the potential of Ao. All electrodes of the sonde are thus held at the same constant potential. The magnitude of the io current is then proportional to formation conductivity. The iocurrentsheetisconstrainedtothedisk-shapedarea.Thethickness,O1O2,ofthecurrentsheetisusuallyabout12in.,muchthinnerthanfortheLL7device.Asaresult,theLL3toolhadabetterverticalresolutionandshowsmoredetailthandidtheLL7tool.Furthermore,theinfluencesoftheboreholeandoftheinvadedzonewereslightly less.

Laterolog 8The shallow-investigation LL8 measurement is recorded with small electrodes on the dual induction-laterolog sonde. The device is similar in principle to the LL7 toolexceptforitsshorterspacings.Thethicknessofthei0currentsheetis14in.,andthedistancebetweenthetwobuckingelectrodesissomewhatlessthan40in.The current-return electrode is located a relatively short distance from A0. With this configuration,theLL8devicegivessharpverticaldetail,andthereadingsaremoreinfluencedbytheboreholeandtheinvadedzonethanthoseoftheLL7andLL3tools.

Dual Laterolog-Rxo SystemTheobjectiveofanydeep-readingresistivitydeviceistomeasurethetrueformationresistivity,Rt.Deep-readingresistivitytoolsweredesignedsothat,asmuchaspossible,theirresponseisdeterminedbytheresistivityofthevirginformationbeyondtheinvadedzone.Unfortunately,nosinglemeasurementhasyetsucceededinentirelyeliminatingtheeffectsoftheinvadedzone.

A solution is to measure the resistivity with several arrays having different depths of investigation. Measurements responding to three appropriately chosen depths of investigationusuallyapproximatetheinvasionprofilewellenoughtodetermineRt.

For best interpretation accuracy such a combination system should have certaindesirablefeatures:



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• Boreholeeffectsshouldbesmalland/orcorrectable

• Verticalresolutionsofthedevicesshouldbesimilar

• Radial investigations shouldbewelldistributed; i.e.,one readingasdeep aspractical,onereadingveryshallow,andthethirdreadinginbetween

This need resulted in the development of the DLL dual laterolog-MicroSFL tool with simultaneous recording. Figure 31isasketchofthetoolshowingtheelectrodearrayused for the two laterolog devices. Both use the same electrodes and have the range thancoveredbypreviouslaterologdevices.Bothusethesameelectrodesandhavethesamecurrent-beamthickness,buthavedifferentfocusingtoprovidetheirdifferentdepthofinvestigationcharacteristics.Figure32illustratesthefocusingusedbythedeeplaterologdevice(left)andbytheshallowlaterologdevice.

A2

A1M2M1

Ao

M’1 M’2A’1

A’2

12 in.

12 in.

Rxo Pad

14 ft

14 ft

Figure 31 Schematic of the Dual laterolog - Rxo tool.


46

Figure 32 Schematic of the Dual Laterolog.

TheDLLtoolhasaresponserangeof0.2to40,000ohm-m,whichisamuchwiderthanthatcoveredbypreviouslaterologdevices.

Toachieveaccuracyatbothhighandlowresistivities,a“constant-power”measuringsystemisemployed.Inthissystem,bothmeasurecurrent(I0) and measure voltage (Vo)arevariedandmeasured,buttheproductofthetwo(i.e.,power),i0Vo,isheldconstant.

The deep laterolog measurement (LLD) of the DLL tool has a deeper depth of investigation than previous laterolog tools and extends the range of formation conditionsinwhichreliabledeterminationsofRtarepossible.

Toachievethis,verylongguardelectrodesareneeded;thedistancebetweentheextreme ends of the guard electrodes of the DLL-Rxo tool is approximately 28 ft. The nominalbeamthicknessof2ft,however,insuresgoodverticalresolution.

The shallow laterolog measurement (LLS) has the same vertical resolution as the deep laterologdevice(2ft),butitrespondsmorestronglytothatregionaroundtheboreholenormallyaffectedbyinvasion.Itusesatypeoffocusingcalled“pseudolaterolog,”whereinthefocusingcurrentisreturnedtonearbyelectrodesinsteadoftoaremoteelectrode.Thiscausesthemeasurecurrenttodivergemorequicklyonceithasenteredtheformations,thusproducingarelativelyshallowdepthofinvestigation.

Spherically Focused LogThe Spherically Focused Log SFL device measures the conductivity of the formation neartheboreholeandprovidestherelativelyshallowinvestigationrequiredtoevaluate



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the effects of invasion on deeper resistivity measurements. It is the short-spacing device now used on the DIL-SFL tool—developed to replace the 16-in. normal and LL8 devices.

The SFL system differs from previous focused electrode devices. Whereas the LL7 andLL8 systems attempt to focus the current into planar discs, theSFL systemestablishesessentiallyconstantpotentialshellsaroundthecurrentelectrode.TheSFLdeviceisabletopreservethesphericalpotentialdistributionintheformationoverawiderangeofwellborevariables,evenwhenaconductiveboreholeispresent.Toaccomplishthis,theSFLdeviceiscomposedoftwoseparate,andmoreorlessindependent, current systems. The bucking current system serves to “plug” theboreholeandestablishtheequipotentialspheres.Theio survey current system causes anindependentsurveycurrenttoflowthroughthe“volumeofinvestigation”;theintensity of this current is proportional to formation conductivity.

TheSFLdeviceconsistsofcurrent-emittingelectrodes,current-returnelectrodes,andmeasureelectrodes.Twoequipotentialspheresaboutthetool’scurrentsourceareestablished.Thefirstsphereisabout9in.awayfromthesurveycurrentelectrode;theotherisabout50in.away.Aconstantpotentialof2.5mVismaintainedbetweenthese two spherical surfaces. Since thevolumeof formationbetween these twosurfacesisconstant(electrodespacingisfixed)andthevoltagedropisconstant(2.5mV),theconductivityofthisvolumeofformationcanbedeterminedbymeasuringthecurrentflow.

Note the excellent spread in radial characteristics of the deep and shallow laterolog measurements. This feature permits accurate resistivity analysis over a wide range of invasion conditions.

9.4 Induction Logging ToolsThe induction logging tool was originally developed to measure formation resistivity inboreholescontainingoil-basemudsandinair-drilledboreholes.Electrodedevicesdid not work in these non-conductivemuds, and attempts to use wall-scratcherelectrodes were unsatisfactory.

Experience soon demonstrated that the induction log had many advantages over theconventionalESlogwhenusedforloggingwellsdrilledwithwater-basemuds.Designedfordeepinvestigation,inductionlogscanbefocusedinordertominimisetheinfluencesoftheborehole,thesurroundingformations,andtheinvadedzone. Todays induction tools havemany transmitter and receiver coils. However, theprinciplecanbeunderstoodbyconsideringasondewithonlyonetransmittercoiland one receiver coil (Figure 33).


48

Transmitter Oscillator

ReceiverAmplifier

FoucaultCurrent Transmitter

Coil

Ground Loop

ReceiverCoil

Amplifier and OscillatorHousing

Borehole

Figure 33 Basic Two Coil Induction System.

A high frequency alternating current of constant intensity is sent through a transmitter coil. The alternating magnetic field created induces currents in the formationsurroundingtheborehole.Thesecurrentsflowincirculargroundloopscoaxialwiththetransmittercoilandcreate,inturn,amagneticfieldthatinducesavoltageinthereceiver coil. Because of the alternating current in the transmitter coil is of constant frequency andamplitude,thegroundloopcurrentsaredirectlyproportionaltotheformationconductivity. The voltage induced in the receiver coil is proportional to the ground loopcurrentsand,therefore,totheconductivityoftheformation.

Thereisalsoadirectcouplingbetweenthetransmitterandreceivercoils.Thesignaloriginatingfromthecouplingiseliminatedbyusing“bucking”coils.

Theinductiontoolworksbestwhentheboreholeisfilledwithaninsulator-evenairorgas.Thetoolalsoworkswellwhentheboreholecontainsconductivemudunlessthemudistoosalty,theformationsaretooresistive,ortheboreholediameteris too large.

Thesimpletwo-coilsystemdoesnotrepresentthetoolusedtoday.However,itcan



22/10/13

beconsideredthebuildingblockfromwhichtodaysmulti-coilsondesarebuilt.Theresponseofamulticoilsondesareobtainedbybreakingitdownintoallpossibletwo-coilcombinationsoftransmitter-receiverpairs.Theresponseofeachcoilpairisweightedbytheproductofthenumberofturnsonthetwocoilsandbytheproductoftheircross-sectionalarea.Theresponsesofallcoilpairsareadded,withdueregardtothealgebraicsignoftheircontributionsandtheirrelativepositions.

Multi-coilsondes,orfocusedsondes,offercertainadvantages.Verticalresolutionisimprovedbysuppressingtheresponsefromtheshoulderformations,anddepthofinvestigationisimprovedbysuppressingtheresponsefromthemudcolumnandtheformationclosetotheborehole.

Theinductiontoolhasbeenthebasicresistivitytoolusedinlogginglow-tomedium-resistivityformationsdrilledwithfreshwater,oil,orairforover25years.Duringthatperiod,severaltypesofequipmenthavebeendevelopedandused.

1. The 6FF40 induction-electrical survey (IES) tool included a six-coil focused inductiondeviceof40-in.nominalspacing(hence,thenomenclature,6FF40),a16-in.normal,andanSPelectrode.Thetoolwasfirstintroducedinthelate1950’sandwasthestandardinductiontoolthroughoutthe1960’s.Ithassincebeenreplacedbyimprovedtools.

2. The DIL-LL8 systemusedadeep-readinginductiondevice(theID,whichwassimilartothe6FF40),amediuminductiondevice(theIM),anLL8device(whichreplacesthe16-in.normal),andanSPelectrode.

TheIMdevicehasaverticalresolutionsimilartothatofthe6FF40(andID)butonlyabouthalfthedepthofinvestigation.TheLL8wasafocused,shallow-investigationdevicewithbetterthin-bedresolutionandlessboreholeinfluencethanthe16-in.normal.Itwasalsovoidofsomedisturbingcharacteristicsofnormaldevicessuchasreversalsinthinresistivebeds.

3. The induction-SFL (ISF) tool incorporated a deep induction device similar tothe6FF40,theSFLdevice,andanSPelectrode.Thetoolwascombinablewiththeboreholecompensatedsonictoolandwithagammaray(GR)device.Thecombinationoffered,incertaingeologicalhorizons,theabilitytoevaluatethehydrocarbonpotentialofthewellinasingleloggingrun.Thesoniclogprovided porosity evaluation and the ISF log provided saturation evaluation.

4. The DIL-SFL tool is similar to the DIL-LL8 tool except that the SFL has replaced the LL8 as the shallow-investigation device. The SFL measurement islessinfluencedbytheboreholethanistheLL8measurement.

5. The Phasor induction toolhasadeep-readinginductiondevice(IDPH),amedium-readinginductiondevice(IMPH),anSFLdevice,andanSPelectrode.The tool employs a digital transmission and processing system and a continuous calibrationverificationsystem.Italsocanbeoperatedatfrequenciesof10and40kHz,aswellasat20kHz(theoperatingfrequencyofmostpreviousinductiondevices).thelowerfrequencyreducesskineffectinverylowresistivity


50

formations and the higher frequency provides more accurate measurements inhigh-resistivityformations.However,exceptforthesespecialsituations,mostlogsarerunat20kHz.

More importantly, in addition to in-phase resistivity (or conductivity)measurements,theinductiondevices(bothIDPHandIMPH)measuretheout-of-phasequandrature,orX-signal.TheavailabilityoftheX-signalimprovestheaccuracyoftheskin-effectcorrection,improvesthethin-bedresponseoftheinductionmeasurements,andpermitstheuseofasuperiordeconvolutiontechnique.

ThePhasorlogsarecompletelycorrectedforshouldereffect,haveverticalresponsefunctionsthatareconstantwithformationconductivitychanges,andhave more nearly linear radial responses.

6. The 6FF28 IES tool(25/8-in.diameter)isascaled-downversionofthe6FF40device,havinga28-in.primarycoilspacing,andincludesastandard16-in.normal device and an SP electrode. It is used for logging in small holes and for through-drillpipe operations.

7. The array induction tools (AIT) measure formation conductivity as a function ofbothdepthandradius.Suchtoolsuseanarrayinductioncoilwhichoperatesatmultiplefrequenciesinordertogenerateanumberofresistivitylogswithdifferentdepthsofinvestigation.Thelargedataenablesonetocreate2Dimagesofformationresistivitieswithbeddingandinvasionfeaturesclearlyidentified.

9. 5 Environmental Factors on Induction Logging ToolsDuringthedescriptionofeachtypeofresistivitymeasurement,unwantedenvironmentaleffects'whichaffectthemeasurement'shouldbetakenintoaccount.Inmostcases,thesignaltravelsthroughmud,mud-cake,flushedzone,transitionzone,virginzoneandshoulderbeds.Thereforenecessarycorrectionsshouldbemadebyusingappropriatemeans(e.g.byusingthechartssuppliedbyoperatingcompanies). InvasionTheinvadedandflushedzonesignalsbecomemoreimportantwheninvasiondiameter(di)increasesandtheresistivitycontrastbetweeninvadedandvirginzonesincreases.Fortheoldtools,servicecompaniesprovidechartsallowingthedeterminationofdiandRtwhenRxowasknown.Theinvasionaffectbecomessignificantwhentheresistivityoftheformationishigherthanthatoftheinvadedzone.

AnnulusInhighlypermeableoilbearingformationswithlowwatersaturationandhighoilmobility, it ispossibleforanannulusofhighformationwatersaturationtoformbetweentheinvadedandvirginzones.TheoutcomeofthisresultsinanerroneouslylowRt(Figure34).Necessarycorrectionsprovidedbytheservicecompaniesshouldbeappliedtocompensateforthiseffect.



22/10/13

Ejected photoelectron

Incidentphoton

Residual Oil Saturation

Formation Water

Mud-cake

Mud

Hole axis

100

Oil

Depth of invasion, di

Borehole wall

0

Mud

Virgin zone

m

Annulus zoneTransition zone

Flushed zone

Depth of invasion

e

Rw

Rmf Filtrate

Water saturation, Sw

Radial distribution of fluids in the formation

RiRxo

Rt

Ran

R

Radial distribution of resistivities

mcR

Figure 34.Fluidandresistivitydistribution(annuluseffect).

Skin EffectForveryconductiveformations,secondarycurrents(alsocallededdycurrents)areproduced within the formation. These currents create a negative electromotive force (emf)whichopposestheoriginalmagneticfieldproducedbythetransmittercoilintheinductionloggingtool.Whenpresentnearthevicinityofthetool,thesesecondarycurrentstendtheelectromagneticfieldtopenetratedeeperintotheformation.Moderntools have auto corrections applied.

Bed Thickness and Adjacent BedsServicecompaniesprovidechartstocorrectforbedthickness(ifitissmallerthantheverticalresolutionofthetool)andforshoulderbedresistivities.Ifthebedisverythinandconductive,correctionbecomesnecessarybecausethemeasuredresistivityinthatzonewillreadtoolow.


52

9.6 Microresistivity Devices MicroresistivitydevicesareusedtomeasuretheresistivityoftheflushedzoneRxo,andtodelineatepermeablebedsbydetectingthepresenceofmudcake.

Measurements of Rxo are important for several reasons. When invasion is moderate todeep,aknowledgeofRxoallowsthedeepresistivitymeasurementtobecorrectedtotrueformationresistivity.Also,somemethodsforcomputingsaturationrequirethe Rxo/Rtratio.Incleanformations,avalueofFcanbecomputedfromRxo and Rmf if Sxoisknownorcanbeestimated.

To measure Rxo,thetoolmusthaveaveryshallowdepthofinvestigationbecausetheflushedzonemayextendonlyafewinchesbeyondtheboreholewall.Sincethereadingshouldnotbeaffectedbytheborehole,asidewall-padtoolisused.Thepad,carryingshort-spacedelectrodedevices,ispressedagainsttheformationandreducesthe short-circuiting effect of the mud. Currents from the electrodes on the pad must passthroughthemudcaketoreachtheflushedzone.

Microresistivityreadingsareaffectedbymudcake;theeffectdependsonmudcakeresistivity,Rmc,andthickness,hmc. Moreover,mudcakescanbeanisotropic,withmudcakeresistivityparalleltotheboreholewalllessthanthatacrossthemudcake.Mudcakeanisotropyincreasesthemudcakeeffectonmicroresistivityreadingssothattheeffective,orelectrical,mudcakethicknessisgreaterthanthatindicatedbythe caliper.

Older microresistivity equipment included a tool with two pads mounted on opposite sides. Onewasthemicrologpad,andtheotherwaseitherthemicrolaterologorProximitypad,as requiredbymudandmudcakeconditions. Themeasurementswere recorded simultaneously.

Newer microresistivity equipment includes a microlog tool and a MicroSFL tool. Mountedon thepoweredcaliperdevice, themicrologcanberunsimultaneouslywithanycombinationofLitho-Density,CNL. DIL,NGS,orEPTloggingservices.

MicrologWiththemicrologtool,twoshort-spaceddeviceswithdifferentdepthsofinvestigationprovideresistivitymeasurementsofaverysmallvolumeofmudcakeandformationimmediatelyadjoiningtheborehole.Comparisonofthetwocurvesreadilyidentifiesmudcake,whichindicatesinvadedand,therefore,permeableformations.

Therubbermicrologpadispressedagainsttheboreholewallbyarmsandsprings.The face of the pad has three small in-line electrodes spaced 1 in. apart. With these electrodesa1-by1-in.microinverse(R1”x1”) and a 2-in. micronormal (R2”) measurement are recorded simultaneously.

Asdrillingfluidfiltersintothepermeableformations,mudsolidsaccumulateontheholewallandformamudcake.Usually,theresistivityofthemudcakeisslightlygreaterthantheresistivityofthemudandconsiderablylowerthantheresistivityoftheinvadedzoneneartheborehole.



22/10/13

The 2-in. micronormal device has a greater depth of investigation than the microinverse. Itis,therefore,lessinfluencedbythemudcakeandreadsahigherresistivity,whichproduces“positive”curveseparation.Inthepresenceoflow-resistivitymudcake,bothdevicesmeasuremoderateresistivities,usuallyrangingfrom2to10timesRm.

Inimperviousformations,thetwocurvesreadsimilarlyorexhibitsome"negative"separation,andtheresistivitiesareusuallymuchgreaterthaninpermeableformations.

Althoughthemicrologcurvesidentifypermeableformations,quantitativeinferencesofpermeabilityarenotpossible. Whennomudcakeexists,themicrologreadingsmayyieldusefulinformationaboutboreholeconditionorlithology,butthelogisnotquantitativelyinterpretable.

Under favourable circumstances, Rxo values can be derived from the micrologmeasurements using Chart Rxo-1. Rmcvaluesfor thispurposecanbemeasureddirectly or estimated from Chart Gen-7,andhmcisobtainedfromthecalipercurve.Limitations of the method are:

• TheratioRxo/Rmcmustbelessthanabout15(porositymorethan15%)

• hmcmustbenogreaterthan0.5in.

• Depthofinvasionmustbeover4in.;otherwise,themicrologreadingsare affectedbyRt

TheMicroSFLtoolcanalsoberunincombinationwithotherservices.ItismostcommonlycombinedwiththeDLLorDILequipment.Microresistivitylogsarescaled in resistivity units.

• Whenrecordedbyitself,themicrologisusuallyrecordedoverTracks2and 3onalinearscale.ThemicrocaliperisshowninTrack1

• ThemicrolaterologandProximitylogsarerecordedonafour-decadelogarithmic scaletotherightofthedepthtrack.ThecaliperisrecordedinTrack1.When themicrologisalsorecorded,itispresentedinTrack1onalinearscale

• TheMicroSFLmeasurementisalsorecordedonthelogarithmicgrid.When runwiththeDLLorDILlog,itispresentedonthesamefilmandonthesame resistivity scale

MicrolaterologThe microlaterolog tool was designed to determine Rxo accurately for higher values of Rxo/Rmcwherethemicrologinterpretationlacksresolution.Themicrolaterologpadisshown in Figure 35.Asmallelectrode,A0,andthreeconcentriccircularelectrodesareembeddedinarubberpadappliedagainsttheholewall.Aconstantcurrent,io,is emitted through A0. Throughtheouterelectrodering,A1,avaryingcurrent isemittedandautomaticallyadjustedsothatthepotentialdifferencebetweenthetwomonitoringelectroderings,M1 and M2,ismaintainedessentiallyequaltozero.Theiocurrentisforcedtoflowinabeamintotheformation.Theresultingcurrentlines


54

areshownonthefigure.Theiocurrentnearthepadformsanarrowbeam,whichopens up rapidly a few inches from the face of the pad. The microlaterolog resistivity readingisinfluencedmainlybytheformationwithinthisnarrowbeam.

Insulating Pad

BoreholeImperviousFormation

A1A1

A1

AO

O1

O2

M2M2

M2

M1M1

M1AO

Figure 35 Microlaterolog pad showing electrodes (left) and schematic current lines (right).

Figure 36comparesqualitativelythecurrent-linedistributionsofthemicrolaterologandthemicrologdeviceswhenthecorrespondingpadisappliedagainstapermeableformation. The greater the value of Rxo/Rmc,thegreaterthetendencyforthemicrologiocurrenttoescapethroughthemudcaketothemudintheborehole.Consequently,for high Rxo/Rmcvalues,micrologreadingsrespondverylittletovariationsofRxo. Onthecontrary,allthemicrolaterologiocurrentflowsintothepermeableformationand the microlaterolog reading depends mostly on the value of Rxo.



22/10/13

PermeableFormation Permeable

Formation

InsulatingPadMud Cake

Mud Cake

MicrologMicrolaterolog

Current Paths In Focused and Non-FocusedContact Logs

A1

M2

M12

M11

A1

M1

A0

M1M2

A1

Mud Mud

Figure 36 ComparitiveDistributionofCurrentLinesofMicrolaterologandMicrolog.

Laboratorytestsandcomputersimulationresultshaveshownthatthevirginformationhaspracticallynoinfluenceonthemicrolaterologreadingsiftheinvasiondepthismore than 3 or 4 in.

Theinfluenceofmudcakeisnegligibleformudcakeslessthan3/8in.,butincreasesrapidlywithgreaterthickness.Chart Rxo-2 (top) gives appropriate corrections.

Proximity LogThe proximity tool is similar in principle to the microlaterolog device. The electrodes aremountedonawiderpad,whichisappliedtothewalloftheborehole;thesystemisautomaticallyfocusedbymonitoringelectrodes.

Padandelectrodedesignaresuchthatisotropicmudcakesupto3/4in.haveverylittle effect on the measurements (see Chart Rxo-2,bottom).TheProximitytoolhasasignificantlydeeperdepthofinvestigationthandoesthemicrologormicrolaterologtools. Thus, if the invasion isveryshallow, theProximitymeasurementmaybeinfluencedbyRt.Theresistivitymeasuredcanbeexpressesas:

Rp = Jxo Rxo + (1 - Jxo) Rt,

where RpisresistivitymeasuredbytheProximitylogandJxo is the pseudogeometrical factoroftheflushedzone.Jxo depends,tosomeextent,onthediameteroftheboreholeand on the ratio Rxo/Rt.


56

If diisgreaterthan40in.,Jxoisveryclosetounity;accordingly,theProximitylogmeasures Rxo directly. If di is less than40 in.,Rp isbetweenRxo and Rt,usuallymuch closer to Rxo than to Rt. RpcanbefairlyclosetoRt only if the invasion is non-existentorextremelyshallow;ofcourse,whenRxo and Rtaresimilar,thevalueofRp depends very little on di.

TheresolutionoftheProximitylogisabout6in.Correctionsfortheeffectofadjacentbedsareunnecessaryforbedthicknessgreaterthan1ft.

MicroSFLThe MicroSSFL is a pad-mounted spherically focused logging device that has replaced the microlaterolog and Proximity tools. It has two distinct advantages over the other Rxodevices.Thefirstisitscombinabilitywithotherloggingtools,includingtheDILandDLLtools.ThiseliminatestheneedforaseparateloggingruntoobtainRxo information. The second improvement is in the tool’s response to shallow Rxozonesinthepresenceofmudcake.Thechieflimitationofthemicrolaterologmeasurementisitssensitivitytomudcakes.

When mudcake thickness exceeds about 3/8 in., the log readings are severelyinfluencedathighRxo/Rmccontrasts.TheProximitylog,ontheotherhand,isrelativelyinsensitivetomudcakes,butitrequiresaninvadedzonewithadiofabout40in.inorder to provide direct approximations of Rxo.

The solution was found in an adaptation of the principle of spherical focusing in a sidewall-paddevice.Bycarefulselectionofelectrodespacingsandbucking-currentcontrols, theMicroSFLmeasurementwasdesignedforminimummudcakeeffectwithout an undue increase in the depth of investigation (see Chart Rxo-3). Figure 37 illustrates,schematically,theelectrodearrangement(right)andthecurrentpatterns(left) of the MicroSFL tool.

MudcakeMud

Formation

MonitorElectrodes

MeasureVoltageMonitorVoltage

A1

A1

MO

MO

AO

iOia

AO

V = O

Figure 37ElectrodearrangementofMicroSFLdevice(right)andcurrentdistribution(left).



22/10/13

Thesurveyingcurrentflowsoutwardfromacentralelectrode,A0.Buckingcurrents,passingbetweentheelectrodes,A0 and A1,flowinthemudcakeand,tosomeextent,intheformation.Themeasuringcurrent,io,istherebyconfinedtoapathdirectlyintotheformation,whereitquickly“bells”outandreturnstoaremoteelectrode,B.Toachievethis,thebuckingcurrentisadjustedtomakethemonitorvoltageequaltozero.Byforcingthemeasurecurrenttoflowdirectlyintotheformation,theeffectofmudcakeresistivityontoolresponseisminimised;yet,thetoolstillhasaveryshallow depth of investigation.

SyntheticmicrologcurvescanbecomputedfromMicroSFLparameters.Sincethemeasurecurrentseesmostlytheflushedzoneandthebuckingcurrentseesprimarilythemudcake,itispossibletomathematicallyderivemicronormalandmicroinversecurves.

MicroCFLMicro-Cylindrically focussed log is also an Rxo device and replaces the MSFL andmicrolaterologtools.MCFLprovidesinformationoninvadedzoneresistivity,mudcakeresistivityandmudcakethicknesses.ItcontainsmeasurementelectrodesBwhichfocuscurrentsintotheformation,guardelectrodesA0andA1forpassiveandactivefocussinginbothverticalandhorizontaldirection,monitorelectrodeMandauxiliary electrode N. Cylindrically focusing means that the equipotential surfaces (VM-VA0=0)infrontoftheMCFL-platearecylindricallyshapedwhichprovidesagoodfitwiththeboreholeandmudcakegeometryandprovidesbettermeasurements.

AO

BO

B1

B2N

MA1

Figure 38 Electrode arrangement of MicroCFL device.


58

APPENDIX

Summaries of Selected Passive and Active Tools



22/10/13

1. PASSIVE TOOLS

Passive Tools

SP Tool Gamma Ray Tool

Passive tools collect data from the for-mation without firing anything into the formation.

Differentiates potentially porous and permeable reservoirs from impermeable claysDefines bed boundariesGives an indication of shalinessRw determination

The SP deflection depends on the difference between Rw and Rmf. The amplitude and shape of the curve depends on:-Bed thickness and true formation resistivity-Depth of invasion and invaded zone resistivity-Resistivity of the shale, the mud and borehole diameter

Some special events that affect SP Log:-Baseline shifts due to beds of different salinity separated by shale imperfect membranes-Resistive formations in a permeable bed-SP is usually poor or non-existent in carbonatesCan’t be used in oil based mud or in cased holes Won’t detect permeable zones if salinities are equal

Used for:Shale content LithologyCorrelation (well to well, tool string-tool string in the same well) Permeability indicator only if permeability is controlled by clayCan be used in oil-based mud and in cased holes

Measures natural K, U, Th emissions from the earth. Computed gamma ray gives information on the total gamma ray minus the Uranium contribution

Can’t pick out naturally cemented zones (bulk density log can pick these out) Difficult to use in KCL based mud


60

GR Parameters:Vertical Resolution 18"Depth of Investigation 6" - 8"

Readings:Limestone <20APISandstone <30Dolomite <30Anhydrite <10Salt <10Shale 80-300



22/10/13

2. ACTIVE TOOLS

Sonic/Acoustic Tool

Borehole Compensated Tool Long Spaced Sonic Tool Array Sonic Tool

Uses:Porosity determinationCorrelationLithology identificationFracture detection close to the bore-hole wall

Transducers transmit acoustic pulses and a series of receivers detect the returning acoustic pulse from the formation. There are slits on the tool to slow down the acoustic pulse trav-elling from the transmitter to the re-ceiver through the tool body. This makes the first arrival of the acoustic pulse from the formation.

Compensates for the path of the acoustic pulse through the borehole fluid and also compensates for any tilt in the tool.

Similar to the BHC tool but it has much larger separation b/w transmit-ter and receiver such that the P wave through the tool body doesn’t become the first arrival.

Uses a number of receivers to take a series of measurements of the acoustic properties of the formation. The tool is able to measure Shear and Stoneley waves in hard formations.


62

Acoustic Waves:StonelyMud WaveRayleighShearCompressional

Borehole Effects:Borehole Rugosity and Large Holes:CycleSkippingRoad NoiseGasAlteredZoneCavesFractures

Sonic Parameters:VerticalResolution(BHC,LSS,MSTC, 24"STC) 36"Vertical Resolution 6"DT 6"Depth of Investigation BHC 5"Depth of Investigation LSS-SDT 12"

Readings:Limestone 47.5ms/ftSandstone 51-55Dolomite 43.5Anhydrite 50Salt 67Shale >90Coal >120Steel (Casing) 57



22/10/13

Bulk Density Tool

Compensated Formation Density Tool

Lithodensity Tool

It measures the density of the formation by shooting gamma rays into the formation and one essentially sees how many of the gamma rays come back to the detector. Higher the amount of radiations coming back to the detector, the less dense is the formation.

It not only measures formation den-sity but also gives information on the lithology/mineralogy of the formation by measuring the photo-electric factor. E.g. if there are big targets like Barite in the formation, gamma rays lose their energy quickly and photoelectric effect happens. By measuring these energy levels, you can determine the mineralogy of the formation.

Gamma rays get scattered due to collisions with electrons in the formation and lose some of their energy due to Compton scattering effect.

Number of Compton scattering events: Number of electrons in the formation, Electron density within the formation, 1/ Formation porosity.

88

8


64

Corrections:BoreholeSizeHole RugosityLDT Parameters:Vertical Resolution 18"Enhanced 6"Depth of Investigation 6" - 9"

Readings:Limestone 2.71 g cm3Sandstone 2.65Dolomite 2.85Anhydrite 2.98Salt 2.03Shale 2.2-2.7Coal 1.5

PEF Parameters:Vertical Resolution 4"

Readings:Limestone 5.08barnsperelectronSandstone 1.81Dolomite 3.14Anhydrite 5.05Salt 4.65Shale 1.8 - 6Barite 266.80



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Neutron Tool

Sidewall NeutronPorosity (SNP) Tool

Compensated NeutronLog (CNL)

Dual Property Tool(DTP)

Shoots high energy neutrons into the formation which collide with hydro-gen atoms in the formation. More collisions would result less neutrons coming back to the detector and a higher fluid filled porosity.

Tool sees bound water in clays and hence overestimates porosity.

The tool detects both Thermal and Epithermal neutrons.

The tool has problem with over estimating porosity due to the bound water in clays and water of crystallization.

Large spacing between the source and the detector. The tool detects Thermal neutrons only.Can be used in open and cased hole.

If Boron or Chlorine is present in the formation, they absorb thermal neu-trons and the tool sees this as addi-tional porosity.

Small spacing between the source and the detector. The tool detects only Epithermal neutrons.

Smaller depth of investigation due to a short spacing between the source and the detector. Can only be used in openholes and not in cased holes.


66

Corrections to CNL: BoreholeSize Mudcake Borehole Salinity Mud weight Temperature Pressure Formation Salinity Standoff

Parameters: Vertical Resolution 24" Enhanced 12" Depth of Invasion 9"-12"



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SUMMARY TABLES OF TOOLS AND MEASUREMENTS

Tool

Gam

ma

Ray

Spon

tane

ous

Pote

ntia

lSP

Elec

trica

l Pot

entia

lAc

ross

Sa

nd/S

hale

Inte

rface

s

Dete

ction

of P

erm

eable

Zone

s

Corre

lation

Form

ation

Wat

er S

alinit

y

Bed

Thick

ness

Dete

rmina

tion

GR

Gam

ma

Rad

iatio

nfro

mFo

rmat

ion

Cor

rela

tion

Dep

th C

ontro

lSh

ale

Con

tent

Des

igna

tion

Schl

um.

WA

Mea

sure

men

tQ

ualit

ativ

e U

seQ

uant

itativ

e U

se

Shal

e vs

. Non

-Sha

le

Dete

ction

of R

adioa

ctive

Mine

rals

Estim

ate

Shale

in “D

irty”

Sand

s

Table 1 Summary of gamma ray and spontaneous potential logging tools.


68

TOO

LD

ESIG

NA

TIO

NM

EASU

REM

ENT

QU

ALI

TA

TIV

E U

SEQ

UA

NTI

TATI

VE

USE

Soni

c:

Bore

hole

Com

pens

ated

Long

Spa

ced

Soni

c

Arr

ay S

onic

BHC

LSS

Prop

ogat

ion

of so

und

thro

ugh

rock

Lith

olog

y

Cor

rela

tion

Det

ectio

n of

Fra

ctur

es

Late

ral P

redi

ctio

n

Poro

sity

Seism

ic V

eloc

ity

Den

sity

:

Com

pens

ated

Form

ation

Den

sity

Lith

-Den

sity

Too

l

FDC

LDT

Impa

ct o

f Gam

ma

Rays

on

Elec

trons

in F

orm

atio

n

Iden

tific

atio

n of

min

eral

s in

com

plex

lith

olog

y

Nat

ure o

f Flu

id in

Por

es

Gas

Det

ectio

n

Late

ral P

redi

ctio

n

Poro

sity

Den

sity

Seism

ic V

eloc

ity

Neu

tron

:

Com

pens

ated

Neu

tron

Log

CNL

Impa

ct o

f neu

trons

on

H a

tom

s

Cor

rela

tion

Lith

olog

y

Gas

Det

ectio

n

Poro

sity

Table 2 Summary of porosity logging tools.



22/10/13

Nor

mal

Res

. Log

s:

Shor

t Nor

mal

Long

Nor

mal

Late

ral

SN LN LAT

Resis

tivit y

Det

erm

ine

Sw

Non

- Foc

used

Seve

re In

vasi

on E

ffect

Not

in

cono

n-nd

uctiv

e

mud

s

Late

rolo

g 3

Late

rolo

g 7

Late

rolo

g 9

Dua

l Lat

erol

og

LL3

LL7

LL9

DLL

Dee

p Re

sistiv

ity in

salty

mud

s

Det

erm

ine

Sw

Focu

sed

Reso

lutio

n po

wer

ca.

2-4f

t

Salt

sat.

mud

s

Indu

ctio

n L

ogs:

Indu

ctio

n El

ectri

cal

Surv

ey

Indu

ctio

n To

ol

Indu

ctio

n Sp

heric

ally

Focu

sed

Dua

l Ind

uctio

n

IES

6FF

40

ISF

DIL

Dee

p Re

sistiv

ity in

resi

stiv

e

mud

s

Det

erm

ine

Sw

Focu

sed

Reso

lutio

n po

wer

ca.

5ft

Oil

Bas

ed o

r Fre

shw

ater

mud

s

Mic

rolo

gM

LM

udca

ke In

dica

tor

Det

erm

ine

Sw

Thin

bed

det

ecto

r

Reso

lutio

n po

wer

ca.

2”

Mic

rore

sist

ivit

y

Log

s:

Mic

rola

tero

log

MLL

Re

sistiv

ity (I

nvad

ed Z

one)

D

eter

min

e Sw

Prox

imity

Log

PL

Poor

if th

ick

mud

cake

Mic

ro sp

heric

ally

M

SFL

Po

or if

shal

low

inva

sion

TOO

LD

ESIG

NA

TIO

NM

EASU

REM

EN

TQ

UA

LIT

ATI

VE

USE

QU

AN

TITA

TIV

E U

SE

Table 3 Summary of resistivity logging tools.


70


CHART RXO-1CHART RXO-2CHART RXO-3

CHART GEN-7

CHART CP-16

CHART POR-5



22/10/13


72


Determination of Porosity F I V E

ConductivitySonic BHCSP

Depths

15002000

2500

150 100 50 2 10 1000mV Millimhos m/m2µs/ft

ØDρb

ρma

∆t∆tma

3030

473

152

6

20

10

2.2

2.3

2.4

2.5

2.6

60 70 80 90 100 110

20

10

22/10/13

1 INTRODUCTION

2 DETERMINATION OF POROSITY FROM ACOUSTIC LOG2.1 Porosity from Wyllie Time-Average

Equation2.2 Porosity from Empirical Equation

3 DETERMINATION OF POROSITY FROM DENSITY LOG

4 DETERMINATION OF POROSITY FROM

NEUTRON LOGS4.1 SNP Corrections4.2 Hole Size and Mudcake Corrections4.3 Effects of Lithology on Neutron Log

5 EFFECT OF HYDROCARBONS ON POROSITY DETERMINATION5.1 Acoustic Log5.2 Density Log5.3 Neutron Log

6 EFFECT OF SHALE ON POROSITY DETERMINATION6.1 Acoustic Log6.2 Density Log6.3 Neutron Log

7 EFFECT OF CARBONATES ON POROSITY DETERMINATION

8 EFFECT OF UNCOMPACTED SANDS ON POROSITY DETERMINATION

9 EFFECT OF PRESSURE ON POROSITY DETERMINATION 9.1 Acoustic Log9.2 Density Log



C O N T E N T S


22/10/13

LEARNING OBJECTIVES


• Determine porosity from Acoustic, Density and Neutron logs

• Describetheeffectsofhydrocarbons,shale,uncompactedsands,carbonatesand pressure on porosity determination.

• Understandanduseofinterpretationcharts


2

1 INTRODUCTION

Rock porosity is generally determined from the measurements from one, or a combinationof,thefollowinglogs:

• Acousticlog,• Densitylogand/or• Neutronlog.

The measurements of the neutron, density, and sonic logs depend not only on porosity (f)butalsoontheformationlithology,onthefluidinthepores,and,insomeinstances,on the geometry of the pore structure. When the lithology and, therefore, the matrix parameters (tma, rma, fma)areknown,correctporosityvaluescanbederivedfromany one of these logs, appropriately corrected for environmental effects, in clean water-filledformations.

Accurateporositydeterminationismoredifficultwhenthematrixlithologyisunknownorconsistsoftwoormoremineralsinunknownproportions.Determinationisfurthercomplicatedwhentheresponseof theporefluids in theportionof theformationinvestigatedbythetooldiffersappreciablyfromthatofwater.Inparticular,lighthydrocarbons(gas)cansignificantlyinfluencetheresponseofallthreeporositylogs.Even the nature or type of pore structure affects the tool response. The neutron and density logs respond to total porosity - that is, the sum of the primary (intergranular orintercrystalline)porosityandthesecondary(vugs,fissures,fractures)porosity.Thesoniclogs,however,tendtorespondonlytoevenlydistributedprimaryporosity.When any of these complicating situations exists the porosity of the rock can only be determined by cross plotting the measurements from two different log types. In other words the porosity cannot be determined from a single porosity log.ThewayinwhichtheporositycanbedeterminedinthesesituationswillbedescribedinChapter6.

Thischapterwilldescribethewayinwhichtheporosityofarockcanbedeterminedfromthe:

• Acousticlog,• Densitylogand/or• Neutronlog.

Themostsimpleenvironmentinwhichtheporosityofaformationcanbedeterminedisacleanwaterbearingformation.Thefirstpartofthischapterwillthereforedescribehow theporosity in a cleanwaterbearing formationcanbedetermined fromanAcoustic, Density and Neutron log.

Theporositymeasuredbytheselogsishoweverinfluencedbyarangeofvariablesassociatedwiththewellboreandtheformation,suchasthepresenceof:

• Hydrocarbons• Shales• Carbonates



22/10/13

andthereforetheirimpactondeterminationofporositywhenthesesituationsexistwillbedescribedattheendofthechapter.

2 DETERMINATION OF POROSITY FROM ACOUSTIC LOG

The speed of sound in sedimentary formations depends on many parameters. Principally, it depends on the rock matrix material (sandstone, limestone, dolomite etc.)andonthedistributedporosity.Thesonicvelocityandtransittime(inverseofsonicvelocity)forcommonrockmatrixmaterialsandcasingarelistedinTable1. Thesonicvelocitiesofmostofthedrillingfluids,drillingmudcakesanddistilledwaterarecloseto5000ft/sec.

Thevalueslistedarefornonporoussubstancesi.e.forpurelymatrixmaterial.Porositydecreases the velocity of sound through the rock material and, correspondingly, increases the interval transit time.

Vma(ft/sec) ∆∆∆∆tma(µµµµs/ft)

∆∆∆∆tma(µµµµs/ft)(commonly

used)

S andstones

Limestones

Dolomites

Anhydrite

S alt

Casing (iron)

18,000-19,500

21,000-23,000

23,000

20,000

15,000

17,500

55.5-51.0

47.6-43.5

43.5

50.0

67.0

57.0

55.5 or 51.0

47.5

43.5

50.0

67.0

57.0

Table 1 Sonic Velocity vma and transit times Dtma for common rocks and casing.

2.1 Porosity from Wyllie Time-Average EquationM.R.J.Wyllieconductedlaboratoryexperimentstodeterminetherelationshipbetweenporosity and transit time. After numerous experiments, he proposed, for clean and consolidatedformationswithuniformlydistributedsmallpores,alineartime-averageorweighted-averagerelationship:

t LOG = φ tf + 1 - φ( ) t ma

or

f = t LOG - tma

tf - tma

Equation 1 Porosity using the Time-Average Equation

where


4

t Log is the reading on the sonic log in µs/ft,t ma is the transit time of the matrix material,t fisthetransittimeofthesaturatingfluid(about189µs/ftforfreshwatermud systems).

Generally,consolidatedandcompactedsandstoneshaveporositiesofbetween15and25%.Insuchformations,theresponseofthesoniclogseemstoberelativelyindependentoftheexactcontentsofthepores:water,oil,gas,orevendisseminatedshale.

2.2 Porosity from Empirical EquationLong-standingproblemswithusingthetime-averageequation,coupledwithnumerouscomparisons of sonic transit time versus porosity, led to the development of an empirical transittime-to-porositytransform.Thetransformisempirical,beingbasedentirelyon comparisons of sonic transit time and an independent porosity measurement.

Thisempiricaltransformcanbeapproximatedovertherangeofnormallyencounteredporositiesbythefollowingequation:

φSV = C t LOG − tma( )

t LOG

Equation 2 Porosity using the Empirical Equation

ThevalueoftheconstantChasarangeof0.625to0.7dependingupontheinvestigator.0.7wasoriginallyproposedforCandthisvalueisoftenusedinchartbooks(e.g.Chart Por-3).However,morerecenttransittime-toporositycomparisonsindicate0.67ismoreappropriate.

Forthecaseofagas-saturatedreservoirrock,Cbecomes0.6.Itshouldbeusedwhentherockinvestigatedbythesonictoolcontainsanappreciableamountofhydrocarboninthegassy(vapour)phase.Becauseoftheveryshallowdepthofinvestigation,thisconditionnormallyexistsonlyinhigherporositysandstones(greaterthan30%).

Theempiricaltransformexhibitsseveralsalientfeatures.First,itappearsthatallpurequartzsandstonesmaybecharacterisedbyauniquematrixvelocity,slightlylessthan18,000ft/sec.Avalueof17,850ft/sec(ortma = 56µs/ft)issuggested.Limestoneanddolomitealsoseemtoexhibituniquematrixvelocities:20,500ft/sec(ortma = 49µs/ft)forlimestone,and22,750ft/sec(ortma = 44µs/ft)fordolomite.

It canbe seen fromChart Por-3 that in sandstone, the transform yields slightly greaterporosityvaluesoverthelowto-medium-porosityrange(i.e.,the5to25%range)thandoesthetime-averageequationusingan18,000ft/secmatrixvelocity.Infact,at15%porositythetransformindicatesaporositysimilartothatgivenbythetime-averageequationusingamatrixvelocityof19,500ft/sec.Thus,itappearsthehighermatrixvelocitiesusedinsonicinterpretationinthepasthavebeenselectedtoforcethetime-averageequationtoyieldatruerporosityoverthelowtomediumrange;thisistrueforbothcarbonatesandsandstones.



22/10/13

For moderately high porosity sands (21-24%), the proposed empirical transform generally corresponds to the time-average equation using vma=18,000ft/sec.Above30%porosity,however,sonictransittimeincreasesmuchmorerapidlythanporosity,anditsresponsequicklydepartsfromthatpredictedbythetime-averageequation.This is the region inwhich the time-average equationwould require a “lack ofcompaction” correction. The transform eliminates the need for the correction factor and yields porosity directly.

3 DETERMINATION OF POROSITY FROM DENSITY LOG

Thedensitylogrespondstotheelectrondensityoftheformations.Forasubstanceconsisting of a single element, the electron density index, re,isrelatedtothebulkdensityby,

ρe = ρb2ZA

Equation 3ElectronDensityinasubstanceconsistingofasingleelement

where, rbistheactualbulkdensity, Zistheatomicnumber(numberofelectronsperatom),and Aistheatomicweight(rb/Aisproportionaltothenumberofatomspercubic centimetreofthesubstance).

Ele me nt A Z 2Z / A

H 1.008 1 1.9841

C 12.011 6 0.9991

O 16.000 8 1.0000

Na 22.990 11 0.9569

Mg 24.320 12 0.9868

Al 26.980 13 0.9637

Si 28.090 14 0.9968

S 32.070 16 0.9978

Cl 35.460 17 0.9588

K 39.100 19 0.9719

Ca 40.080 20 0.9980

Table 2Atomicnumberandatomicweightforformationelements.


6

Foramolecularsubstance,theelectrondensityindexisrelatedtothebulkdensityby,

ρe = ρb 2

′ Z s∑Mol. Wt.

,

Equation 4ElectronDensityinamolecularsubstance

whereSZ‘sisthesumoftheatomicnumbersofatomsmakingupthemolecule(equaltothenumberofelectronspermolecule)and,Mol.Wt.istheMolecularweight.

Formostformationsubstances,thebracketedquantitiesinEquations3 and 4 are very close to unity (Column 4 of Tables 2 and 3).Whenthedensitytooliscalibratedinfreshwater-filledlimestoneformations,theapparentbulkdensity,ra,asreadbythetool is related to the electron density index, re,by:

ρa = 1.0704 ρe − 0.1883.

Table 3Propertiesofvariousformationsubstances.

Forliquid-filledsandstones,limestones,anddolomitesthetoolreading,ra is practically identicaltoactualbulkdensity,rb.Forafewsubstances,suchassylvite,rocksalt,gypsum,anhydrite,coal,andgas-bearingformations,thecorrectionsshowninFigure1 areneededtoobtainbulkdensityvaluesfromthedensitylogreadings.



22/10/13

0.14

0.12

0.1

0.08

0.06

0.04

0.02

0

-0.02

-0.04

e b -

e LO

G

eLOG (g/cm3)1 2 3

f = Zero

Add correction(Ordinate) to eLOGto obtain True Bulk Density, eb

Aluminium

Salt(NaCl)

Low-pressure gas or air in pores

Dolomite

Magnesium

Sylvite (KCl)

SandstoneLimestoneAnthraciteCoal

BituminousLimestone + Water

Dolomite + Water

Sandstone + Water

f = 40%

f = 40%Anhydrite

Gypsum

Figure 1Correctionneededtogeneratetruebulkdensityfromlogdensity.

Foracleanformationofknownmatrixdensity,rma, having a porosity, f, that contains afluidofaveragedensity,rf,theformationbulkdensity,rb,willbe:

ρa = 1.0704 ρe − 0.1883.

Forusualporefluids(exceptinggasandlighthydrocarbons)andforcommonreservoirmatrixminerals,thedifferencebetweentheapparentdensity,ra,readbythedensitylog,andthebulkdensity,rb, is so trivial that it is disregarded. Solving for f,

φ = ρma − ρb

ρma − ρf,

Equation 5 Porosity from the Density Log

where, rma isthematrixdensity(seeTable3). rf isthefluiddensity rb isthebulkdensityreadfromthelog(=ra)

Thefluidintheporesofthepermeableformations,withintherelativelyshallowzoneinvestigatedbythetool(about6in.),isusuallymostlymudfiltrate.Thismudfiltratemay have a density ranging from slightly less than 1 to more than 1.1 depending upon its salinity, temperature, and pressure. Figure 2 showsthedensitiesofwaterand NaCl solutions at various temperatures, pressures, and salinities. At 750 F and atmosphericpressure,therelationbetweenNaClwatersalinityanddensitymaybeapproximatedby:

rw = 1 + 0.73P,


8

whereP is the NaCl concentration in parts per million.

Chart Por-5showsdensitylog(FDClog)porositiesversusrb readings for various matrices and rf values of 1 through 1.2.

2001501005025

44040030020010040

1.15

1.05

0.95

0.90

0.85

1

1.1

1.1D

ensi

ty (g

/cm

3 )

Temperature (oF)

Temperature (oC)

250,000 ppm

150,000 ppm

100,000 ppm

50,000 ppm

200,000 ppm

NaCl

NaCl

NaCl

NaCl

NaClDistilled Water

7000 psi1000 psi

14.7 psi

7000 psi

7000 psi

7000 psi

7000 psi

7000 psi

1000 psi

1000 psi

1000 psi

1000 psi

1000 psi

14.7 psi

14.7 psi

14.7 psi

14.7 psi

14.7 psi

Pressure

Figure 2Densityofwateratvarioustemperatures,pressuresandsalinities.

4 DETERMINATION OF POROSITY FROM NEUTRON LOGS

Theresponsesoftheneutrontoolsprimarilyreflecttheamountofhydrogenintheformation. Sinceoilandwatercontainpracticallythesameamountofhydrogenperunitvolume,theresponsesreflecttheliquid-filledporosityincleanformations.However,thetoolsrespondtoallthehydrogenatomsintheformation,includingthosechemicallycombinedinformationmatrixminerals.Thus,theneutronreadingdepends mostly on the hydrogen index of the formation. The hydrogen index is proportionaltothequantityofhydrogenperunitvolume,withthehydrogenindexoffreshwateratsurfaceconditionstakenasunity.

Subjecttovariousassumptionsandcorrections,valuesofapparentporositycanbederiveddirectlyfromanyneutronlog.However,certaineffects,suchaslithology,claycontent,andamountandtypeofhydrocarbon,canberecognisedandcorrected



22/10/13

for only if additional porosity information - from sonic and/or density logs - isavailable.Anyinterpretationofaneutronlogaloneshouldnotbeundertakenwithouta realisation of the uncertainties involved.

4.1 SNP CorrectionsMostoftheSNP(SidewallNeutronPorosity)corrections(e.g.,mudweight,salinity,borehole diameter, temperature) and the porosity computation are automaticallyperformedinthetoolinstrumentation.However,becausetheSNPtoolisadirectionalsidewalldevice,itaveragesthehydrogenconcentrationofwhatevermaterialliesinfront of the pad, including the mudcake. (A chart for mudcake correction is provided on Chart Por-15a.)Thepadispressedagainsttheholewallwithgreatforcesothatmuchofthesoftermudcakeisscrapedaway.Moreover,thebackuppadissmallandtends to cut through the mudcake. To get the mudcake thickness in front of the pad, takethedifferencebetweencaliperreadingandbitsize.(Donotdividebytwo.)

4.2 Hole Size and Mudcake CorrectionsThe CNL (Compensated Neutron Log) and Dual Porosity tools are designed to minimise the effects of hole size, mudcake, etc. on the thermal neutron measurement. WheneithertoolisrunincombinationwiththeFDCtool,thecalipersignalprovidesanautomaticholesizecorrection. However, for theotherperturbing influences,andforholesizewhentheFDCtoolisnotrun,automaticcorrectionisnotpossiblebecausethevariablesarenotmeasuredorcontrolled.

4.3 Effects of Lithology on Neutron LogThereadingsofallneutronlogsareaffectedtosomeextentbythelithologyofthematrix rock. SNP and CNL logs are usually scaled for a limestone matrix. Porosities forotherlithologiesareobtainedfromChartsPor-13aandPor-13borfromscalesonthelogheadings.TheSNPcorrectionsapplyonlytologsruninliquid-filledholes.Whentheholeisgasfilled,thelithologyeffectisreducedtoanegligiblelevel,andporositymaybereaddirectlysubjecttolimitations.

ThestandardconditionsforCNLtoolandDualPorositytoolcalibrationare:

• 77/8-in.boreholediameter• Freshwaterinboreholeandformation• Nomudcakeorstand-off• 750Ftemperature• Atmosphericpressure• Tooleccenteredinhole

Iftherearedeparturesfromtheseconditions,thelogswillrequirecorrections.Thecombinedcorrectionforallfactors,usuallysmall,yieldsavalueofcorrectedneutronporosity index. Chart Por - 14c provides the corrections to the CNL and Dual Porosity thermalneutronmeasurementsforboreholesize,mudcakethickness,boreholeandformation-watersalinities,mudweight,pressure,andtemperature.


10

5 EFFECT OF HYDROCARBONS ON POROSITY DETERMINATION

5.1 Acoustic LogGenerally, consolidated and compacted sandstones have porosities from 15 to 25%. Insuchformations,theresponseofthesoniclogseemstoberelativelyindependentof the exact contents of the pores: water, oil, gas, or even disseminated shale.However,insomehigherporositysandstones(30%orgreater)thathaveverylowwatersaturation(highhydrocarbonsaturation)andveryshallowinvasion,thet values maybesomewhatgreaterthanthoseinthesameformationswhenwatersaturated.

5.2 Density LogIfresidualhydrocarbonsexistintheregioninvestigatedbytheFDCtool,theirpresencemayaffectthelogreadings. Theeffectofoilmaynotbenoticeablebecausetheaveragefluiddensity,rf (from ro and rmf)willprobablystillbeclosetounity.Ifthereisappreciableresidualgassaturation,itseffectwillbetolowerthera. Figure 3showsthecorrectionsthatmustbeaddedtotherecordedravaluestoobtaintruerbvalueswhenlow-pressuregasorair(rg approx.=0)occupiesthepores.

0.14

0.12

0.1

0.08

0.06

0.04

0.02

0

-0.02

-0.04

e b -

e LO

G

eLOG (g/cm3)1 2 3

f = Zero

Add correction(Ordinate) to eLOGto obtain True Bulk Density, eb

Aluminium

Salt(NaCl)

Low-pressure gas or air in pores

Dolomite

Magnesium

Sylvite (KCl)

SandstoneLimestoneAnthraciteCoal

BituminousLimestone + Water

Dolomite + Water

Sandstone + Water

f = 40%

f = 40%Anhydrite

Gypsum

Figure 3Correctionneededtogeneratetruebulkdensityfromlogdensity.

The apparentdensityofgas, as seenby thedensity log, canbe computed if thecompositionanddensityofthegasareknown.Figure4isachartshowing,foragasofspecifiedcomposition,thevaluesofrgas (actual density) and ragas, the apparent gas densityseenbythedensitytool(basedonelectrondensity)asafunctionofpressureandtemperature.Ifformationssaturatedwithgasareinthevicinityoftheborehole,use rga instead of rf in Equation 5.



22/10/13

0.7

0.6

0.5

0.4

0.3

0.2

0.1

0.

0.25

0.20

0.15

0.10

0.05

0.

-0.05

-0.10

-0.15

0 2 4 6 8 100

0.1

0.2

0.3 100150200250300350

Sp Gr 0.6Mol. Wt 17.4Eg. Comp. C1.1 H4.2

gHgasagas

Gas Pressure x 1000 in psia

gas = True gas density

agas = Apparent density from FDC log

Hgas = Gas hydrogen index based on SNP Limestone Porosity

Gas Temperaturein oF

Figure 4 Gas density and hydrogen index as functions of pressure and temperature for a gas mixture slightly heavier than methane.

5.3 Neutron LogLiquidhydrocarbonshavehydrogenindexesclosetothatofwater.Gas,however,usuallyhasaconsiderablylowerhydrogenconcentrationthatvarieswithtemperatureandpressure. Therefore,whengas ispresentnearenough to theborehole tobewithinthetool’szoneofinvestigation,aneutronlogreadstoolowaporosity.Thischaracteristicallowstheneutronlogtobeusedwithotherporositylogstodetectgaszonesandidentifygas/liquidcontacts.Aneutronanddensitylogcombinationprovidesamoreaccurateporosityandavalueofminimumgassaturation.(HydrocarboneffectwillbediscussedfurtherinChapter6 in the Cross plotting Section.)

Thequantitativeresponseoftheneutrontooltogasorlighthydrocarbondependsprimarilyonhydrogenindexandanotherfactor-the“excavationeffect.”Thehydrogenindexcanbeestimatedfromthecompositionanddensityofthehydrocarbon.Forlighthydrocarbons(gases),Figure4 provides an estimate of its hydrogen index, Hh. The hydrogenindexofheavierhydrocarbons(oils)canbeapproximatedbytheequation:

H 0 = 1.28 r0 .

Equation 6 Hydrogen Index of Oils


12

This equation assumes the chemical composition of the oil is n CH2. Ho is derived fromthecomparisonofthehydrogendensityandmolecularweightofwatertothoseof oil.

Anothersetofequationscanbeusedtoestimatethehydrogenindexofhydrocarbonfluids:

Forlighthydrocarbons(rh <0.25), H h ≈ 2.2 ρh .

Equation 7HydrogenIndexforlightHydrocarbons

Forheavyhydrocarbons(rh>0.25),

H h ≈ ρh + 0.3.

Equation 8HydrogenIndexheavyhydrocarbons

Still another proposal suggests the equation

H h = 9 4 - 2.5 ρh

16 - 2.5 ρh.

ρh.

Equation 9 General Hydrogen Index of Oils

Mathematical investigations indicate that the effect of gas in the formation near the boreholeisgreaterthanwouldbeexpectedbytakingintoaccountonlyitssmallerhydrogendensity.Previouscalculationshadbeenmadeasifthegas-filledportionoftheporositywerereplacedbyrockmatrix.Thenewcalculationsshowthatwhenthisadditionalrockmatrixis“excavated”andreplacedwithgas,theformationhasasmallerneutron-slowingcharacteristic.Thecalculateddifferenceintheneutronlogreadingshasbeentermedtheexcavationeffect.Ifthiseffectisignored,too-highvaluesofflushed-zonegassaturationandtoo-lowvaluesofporosityaregiven.

Figure5showsthecorrectionsneededforexcavationeffect.Thevaluesofporosityfor sandstone, limestone, and dolomite lithologies are plotted. Intermediate porosity valuescanbeinterpolated.

The ordinate scale is used to correct neutron log porosities. An additional ordinate scale is provided for correcting porosities derived from a neutron-density cross plot that does not contain the excavation effect correction. Excavation effect corrections havealreadybeenincorporatedintoChart CP-5.



22/10/13

ThecorrectionsforexcavationeffectgivenbyFigure5canbeapproximatedbytheformula

φNex = K 2 φ2 SwH + 0.04 φ[ ] 1 - SwH( )

Equation 10 Corrections for excavation effect

whereDfNex, f, and SwHareinfractionalunits.Forsandstonethecoefficient,K,is1;forlimestoneitisabout1.046,andfordolomiteitisabout1.173.Notethatthesecondtermofthisequationisrathersmallandcanoftenbedisregarded.

Dol

omite

Lim

esto

neSa

ndst

one

φ =

30%

φ =

20%

φ =

10%

020

4060

8010

0

∆fN

ax

S wH =

Sxo

Hw +

(1-S

xo) H

h

4 2 0 -2

Add To φN - φD Crossplot Porosity

Add To Neutron Log Porosity

8 4 0 -4

Figure 5 Correction for excavation effect as a function of Sxo for three values of porosity andforHg.Effectsoflimestone,sandstoneanddolomiteincludedwithintheshadedbands.

6 EFFECT OF SHALE ON POROSITY DETERMINATION

6.1 Acoustic LogIfanyshalelaminaeexistwithinthesandstone,theapparentsonicporosityvaluesareusuallyincreasedbyanamountproportionaltothebulkvolumefractionoflaminae.


14

The treadingsareincreasedbecausetsh is generally greater than t ma of the sandstone matrix.Thefollowingformulaisusedtocorrectforshaliness.

6.2 Density LogInterpretationofthedensitylogcanbeaffectedbyshaleorclayintheformations.Although the properties of shales vary with the formation and locality, typicaldensitiesforshalebedsandlaminarshalestreaksareoftheorderof2.2to2.65g/cm3.Shaledensitiestendtobeloweratshallowdepthswherecompactingforcesare not as great. Dispersed clay or shale disseminated in the pore spaces may have asomewhatlowerdensitythantheinterbeddedshales.Thefollowingrelationexiststo correct for shaliness.

ρ b − ρshρbclean.Vsh

1-Vsh=

6.3 Neutron LogNeutron tools see all the hydrogen in the formation even if some is not associated withthewatersaturatingtheformationporosity.Forexample,itseesboundwaterassociatedwiththeshales.Shalesingeneralhaveanappreciablehydrogenindex;inshalyformationstheapparentporosityderivedfromtheneutronresponsewillbegreater than the actual effective porosity of the reservoir rock.

Also,theneutrontoolmeasureswaterofcrystallisation.Forexample,nonporousgypsum (CaSO4 + 2H2O)hasa largeapparentporositybecauseof its significanthydrogen content. To correct for shaliness, use the relation

φ N − φNshφNclean.Vsh

1-Vsh=

The Vsh calculations using GR and SP logs are given in Appendix 2 chapter 7.

7 EFFECT OF CARBONATES ON POROSITY DETERMINATION

Incarbonateshavingintergranularporositythetimeaverageformulastillapplies,but,sometimes,porestructureandporesizedistributionarequitedifferentfromthatofsandstones.Thereisoftensomesecondaryporosityconsistingofvugsand/orfractureswithmuchlargerdimensionsthantheporesoftheprimaryporosity.

In vuggy formations, the velocity of sound seems to depend mostly on the primary intergranular porosity, and the porosity derived from the sonic reading through the time-average formula (fSV)willtendtobetoolowbyanamountapproachingthesecondary porosity. Thus, if the total porosity (ft)ofaformationexhibitingprimary



22/10/13

and secondary porosity (f2) is available (from a neutron and/or density log, forexample,theamountofsecondaryporositycanbeestimated:

f2 = f t - fSV

Equation 11 Secondary Porosity in vuggy formations

8 EFFECT OF UNCOMPACTED SANDS ON POROSITY DETERMINATION

8.1 Acoustic LogDirect application of the time-average equation gives values of porosity that are too highinunconsolidatedandinsufficientlycompactedsands.Uncompactedsandsaremostprevalentinthegeologicallyyoungerformations,particularlyatshallowdepths.However,evenatdeeperdepthstheseyoungersandsareoftenuncompactedwhentheoverburden-to-formationfluidpressuredifferentialsarelessthanabout4000to5000psi.Suchlackofcompactionmaybeindicatedwhenadjacentshalesexhibittvaluesgreaterthan100µs/ft.

Whentheformationsarenotsufficientlycompacted,theobservedt values are greater thanthosethatcorrespondtotheporosityaccordingtothetime-averageformula,butthe f versus t relationship is still approximately linear. In these cases, an empirical correction factor, Cp, (Equation 12) gives a corrected porosity, fSVcor:

φSVcor = t - tma

tf − tma 1Cp

Equation 12 Porosity in uncompacted sands

The value of Cpisgivenapproximatelybydividingthesonicvelocityinnearbyshalebedsby100.However,thecompactioncorrectionfactorisbestdeterminedbycomparing fSV,asobtainedfromEquation1,withthetrueporosityobtainedfromanothersource.Severalapproachesarepossible.

The R0 method:Comparethesonicandinductionorlaterologvaluesinacleanwatersand.ThevalueofR0foundfromtheresistivityisdividedbyRwtoobtainF.Then f is found from F (Chart Por-1)andcomparedwithfSV from Equation 1 (sonic porositywithoutcompactioncorrection).ThevalueofCp is equal to fSV/f. This value of Cpcanthenbeusedtoanalysenearbypotentialhydrocarbon-bearingsands.

Density-sonic cross plot method:Whensonicanddensitylogsareavailable,rb (in ordinate) and t(inabscissae)valuesarecrossplottedoverseveralsandsintheinterval of interest. If the sands contain no gas and some of them are clean, a line drawnfromthematrixpointthroughthepointslyingtowardtheupperrightwillbethecleansandline(Figure6).Foranygivenporosityvalueonthiscleansandline,therewillbeavalueoft. Enter this t in Chart Por-3 and go vertically to the fvalue.TheintersectionwillgivethevalueforCp.Ifasandisknowntobecleanandliquidfilled,thenCp = fSV/fD.


16

Neutron method:Theprevioustwomethodsrequireacleansand.Ifthesandsareshaly,neithermethodcanbesafelyused.IfanSNPorCNL*neutronlogisavailable,fNmaybecomparedwithfSV (or t ) using Chart Por-3.DifferencesbetweenfN and fSVinwater-filledsandsareduetolackofcompaction.Forsuchsands,Cp = fSV/fN.

Insomeshallowlyinvadedhigh-porosityrockswithhighhydrocarbonsaturation,sonic-derivedporositymaybetoohighbecauseoffluideffect. Bothoilandgastransmitsoundatlowervelocities(highertransittimes)thandoeswater.Therefore,thetransittime-to-porositytransform,whichassumeswaterasthesaturatingporefluid,sometimesoverstatesrockporosity.Inthesecases,thetimeaverage-derivedporosity ismultipliedby0.9 inoil-bearing formationsandby0.7 ingas-bearingformations.Thesefluidcorrectionsareappliedonlywhenthetimeaverage-derivedporosityisobviouslytoohigh.

ØDρb

ρma

∆t∆tma

3030

473

152

6

20

10

2.2

2.3

2.4

2.5

2.6

60 70 80 90 100 110

20

10

Figure 6 Density-sonic crossplot as used for compaction-factor determination.

9 EFFECT OF PRESSURE ON POROSITY DETERMINATION

9.1 Acoustic LogFormationshavingabnormallyhighfluidpressuresareoftenoverlainbyover-pressuredshales,whichhaveanexcessofporewater.Sonictransittimeisgreaterintheseshalesthaninnormallycompactedshales.Thus,asoniclogmaybeusedtopredictthepossibilityofover-pressure.

Thesonictraveltimeinshalesnormallydecreaseswithincreasingburialdepth.Aplotof this trend, tshversusdepth,definesthenormalcompaction.Departuresfromthistrendtowardhighervaluessuggestanabnormal,over-pressuredsection(Figure7).Withexperienceinthearea,themagnitudeoftheover-pressurecanoftenberelatedtothedifferencebetweentheactualshaletransittimeandthatexpectedfromthenormal compaction trend line.



22/10/13

ConductivitySonic BHCSP

Depths

15002000

2500

150 100 50 2 10 1000mV Millimhos m/m2µs/ft

Figure 7 Detecting Overpressured zone using the sonic log.

9.2 Density LogThebulkdensityofshaleincreaseswithcompaction,andinareaswherethesedimentsarerelativelyyoungtheincreaseofshaledensitywithdepthisapparentonthelogs.However, departure from this trend is observed in over-pressured zones; shaledensitydecreaseswithincreasingdepth(Figure8).Thisdecreaseoftenappearsin shalesasmuchas severalhundred feetabovehigh-pressurepermeablesands.Ahigh-densityzone(thesealingbarrier)usuallyliesatthetopofthisintervalofdecreaseddensity. Densitylogsrunatintervalsduringthedrillingofawellcanbeusedtopredictabnormallypressuredzonessothatprecautionscanbetakentoeliminatepossiblehazards.


18

Bulk Densityg/cm3

Gamma RayAPI Units

20 120 1.8 2.8

50005100

52005300

54005500

5600

Figure 8 The Density log in overpressured shales.



22/10/13


Chart POR-1Chart POR-3Chart POR-5 Chart POR-13aChart POR-13bChart POR-14c Chart POR-15a Chart CP-5


20


Lithology and Porosity in Complex Formations S I X

Pe, P

hoto

elec

tric

Cro

ss S

ectio

n

(Bar

ns/E

lect

ron)

10

8

6

4

2

00 2 4 86 10

K, Potassium Concentration (%)

Glauconite

BiotiteChlorite

Muscovite

Illite

Montmorillonite

Kaolinite

Pe, PhotoelectricCross Section

(Barns/Electron)

3.0

2.5

2.0

0%

10

203040

Umaa, Apparent MatrixVolumetric Cross Section

(Barns/cm3)

Fresh Water (0 ppk) ρf = 1 Uf = 0.398

6 5 4 3 2 1 4 6 8 10 12 14

φ ta, A

ppar

ent T

otal

Por

osity

(%)

ρ b, Bu

lk D

ensi

ty (g

/cm

3 or M

g/m

3 )

22/10/13

1 POROSITY DETERMINATION IN COMPLEX CONDITIONS

2 NEUTRON-DENSITY CROSSPLOTS

3 SONIC-DENSITY CROSSPLOTS

4 SONIC-NEUTRON CROSSPLOTS

5 DENSITY-PHOTOELECTRIC CROSS SECTION CROSSPLOTS

6 NGS CROSSPLOTS

7 EFFECT OF SHALINESS, SECONDARY POROSITY AND HYDROCARBONS ON SONIC, DENSITY AND NUETRON CROSSPLOTS7.1 Effect of Shaliness on Crossplots7.2 Effect of Secondary Porosity on Crossplots7.3 The Secondary Porosity Index Log 7.4 Effect of Hydrocarbons on Crossplots

8 M-N PLOT

9 MID PLOT

10 PMAA VS UMAA MID PLOT



C O N T E N T S


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LEARNING OBJECTIVES


• Determine the porosity of a mixed lithology rock and explain the reasons for using mixed lithology models.

• Describe the technique and the assumptions used for deriving porosity from neutron-density, sonic-density, sonic-neutron and density-Pe crossplots.

• Describe the technique and the assumptions used for deriving minerals from NGS , M-N and MID crossplots.

• Describe the effect of shaliness, secondary porosity and hydrocarbons on crossplots.


2

1 POROSITY DETERMINATION IN COMPLEX CONDITIONS

The measurements of the neutron, density, and sonic logs depend not only on porosity (φ) but also on the formation lithology, on the fluid in the pores, and, in some instances, on the geometry of the pore structure. When the lithology and, therefore, the matrix parameters (tma, ρma, φma) are known, correct porosity values can be derived from these logs, appropriately corrected for environmental effects, in clean water-filled formations. Under these conditions, a single log, either the neutron or the density or, if there is no secondary porosity, the sonic, can be used to determine porosity (Chapter 5).

Accurate porosity determination is more difficult when the matrix lithology is unknown or consists of two or more minerals in unknown proportions. Determination is further complicated when the response of the pore fluids in the portion of the formation investigated by the tool differs appreciably from that of water. In particular, light hydrocarbons (gas) can significantly influence the response of all three porosity logs.

Even the nature of type of pore structure affects the tool response. The neutron and density logs respond to total porosity - that is, the sum of the primary (intergranular or intercrystalline) porosity and the secondary (vugs, fissures, fractures) porosity. The sonic logs, however, tend to respond only to evenly distributed primary porosity.

To determine porosity when any of these complicating situations exists requires more data than provided by a single porosity log. Fortunately, neutron, density, and sonic logs respond differently to matrix minerals, to the presence of gas or light oils, and to the geometry of pore structure. Combinations of these logs and the photoelectric cross section index, Pe, measurement from the Litho-Density* log and the thorium, uranium, and potassium measurement from the NGS* natural gamma ray spectrometry log can be used to unravel complex matrix or fluid mixtures and thereby provide a more accurate porosity determination.

The combination of measurements depends upon the situation. For example, if a formation consists of only two known minerals in unknown proportions, the combination of density and neutron logs or the combination of bulk density (ρb) and photoelectric cross section will define the proportions of the two minerals and a better value of porosity. If it is known that the lithology is more complex but consists of only quartz, limestone, dolomite, and anhydrite, then a relatively accurate value of porosity can again be determined from the density-neutron combination; however, the mineral fractions of the matrix cannot be precisely determined.

Crossplots are a convenient way to demonstrate how various combinations of logs respond to lithology and porosity. They also provide visual insight into the type of mixtures that the combination is most useful in unravelling. Charts CP-1a through - 21 present many of these combinations.

Figure 1 (Chart CP-1c) is an example in which neutron and density porosities are crossplotted on linear scales. Points corresponding to particular water-saturated pure lithologies define curves (sandstone, limestone, dolomite, etc.) that can be graduated in porosity units, or a single mineral point (e.g., salt point) may be defined. This chart is entered with porosities computed as if the matrix had the same properties as



22/10/13

water-saturated limestone; as a result, the limestone line is the straight line of equal density and neutron porosities.

When the matrix lithology is a binary mixture (e.g., sandstone-lime or lime-dolomite or sandstone-dolomite) the point plotted from the log readings will fall between the corresponding lithology lines.

2 NEUTRON-DENSITY CROSSPLOTS

Charts CP-1a and -1b are for SNP neutron versus density data. These charts were constructed for clean, liquid-saturated formations and boreholes filled with water or water-base mud. The charts should not be used for air-gas-filled boreholes; in these, the SNP matrix effect is changed. Chart CP-1c is a similar plot for CNL* neutron versus density data.

The separations between the quartz, limestone, and dolomite lines indicate good resolution for these lithologies. Also, the most common evaporites (rock salt, anhydrite) are easily identified.

In the example shown on Figure 1, φDls = 15 and φNls = 21. This defines Point P, lying between the limestone and dolomite curves and falling near a line connecting the 18% porosity graduations on the two curves. Assuming a matrix of limestone and dolomite and proportioning the distance between the two curves, the point corresponds to a volumetric proportion of about 40% dolomite and 60% limestone; porosity is 18%.

30

20

10

0

-10

-20 0 10 20 30

Dolomite

Limes

tone

Sands

tone

Anhyd

rite

0

5

10

1520

25

30

00

0

5

5

510

1015

1520

2025

2530

φ CNL (Limestone)

φ D

(Lim

esto

ne)

Figure 1 Porosity and lithology determination from FDC density and CNL neutron logs in water-filled holes.


4

An error in choosing the matrix pair does not result in large error in the porosity value found, as long as the choice is restricted to quartz (sandstone or chert), limestone, dolomite, and anhydrite; shaliness and gypsum are excluded. For instance, in the above example, if the lithology were sandstone and dolomite instead of limestone and dolomite, the porosity found would be 18.3%; the mineral proportions would, however, be about 40% sandstone and 60% dolomite.

In fact, the plotted Point P of Figure 1 could correspond to various mixtures of sandstone, limestone, and dolomite. In all cases, the porosity would be in the 18% range. Thus, although the rock volumetric fractions estimated from the neutron-density data could be considerably in error, the porosity value will always be essentially correct if only sandstone, limestone, and/or dolomite are present. This feature of the neutron-density combination, coupled with its use as a gas-finder, has made it a very popular log combination.

3 SONIC-DENSITY CROSSPLOT

Crossplots of sonic t versus density ρ b or φD have poor porosity and reservoir rock (sandstone, limestone, dolomite) resolution, but they are quite useful for determining some evaporite minerals. As can be seen from Figure 2 (Chart CP-7), an error in the choice of the lithology pair from the sandstone-limestone-dolomite group can result in an appreciable error in porosity. Likewise, a small error in the measurement of either transit time or bulk density can result in an appreciable error in porosity and lithology analysis. The good resolution given by the chart for salt, gypsum, and anhydrite is shown by the wide separation of the corresponding mineral points on the figure. Several log-data points are shown that correspond to various mixtures of anhydrite and salt and, perhaps, dolomite.



22/10/13

240

40

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

340 50 7060 80 90 100 110

40

1.2

4.6

5

7

8

3 3030

Salt

Gypsum

Anhydrite

ρI = 1

t (µs/ft)

Form

atio

n - B

ulk

Den

sity

ρb

(g/c

m3 )

Dolomite

Quartz

Limes

tone

302020

20

10

16

21

910

171820

1922

1010

0

0

0

Figure 2 Porosity and lithology determination from FDC density and sonic logs.

4 SONIC-NEUTRON CROSSPLOTS

Chart CP-2a is a plot of sonic t versus porosity from an SNP log. As with the density-neutron plots, resolution between sandstone, limestone, and dolomite lithologies is good, and errors in choosing the lithology pair will have only a small effect on the porosity value found. However, resolution is lost if evaporites are present. Chart CP-2b is a similar plot of sonic t versus porosity from the CNL log.

The sonic crossplots (Charts CP-2b and -7) are constructed for both the weighted-average (Wyllie) and the observed (Raymer, Hunt, and Gardner) sonic transit time-to-porosity transforms. Chart CP-2b is shown in Figure 3. For mineral identification and porosity determination, use the transform previous experience has shown most appropriate for the area.


6

40

4040

50

60

70

80

90

100

110

3020100

Time Average

Porosit

y

Field Observation

φCNLcor, Neutron Porosity Index (ρu)(Apparent Limestone Porosity)

Anhyd

rite

t Son

ic T

rans

it Ti

me

(µs/

ft)

DolomiteLim

eston

e

Sand

stone

Salt

40

35

35

35

35

35

30

3030

30

3030

25

25

25

2525

25

20

15

10

20

20

2020

20

15

15

1515

15

1010

1010

10

5

55

5

5

5

0

0

00

0

4035

Figure 3 Porosity and lithology determination from sonic log and CNL*

5 DENSITY-PHOTOELECTRIC CROSS SECTION CROSS PLOTS

The photoelectric cross section index, Pe, curve is, by itself, a good matrix indicator. It is slightly influenced by formation porosity; however, the effect is not enough to hinder a correct matrix identification when dealing with simple lithologies (one-mineral matrix). Pe is little affected by the fluid in the pores.

The bulk density versus photoelectric cross section index crossplot (Chart CP-16 for fresh water, Figure 4, or Chart CP-17 for salt water) can be used to determine porosity and to identify the mineral in a single-mineral matrix. The charts can also be used to determine porosity and the mineral fractions in a two mineral matrix where the minerals are known. To use these charts the two minerals known or assumed to be in the matrix must be selected. A rib is then drawn through the log point to equal porosity points on the spines of the assumed minerals. These spines correspond to pure mineral matrices. The ribs are constant porosity approximates for any matrix mixture of the two minerals assumed. The distances from the log point to the pure mineral spines approximate the relative proportions of the minerals in the matrix.

If the porosity value from Chart CP-16 or -17 is equal to that of Chart CP-1a, the choice of minerals is correct and the porosity is liquid filled. If the two values are different, choosing another pair of minerals may reconcile the difference.



22/10/13

Bulk

Den

sity

(g/c

m3

or M

g/m

3 )b,ρ

Pe, Photoelectric Cross Section (Barns/Electron)

2.9

3

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2

1.9

0 1 2 3 4 5 6

Dol

omite

Sand

ston

e

Lim

esto

ne

Anhy

drite

Salt

010

2030

40

010

2030

40

00

1020

3040

Figure 4 Porosity and lithology determination from Litho-Density* log; fresh water, liquid-filled holes, ρf = 1.0

If one knows which pair of minerals is present in the matrix and the ρb-φN porosity is less than the ρb-Pe porosity, the presence of gas may be suspected. The location of the log point on the porosity rib of the ρb-Pe plot permits the computation of the matrix density (mixture of two minerals in known proportions). If ρmaa (from the ρb-φN plot) is less than ρmaa (from the ρb - Pe plot), the presence of gas is confirmed.

6 NGS CROSSPLOTS

Because some minerals have characteristic concentrations of thorium, uranium, and potassium, the NGS log can be used to identify minerals or mineral type. Chart CP-19 compares potassium content with thorium content for several minerals; it can be used for mineral identification by taking values directly from the recorded NGS curves. Usually, the result is ambiguous and other data are needed. In particular, Pe is used with the ratios of the radioactive families: Th/K, U/K, and Th/U. Use care when working with these ratios because they are not the ratios of the elements within the formation but rather the ratios of the values recorded on the NGS log, ignoring the units of measurement. Charts have been constructed that allow Pe to be compared with either the potassium content, Figure 5 (upper part of Chart CP-18), or the ratio of potassium to thorium, Figure 6 (lower part of Chart CP-18).


8

Pe, P

hoto

elec

tric

Cro

ss S

ectio

n

(Bar

ns/E

lect

ron)

10

8

6

4

2

00 2 4 86 10

K, Potassium Concentration (%)

Glauconite

BiotiteChlorite

Muscovite

Illite

Montmorillonite

Kaolinite

Figure 5 Mineral identification from Litho-Density log and natural gamma ray spectrometry log.

The major occurrences of the three radioactive families are as follows:

• Potassium - micas, feldspars, micaceous clays (illite), radioactive evaporates • Thorium - shales, heavy minerals • Uranium - phosphates, organic matter

The significance of the type of radiation depends on the formation in which it is found. In carbonates, uranium usually indicates organic matter, phosphates, and stylolites. The thorium and potassium levels are representative of clay content. In sandstones, the thorium level is determined by heavy minerals and clay content, and the potassium is usually contained in micas and feldspars. In shales, the potassium content indicates clay type and mica, and the thorium level depends on the amount of detrital material or the degree of shaliness.

Pe, P

hoto

elec

tric

Cro

ss S

ectio

n

(Bar

ns/E

lect

ron)

10

8

6

4

2

00.1 0.2 0.3 0.6 1 2 3 6 10 20 30 60 100

Th/K, Thorium-Potassium Ratio

Glauconite

Biotite Chlorite

Muscovite

Mixed LayerIllite

MontmorilloniteKaolinite

Figure 6 Mineral identification from Litho-Density log and natural gamma ray spectrometry log.



22/10/13

High uranium concentrations in a shale suggest that the shale is a source rock. In igneous rocks the relative proportions of the three radioactive families are a guide to the type of rock, and the ratios Th/K and Th/U are particularly significant.

The radioactive minerals found in a formation are, to some extent, dependent on the mode of sedimentation. The mode of transportation and degree of reworking and alteration are also factors. As an example, because thorium has a very low solubility, it has limited mobility and tends to accumulate with the heavy minerals. On the other hand, uranium has a greater solubility and mobility, and so high uranium concentrations are found in fault planes, fractures, and formations where water flow has occurred. Similarly, high concentrations can build up in the permeable beds and on the tubing and casing of producing oil wells. Chemical marine deposits are characterised by their extremely low radioactive content, with none of the three families making any significant contribution. Weathered zones are often indicated by pronounced changes in the thorium and potassium content of the formation but a more or less constant Th/K ratio.

7 EFFECT OF SHALINESS, SECONDARY POROSITY AND HYDROCARBONS ON SONIC, DENSITY AND NUETRON CROSSPLOTS

7.1 Effect of Shaliness on CrossplotsShaliness produces a shift of the crossplot point in the direction of a so-called shale point on the chart. The shale point is found by crossplotting the measured values (ρsh, φNsh, tsh) observed in the neighbouring shale beds. Generally, the shale point is in the south-east quadrant of neutron-density and sonic-density crossplot, and in the lower centre of the density-photoelectric cross section crossplot. These shale values, however, may only approximate the parameters of the shaly material within the permeable beds.

7.2 Effect of Secondary Porosity on CrossplotsSonic logs respond differently to secondary porosity than the neutron and density logs. They largely ignore vuggy porosity and fractures and respond primarily to intergranular porosity; neutron and density tools respond to the total porosity.

Thus, on crossplots involving the sonic log, secondary porosity displaces the points from the correct lithology line and indicates something less than the total porosity The neutron-density crossplots yield the total porosity.

7.3 The Secondary Porosity Index Log In clean, liquid-filled carbonate formations with known matrix parameters, a secondary porosity index (Iφ2) can be computed as the difference between total porosity, as determined from neutron and/or density logs, and porosity from the sonic log

Iφ2 = φ - φSV.

Equation 1 Secondary porosity index


10

A relative secondary porosity index is sometimes computed as the ratio of the absolute index, defined above, to total porosity.

7.4 Effect of Hydrocarbons on CrossplotsGas or light hydrocarbons cause the apparent porosity from the density log to increase (bulk density to decrease) and porosity from the neutron log to decrease. On a neutron-density crossplot this results in a shift (from the liquid-filled point of the same porosity) upward and to the left, almost parallel to the isoporosity lines. If a gas correction is not made, the porosity read directly from the crossplot chart may be slightly too low. However, the lithology indication from the chart can be quite erroneous.

10

1010 20

A

B

ρh

ρb

φN

2.1

2.3

2.3

2.7

2.90 10 20 30

2020

Dolomite

LimestoneSandsto

ne

30

0.30.1

0.50.70.8

3030

0

00

Figure 7 Effect of hydrocarbon. Arrow B-A represents correction of log Point B for hydrocarbon effect for a gas case. The arrows at lower right represent approximate hydrocarbon shifts for various values of ρh for φ Shr = 0.15, Pmf = 0, and ρmf = 1

Arrow B-A on Figure 7 illustrates the correction for this hydrocarbon shift. Log Point B is for a clean limestone containing gas of density 0.1 g/cm3. Corrected Point A falls near the limestone line, and porosity can be read directly.

The hydrocarbon shift (∆ρb)h and (∆φN)h are given by:

(∆ρb)h = - AφShr

Equation 2 Hydrocarbon shift (∆ρb)h



22/10/13

and

(∆φN)h = - BφShr - ∆φNex,

Equation 3 Hydrocarbon shift (∆φN)h

where ∆φNex is excavation effect (discussed in Chapter 5).

For oil-bearing formations A = (1.19 - 0.16 Pmf) ρmf - 1.19 ρh - 0.032

and

B = 1 −

ρh + 0.30ρmf (1 − Pmf )

⋅

Equation 4 For gas-bearing formations

A = (1.19 - 0.16 Pmf) ρmf - 1.33ρh

and

B = 1 −

2.2 ρh

ρmf (1 – Pmf ),

Equation 5

where

Shr = residual hydrocarbon saturation,ρh = hydrocarbon density in grams per cubic centimetre,ρmf = mud filtrate density in grams per cubic centimetre,Pmf = filtrate salinity in parts per million NaCl.

The arrows at the lower right of Figure 7 show, for various hydrocarbon densities, the approximate magnitudes and directions of the hydrocarbon shifts as computed from the above relations for φ Shr = 15%. (Fresh mud filtrate was assumed and excavation effect was neglected.) This value of φ Shr could occur in a gas sand (e.g., φ = 20%, Shr = 75%).

Gas will also shift the points on a sonic-neutron plot as a result of the decrease in φN. Similarly, gas will shift points on a sonic-density plot as a result of the increase in φD because of the presence of gas. In uncompacted formations, the sonic t reading may also be increased by the effect of the gas.

Hydrocarbon shifts in oil-bearing formations are usually negligible; for clean formations, porosities can be read directly from the porosity graduations on the chart.


12

8 M-N PLOT

In more complex mineral mixtures, lithology interpretation is facilitated by use of the M-N plot. These plots combine the data of all three porosity logs to provide the lithology-dependent quantities M and N. M and N are simply the slopes of the individual lithology lines on the sonic-density and density neutron crossplot charts, respectively. Thus, M and N are essentially independent of porosity, and a crossplot provides lithology identification.

M and N are defined as:

M =

t f − tρb − ρf

x 0.01

Equation 6

N =

φNf − φN

ρb − ρf

.

Equation 7

For fresh muds, tf = 189μs/ft, ρf = 1g/cc, and φNf = 1. Neutron porosity is in limestone porosity units. The multiplier 0.01 is used to make the M values compatible for easy scaling.

If the matrix parameters (tma, ρma, φNma) for a given mineral are used in Equations 6 and 7 in place of the log values, the M and N values for that mineral are defined. For water-bearing formations, these will plot at definitive points on the M-N plot. Based on the matrix and fluid parameters listed in Tables 1a and 1b, M and N values are shown in Table 2 for several minerals in both fresh mud- and salt mud-filled holes. (N is computed for the CNL log.)

Points for a mixture of three minerals will plot within the triangle formed by connecting the three respective single-mineral points. For example, suppose a rock mixture exhibits N = 0.59 and M = 0.81. In Figure 8 this point falls within a triangle defined by the limestone-dolomite-quartz points. It would therefore be interpreted in most cases as representing a mixture of limestone, dolomite, and quartz. However, it could also be a limestone-quartz-anhydrite mixture, or (less likely) a dolomite-quartz-gypsum mixture, since the point is also contained in those triangles. The combination selected would depend on the geological probability of its occurrence in the formation.

Secondary porosity, shaliness, and gas-filled porosity will shift the position of the points with respect to their true lithology, and they can even cause the M-N points to plot outside the triangular area defined by the primary mineral constituents. The arrows on Figure 8 indicate the direction a point is shifted by the presence of each.



22/10/13

In the case of shale, the arrow is illustrative only since the position of the shale point will vary with area and formation.

In combination with the crossplots using other pairs of porosity logs and lithology-sensitive measurements, the M-N plot aids in the choice of the probable lithology. This information is needed in the final solution for porosity and lithology fractions.

Mineral tma ρma φmaSNP φmaCNL

Sandstone 1 55.5 2.65 -0.035* -0.05*(Vma = 18,000)f > 10%

Sandstone 2 51.2 2.65 -0.035* -0.05*(Vma = 19,500)f > 10%

Limestone 47.5 2.71 0.00 0.00

Dolomite 1 43.5 2.87 0.02* 0.065*(f = 5.5% to 30%)

Dolomite 2 43.5 2.87 0.02* 0.065*(f = 1.5% to 5.5%& > 30%)

Dolomite 3 43.5 2.87 0.005* 0.04*(f = 0.0% to 1.5%)

Anhydrite 50.0 2.98 -0.005* -0.0020

Gypsum 52.0 2.35 0.49**

Salt 67.0 2.03 0.04 -0.01

Table 1a Matrix and fluid coefficients of several minerals and types of porosity (liquid-filled boreholes).


14

Fluids tf ρf φfN

Primary Porosity(Liquid - Filled): Fresh mud 189.0 1.00 1 Salt mud 185.0 1.10

Secondary Porosity(In Dolomite): Fresh mud 1.00 1 Salt mud 43.5 1.10

(In Limestone): Fresh mud 1.00 1 Salt mud 47.5 1.10

(In Sandstone): Fresh mud 1.00 1 Salt mud 55.5 1.10

* Average Values** Based on Hydrogen-index Computation

Table 1b Matrix and fluid coefficients of several minerals and types of porosity (liquid-filled boreholes).

Mineral

Fresh Mud (ρf=1)

Salt Mud (ρf=1.1)

M N* M N*

Sandstone 1 0.810 0.636 0.835 0.667Vma = 18,000

Sandstone 2 0.835 0.636 0.862 0.621Vma = 19,500

Dolomite 1 0.778 0.489 0.800 0.517φ = 5.5-30%

Dolomite 2 0.778 0.500 0.800 0.528φ = 1.5-5.5%

Dolomite 3 0.778 0.513 0.800 0.542φ = 0-1.5%Anhydrite 0.702 0.504 0.718 0.533ρma = 2.98

Limestone 0.827 0.585 0.854 0.621

Gypsum 1.015 0.296 1.064 0.320

Salt 1.269 1.086

* Values of N are computed for CNL neutron log

Table 2 M and N values for common minerals.



22/10/13

Gyp1

0.9

0.8

0.7

0.6

0.50.50.4 0.6

N

M

0.7

Gas

Qtz

Lm

Dol

Anh

ApproximateShale Region

SecondaryPorosity

Figure 8 M-Nplot showing the points for several single-mineral formations. This plot is a simplified version of Chart CP-8.

9 MID PLOT

Indications of lithology, gas, and secondary porosity can also be obtained using the matrix identification (MID) plot (Chart CP-15).

To use the MID plot, three data are required. First, apparent total porosity, φta, must be determined using the appropriate neutron-density (Chart CP-1a or CP-1b depending upon whether it is fresh or salt water) and empirical (red curves) neutron-sonic crossplots (Charts CP-2a or CP-2b ). For data plotting above the sandstone curve on these charts, the apparent total porosity is defined by a vertical projection to the sandstone curve.

Next, an apparent matrix transit time, tmaa and an apparent grain density, ρmaa, are calculated:

ρmaa =

ρb − φ ta ρf

1- φ ta

Equation 8 Apparent grain density


16

t maa =

t - φ ta tf

1 - φ ta

time- average relationship

Equation 9 Apparent matrix transit time

t maa = t -

φ ta tc

field- observed relationship

Equation 10 Apparent matrix transit time (field observed)

where,ρb is bulk density from density log,t is interval transit time from sonic log,ρf is pore fluid density,tf is pore fluid transit time,φta is apparent total porosity,andc is a constant (c approx. = 0.67)

The apparent total porosity is not necessarily the same in the equations. For use in the tmaa equations (Equations 9 and 10), it is the value obtained from the neutron-sonic crossplots (Charts CP-2a or CP-2b). For use in the ρmaa equation (Equation 8), it is the value obtained from the neutron-density crossplot (Charts CP-1a or CP-1b).

Chart CP-14 (Figure 9) can be used to solve graphically for ρmaa (Equation 8) and for tmaa using the empirical field-observed transit time-to-porosity relationship (Equation 10). The north-east half (upper right) of the chart solves for the apparent matrix interval transit time, tmaa. The south-west half (lower left of the same chart) solves for the apparent matrix grain density, ρmaa.



22/10/13

tmaa, Apparent Matrix Transit Time (µs/ft)

ρmaa, Apparent Matrix Density (g/cm3)

130130

120

110

100

90

80

70

60

50

40

30

3

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2.8

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120 110 100 90 80 70 60 50 40

40

30

20

10

10

20

30

40

30

t, In

terv

al T

rans

it Ti

me

(µs/

ft)

ρ b, Bu

lk D

ensi

ty (g

/cm

3 )

Figure 9 Determination of apparent matrix parameters from bulk density or interval transit time and apparent total porosity; fluid density = 1

The crossplot of the apparent matrix interval transit time and apparent grain density on the MID plot will identify the rock mineralogy by its proximity to the labelled points on the plot. On Chart CP-15 the most common matrix minerals (quartz, calcite, dolomite, anhydrite) plot at the positions shown (Figure 10). Mineral mixtures would plot at locations between the corresponding pure mineral points. Lithology trends may be seen by plotting many levels over a zone and observing how they are grouped on the chart with respect to the mineral points.

The presence of gas shifts the plotted points to the north-east on the MID plot. Secondary porosity shifts points in the direction of decreased tmaa; i.e., to the left. For the SNP log, shales tend to plot in the region to the right of anhydrite on the MID plot. For the CNL log, shales tend to plot in the region above the anhydrite point.

Sulfur plots off the chart to the north-east at tmaa approx. = 122 and ρmaa approx. = 2.02. Thus, the direction to the sulfur point from the quartz, calcite, dolomite, anhydrite group is approximately the same as the direction of the gas-effect shift. Gypsum plots to the south-west.

The concept of the MID plot is similar to that of the M-N plot. However, instead of having to compute values of M and N, values of ρmaa and tmaa are obtained from charts (Chart CP-14). For most accurate results, log readings should, of course, be depth matched and corrected for hole effect, etc. The need for such corrections can often be seen from the trend of the plotted points on the MID plot (Figure 10).


18

SaltCNLSalt

SNP

QuartzGas Direction

Calcite

Dolomite

Anhydrite3

3.1

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2

100 120 140 160 180 200 220 240

tmaa (µs/m)

ρ maa

, (M

g/m

3 )

Figure 10 Matrix identification (MID) Plot

10 ΡMAA VS. UMAA MID PLOT

Another crossplot technique for identifying lithology uses data from the Litho-Density log. It crossplots the apparent matrix grain density, ρmaa, and the apparent matrix volumetric cross section, Umaa (in barns per cubic centimetre).

The apparent matrix grain density is obtained as previously described in the MID plot discussion. Charts CP-1a (or CP-1b) and Chart CP-14 are used for its determination.

The apparent matrix volumetric cross section is computed from the photoelectric cross section index and bulk density measurements

U maa =

Pe ρe - φ ta Uf

1- φta

Equation 11 Apparent matrix volumetric cross section

wherePe is photoelectric absorption cross section index,ρe is electron density ,φτa is apparent total porosity.

The apparent total porosity can be estimated from the density-neutron crossplot if the formation is liquid filled.



22/10/13

Chart CP-20 solves Equation 11 graphically. A simplified version is shown in Figure 11.

Table 3 (Chapter 4) lists the photoelectric absorption cross section index, the bulk density, and the volumetric cross section for common minerals and fluids. For the minerals, the listed value is the matrix value (ρma, Uma); for the fluids, it is the fluid value (ρma, Uf). Chart CP-21 (Figure 12) shows the location of these minerals on a Umaa versus ρmaa crossplot. The triangle encompassing the three common matrix minerals of quartz, calcite, and dolomite has been scaled in the percentages of each mineral. For example, a point exhibiting an apparent matrix grain density of 2.76 g/cm3 and volumetric cross section of 10.2 barns/cm3 would be defined by 40% calcite, 40% dolomite, and 20% quartz provided no other minerals exist and the pores are liquid saturated.

On this crossplot, gas saturation displaces points upwards on the chart and heavy minerals displace points to the right. Clays and shales plot below the dolomite point.

Pe, PhotoelectricCross Section

(Barns/Electron)

3.0

2.5

2.0

0%

10

203040

Umaa, Apparent MatrixVolumetric Cross Section

(Barns/cm3)

Fresh Water (0 ppk) ρf = 1 Uf = 0.398

6 5 4 3 2 1 4 6 8 10 12 14

φ ta, A

ppar

ent T

otal

Por

osity

(%)

ρ b, Bu

lk D

ensi

ty (g

/cm

3 or M

g/m

3 )

Figure 11 Matrix Identification Plot.


20

3

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

20

20

20

40

4040

60

60

60

80

80

80

3.12 4 6 8 10 12 14 16

Umaa, Apparent Matrix Volumetric Cross Section(Barns/cm3)

ρ maa

, App

aren

t Mat

rix G

rain

Den

sity

(g/c

m3

or M

g/m

3 )

Salt

HeavyMinerals

% CalciteQuartz

Calcite

K-Feldspar

Barite

Dolomite

Anhydrite

IlliteKaolinite

% Quartz

% Dolomite

Gas

Dire

ctio

n

Figure 12 Matrix Identification Plot ρmaa vs. Umaa



22/10/13

LIST OF INTERPRETATION CHARTS FOR CHAPTER 6 Chart CP-1aChart CP-1bChart CP-1cChart CP-2aChart CP-2bChart CP-7Chart CP-14Chart CP-15Chart CP-16Chart CP-17Chart CP-18Chart CP-19Chart CP-20Chart CP-21


22


Saturation Determination S E V E N

50

30

20

15

10

8

6

4

3

2

1

100 - 180- 160- 140

- 120

- 100- 90

- 80

- 70

- 60

- 50

- 40

- 30

- 20

- 10

0

5030

2015

10

8

6

4

3

2

1

0.7

0.4

Z = 0.075 Z = 0.035

Saturation %50

40

30

20

10

Rmf

Rw

Rmf

Rw

SPK = 90

R/R1

7 10 15 20 30 4050 70 150

1.5

1

2

34

56

7 810 12

0.80.6

0.50.4

0.3

0.2

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20

40

60

80

Water

Matrix

Porosity

(%)

Shale

0 10 20 30 40 50 60 70 80 90 100

φN

0

40

60

20

Vsh (%)

0 b

1

1.2

1.4

1.6

1.8

2

2.2

2.4

2.6

2.8

00

0 ma = 2.65sh = 2.45w = 1

22/10/13

1 INTRODUCTION

2 DETERMINATION OF SATURATION IN CLEAN FORMATIONS2.1 Formation Factor2.2 True Formation Resistivity Rt

3 RESISTIVITY VS POROSITY CROSSPLOTS

4 MICRORESISTIVITY VS POROSITY CROSSPLOTS

5 RESISTIVITY RATIO METHODS

6 SHALY FORMATIONS

APPENDIX 1 – DETERMINATION OF RW

APPENDIX 2 – DETERMINATION OF SHALE VOLUME (VSH)



C O N T E N T S


22/10/13

LEARNING OBJECTIVES


• Describe the Archie Equation, formation resistivity factor and typical values for n, m and a.

• Calculate water saturation from a crossplot of resistivity and porosity logs, from Rwa, and from resistivity ratio methods.

• Describe the Impact of Shale on saturation determination.

• Calculate Rw and Vsh from various logs.


2

1 INTRODUCTIONWater saturation is the fraction (or percentage) of the pore volume of the reservoir rock that is filled with water. It is generally assumed, unless otherwise known, that the pore volume not filled with water is filled with hydrocarbons. Determining water and hydrocarbon saturation is one of the basic objectives of well logging.

2 DETERMINATION OF SATURATION IN CLEAN FORMATIONS

All water saturation determinations from resistivity logs in clean (nonshaly) formations with homogeneous intergranular porosity are based on Archie’s water saturation equation, or variations thereof. The equation is:

Sw

n = F Rw

Rt

(1)

where Rw is the formation water resistivity (see Appendix 1), Rt is the true formation resistivity, and F is the formation resistivity factor

Equation 1 (with n = 2) is solved, in nomograph form, in Chart Sw-1.

For Sxo, the water saturation in the flushed zone, a similar expression exists:

Sxo

n = F Rmf

Rxo

(2)

where Rmf is the mud filtrate resistivity, and Rxo is the flushed zone resistivity

In these equations, the saturation exponent n is usually taken as 2. Laboratory experiments have shown that this is a good value for average cases.

The accuracy of the Archie equations 1 and 2 depend on the accuracy of the input parameters (Rw, F, and Rt for equation 1 e.g.) The formation water resistivity (Rw) should be verified in as many ways as possible: calculation from the SP curve, water catalogue, calculation from nearby water-bearing formation, and/or water sample measurement. The calculation of Rw is explained in Appendix 1,

2.1 Formation FactorFormation factor F is usually obtained from the measured porosity of the formation through the relationship shown in Chart Por-1 and in equation 3 below where the cementation exponent m represents the slope of the straight line.

F = a/fm (3)



22/10/13

The value of cementation exponent reflects the tortuosity of the interconnected pore space, i.e. the more complex the current path, the higher the cementation and the higher the value of m.

The formation factor is also defined by another relationship as the ratio of the resistivity of the rock completely saturated with brine to the resistivity of the brine and is given below.

F = R0/Rw (4)

From equations 3 and 4, it is obvious that the porosity and the degree of cementation should be the main factors in controlling the passage of current and therefore the resistivity. The values of a and m in Equation 3 are subject to more variation:

in carbonates, F = 1/f2 is usually used; in sands, F = 0.62/f2.15 (Humble formula), or F = 0.81/f2 (a simpler form practically equivalent to the Humble formula).

Within their normal range of application, these two ways of expressing the Humble formula yield quite similar results.

While the Humble formula is satisfactory for sucrosic rocks, better results are obtained using F = 1/Ø2.2 to 1/Ø2.5 in compact or oolicastic rocks. In some severely oolicastic rocks, m may even be as high as 3.

2.2 True Formation Resistivity RtThe true formation resistivity is one of the main parameters of the Archie equation. It is measured by either a deep laterlog or a deep induction logging tool in the borehole. The following factors must be taken into consideration whilst using Rt value in the Archie's equation.

• Since drilling mud invasion affects a significant portion of the formation around the borehole, it is important to evaluate the invasion profile and, if necessary, perform the necessary corrections.

• The determination of Rt can be a problem in case of thin beds. It is a good practice to make sure that the resistivity devices in use have the resolution that we need.

• If there are clays present in the formation, the bound water in clays can act as a conductor and this can decrease the Rt value. Also the overburden pressure at in- situ downhole can cause a significant increase in Rt.


4

Humble Equation Procedure:

Step 1: Determine f from acoustic, density or Neutron log.

Step 2: Determine F from Humble Formula

Step 3: Determine Rt from deep reading resistivity (induction or laterolog) log corrected for borehole, bed thickness and invasion.

Step 4: Determine Rw from Appendix 1 of Chapter 7

Step 5: Determine Sw from the Archie Equation (Equation 1)

Chart Sw-1 may also be used to solve Equation 2 for the flushed zone water saturation. To do this, the Rxo reading is inserted on the Rt leg of the nomograph and the Rmf value is inserted in the Rw leg. Chart Sw-1 is constructed using the F = 1/f2 porosity-to-formation factor relationship. For any other porosity-to-formation factor relationship the nomograph should be entered with the formation factor.

Flushed Zone in Humble Formula Procedure:

Step 1: Determine porosity from acoustic, density or Neutron log.


Step 3: Determine and use Rxo from shallow resistivity log in place of Rt from deep reading resistivity log

Step 4: Determine and use Rmf in place of Rw

Step 5: Determine Sw from the Archie Equation (Equation 1)

3 RESISTIVITY VS POROSITY CROSSPLOTS

Combining Equation 1 and 3, the Archie saturation equation may be written

Sw

n = a Rw

fm Rt (5)

If n and m are equal to 2, and a = 1, then

f Sw = Rw / Rt . (6)



22/10/13

Equation 6 shows that for constant Rw, f Sw is proportional to 1/√Rt. f Sw is the quantity of water per unit volume of formation. To emphasise the proportionality between f and 1/√Rt, Equation 6 may be rewritten:

f =

Rw

Sw 1

Rt (7)

For a 100% water-saturated formation, Sw = 1 and Rt = Ro. If Ro for water-saturated formations is plotted on an inverse square-root scale versus f, all points should fall on a straight line given by f = √Rw/√Ro.

Furthermore, the points corresponding to any other constant value of Sw will also fall on a straight line, since in Equation 7 the coefficient,√Rw/Sw, is constant for constant values of Rw and Sw.

Instead of an actual Rt value, it is usually satisfactory to plot the log reading of the deep resistivity device provided the readings are not much influenced by invasion or other environmental factors (e.g., from a deep induction log or deep laterolog).

Figure 1 shows several points plotted over an interval in which formation-water resistivity is constant (as indicated by constant SP deflections opposite the thick, clean permeable beds). Assuming that at least some of the points are from 100% water-bearing formations, the line for Sw = 1 is drawn from the pivot point (f = 0, Rt = ∞) through the most north-westerly plotted points. The slope of this line defines the value of Rw. As shown on Figure 1, for f = 10%, Ro = 6.5 ohm-m. For this formation, the most appropriate F - f relation is F = 1/f2. Thus, for f = 10%, F = 100. Since Rw = Ro/F, Rw = 6.5/100 = 0.065 ohm-m as shown.

For other Sw values, Rt and Ro are related by the equation Rt = Ro/Sw2 . For Sw = 50%,

1/Sw2 = 4, and Rt = 4 Ro. This relation establishes the line for Sw = 50%.


6

Res

istiv

ity

1

1.5

2

3

4

6810

20

50100

10000 5 10 15 20 25

Porosity

C 1969 SchlumbergerR 0

RW = 0.065

R04

7

513

11910

8

142

63,12

1,4

17

16

8

Figure 1 Resistivity-Porosity Crossplot for determining Rw and Sw.

On Figure 1, for the same porosity as before (f = 10%), Rt = 4, Ro = 4 x 6.5 = 26 ohm-m gives a point that defines the line for Sw = 50%. Other Sw lines may be defined in a similar manner.

Charts Appendix A3 and A4 provide blank grids for making resistivity-porosity crossplots. Chart A4 is used when F = 1/f2 is the more appropriate formation factor-porosity relationship and Chart A3 is used when F = 0.62/f2.15 is more appropriate.

Hingle PlotIf the matrix composition remains constant over the formations under investigation, the basic measurement from the sonic, density, or neutron logs can be plotted directly versus Rt with similar results. This is possible because of the linear relationship between porosity and bulk density, sonic transit time or neutron hydrogen index response. An example of a sonic-induction crossplot is shown in Figure 2. The transit time has been plotted against the induction resistivity for several levels. The north-westerly points define the 100% water saturation line. The transit time value at the point where this line intersects the horizontal line of infinite resistivity is the matrix transit time, tma. In Figure 2, tma is found to be approximately 47.5 ms/ft (156 ms/m), corresponding to a matrix velocity of 21,000 ft/sec (6,400 m/s).



22/10/13

400 100 44.51,455.86

40 43 46 49 52 55 58 61 64 67 70 73

tma

vma= 21000 0% 5% 10% 15%

Indu

ctio

n R

esis

tivity

5

6

7.5

10

15

25

50

100

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150

100

50403025201510

5

1

0

2505001000

8

Con

duct

ivity

© 1969 Schlumberger

t

fF

F = 1/f2

Sw =

100

%Sw

= 50

%

Figure 2 Sonic-Induction Crossplot.

By knowing tma, a porosity scale, from Chart Por-3, and a scale of formation factor (e.g., from F = 1/f2 using Chart Por-1) can be easily derived. A vertical line drawn through F = 100 (or f = 10) intersects the water line at Ro = 5 ohm-m; accordingly, Rw (= Ro/F) is 0.05 ohm-m.

The lines for other Sw values are straight lines, determined as previously described, radiating out from the Rt = ∞ , tma = 47.5 pivot point.

Density and neutron logs can be crossplotted against resistivity in a manner identical to the sonic logs. For density logs, the intersection of the 100% water line with the infinite resistivity line yields the matrix density value, rma. For neutron logs, the intersection defines the matrix hydrogen index, or apparent matrix porosity. Knowledge of matrix density or hydrogen index permits the rb or fN scale to be rescaled in f and F units. With the F scale defined, Rw can be calculated as for the sonic-resistivity crossplot, and lines of constant water saturation can be constructed in a similar manner.

These resistivity-versus-porosity crossplots require that formation water resistivity be constant over the interval plotted, that lithology be constant, that invasion not be deep, and that the measured porosity log parameter (i.e., t, rb, fN) can be linearly related to porosity. This last condition implies that the time average transform for the conversion of t into porosity is appropriate.

The neutron-resistivity crossplot is not as satisfactory in gas-bearing formations as the sonic- or density-resistivity crossplots. The apparent porosity measured by the neutron log in gas zones is often much too low. This results in pessimistic Sw values


8

in gas zones. Indeed, in a gas zone, the neutron-resistivity may indicate a porous gas-bearing zone, the neutron-resistivity may indicate a porous gas-bearing zone to be near zero porosity and 100% water bearing. In contrast, the sonic- or density-resistivity tends to be slightly optimistic in gas zones (i.e., porosities may be slightly high and water saturations slightly low).

Resistivity vs Porosity Crossplot Procedure

Step 1: Determine f for a number of zones from porosity acoustic, density or Neutron log.

Step 2: Determine the resistivity Rt of the zones from a deep reading resistivity log

Step 3: Plot the values of f (on a linear scale) versus Rt (on an inverse square root scale).

Step 4: Draw a line through the average points in the northwest part of the plot. If water zones are present in the zone this line represents the water (or 100% Sw) line. The values of Rt along this line represent the resistivity of the water-saturated formations, Ro. The extrapolation of this line to zero conductivity defines the matrix travel time.

Step 5: Check the matrix value derived in Step 4 against the value of matrix travel time derived from other sources. This is a good check for errors in the 100%Sw line.

Step 6: For other Sw values, Rt and Ro are related by the equation Rt = Ro/Sw2. For Sw =

50%, 1/Sw2 = 4, and Rt = 4 Ro. This relation establishes the line for Sw = 50%. Calculate

the relationship between Rt and Ro for various values of Sw from the equation. Plot the values of Ro for Sw = 10%, 20%, 30% and 50%, using the above relationship, for a set of porosities.

Step 7: Determine Sw in the zones of interest, from the position of the plotted points in relation plot saturation lines.

4 MICRORESISTIVITY VS POROSITY CROSSPLOTS

A resistivity-porosity plot can also be made using the values from a shallow-investigation resistivity log, such as the microlaterolog or MicroSFL log. If the microresistivity log reads substantially Rxo, then a line through points of mud filtrate-saturated formations (Sxo = 1) should have a slope related to Rmf. Rmf is an important parameter, and this check of its value by means of a sonic-microresistivity or density-microresistivity crossplot is often useful.

These plots are also valuable for improved determinations of matrix parameters (either tma or rma), particularly in cases where the sonic-resistivity or density-resistivity plot does not give a clear answer because of hydrocarbon saturation. The F Rmf line should be easier to determine since Sxo is usually fairly high even in hydrocarbon-bearing formations.



22/10/13

200

150

100

50 40 30 25 20 15 10

5

1

5

-6

7.5

10

15

25

50

100

2505001000

0 10 20

8

Res

istiv

ity

Con

duct

ivity

Porosity From b / f N Crossplot

8 3

2

109

1

4

7

6

5

Sw =

100%

Sxo = 100%

Figure 3 Resistivity-porosity crossplot showing points from deep induction and microlaterolog. Sw = 1 and Sxo = 1 lines are shown. (After Baird, 1968).

Figure 3 shows a resistivity-porosity plot in which both the deep induction reading and the microlaterolog at the same levels are plotted in a series of water-bearing formations. The porosity values were derived in this case from a neutron-density crossplot. The plots from the two logs define two trends corresponding respectively to Sw = 1 (using deep induction) and Sxo = 1 (using microlaterolog data). The points not in these trends can be divided into two groups.

1. Points whose microlaterolog readings fall on the Sxo = 1 line but whose deep induction log readings fall below the Sw = 1 line (Points 2, 9, 10) are probably the result of either deep invasion or adjacent-bed effect in which RID is greater than Rt.

2. Points whose induction log readings fall on the Sw = 1 line but whose microlaterolog points fall above the Sxo = 1 line are possibly due to shallow invasion in which RMLL is lower than Rxo.

Resistivity-porosity plots are thus often more informative if the short-spaced resistivity values are also plotted. Not only does this permit an appreciation of invasion effects but it may also indicate moved oil.

Rwa ComparisonIf water saturation is assumed to be 100%, the Archie water saturation equation (Equation 1) reduces to


10

Rwa = Rt

F ≈ RID

F (8)

The term Rwa is used in Equation 8, rather than Rw, to indicate that this is an apparent formation water resistivity. It is only equal to Rw in 100% water-bearing formations. In hydrocarbon-bearing formations, Rwa computed from Equation 8 will be greater than Rw. Indeed, by combining Equations 1 and 8, the relationship between Sw, Rwa, and Rw can be shown to be

Sw = Rw / Rwa . (9)

The Rwa technique can, therefore, be useful for identifying potential hydrocarbon-bearing zones and for obtaining Rw values.

In practice, Rwa is obtained by simply dividing the deep induction resistivity (or deep laterolog resistivity) by the formation factor obtained from a porosity log or a combination of porosity logs. To be most effective, either a continuous Rwa computation is made over a long interval of the borehole or many individual manual computations are made so as to approximate a continuous computation.

For manual computation of Rwa, the logs are divided into sections of consistent lithology, shaliness, and Rw. The SP curve is most useful for this, but the GR, resistivity, and other curves should be consulted. The log readings, deep resistivity and porosity (t, rb, or fN), are read and tabulated, and the corresponding values of Rwa are calculated. Various charts are helpful in these calculations. For example, if porosity is obtained from the FDC* formation density or Lith-Density* log, Chart Por-5 can be used for porosity calculation, Chart Por-1 can be used to convert porosity to formation factor, and Chart Sw-1 (in reverse starting at Sw = 100%) can be used to make the Rwa computation.

Since the Rwa technique, as normally applied, requires that deep resistivity (Rdeep) @ Rt, invasion must be shallow enough that the deep resistivity reads essentially the same as the true resistivity. In addition, Rw should be constant or vary in a consistent and recognisable manner over the interpreted intervals, lithology should be essentially constant and known, and permeable zones should be reasonably clean (i.e., shale free). If these conditions are fulfilled, the calculated Rwa values will approximate Rw values in clean water-bearing sands. Usually, an Rwa value at least three times that of Rw is needed to indicate possible hydrocarbon potential; that corresponds to a water saturation of less than 60%.

A useful feature of the Rwa method is that foreknowledge of Rw is not needed; indeed, if some reasonably clean water zones are included in the computations, their Rwa’s are Rw.



22/10/13

SFL

SFL

SP

SP

200 mV- +

Rwa

Rwa

0.2 10

Induction Log BHC Sonic150 50Ω-m

Ω-m

µs/ft0 1

ISF/Sonic Combination

tI

200300

A

B

C

Figure 4 Rwa Curve recorded on ISF/sonic log.

A continuous log of Rwa can be recorded at the wellsite using resistivity and porosity logs. Figure 4 is an example computed from the BHC sonic log and induction-SFL log combination. The Rwa combination indicates the lower sand to be predominately water bearing with a good show of hydrocarbons at its top. Rw is indicated to be about 0.08 ohm-m by the consistent Rwa computations over Interval C. Rwa reaches 0.6 ohm-m at Level B in the top of this zone. That corresponds to a water saturation of 37%. The entire upper sand, Interval A, is indicated as hydrocarbon bearing by the Rwa computations, assuming it contains formation water similar to that of the lower zone. Similar SP deflections in the two zones suggest this is the case.

A continuous Rwa log provides ready visual identification of water- and hydrocarbon-bearing formations, changes in Rw, in lithology, etc.

Rwa to Rw Comparison Procedure:

Step 1: Determine f for a number of zones from porosity acoustic, density or Neutron log.



12

Step 3: Determine the resistivity Rt of the zones of interest from a deep reading resistivity log

Step 4: Calculate Rwa from Equation 8.

Step 5: Determine the value of Rwa (assumed to be Rw) in clean water-bearing zones.

Step 6: Determine the values of Rwa in zones suspected on being hydrocarbon bearing.

Step 7: Calculate Sw in the hydrocarbon bearing zones of interest from

Equation 9.

5 RESISTIVITY RATIO METHODS

In resistivity ratio methods, it is assumed that a formation is divided into two distinct regions, a flushed or invaded zone and a non-invaded zone. Both zones have the same F, but each contains water of a distinct resistivity (Rmf or Rz in the invaded zone and Rw in the non-invaded zone). The resistivities of the two zones must be measurable or derivable from logs, and methods for determining the resistivity of the water in each zone must be available.

Because of the necessary assumptions, the resistivity ratio methods have limitations, but when no porosity or formation factor data are available, they are sometimes the only choice. The principal limitation arises from the inability of any resistivity device to measure either Rxo or Rt totally independent of the other. Simply put, invasion must be deep enough to allow a shallow-investigating resistivity device to measure Rxo but not so deep that a deep resistivity device cannot measure Rt.

Another difficulty appears when hydrocarbons are present. In this case, some knowledge or assumption of the value of the flushed or invaded zone saturation is necessary.

Flushed Zone MethodIf n = 2 is assumed and Equation 1 is divided by Equation 2,

Sw

Sxo

2

= Rxo / Rt

Rmf / Rw

(10)

This equation gives the ratio of Sw to Sxo, and no knowledge of formation factor or porosity is needed. Rxo may be found from a MicroSFL log, Rt from an induction or laterolog, and Rmf /Rw from a measured values or from the SP curve.

The ratio Sw/Sxo,is valuable in itself as an index of oil movability. If Sw/Sxo = 1, then no hydrocarbons have been moved by invasion, whether or not the formation contains hydrocarbons. If Sw/Sxo is about 0.7 or less, movable hydrocarbons are indicated. The value of Sw/Sxo along with f and Sw, is useful in evaluating reservoirs.



22/10/13

To determine Sw from Equation 10, Sxo must be known. For moderate invasion and average residual oil saturation, an empirical relation between Sxo and Sw has been found useful: Sxo = Sw

1/5. Inserting this into Equation 10 gives:

Sw = Rxo / Rt

Rmf / Rw

58

(11)

Chart Sw-2 provides a solution of Equation 11 using the values of Rxo/Rt and Rmf/Rw .Preferably, the chart is entered with Rmf/Rw; optionally, the SP can be used. Provision is also made in the upper right portion of the chart for using values of Sor (residual oil

The relationship Sxo = Sw1/5 is strictly empirical and may differ appreciably from the

actual case.

Invaded Zone MethodThe invaded zone method is useful for water saturation determination when only an ES, IES, or other early resistivity log is available and no porosity log or formation factor data exist. For application of the method, Ri /Rm must be at least 10.

Archie’s equation for the invaded zone is

Si2 =

FRz

Tt

(12)

where Rz is the resistivity of the water in the invaded zone. Because of incomplete Rz Rmf, and formation water, Rw.

Studies of many logs suggest that Si and Sw are related by

Si = Sw

12 (13)

Dividing the non-invaded zone water saturation equation (Equation 1) by Equation 13 and using the relationship presented in Equation 13 yields an expression for Sw:

Sw = Ri / Rt

Rz / Rw

(14)

To use Equation 14, Rt is taken from a deep resistivity device such as a deep induction or deep laterolog (corrected as necessary for borehole effect and bed thickness). Ri is taken from a shallow resistivity device such as Laterolog 8, 16-in. normal, or SFL (corrected for borehole effect and bed thickness).

Rz is given by the relationship


14

1Rz

= zRw

+ 1- zRmf

(15)

where z is the fraction of the invaded zone pore water, which is formation water, and 1 - z is the fraction that is mud filtrate. Experience has indicated that z varies from 0.075 in cases of normal invasion to 0.035 in cases of deep invasion or vuggy formations.

Figure 5 solves Equation 14. It is entered with Rmf /Rw on the appropriate z scale and Ri/Rt (oblique lines) to determine Sw. When Ri/Rt is close to unity, some caution is required. The formation may be extremely invaded or there may be little invasion, or it may be dense and impermeable. On the other hand, many good hydrocarbon-bearing reservoirs will have Ri /R ª 1.0.

50

30

20

15

10

8

6

4

3

2

1

100 - 180- 160- 140

- 120

- 100- 90

- 80

- 70

- 60

- 50

- 40

- 30

- 20

- 10

0

5030

2015

10

8

6

4

3

2

1

0.7

0.4

Z = 0.075 Z = 0.035

Saturation %50

40

30

20

10

Rmf

Rw

Rmf

Rw

SPK = 90

R/R1

7 10 15 20 30 4050 70 150

1.5

1

2

34

56

7 810 12

0.80.6

0.50.4

0.3

0.2

0.1

Figure 5 Empirical resistivity-ratio method. (Ref. 4)

Porosity BalanceTo verify that invasion falls within the limits required by the resistivity ratio methods, the porosity balance can be used. It requires an independent value of porosity; this can be obtained from cores, logs, reservoir analysis, etc. This “porosity check” can verify the applicability of the ratio method and the validity of the Sw value derived. If the porosity check indicates the ratio method results are in error, the porosity balance will indicate how the error can be corrected.

For comparison with the independent value of porosity, ft, a porosity value, fc, is derived from Swc. (Swc is the value of Sw from the ratio method chart. The subscript t



22/10/13

stands for the “true” value and the subscript c for the “calculated value.) This is done by computing a formation factor, Fc, from the relation

Fc = Swc2 Rt

Rw

(16)

and then deriving fc using the appropriate F - f relationship from Chart Por-1. Then:

1 If fc = ft, the ratio method solution is correct and Swc = Sw.

2 If fc > ft, then Fc is too low and Swc is too low. The ratio Rxo/Rt or Ri/Rt is too low, probably because invasion is either deeper or shallower than one of the resistivity measurements can handle. The shallow resistivity (Rxo or Ri) is too low because of shallow invasion or the deep resistivity (Rt) is too high because of deep invasion.

(a) If Rshallow/Rdeep < 1.4 and the induction was used for Rt, use RID = Rt in Equation 1 to find Sw.

(b) If Rshallow/Rdeep > 1.4 and FRz > Rshallow, invasion is shallow. Use Rdeep = Rt in Equation 1 to find Sw.

(c) If Rshallow/Rdeep > 1.4 but FRz < Rshallow, invasion is deep. Equation 12 is solved for Sw (with Sw = Si2).

3. If fc > ft, then Swc is too high. This occurs when Rxo/Rt or Ri /Rt is too high, as might happen in the case of annulus. Equation 12 is used for Sw determination (with Ss = Si2).

Invasion-Corrected Ratio MethodsThe uncertainty in invasion diameter can be eliminated by correcting the log data before using it in a resistivity ratio interpretation method. This requires at least three resistivity measurements of different depths of investigation.

The three resistivity measurements (corrected for borehole effect and bed thickness) are entered in the appropriate invasion correction chart and Rxo/Rt obtained. For example, for the DIL-SFL data, Chart Rint -2b would be used (dependent on the Rxo/Rm ratio). RxoRt is obtained, and ideally Rt, from the Rt/RID value. Rxo/Rt can then be entered into Chart Sw-2 or Equation 10 to determine Sw.

The invasion correction charts generally assume a step profile of invasion. If a transition profile (one in which mud filtrate and formation water are intermixed) or an annulus profile exists, the Rxo/Rt and Rt /RID values given by the charts may be in error. The “porosity balance” may be used to detect and correct the error. An independent source of porosity, such as a porosity log, is required.

Rather than compare porosity computed from the ratio method saturation with true porosity measured by the porosity log, the ratio method water saturation, SwR, (i.e., Sw from Equation 12) is compared to the Archie water saturation, SwA, (i.e., Sw from


16

Equation 1). If SwA and SwR are equal, the assumption of a step-contact invasion profile is verified, and all values found (Sw, Rxo/Rt, Rt/RID, Rt, di) are considered good.

If SwA > SwR, either invasion is very shallow or a transition type of invasion profile is indicated. In these cases, SwA is considered the better value for Sw. If SwA < SwR, an annulus type of invasion profile is indicated. In this case, a more accurate value can be estimated using the relation:

Sw = SwA SwA

SwR

14

(17)

Rxo/Rt QuicklookThe Rxo/Rt quicklook can be used to identify hydrocarbon-bearing formations and to indicate hydrocarbon movability (producibility). When Sw/Sxo is 1 in a permeable zone, the zone will produce water or be non-productive regardless of water saturation. An Sw/Sxo significantly less than 1 indicates the zone is permeable and contains some hydrocarbons, and that the hydrocarbons have been flushed (moved) by invasion. Thus, the zone contains producible hydrocarbon.

Equation 10 can be written as

Sw

Sxo = Rxo / Rt

Rmf / Rw( )SP

12

(18)

which shows that an indication of Sw/Sxo can be obtained by comparing Rxo/Rt with Rmf/Rw, where the subscript SP emphasises that Rmf/Rw is derivable from the SP. Equivalently, the comparison can be between log RxoRt and the SP curve for an indication of log Sw/Sxo.

The log Rxo/Rt is computed from a comparison of the deep and shallow resistivity measurements or from all three resistivity measurements or from all three resistivity measurements and is used as an overlay comparison curve with the SP. Separations

between the log Rxo/Rt curve, properly scaled to match the SP, and the SP curve provide a quicklook location of producible hydrocarbons.

Originally, log Rxo/Rt was computed from RLL8/RID or RSFL/RID. Use was made of the observation that over a wide range of invasion diameters (from about 20 to 100 in.) Rxo/Rt depends primarily on the value of RLLS/RID or RSFL/RID (Figure 11). The relationship employed for the LL8 device was

Rxo / Rt = 1.85 RLL8 / RID( ) − 0.85 (19)

For the SFL device, it was



22/10/13

Rxo / Rt = 1.45 RSFL / RID( ) − 0.45 (20)

Much more sophisticated algorithms are now used to obtain Rxo/Rt. All three resistivity measurements of the DIL-SFL tool are employed. As a result, the computed Rxo/Rt values more closely duplicate the values given by the relevant invasion correction chart and by Figure 6 over a greater range of invasion diameters.

2030

20

20 40 60 80 100

10

5

2

10

8

6 5

4

3

2

1

Induction - Laterlog 8

RLL8

RID

RXO

Rt

di (in.)

(Rxo

/Rt)Q

L =

1.8

5 (R

LL8/R

ID) -

0.8

5

Figure 6 Plot illustrating strong interdependence of RLL8/RID and Rxo/Rt

in the range of di values from 20 to 100 in.

To interpret the Rxo/Rt quicklook curve, the impermeable zones must be eliminated by reference to the SP, GR, or microlog curves or by resistivity ratios. Then, if the SP and Rxo/Rt (actually - K log Rxo/Rt) curves coincide in a permeable zone, the zone will most probably produce water. If however, the Rxo/Rt curve reads appreciably lower (i.e., to the right) than the SP, the zone should produce hydrocarbons. An Rxo/Rt value less than the SP amplitude indicates movable hydrocarbons are present.

The Rxo/Rt quicklook technique is applicable to fresh mud conditions (Rxo > Rt) in formations where invasion falls within the limits demanded by the Rxo/Rt computation. For the simpler computation technique using Equation 19, that is about 30 to 70 in.; for the more sophisticated techniques, that is between 20 and 120 in. Even in the more restrictive case, however, any errors are optimistic. In other words, water zones may appear to be hydrocarbon productive. This constitutes a safeguard against overlooking pay zones, and is considered a desirable feature in any quicklook approach.


18

The Rxo/Rt technique efficiently handles variations in formation water resistivity, Rw, and in shaliness. Any change in Rw is reflected similarly into both the computed Rxo/Rt and the SP amplitude. Thus, comparing the two curves still permits formation fluid identification. Shaliness also affects the two curves in a similar manner. All other things remaining constant, shaliness reduces the Rxo/Rt value and the SP amplitude. Finally, the Rxo/Rt quicklook technique does not require porosity data nor use of any F - f relationships.

SP10

SP

IDIMLL8

0.2 1 10 100 1000

R0 From Density

38003700

QLRxoRt( (

Figure 7 Example of (Rxo/Rt)QL curve used for comparison with SP to identify zones with movable hydrocarbons.

Figure 7 is an example of a shaly gas sand at 3760 through 3788 ft and several water- productive sands with varying amounts of shaliness. The productive gas sand is identified by the separation between the Rxo/Rt and SP curves. Water-productive zones are shown by lack of separation. In shaly water zones the variation in the SP curve is essentially the same as the variation in the Rxo/Rt ratio - a result of the same shale; so, the comparison is not significantly disturbed by shaliness. Neither is it disturbed by variations in Rw.

Estimates of water saturation and saturation ratio in clean formations can be made by comparing the Rxo/Rt and SP curves. Equation 18 permits Sw/Sxo to be estimated and Equation 11 (assuming Sxo = Sw) permits Sw to be estimated.

6 SHALY FORMATIONS

Shales are one of the more important common constituents of rocks in log analysis. Aside from their effects on porosity and permeability, this importance stems from their electrical properties, which have a great influence on the determination of fluid saturations.



22/10/13

Shales are loose, plastic, fine-grained mixtures of clay-sized particles or colloidal particles and often contain a high proportion of clay minerals. Most clay minerals are structured in sheets of alumina-octahedron and silica-tetrahedron lattices. There is usually an excess of negative electrical charges within the clay sheets. The substitution of Al+++ by ions of lower valence is the most common cause of this excess; the structure of the crystal remains the same. This local electrical imbalance must be compensated to maintain the electrical neutrality of the clay particle. The compensating agents are positive ions - cations or counterions - which cling to the surface of the clay sheets in a hypothetical dry state. The positive surface charge is usually measured in terms of milli-ions equivalents per 100 grams of dry clay minerals and is called the cation exchange capacity (CEC). When the clay particles are immersed in water, the Coulomb forces holding the positive surface ions are reduced by the dielectric properties of water. The counterions leave the clay surface and move relatively freely in a layer of water close to the clay water interface) and contribute to the conductivity of the rock.

Since the Archie water saturation equation, which relates rock resistivity to water saturation, assumes that the formation water is the only electrically conductive material in the formation, the presence of another conductive material (i.e., shale) requires either that the Archie equation be modified to accommodate the existence of another conductive material or that a new model be developed to relate rock resistivity to water saturation in shaley formations. The presence of clay also complicates the definition or concept of rock porosity. The layer of closely bound surface water on the clay particle can represent a very significant amount of porosity. However, this porosity is not available as a potential reservoir for hydrocarbons. Thus, a shale or shaley formation may exhibit a high total porosity yet a low effective porosity as a potential hydrocarbon reservoir.

Clean Sand

Laminar Shale

Structural Shale

Dispersed Shale

Quartz

Disf

Qtz Str

f

Quartz

f

Quartz

f

Lam

Figure 8 Forms of shale classified by manner of distribution in formation. Pictorial representations above, volumetric representations below

The way shaliness affects a log reading depends on the amount of shale and its physical properties. It may also depend on the way the shale is distributed in the formation. Shaley material can be distributed in the formation in three ways.


20

1. Shale can exist in the form of laminae between which are layers of sand. The laminar shale does not affect the porosity of permeability of the sand streaks themselves. However, when the amount of laminar shale is increased and the amount of porous medium is correspondingly decreased, overall average effective porosity is reduced in proportion.

2. Shale can exist as grains or nodules in the formation matrix. This matrix shale is termed structural shale; it is usually considered to have properties similar to those of laminar shale and nearby massive shales.

3. The shaly material can be dispersed throughout the sand, partially filling the intergranular interstices. The dispersed shale may be in accumulations adhering to or coating the sand grains, or it may partially fill the smaller pore channels. Dispersed shale in the pores markedly reduces the permeability of the formation.

All these forms of shale can, of course, occur simultaneously in the same formation.

Over the years, a large number of models relating resistivity and fluid saturations have been proposed. Many have been developed assuming the shale exists in a specific geometric form (i.e., laminar, structural, dispersed) in the shaly sand. All these models are composed of a clean sand term, described by the Archie water saturation equation, plus a shale term. The shale term may be fairly simple or quite complex; the shale term may be relatively independent of, or it may interact with, the clean sand term. All the models reduce to the Archie water saturation equation when the fraction of shale is zero; for relatively small amounts of shaliness, most models and methods yield quite similar results.

Only a very few of these models will be reviewed here in order to provide some flavour and understanding for the evolution of shaly sand interpretation logic.

Laminated Sand-Shale Simplified ModelIn this laminar shale model, Rt, the resistivity in the direction of the bedding planes, is related to Rsh (the resistivity of the shale laminae) and to Rsd (the resistivity of the clean sand laminae) by a parallel resistivity relationship,

1Rt

= 1- Vlam

Rsd+

Vlam

Rsh

(21)

where Vlam is the bulk-volume fraction of the shale, distributed in laminae, each of more-or-less uniform thickness.

For clean-sand laminae, Rsd = Fsd Rw/Sw2 , where Fsd is the formation resistivity factor

of the clean sand. Since Fsd = a /fsd2 , (where f sd is the sand-streak porosity) and f

= (1 - Vlam) fsd (where f is the bulk-formation porosity), then

1Rt

= φ2Sw2

1− Vlam( )aRw+

Vlam

Rsh (22)



22/10/13

To evaluate Sw by the laminated model, Rt, Rw, f, Vlam, and Rsh must be determined.

For the determination of Rt, the problem is the same as for clean formations. If Rw is not known, its determination usually involves looking at a nearby clean sand and solving for Rw using the SP measurement or, if the formation is water bearing, using the resistivity and porosity measurements.

For the determination of f and Vlam, a combination of porosity logs can be used. For example, as illustrated in Figure 9, a crossplot of fN and rb from a density log is effective. The triangle of the figure is defined by the matrix point, water point, and shale point. In this example, the matrix point is at fN = 0 (the neutron log was scaled in apparent sandstone porosity) and rma = 2.65 g/cm3 (quartz matrix). The shale point is at fN = 50 pu and rsh = 2.45 g/cm3. These values were taken in a nearby thick shale bed; it is assumed that shale laminae in the shaly sand under investigation are similar to the nearby massive shale beds. The water point is, of course, located at fN = 100 pu and rb = 1 g/cm3. The matrix-water line and shale-water line are linearly divided into porosity; the matrix-shale line and water-shale line are linearly divided into shale percentages.

20

40

60

80

Water

Matrix

Porosity

(%)

Shale

0 10 20 30 40 50 60 70 80 90 100

fN

0

40

60

20

Vsh (%)

0 b

1

1.2

1.4

1.6

1.8

2

2.2

2.4

2.6

2.8

00

0 ma = 2.65sh = 2.45w = 1

Figure 9 Neutron-density crossplot showing matrix, water, and shale points, scaled for determination of Vsh and porosity.

Point A, plotted as an example, corresponds to log readings of rb = 2.2 g/cm3 and fN = 33 pu. Interpretation by the lines on the plot yields f = 23% and Vsh (or Vlam) = 16%.


22

Direct use of this crossplot assumes 100% water saturation in the zone investigated by the tools. Since oil has a density and hydrogen content normally not greatly different from water, this crossplot technique can be used with acceptable accuracy in oil-bearing formations. The presence of gas or light hydrocarbon, however, decreases fN and decreases rb. This would cause the point to shift in a north-westerly direction. When gas or light hydrocarbon are present, an additional shaliness indicator, such as GR or SP data, is needed in order to evaluate the amount of the shift.

Using the laminated model, an equation for Rxo analogous to Equation 22 could be written. Sxo would replace Sw and Rmf would replace Rw. The other terms (f, Vlam, Rsh) remain the same in the two equations. Assuming Sxo = Sw

1/5 (as in the flushed-zone ratio method) and the ratio of the PSP (SP deflection in the shaley sand) to the SSP (SP deflection in a nearby clean sand of similar formation water) is a measure of shaliness, Vlam, water saturation could be calculated from RxoRt and PSP in the shaley sand and SSP (or Rmf/Rw) in a nearby clean sand. Chart Sw-2 performs the calculation.

Dispersed Shale Simplified ModelIn this model, the formation conducts electrical current through a network composed of the pore water and dispersed clay. As suggested by L. de Witte, it seems acceptable to consider that the water and the dispersed shale conduct an electrical current like a mixture of electrolytes.

Development of this assumption yields

1Rt

= φ im2 Sim

aq

Rshd+

Sim − qRw

(23)

where, fim is intermatrix porosity, which includes all the space occupied by fluids and dispersed shale, Sim is the fraction of the intermatrix porosity occupied by the formation- water,dispersed-shale mixture, q is the fraction of the intermatrix porosity occupied by the dispersed shale,

and Rshd is the resistivity of the dispersed shale.

Also, it can be shown that Sw = (Sim - q)/(1 - q) where Sw is the water saturation in the fraction of true effective formation porosity:

Combining these relations and solving for Sw yields

Sw =

aR w

φ im2 Rt

+ q Rshd − R w( )2

2 R shd

- q Rshd + R w( )

2 Rshd

1 - q (24)



22/10/13

Usually, fim can be obtained directly from a sonic log since dispersed clay in the rock pores is seen as water by the sonic measurement. The value of q can be obtained from a comparison of a sonic and density log. Indeed, if, rsh ≈ rma, then qSV ≈ (fD - fSV)/f, where fSV and fD are the sonic and density derived porosities, respectively. In this case, fD approximates f, the effective porosity available for fluid saturation.The value of Rshd is more difficult to evaluate. It is usually taken as equal to Rsh in nearby shale beds. Fortunately, its value is not too critical if it is at least several times greater than Rw. In fact, when Rw is small compared to Rshd and the sand is not too shaly, Equation 24 can be simplified to a form independent of Rshd:

Sw =

aRw

f im2 Rt

+ q2

4 - q

2 1 - q

(25)

Total Shale RelationshipBased upon the above ideas, laboratory investigations and field experience, it has been found that a simple relationship of the following form works well for many shaly formations independent of the distribution of the shale and over the range of Sw values encountered in practice:

1Rt

= φ2 Sw2

a Rw 1 − Vsh( ) + Vsh Sw

Rsh

(26)

In using this equation, Rsh is taken equal to the resistivity of the adjacent shale beds and Vsh is the shale fraction as determined from a total shale indicator.

In recent years, it is equations of the form of Equation 24 and 26 that have gained the widest acceptance in the evaluation of shaly sands. These equations have a general form

1Rt

= αSw2 + γSw, (27)

where a denotes a predominant sand term that is dependent on the amount of sand, its porosity, and the resistivity of the saturating water. The sand term always reduces to Archie’s water saturation equation when the shale fraction is zero. g denotes a predominant shale term that depends on the amount and resistivity of the shale.

Although the general form of shaly sand interpretation models may be quite similar, the methods of determining the amount of shale and its resistivity may differ greatly.


24

APPENDIX 1 - DETERMINATION OF RW

In addition to formation factor or porosity, values of formation water resistivity, Rw, and mud filtrate resistivity, Rmf, are needed for the water saturation calculations. Mud resistivity, Rm, mudcake resistivity, Rmc, and Rmf are generally measured at the time of the survey on a mud sample from the flowline or mud pit. These values are recorded on the log heading. If a measured value of Rmf or Rmc is not available. Since the resistivity of a material is a function of temperature, Rm, Rmf, and Rmc must be corrected to formation temperature (Chart Gen-9). Rw can be determined in a number of ways:

• From the SP Log • From water saturation equation in a 100% water-bearing formation • From produced water samples • From water catalogues

1.1 RW from the SP Log

In a clean formation, the static SP (SSP) curve value is

= - k log Rmfeq

RweqSSP

(28)

where,K = temperature-dependent constant = 61 + 0.133 T degrees FT = Formation Temperature, degrees FRmfe = Resistivity of Mud FiltrateRwe = Equivalent Formation Water Resistivity Knowing the formation temperature, the static SP value recorded opposite a porous, permeable, nonshaly formation can be transformed into the resistivity ratio Rmfe/Rwe Chart SP-1 performs this translation graphically. Charts SP-1 and -2 solve the above SP equation for Rw

Procedure:Step 1: Identify a permeable, water bearing zone near to the hydrocarbon bearing zone of interest

Step 2: Determine the formation temperature at the zone of interestThe formation temperature can be found from either:

• Direct measurement (if the zone is at total depth and maximum temperature reading is used); or

• The bottom hole temperature, total depth and average surface temperature and Chart Gen-6.



22/10/13

Step 3: Correct the Rmf resistivity values for the formation temperature found in Step 2.The value of Rmf can be found on the log heading. For predominantly NaCl muds: if Rmf at 75 degrees F is greater than 0.1 ohm-m, use Rmfe = 0.85 Rmf at formation temperature; if Rmf at 75 degrees F is less than 0.1 ohm-m use the NaCl (solid) curves of Chart SP-2 to derive a value of Rmfe value corrected to formation temperature from Chart Gen-9.

For freshwater gypsum muds, the dashed lines of Chart SP-2 are used to convert Rmf to Rmfe.

Step 4: Draw the shale base line on the SP LogThe shale base line in fresh mud environments will generally be the line established by the maximum SP deflections to the right. This shale base line is not necessarily perpendicular to the depth lines on the log due to drifting with depth. Usually, over limited sections, this drift is negligible. If a significant change in the base line occurs, use the average shale base line.

Step 5: Mark out the bed boundaries on the SP LogThe bed boundaries on the SP Log are the inflection points on the curve. The inflection point (or maximum slope) on the curve occurs due to maximum current flow in the well bore at the boundary. The apparent bed thickness from the SP is used, not the bed thickness indicated on some other log. Sometimes it is difficult to pick a bed thickness if there are large shale beds within the sand. A judgement decision must be made under these circumstances as to the real thickness of the bed.

Step 6: Read the maximum SP value for the permeable zone of interest The SP value is the millivolt reading indicated on the log, from the shale base line to the maximum deflection on the SP in the permeable bed.

Step 7: Correct the SP value in Step 6 for thickness and resistivity effectsChart SP-4 is a generalised correction chart for the SP. It corrects for bed thickness and resistivity effects on the SP amplitude. Notice on Chart SP-4 that low resistivity, thick beds require little to no correction. If the bed is thick enough, the SP will have reached maximum amplitude. On this particular chart, the resistivity value from the short normal is used as Ri. A focused log (from the dual induction) also can be used.

Step 8: Determine the mudfiltrate to apparent formation water resistivity ratio, Rmfe/RweChart SP-1 relates the corrected SP deflection, formation temperature and the ratio of the resistivity of the mud filtrate to apparent formation water resistivity for a sodium chloride solution (Rwe). Determine Rmfe/Rwe from this chart

Step 9: Determine RweRwe is obtained from the Rmfe/Rwe ratio determined from Chart SP-1 by dividing Rmfe by the Rmfe/Rwe ratio. The correlation in Chart SP-1 is based on formation water containing only sodium chloride, NaCl.


26

Step 10: Correct Rwe to a more realistic salt content and determine RwCorrect Rwe to Rw for the average deviation from sodium chloride solutions found in formation water. Chart SP-2 corrects for high salinity’s and normal concentrations of calcium, magnesium and other divalent ions, as well as the influence of formation temperatures.

1.2 Rw from water saturation equation in a 100% water-bearing formation

When the water saturation is assumed to be 100%, the Archie water saturation equation reduces to:

Rw = Rt/F (29)

Where Rt is from a deep-investigation resistivity log, and F is computed from a porosity log reading.

If we assume all zones are water bearing and generalise this equation we have:

Rwa = Rt/F (30)

The values of Rwa can be calculated for a number of water bearing zones and if the same then the value of Rwa can be assumed to be equal to Rw. If Rwa is calculated mistakenly in a hydrocarbon zone then Rt will increase and if the porosity is unaf-fected by the presence of hydrocarbons then the value of Rwa will increase.

Procedure:

Step 1: Identify a permeable, water bearing zone near to the hydrocarbon bearing zone of interest.

Step 2: Read the resistivity of the zone of interest from a deep investigation resistivity log.

Step 3: Determine the Formation Resistivity Factor, F Determine porosity from the acoustic, density or Neutron Log. Calculate F from the Humble formula.

Step 4: Determine Rwa from Equation 30 above

Step 5: Compare values of Rwa The values in the water bearing zone should be similar. The lowest value of Rwa is generally the value of Rw. If the calculated value of Rwa at a particular depth is over three times that of Rw determined in a definite water bearing zone then the zone is potentially hydrocarbon bearing.



22/10/13

APPENDIX 2 – DETERMINATION OF SHALE VOLUME (Vsh)

Using Gamma Ray logShales normally contains radioactive bearing minerals and therefore gamma ray log can be used to calculate volume of shale. However care should be taken to make sure that the formation does not contain radioactive sandstone or carbonates.

First step is to calculate the gamma ray index IGR.

I GR =GRmax - GR min

GRlog - GR min

(31)

Where IGR = gamma ray indexGRlog = gamma ray reading from the logGRmin = minimum gamma ray on the log (clean sand or carbonate)GRmax = maximum gamma ray on the log (shale)

Several non-linear relationships can then be applied to calculate Vsh depending on the rock age, type or other available information.

Vsh = IGR

3 - 2 x IGR (Steiber 1970) (32)

Vsh = 1.7-[3.38 - (IGR + 0.7)2] 12

(Clavier 1971)

(33)

For consolidated/older rocks (Larionov 1969)

Vsh = 0.33 x (2 2IGR - 1) (34)

For unconsolidated/Tertiary rocks (Lariono 1963)

Vsh = 0.083(2 3.7IGR - 1) (35)

Using SP logUnlike Vshale from the gamma ray measurement, Vshale from SP measurement is not affected by changes in mineralogy. Therefore if one experiences with variable clay types or the possibility of additional radioactive components, it is a good practice to supplement the gamma ray calculated Vsh values with SP and/or Density-Neuotron.

The SP log can be used to calculate the volume of shale in a permeable zone using the following equation

Vsh = 1 – ASP/SSP


28

WherePSP(ASP) = actual or pseudo spontaneous potential SSP = static spontaneous potential

The calculated volume of shale can then be used in the shaly formation log interpretation.


CHART POR-1Chart POR-3Chart POR-5

Chart SW-1Chart SW-2

Chart Rint-2b

Chart SP-1Chart SP-2Chart SP-4

Chart Gen-6Chart Gen-9

Chart Appendix A3Chart Appendix A4



22/10/13


30


Interpretation Charts E I G H T

Crossplots for Porosity, Lithology and SaturationSchlumberger

4-24

CP

30 40 50 60 70

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

t maa (µsec/ft)

ρ maa

(g/c

m3 )

ρmaa versus t maa

Calcite

Dolomite

Anhydrite

Quartz

Gas direction

SaltSNP

SaltCNL*

© Schlumberger

Matrix Identification (MID) PlotCP-15

(English)

Examples: Level 1 Level 2t = 67 µsec/ft t = 63 µsec/ftρb = 2.04 g/cm3 ρb = 2.46 g/cm3

φCNL = –3 φCNL = 24 p.u.ρf = 1.0 g/cm3

giving φaND = –1 φaND = 21φaNS = –1 φaNS = 21

and t maa = 66 µsec/ft t maa = 43.5 µsec/ftρmaa = 2.03 g/cm3 ρmaa = 2.85 g/cm3

From the MID plot, Level 1 is identified as salt and Level 2as dolomite.

Continued on next page

22/10/13


Interpretation Charts Chapter F O U R

22/10/13

Electromagnetic Propagation and MicroresistivitySchlumberger

5-9

Rxo

Microlog Interpretation ChartRxo-1

Enter the chart with the ratios R1×1/Rmc and R2/Rmc. The pointof intersection defines the Rxo/Rmc ratio and the mudcake thick-ness, hmc. Knowing Rmc, Rxo can be calculated.

For hole sizes other than 8 in. [203 mm], multiply R1×1/Rmcby the following factors before entering the chart: 1.15 for 43⁄4-in. [120-mm] hole, 1.05 for 6-in. [152-mm] hole, and 0.93for 10-in. [254-mm] hole.

Note: An incorrect Rmc will displace the points in the chartalong a 45° line. In certain cases this can be recognized when

the mudcake thickness is different from direct measurementby the microcaliper. To correct, move the plotted point at 45°to intersect the known hmc. For this new point, read Rxo/Rmcfrom the chart and R2/Rmc from the bottom scale of the chart.

R RR RR Rxo

xo mc

mc=

2

2

//

1 1.5 2 3 4 5 6 7 8 9 10 15 20

20

15

1098

7

6

5

4

3

2

1.5

1

1.5

2

2.5

3

3.54

4.55

6

7

89

10

12

15

20 3050

100

200 00

R2

Rmc

R1 × 1

Rmc

8-in. [203-mm] hole

Values

ofR xo

/R mc

Zero h mc

Zeroh mc

1⁄16 in.[1.5 mm]

1⁄8 in. [3 mm]

1⁄4 in. [6.4 mm]

3⁄8 in. [9.5 mm]

1⁄2 in. [13 mm]

5⁄8 in. [16 mm]

3⁄4 in. [19 mm]

1 in. [25.4 mm]

© Schlumberger


5-9

Rxo

Microlog Interpretation ChartRxo-1

Enter the chart with the ratios R1×1/Rmc and R2/Rmc. The pointof intersection defines the Rxo/Rmc ratio and the mudcake thick-ness, hmc. Knowing Rmc, Rxo can be calculated.

For hole sizes other than 8 in. [203 mm], multiply R1×1/Rmcby the following factors before entering the chart: 1.15 for 43⁄4-in. [120-mm] hole, 1.05 for 6-in. [152-mm] hole, and 0.93for 10-in. [254-mm] hole.

Note: An incorrect Rmc will displace the points in the chartalong a 45° line. In certain cases this can be recognized when

the mudcake thickness is different from direct measurementby the microcaliper. To correct, move the plotted point at 45°to intersect the known hmc. For this new point, read Rxo/Rmcfrom the chart and R2/Rmc from the bottom scale of the chart.

R RR RR Rxo

xo mc

mc=

2

2

//

1 1.5 2 3 4 5 6 7 8 9 10 15 20

20

15

1098

7

6

5

4

3

2

1.5

1

1.5

2

2.5

3

3.54

4.55

6

7

89

10

12

15

20 3050

100

200 00

R2

Rmc

R1 × 1

Rmc

8-in. [203-mm] hole

Values

ofR xo

/R mc

Zero h mc

Zeroh mc

1⁄16 in.[1.5 mm]

1⁄8 in. [3 mm]

1⁄4 in. [6.4 mm]

3⁄8 in. [9.5 mm]

1⁄2 in. [13 mm]

5⁄8 in. [16 mm]

3⁄4 in. [19 mm]

1 in. [25.4 mm]

© Schlumberger

22/10/13


5-10

Rxo

Charts Rxo-2 and Rxo-3 correct microresistivity measurementsfor mudcake effect. To use, enter the ratio of the microresistivitylog reading divided by the mudcake resistivity into the abscissaof the appropriate chart. Go vertically to the mudcake thickness;

the ratio of the corrected microresistivity value to the microresis-tivity log reading is then given on the ordinate. Multiplication ofthis ratio by the microresistivity log reading yields the correctedmicroresistivity.


Microlaterolog and Proximity LogMudcake Correction Rxo-2

Microlaterolog(Type VIII hydraulic pad)

RMLL/Rmc

RM

LLco

r/RM

LLR

pcor

/Rp

Rp/Rmc

Proximity Log(Isotropic mudcake)

1 2 5 10 20 50 100

1 2 5 10 20 50 100

3.0

2.0

1.0

0.7

3.0

2.0

1.0

0.8

1 in. [25.4 mm]

1 in. [25.4 mm]

3⁄4 in. [19 mm]

3⁄4 in. [19 mm]

3⁄8 in. [9.5 mm]

[0 – 6.4 mm]

0 – 1⁄4 in.

1⁄4 – 1⁄2 in. [6.4 – 12.7 mm]

0 in.

hmc

hmc

© Schlumberger


5-10

Rxo

Charts Rxo-2 and Rxo-3 correct microresistivity measurementsfor mudcake effect. To use, enter the ratio of the microresistivitylog reading divided by the mudcake resistivity into the abscissaof the appropriate chart. Go vertically to the mudcake thickness;

the ratio of the corrected microresistivity value to the microresis-tivity log reading is then given on the ordinate. Multiplication ofthis ratio by the microresistivity log reading yields the correctedmicroresistivity.


Microlaterolog and Proximity LogMudcake Correction Rxo-2

Microlaterolog(Type VIII hydraulic pad)

RMLL/Rmc

RM

LLco

r/RM

LLR

pcor

/Rp

Rp/Rmc

Proximity Log(Isotropic mudcake)

1 2 5 10 20 50 100

1 2 5 10 20 50 100

3.0

2.0

1.0

0.7

3.0

2.0

1.0

0.8

1 in. [25.4 mm]

1 in. [25.4 mm]

3⁄4 in. [19 mm]

3⁄4 in. [19 mm]

3⁄8 in. [9.5 mm]

[0 – 6.4 mm]

0 – 1⁄4 in.

1⁄4 – 1⁄2 in. [6.4 – 12.7 mm]

0 in.

hmc

hmc

© Schlumberger


5-11

Rxo

MicroSFL* Mudcake CorrectionRxo-3

Example: RMLL = 9.0 ohm-mRmc = 0.15 ohm-m at formation temperaturehmc = 9.5 mm

giving RMLL/Rmc = 9.0/0.15 = 60Therefore, RMLLcor/RMLL = 2and RMLLcor = 2(9.0) = 18 ohm-m

RMSFL/Rmc

RM

SFLc

or/R

MSF

L

Standard MicroSFLMSFL version III mudcake correction, 8-in. borehole

1 2 5 10 20 50 100

3.0

2.5

2.0

1.5

1.00.90.80.70.6

1 in. [25.4 mm]

3⁄4 in. [19 mm]

1⁄4 in. [6.4 mm]

1⁄8 in. [3.2 mm]

1⁄2 in. [12.7 mm]

hmc

0 in.

RM

SFLc

or/R

MSF

L

RMSFL/Rmc

Slimhole MicroSFLSlim MSFL mudcake correction, 8-in. borehole

1 2 5 10 20 50 100

3.0

2.5

2.0

1.5

1.00.90.80.70.6

1 in. [25.4 mm] 3⁄4 in. [19 mm]

1⁄2 in. [12.7 mm]1⁄4 in. [6.4 mm]

0 – 1⁄8 in. [0 – 3.2 mm]

hmc

*Mark of Schlumberger© Schlumberger

22/10/13

Gen

Basic Material

Estimation of Rmf and Rmc

Schlumberger

Gen-7

1-3

Direct measurements of filtrate and mudcake samples are pre-ferred. When not available, filtrate resistivity, Rmf, and mudcakeresistivity, Rmc, may be estimated from one of the followingmethods.

Method 1Lowe and Dunlap (Reference 36)For freshwater muds with mud resistivity, Rm, in the range from0.1 to 2.0 ohm-m at 75°F [24°C], and measured values of Rmand mud density, ρm, in pounds per gallon:

Method 2Overton and Lipson (Reference 1)For drilling muds with mud resistivity, Rm, in the range from 0.1to 10.0 ohm-m at 75°F [24°C], where Km is given as a functionof mud weight in the table below:

Example: Rm = 3.5 ohm-m at 75°F [24°C]Mud weight = 12 lbm/gal [1440 kg/m3]

Therefore, Km = 0.584Rmf = (0.584)(3.5)1.07 = 2.23 ohm-m at 75°FRmc = 0.69(2.23)(3.5/2.23)2.65 = 5.07 ohm-m at 75°F

The calculated value of Rmf is more reliable than that of Rmc.

Method 3A statistical approximation, for predominantly NaCl muds, is Rmc = 1.5 Rm, and Rmf = 0.75 Rm.

R K R

R RRR

mf m m

mc mfm

mf

=

=

( )

. ( )

.

.

1 07

2 65

0 69

log . .RR

mf

mm

= −0 396 0 0475 ρ

Mud Weight

lbm/gal kg/m3 Km

10 1200 0.84711 1320 0.70812 1440 0.58413 1560 0.48814 1680 0.41216 1920 0.38018 2160 0.350


4-26

CP

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.00 1 2 3 4 5 6

Pe, photoelectric factor

ρ b, b

ulk

dens

ity (g

/cm

3 )

4030

2010

0

4030

2010

0

0

40

3020

100

0

Qua

rtzsa

ndst

one

Dol

omite

Calci

te(li

mes

tone

)Sa

lt

Anhy

drite

Fresh water, liquid-filled holes (ρf = 1.0)


Porosity and Lithology Determinationfrom Litho-Density* Log CP-16

For more information see Reference 27.

22/10/13

PorositySchlumberger

3-5

Por

Formation Density Log Determination of PorosityPor-5

40

30

20

10

02.8 2.6 2.4 2.2 2.0

2.31

1.0 0.9 0.8

1.1

1.2

φ,po

rosit

y,(p

.u.)

ρb, bulk density (g/cm3)

ρ ma= 2.8

7 (dolom

ite)

ρ ma= 2.7

1 (calcit

e)

ρ ma= 2.6

5 (quart

z sand

stone

)

ρ ma= 2.8

3ρ ma

= 2.68

ρma – ρb

ρma – ρfφ =

ρf


Bulk density, ρb, as recorded with the FDC* CompensatedFormation Density or Litho-Density* logs, is converted to poros-ity with this chart. To use, enter bulk density, corrected for bore-hole size, in abscissa; go to the appropriate reservoir rock typeand read porosity on the appropriate fluid density, ρf, scale inordinate. (ρf is the density of the fluid saturating the rock imme-diately surrounding the borehole—usually mud filtrate.)

Example: ρb = 2.31 g/cm3 in limestone lithologyρma = 2.71 (calcite)ρf = 1.1 (salt mud)

Therefore, φD = 25 p.u.

Interpretation Charts Chapter F I V E


22/10/13


3-1

Por

Formation Resistivity Factor Versus PorosityPor-1

2.5 5 10 20 50 100 200 500 1000 2000 5000 10,000

2.5 5 10 20 50 100 200 500 1000 2000 5000 10,00050

40

3025

20

15

1098765

4

3

2

1

FR, formation resistivity factor

φ, p

oros

ity (p

.u.)

1.4

1.6

1.82.0

2.2

2.5

2.8

FR = 0.81φ2

FR = 1φ2

FR = 0.62φ2.15

FR = 1φmm

Vugs orspherical pores

Fractures

© Schlumberger

This chart gives a variety of formation resistivity factor-to-porosity conversions. The proper choice is best determined bylaboratory measurement or experience in the area. In the absenceof this knowledge, recommended relationships are the following:For soft formations (Humble formula):

For hard formations:

with appropriate cementation factor, m.

Example: φ = 6% in a carbonate in which a cementation factor,m, of 2 is appropriate

Therefore, from chart,FR = 280

FR m= 1φ

,

F FR R= =0 62 0 812 15 2. , . ..φ φ

or


3-1

Por


2.5 5 10 20 50 100 200 500 1000 2000 5000 10,000

2.5 5 10 20 50 100 200 500 1000 2000 5000 10,00050

40

3025

20

15

1098765

4

3

2

1


φ, p

oros

ity (p

.u.)

1.4

1.6

1.82.0

2.2

2.5

2.8

FR = 0.81φ2

FR = 1φ2

FR = 0.62φ2.15

FR = 1φmm


Fractures

© Schlumberger






FR m= 1φ

,

F FR R= =0 62 0 812 15 2. , . ..φ φ

or

22/10/13


3-3

Por

Porosity Evaluation from SonicPor-3

(English)

30 40 50 60 70 80 90 100 110 120 130

t , interval transit time (µsec/ft)

vf = 5300 ft/sec50

40

30

20

10

0

50

40

30

20

10

0

φ, p

oros

ity (p

.u.)

φ, p

oros

ity (p

.u.)

Time averageField observation

1.1

1.2

1.3

1.4

1.5

1.6

Dolomite

Calcite

(limest

one)

Quartz

sandsto

ne

26,00

023

,000

21,00

018

,000

19,50

0

vma(ft/sec)

Bcp

© Schlumberger

These two charts (Por-3) convert sonic log interval transit time,t , into porosity, φ. Two sets of curves are shown. The blue setemploys a weighted-average transform. The red set is based onempirical observation (see Reference 20). For both, the saturat-ing fluid is assumed to be water with a velocity of 5300 ft/sec(1615 m/sec).

To use, enter the chart with the interval transit time from thesonic log. Go to the appropriate matrix velocity or lithologycurve and read the porosity on the ordinate.

For rock mixtures such as limy sandstones or chertydolomites, intermediate matrix lines may be required. Whenusing the weighted-average transform in unconsolidated sand,a lack-of-compaction correction, Bcp, must be made. To accom-plish this, enter the chart with the interval transit time; go to theappropriate compaction correction line, and read the porosity onthe ordinate. If the compaction correction is unknown, it can bedetermined by working backward from a nearby clean watersand whose porosity is known.



3-5

Por


40

30

20

10

02.8 2.6 2.4 2.2 2.0

2.31

1.0 0.9 0.8

1.1

1.2

φ,po

rosit

y,(p

.u.)


ρ ma= 2.8

7 (dolom

ite)

ρ ma= 2.7

1 (calcit

e)

ρ ma= 2.6

5 (quart

z sand

stone

)

ρ ma= 2.8

3ρ ma

= 2.68

ρma – ρb

ρma – ρfφ =

ρf






3-5

Por


40

30

20

10

02.8 2.6 2.4 2.2 2.0

2.31

1.0 0.9 0.8

1.1

1.2

φ,po

rosit

y,(p

.u.)


ρ ma= 2.8

7 (dolom

ite)

ρ ma= 2.7

1 (calcit

e)

ρ ma= 2.6

5 (quart

z sand

stone

)

ρ ma= 2.8

3ρ ma

= 2.68

ρma – ρb

ρma – ρfφ =

ρf





22/10/13


3-9

Por

When the APS or SNP log is recorded in limestone porosityunits, this chart is used to find porosity in sandstones or dolo-mites. First, correct the SNP log for mudcake thickness (ChartPor-15a).

This chart can also be used to find apparent limestoneporosity (needed for entering the various CP crossplot charts) ifthe APS or SNP recording is in sandstone or dolomite porosityunits.

Example: Sandstone bedφSNP = 13 p.u. (apparent limestone porosity)Bit size = 77⁄8 in.SNP caliper = 75⁄8 in.

giving hmc = 1⁄4 in.φSNP = 11.3 p.u. (corrected for mudcake)

and φSNP (sandstone) = 14.5 p.u.

Epithermal Neutron Porosity Equivalence CurvesSidewall Neutron Porosity (SNP) log;Accelerator Porosity Sonde (APS) Near-to-Array (APLC) and Near-to-Far (FPLC) logs

Por-13a

40

30

20

10

00 10 20 30 40

φSNPcor, apparent limestone neutron porosity (p.u.)φAPScor, apparent limestone neutron porosity (p.u.)

φ, tr

ue p

oros

ity fo

r ind

icat

ed m

atrix

mat

eria

l

APLCFPLCSNP

Quartz

sand

stone

Calcite

(limes

tone)

Dolomite



3-10

Por

Thermal Neutron Porosity Equivalence CurvesCNL* Compensated Neutron Log; TNPH and NPHI porosity logs Por-13b

40

30

20

10

00 10 20 30 40

φCNLcor, apparent limestone neutron porosity (p.u.)

φ, tr

ue p

oros

ity fo

r ind

icat

ed m

atrix

mat

eria

l

Quartz

sand

stone

Calcite

(limes

tone)

Dolomite

Formation salinity

TNPHNPHI

0 kppm

250 kppm


Chart Por-13b can be used in the same way as Chart Por-13a,on the previous page, to convert CNL porosity logs (TNPH orNPHI) from one lithology to another. If a log is recorded in lime-stone porosity units in a pure quartz sandstone formation, thetrue porosity can be derived.

Example: Quartz sandstone formationTNPH = 18 p.u. (apparent limestone porosity)Formation salinity = 250 kppm

giving True porosity in sandstone = 24 p.u.

22/10/13


3-17

Por

0 10 20 30 40 50

0 10 20 30 40 50

• Standard conditions

Actual borehole size(in.)

1.0

0.5

0.0

Mudcake thickness(in.)

250

0

Borehole salinity(kppm)

Mud weight(lbm/gal)

Nat

ural

300

50

Borehole temperature(°F)

25

0

Pressure(kpsi)

18161412108

Barit

e

Water-base mudOil mud

250

0

Limestoneformation salinity

(kppm)

Neutron log porosity index (apparent limestone porosity)

2420161284 •

•

•

•

•

•

•

•

1312111098

Dual-Spacing CNL* Compensated Neutron LogCorrection Nomograph for OpenholeFor CNL curves without environmental corrections

Por-14c(English)



3-6

Por

Environmental Corrections to Formation Density Log,Litho-Density* Log and Sidewall Neutron Porosity Log Por-15a

Under some circumstances, the FDC* Compensated Formation Densitylog and Litho-Density log must be corrected for borehole size, and theSNP sidewall neutron log must be corrected for mudcake thickness.These charts provide those corrections.

For the FDC log, enter the chart with borehole diameter, dh. Go tothe apparent formation density, ρb (FDC log density reading), and read,in ordinate, the correction to be added to the FDC log density reading.

Gas-filled holes

Mud-filled holes

0.06

0.05

0.04

0.03

0.02

0.01

10 11 12 13 14 15

150– 225 250 275 300 325 350 375

6–9

dh, borehole diameter (mm)FDC Borehole Correction

dh, borehole diameter (in.)

g/cm

3 to b

e ad

ded

to F

DC

den

sity

2.62.42.2

2.62.42.2

Apparentformationdensity

0.040.030.020.01

0–0.01 –0.02 –0.03

–5 0 5 10 15 20 25

–125 0 125 250 375 500 625

(dh – 200)(ρb – ρm) in metric unitsLitho-Density Borehole Correction

(dh – 8)(ρb – ρm) in English units

g/cm

3 to b

e ad

ded

to L

DT

dens

ity

SNP Mudcake Correction

0 5 10 15 20 25 30 35 40

0 5 10 15 20 25 30 35 40

φSNPcor (p.u.)

φSNP (p.u.)

0

10

20

01⁄41⁄23⁄4

Mud

cake

thic

knes

s(b

it si

ze m

inus

calip

er re

adin

g)(m

m)

(i

n.)


Example: dh = 12 in.ρb = 2.20 g/cm3 (mud-filled borehole)

Therefore, correction = 0.02 g/cm3

ρbcor = 2.20 + 0.02 = 2.22 g/cm3

For the LDT log, enter the chart abscissa with theproduct of the borehole diameter, dh, less 8 in. [200 mm]and the LDT density reading, ρb, less mud density, ρm.Read, in ordinate, the correction to be added to the Litho-Density bulk density reading.

Example: dh = 325 mmρb = 2.45 g/cm3

ρm = 1.05 g/cm3

giving (dh – 200)(ρb – ρm) =(325 – 200)(2.45 – 1.05) = 175

Therefore, correction = 0.014 g/cm3

ρbcor = 2.45 + 0.014 = 2.464 g/cm3

Note: If the borehole diameter from the FDC or LDTcaliper is less than bit size, use the bit size in the abovecharts.

For the SNP log, enter the bottom of the chart with theSNP apparent porosity, φSNP; go vertically to the bit sizeminus caliper reading value; then, follow the diagonalcurves to the top edge of the chart to obtain the correctedSNP apparent porosity.

Example: φSNP = 13 p.u.Caliper = 75⁄8 in.Bit size = 77⁄8 in.

giving Bit size – caliper = 77⁄8 – 73⁄8 = 1⁄4 in.Therefore, φSNPcor = 11.3 p.u.

Note: The full borehole diameter reduction shown on theSNP caliper is used as mudcake thickness, since the SNPbackup shoe usually cuts through the mudcake.

22/10/13


Interpretation Charts Chapter S I X

22/10/13


4-1

CP

The neutron-density-sonic crossplot charts (Charts CP-1, CP-2and CP-7) provide insight into lithology and permit the determi-nation of porosity. Chart selection depends on the anticipatedmineralogy. Neutron-density can be used to differentiate betweenthe common reservoir rocks [quartz sandstone, calcite (lime-stone) and dolomite] and shale and some evaporites.

Sonic-neutron can be used to differentiate between the commonreservoir rocks when clay content is negligible. Sonic-densitycan be used to differentiate between a single known reservoirrock and shale and to identify evaporate minerals.


Porosity and Lithology Determination fromFormation Density Log and SNP Sidewall Neutron Porosity Log CP-1a

0 10 20 30 40

φSNPcor, neutron porosity index (p.u.) (apparent limestone porosity)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

ρ b, b

ulk

dens

ity (g

/cm

3 )

φ D, d

ensi

ty p

oros

ity (p

.u.)

(ρm

a = 2

.71,

ρf =

1.0

)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15

SulfurSalt

Trona

PolyhaliteLangbeinite

Approximategascorrection

Anhydr

ite0

Dolomite

0

5

10

15

20

25

30

35

Quartzsandsto

nePorosity

0

5

10

15

20

25

30

35

40

Calcite (lim

estone)

0

5

10

15

20

25

30

35

40

45


© Schlumberger


4-1

CP

The neutron-density-sonic crossplot charts (Charts CP-1, CP-2and CP-7) provide insight into lithology and permit the determi-nation of porosity. Chart selection depends on the anticipatedmineralogy. Neutron-density can be used to differentiate betweenthe common reservoir rocks [quartz sandstone, calcite (lime-stone) and dolomite] and shale and some evaporites.

Sonic-neutron can be used to differentiate between the commonreservoir rocks when clay content is negligible. Sonic-densitycan be used to differentiate between a single known reservoirrock and shale and to identify evaporate minerals.


Porosity and Lithology Determination fromFormation Density Log and SNP Sidewall Neutron Porosity Log CP-1a

0 10 20 30 40


1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

ρ b, b

ulk

dens

ity (g

/cm

3 )

φ D, d

ensi

ty p

oros

ity (p

.u.)

(ρm

a = 2

.71,

ρf =

1.0

)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15

SulfurSalt

Trona



Anhydr

ite0

Dolomite

0

5

10

15

20

25

30

35

Quartzsandsto

nePorosity

0

5

10

15

20

25

30

35

40

Calcite (lim

estone)

0

5

10

15

20

25

30

35

40

45


© Schlumberger

22/10/13


4-2

CP

0 10 20 30 40


1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

ρ b, b

ulk

dens

ity (g

/cm

3 )

φ D, d

ensi

ty p

oros

ity (p

.u.)

(ρm

a = 2

.71,

ρf =

1.1

)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15

SulfurSalt

Trona

Polyhalite

Dolomite

Calcite (lim

estone)

Quartzsandsto

ne

Langbeinite


Porosity

Anhydr

ite0

0

5

10

15

20

25

30

35

0

5

10

15

20

25

30

35

40

0

5

10

15

20

25

30

35

40

45

40

45

Salt water, liquid-filled holes (ρf = 1.1)

Porosity and Lithology Determination fromFormation Density Log and SNP Sidewall Neutron Porosity Log CP-1b

To use any of these charts, enter the abscissa and ordinatewith the required neutron, density or sonic value. The pointof intersection defines the lithology (mineralogy) and theporosity, φ.

Note that all neutron input is in apparent limestone porosity,that charts for fresh water (ρf = 1.0 g/cm3) and saline water (ρf = 1.1 g/cm3) invasion exist, and that the sonic charts containcurves assuming weighted average response (blue) and empiricalobservation response (red).

© Schlumberger


4-2

CP

0 10 20 30 40


1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

ρ b, b

ulk

dens

ity (g

/cm

3 )

φ D, d

ensi

ty p

oros

ity (p

.u.)

(ρm

a = 2

.71,

ρf =

1.1

)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15

SulfurSalt

Trona

Polyhalite

Dolomite

Calcite (lim

estone)

Quartzsandsto

ne

Langbeinite


Porosity

Anhydr

ite0

0

5

10

15

20

25

30

35

0

5

10

15

20

25

30

35

40

0

5

10

15

20

25

30

35

40

45

40

45


Porosity and Lithology Determination fromFormation Density Log and SNP Sidewall Neutron Porosity Log CP-1b

To use any of these charts, enter the abscissa and ordinatewith the required neutron, density or sonic value. The pointof intersection defines the lithology (mineralogy) and theporosity, φ.

Note that all neutron input is in apparent limestone porosity,that charts for fresh water (ρf = 1.0 g/cm3) and saline water (ρf = 1.1 g/cm3) invasion exist, and that the sonic charts containcurves assuming weighted average response (blue) and empiricalobservation response (red).

© Schlumberger


4-16

CP

Porosity and Lithology Determination fromFormation Density Log and CNL* Compensated Neutron LogFor CNL logs before 1986, or labeled NPHI

CP-1c

0 10 20 30 40φCNLcor, neutron porosity index (p.u.) (apparent limestone porosity)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

ρ b, b

ulk

dens

ity (g

/cm

3 )

φ D, d

ensi

ty p

oros

ity (p

.u.)

(ρm

a = 2

.71;

ρf =

1.0

)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15

Porosity

SulfurSalt


0

Anhyd

rite


Calcite (lim

estone)

Quartzsandsto

ne

Dolomite

0

45

5

15

10

20

25

30

35

40

30

0

5

15

10

20

25

35

40

30

0

5

15

10

20

25

35

40



22/10/13


4-8

CP

Porosity and Lithology Determination from Sonic Logand SNP Sidewall Neutron Porosity Log CP-2a

(English)

110

100

90

80

70

60

50

400 10 20 30 40


t, so

nic

trans

it tim

e (µ

sec/

ft)


0Salt

0 Anhy

drite

00

0

0

5

10

1010

15

15

15

15

15

15

20

2020

20

20

20

25

25

2525

25

30

35

35

40

30 30

25

30

35

4040

30

35

40

05

5

55

0

35

10

10

Calcite

(limes

tone)

Quartz

sand

stone

(v ma= 18

,000 ft/s

ec)

Dolom

ite

Poros

ity

t f = 189 µsec/ft

© Schlumberger


4-8

CP

Porosity and Lithology Determination from Sonic Logand SNP Sidewall Neutron Porosity Log CP-2a

(English)

110

100

90

80

70

60

50

400 10 20 30 40


t, so

nic

trans

it tim

e (µ

sec/

ft)


0Salt

0 Anhy

drite

00

0

0

5

10

1010

15

15

15

15

15

15

20

2020

20

20

20

25

25

2525

25

30

35

35

40

30 30

25

30

35

4040

30

35

40

05

5

55

0

35

10

10

Calcite

(limes

tone)

Quartz

sand

stone

(v ma= 18

,000 ft/s

ec)

Dolom

ite

Poros

ity

t f = 189 µsec/ft

© Schlumberger


4-18

CP

Porosity and Lithology Determination fromSonic Log and CNL* Compensated Neutron LogFor CNL logs before 1986, or labeled NPHI

CP-2b(English)

110

100

90

80

70

60

50

400 10 20 30 40

φCNLcor, neutron porosity index (p.u.) (apparent limestone porosity)

t f = 189 µsec/ft

Poros

ity

0 Anhy

drite

0Sa

lt

Calcite

(limes

tone)

Quartz

sand

stone

Dolom

ite

t, so

nic

trans

it tim

e (µ

sec/

ft)

0

5

15

10

20

25

30

35

40

0

5

10

15

20

25

30

35

40

0

5

10

15

20

25

30

35

40

40

35

30

25

20

15

10

5

0Time averageField observation

35

30

25

20

15

10

5

0

5

0

10

15

20

25

30


22/10/13


4-14

CP

Lithology Identification fromFormation Density Log and Sonic Log CP-7

(English)

40 50 60 70 80 90 100 110 120

1.8

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

t, sonic transit time (µsec/ft)

ρ b, b

ulk

dens

ity (g

/cm

3 )

t f = 189 µsec/ft; ρf = 1.0

Dolomite

Calcite

(limes

tone)


Anhydrite

Polyhalite

Gypsum

Trona

Salt

Sylvite

Sulfur

0

10

10

10

10

10 20

20 30

4040

30

40 40

40

303030

20

20

20

0

0

0

0

10

0Qua

rtzsa

ndsto

ne

Porosity

20

© Schlumberger


4-14

CP

Lithology Identification fromFormation Density Log and Sonic Log CP-7

(English)

40 50 60 70 80 90 100 110 120

1.8

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

t, sonic transit time (µsec/ft)

ρ b, b

ulk

dens

ity (g

/cm

3 )

t f = 189 µsec/ft; ρf = 1.0

Dolomite

Calcite

(limes

tone)


Anhydrite

Polyhalite

Gypsum

Trona

Salt

Sylvite

Sulfur

0

10

10

10

10

10 20

20 30

4040

30

40 40

40

303030

20

20

20

0

0

0

0

10

0Qua

rtzsa

ndsto

ne

Porosity

20

© Schlumberger


4-22

CP

3 2.9 2.8 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2

130 120 110 100 90 80 70 60 50 40 303

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2

130

120

110

100

90

80

70

60

50

40

30

Fluid density = 1.0

ρmaa, apparent matrix density (g/cm3)

ρ b, b

ulk

dens

ity (g

/cm

3 )

t, in

terv

al tr

ansi

t tim

e (µ

sec/

ft)

t maa, apparent matrix transit time (µsec/ft)

40

30

20

10

10

20

30

40

Apparentcrossplotporosity

Density

-neutr

onNeu

tron-s

onic

© Schlumberger

Determination of Apparent Matrix Parameters fromBulk Density or Interval Transit Time and Apparent Total Porosity CP-14

(English)

The MID plot permits the identification of rock mineralogy orlithology through a comparison of neutron, density and sonicmeasurements.

To use the MID plot, three steps are required. First, an appar-ent crossplot porosity must be determined using the appropriate

neutron-density and empirical (red curves) neutron-sonic cross-plot (Charts CP-1 through CP-7). For any data plotting above thesandstone curve on these charts, the apparent crossplot porosityis defined by a vertical projection to the sandstone curve.


22/10/13


4-24

CP

30 40 50 60 70

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

t maa (µsec/ft)

ρ maa

(g/c

m3 )

ρmaa versus t maa

Calcite

Dolomite

Anhydrite

Quartz

Gas direction

SaltSNP

SaltCNL*

© Schlumberger


(English)








4-24

CP

30 40 50 60 70

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

t maa (µsec/ft)

ρ maa

(g/c

m3 )

ρmaa versus t maa

Calcite

Dolomite

Anhydrite

Quartz

Gas direction

SaltSNP

SaltCNL*

© Schlumberger


(English)








4-26

CP

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.00 1 2 3 4 5 6


ρ b, b

ulk

dens

ity (g

/cm

3 )

4030

2010

0

4030

2010

0

0

40

3020

100

0

Qua

rtzsa

ndst

one

Dol

omite

Calci

te(li

mes

tone

)Sa

lt

Anhy

drite



Porosity and Lithology Determinationfrom Litho-Density* Log CP-16


22/10/13


4-27

CP

CP-17

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.00 1 2 3 4 5 6


ρ b, b

ulk

dens

ity (g

/cm

3 )

4030

2010

0

4030

2010

0

0

Qua

rtzsa

ndst

one

Dol

omite

Anhy

drite

4030

2010

0

Calci

te(li

mes

tone

)

0Salt




Porosity and Lithology Determinationfrom Litho-Density* Log


4-29

CP

K, potassium concentration (%)

Th/K, thorium/potassium ratioP e

, pho

toel

ectri

c fa

ctor

P e, p

hoto

elec

tric

fact

or

Glauconite

Glauconite

Chlorite

Chlorite

Biotite

Biotite

Illite

Illite

Muscovite

Muscovite

Montmorillonite

Montmorillonite

Kaolinite

Kaolinite

Mixed layer

0 2 4 6 8 10

0.1 0.2 0.3 0.6 1 2 3 6 10 20 30 60 100

10

8

6

4

2

0

10

8

6

4

2

0


Mineral Identification from Litho-Density* Logand NGS* Natural Gamma Ray Spectrometry Log CP-18


4-29

CP

K, potassium concentration (%)

Th/K, thorium/potassium ratio

P e, p

hoto

elec

tric

fact

orP e

, pho

toel

ectri

c fa

ctor

Glauconite

Glauconite

Chlorite

Chlorite

Biotite

Biotite

Illite

Illite

Muscovite

Muscovite

Montmorillonite

Montmorillonite

Kaolinite

Kaolinite

Mixed layer

0 2 4 6 8 10

0.1 0.2 0.3 0.6 1 2 3 6 10 20 30 60 100

10

8

6

4

2

0

10

8

6

4

2

0


Mineral Identification from Litho-Density* Logand NGS* Natural Gamma Ray Spectrometry Log CP-18

22/10/13


4-30

CP

Radioactive minerals often occur in relatively small concentra-tions in sedimentary rocks. Even shales typically contain only30 to 70% radioactive clay minerals.

Unless there is a complex mixture of radioactive mineralsin the formation, Chart CP-19 can be used to identify the morecommon ones. The ratio of thorium to uranium activity—the

thorium/potassium ratio, Th/K—does not vary with mineralconcentration. A sandstone reservoir with varying amounts ofshaliness, with illite as the principal clay mineral, usually plotsin the illite segment of the chart, with Th/K between 2.0 and 2.5.Less shaly parts of the reservoir plot closer to the origin, andmore shaly parts plot closer to the 70% illite area.

Mineral Identification fromNGS* Natural Gamma Ray Spectrometry Log CP-19

0 1 2 3 4 5

Potassium (%)

25

20

15

10

5

0

Thor

ium

(ppm

)

Mixed layer clay

IlliteMicas

Glauconite

Potassium evaporites, ~30% feldspar

~30% glauconite

~70% illite

100% illite point

~40%mica

Montm

orillo

nite

Chlorite

Kaolinite

Possible 100% kaolinite,montmorillonite,illite “clay line”

Th/K

: 25

Th/K

: 12

Th/K: 3.5

Th/K: 2.0

Th/K: 0.6

Th/K: 0.3Feldspar

Heav

yth

oriu

m-b

earin

gm

iner

als



4-31

CP

6 5 4 3 2 1 4 6 8 10 12 14

3.0

2.5

2.0

%0

10

20

30

40


ρ b, b

ulk

dens

ity (g

/cm

3 )

φ ta,

appa

rent

tota

l por

osity

(%)

Umaa, apparent matrixvolumetric photoelectric factor

Fresh water (0 ppk), ρf = 1.0, Uf = 0.398Salt water (200 ppk), ρf = 1.11, Uf = 1.36

© Schlumberger

Determination of Apparent MatrixVolumetric Photoelectric Factor CP-20


4-30

CP

Radioactive minerals often occur in relatively small concentra-tions in sedimentary rocks. Even shales typically contain only30 to 70% radioactive clay minerals.

Unless there is a complex mixture of radioactive mineralsin the formation, Chart CP-19 can be used to identify the morecommon ones. The ratio of thorium to uranium activity—the

thorium/potassium ratio, Th/K—does not vary with mineralconcentration. A sandstone reservoir with varying amounts ofshaliness, with illite as the principal clay mineral, usually plotsin the illite segment of the chart, with Th/K between 2.0 and 2.5.Less shaly parts of the reservoir plot closer to the origin, andmore shaly parts plot closer to the 70% illite area.

Mineral Identification fromNGS* Natural Gamma Ray Spectrometry Log CP-19

0 1 2 3 4 5

Potassium (%)

25

20

15

10

5

0

Thor

ium

(ppm

)

Mixed layer clay

IlliteMicas

Glauconite

Potassium evaporites, ~30% feldspar

~30% glauconite

~70% illite

100% illite point

~40%mica

Montm

orillo

nite

Chlorite

Kaolinite

Possible 100% kaolinite,montmorillonite,illite “clay line”

Th/K

: 25

Th/K

: 12

Th/K: 3.5

Th/K: 2.0

Th/K: 0.6

Th/K: 0.3Feldspar

Heav

yth

oriu

m-b

earin

gm

iner

als



4-31

CP

6 5 4 3 2 1 4 6 8 10 12 14

3.0

2.5

2.0

%0

10

20

30

40


ρ b, b

ulk

dens

ity (g

/cm

3 )

φ ta,

appa

rent

tota

l por

osity

(%)

Umaa, apparent matrixvolumetric photoelectric factor

Fresh water (0 ppk), ρf = 1.0, Uf = 0.398Salt water (200 ppk), ρf = 1.11, Uf = 1.36

© Schlumberger

Determination of Apparent MatrixVolumetric Photoelectric Factor CP-20

22/10/13


4-33

CP

Umaa, apparent matrix volumetric photoelectric factor

ρ maa

, app

aren

t mat

rix g

rain

den

sity

(g/c

m3 )

2 4 6 8 10 12 14 16

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

Salt

K-Feldspar

Quartz

Dolomite

Kaolinite

Illite

Anhydrite

Heavy minerals

Barite

Calcite

Gas

dire

ctio

n

% Calcite

% Dolomite

%Quartz

2060 80

40

60

40

20

80

6040

20

80

ρmaa versus Umaa

© Schlumberger

Lithology Identification PlotCP-21

Interpretation Charts Chapter S E V E N


22/10/13


3-1

Por


2.5 5 10 20 50 100 200 500 1000 2000 5000 10,000

2.5 5 10 20 50 100 200 500 1000 2000 5000 10,00050

40

3025

20

15

1098765

4

3

2

1


φ, p

oros

ity (p

.u.)

1.4

1.6

1.82.0

2.2

2.5

2.8

FR = 0.81φ2

FR = 1φ2

FR = 0.62φ2.15

FR = 1φmm


Fractures

© Schlumberger






FR m= 1φ

,

F FR R= =0 62 0 812 15 2. , . ..φ φ

or


3-1

Por


2.5 5 10 20 50 100 200 500 1000 2000 5000 10,000

2.5 5 10 20 50 100 200 500 1000 2000 5000 10,00050

40

3025

20

15

1098765

4

3

2

1


φ, p

oros

ity (p

.u.)

1.4

1.6

1.82.0

2.2

2.5

2.8

FR = 0.81φ2

FR = 1φ2

FR = 0.62φ2.15

FR = 1φmm


Fractures

© Schlumberger






FR m= 1φ

,

F FR R= =0 62 0 812 15 2. , . ..φ φ

or

22/10/13


3-3

Por


(English)

30 40 50 60 70 80 90 100 110 120 130

t , interval transit time (µsec/ft)

vf = 5300 ft/sec50

40

30

20

10

0

50

40

30

20

10

0

φ, p

oros

ity (p

.u.)

φ, p

oros

ity (p

.u.)


1.1

1.2

1.3

1.4

1.5

1.6

Dolomite

Calcite

(limest

one)

Quartz

sandsto

ne

26,00

023

,000

21,00

018

,000

19,50

0

vma(ft/sec)

Bcp

© Schlumberger

These two charts (Por-3) convert sonic log interval transit time,t , into porosity, φ. Two sets of curves are shown. The blue setemploys a weighted-average transform. The red set is based onempirical observation (see Reference 20). For both, the saturat-ing fluid is assumed to be water with a velocity of 5300 ft/sec(1615 m/sec).





3-5

Por


40

30

20

10

02.8 2.6 2.4 2.2 2.0

2.31

1.0 0.9 0.8

1.1

1.2

φ,po

rosit

y,(p

.u.)


ρ ma= 2.8

7 (dolom

ite)

ρ ma= 2.7

1 (calcit

e)

ρ ma= 2.6

5 (quart

z sand

stone

)

ρ ma= 2.8

3ρ ma

= 2.68

ρma – ρb

ρma – ρfφ =

ρf






3-5

Por


40

30

20

10

02.8 2.6 2.4 2.2 2.0

2.31

1.0 0.9 0.8

1.1

1.2

φ,po

rosit

y,(p

.u.)


ρ ma= 2.8

7 (dolom

ite)

ρ ma= 2.7

1 (calcit

e)

ρ ma= 2.6

5 (quart

z sand

stone

)

ρ ma= 2.8

3ρ ma

= 2.68

ρma – ρb

ρma – ρfφ =

ρf





22/10/13

ResistivitySchlumberger

6-39

Sw

Saturation DeterminationSw-1

This nomograph solves the Archie water saturation equation

It should be used in clean (nonshaly) formations only. If R0(resistivity when 100% water saturated) is known, a straight linefrom the known R0 value through the measured Rt value giveswater saturation, Sw. If R0 is unknown, it may be determined by

connecting the formation water resistivity, Rw, with the forma-tion resistivity factor, FR, or porosity, φ.Example: Rw = 0.05 ohm-m at formation temperature

φ = 20% (FR = 25)Rt = 10 ohm-m

Therefore, Sw = 35%For other φ/F relations, the porosity scale should be changed

according to Chart Por-1.

SRR

F RRw

t

R w

t= =0 .

Rw(ohm-m)

R0(ohm-m)

R0 = FRRw

Rt(ohm-m)

Sw(%)

φ(%)

FR

2000

1000800600400300200

100806050403020

108654

2.53

456789

10

15

20253035404550

FR = 1φ2.0

m = 2.0

0.01

0.02

0.03

0.040.050.060.070.080.090.1

0.2

0.3

0.40.50.60.70.80.91

1.5

2

5

6

7

89

101112131415161820

25

30

40

50

60

70

8090

100

10,0008,0006,0005,0004,0003,0002,000

1,000800600500400300200

100806050403020

10865432

1.00.80.60.50.40.30.2

0.1

30

201816141210987654

3

21.81.61.41.21.00.90.80.70.60.50.4

0.3

0.20.180.160.140.120.10

Sw = R0

Rt√

Clean formations, m = 2

© Schlumberger


6-41

Sw

Saturation DeterminationRatio method Sw-2

See instructions on previous page. For more information see Reference 12.

5040

30

20

108

654

3

2

10.8

0.60.50.4

0.3

0.2

0.10.08

75100150200300

0.80.6 1.0 1.5 2.52 3 4 5 6 8 10 15 20 25 30 40 50 60

20 10 0 –20 –40 –60 –80 –100 –120 –140

0.80.6 1.0 1.5 2.52 3 4 5 6 8 10 15 20 25 40 50 6030

255075100150

80

0 10 20 30 40

1.0 0.9 0.8 0.7 0.6

80

70

60

50

40

30

25

20

15

10

60

50

40

25

30

20

15

70

90100

Rmf /Rw

Rxo

Rt

Rmf /RwKc

°F °C

EpSP or ESSP (mV)

SxoSw = Sxo (Swa)0.8

Sor (%)

Sw(%)

A

B

CC′

10%

15%

20%

25%30%

40%

50%60%70%

Swa= 100

%

EpSP = –Kc log – 2Kc log Rxo

Rt

Sxo

SwSxo = 5√ Sw

Sxo = 5√ Sw

© Schlumberger


6-41

Sw

Saturation DeterminationRatio method Sw-2

See instructions on previous page. For more information see Reference 12.

5040

30

20

108

654

3

2

10.8

0.60.50.4

0.3

0.2

0.10.08

75100150200300

0.80.6 1.0 1.5 2.52 3 4 5 6 8 10 15 20 25 30 40 50 60

20 10 0 –20 –40 –60 –80 –100 –120 –140

0.80.6 1.0 1.5 2.52 3 4 5 6 8 10 15 20 25 40 50 6030

255075100150

80

0 10 20 30 40

1.0 0.9 0.8 0.7 0.6

80

70

60

50

40

30

25

20

15

10

60

50

40

25

30

20

15

70

90100

Rmf /Rw

Rxo

Rt

Rmf /RwKc

°F °C

EpSP or ESSP (mV)

SxoSw = Sxo (Swa)0.8

Sor (%)

Sw(%)

A

B

CC′

10%

15%

20%

25%30%

40%

50%60%70%

Swa= 100

%

EpSP = –Kc log – 2Kc log Rxo

Rt

Sxo

SwSxo = 5√ Sw

Sxo = 5√ Sw

© Schlumberger

22/10/13


6-15

Rint

DIL* Dual Induction–SFL* Spherically Focused Resistivity LogID–IM–SFL Rint-2b

RIM/RID

RSFL/RID

Thick beds, 8-in. [203-mm] hole, skin-effect corrected,DIS-EA or equivalent

1.0 1.1 1.2 1.3 1.4 1.5 1.7 1.9

20

10

9

8

7

6

5

4

3

2

1

4050

60

70

80

90

15

20

0.38

0.50

0.63

1.27 1.521.78

10

25

30 30

25

15

70.75

di (m) 1.01

5

3

2

0.95 0.850.75

1.0

20

d i (in.)

Rt

RD

Rxo/Rm ≈ 20

Rxo

Rt


Gamma Ray and Spontaneous PotentialSchlumberger

2-5

SP

0.01

0.02

0.040.06

0.1

0.2

0.40.6

1

2

46

10

20

4060

100

0.001

0.005

0.01

0.02

0.05

0.1

0.2

0.5

1.0

2.0

Rmfeq (ohm-m)

Rmfeq /Rweq

a w/a

mf or

Rm

fe /R

we

Rweq(ohm-m)

+50 0 –50 –100 –150 –200

ESSP, static spontaneous potential (mV)

250°C200°C150°C

100°C

50°C0°C

500°F400°F300°F

200°F

100°F

Formationtemperature

0.3

0.4

0.6

0.81

2

4

6

810

20

40

0.3

0.40.50.6

0.81

2

3

4

6

810

20

30

4050

5

Rweq Determination from ESSPClean formations SP-1

© Schlumberger

This chart and nomograph calculate the equivalent forma-tion water resistivity, Rweq, from the static spontaneouspotential, ESSP, measurement in clean formations.

Enter the nomograph with ESSP in mV, turning throughthe reservoir temperature in °F or °C to define theRmfeq/Rweq ratio. From this value, pass through the Rmfeqvalue to define Rweq.

For predominantly NaCl muds, determine Rmfeq asfollows:

a. If Rmf at 75°F (24°C) is greater than 0.1 ohm-m,correct Rmf to formation temperature using ChartGen-9, and use Rmfeq = 0.85 Rmf.

b. If Rmf at 75°F (24°C) is less than 0.1 ohm-m, useChart SP-2 to derive a value of Rmfeq at formationtemperature.

Example: SSP = 100 mV at 250°FRmf = 0.70 ohm-m at 100°F or 0.33 ohm-m at 250°F

Therefore, Rmfeq = 0.85 × 0.33= 0.28 ohm-m at 250°F

Rweq = 0.025 ohm-m at 250°FESSP = –Kc log(Rmfeq /Rweq)KC = 61 + 0.133 T°F

KC = 65 + 0.24 T°C


2-5

SP

0.01

0.02

0.040.06

0.1

0.2

0.40.6

1

2

46

10

20

4060

100

0.001

0.005

0.01

0.02

0.05

0.1

0.2

0.5

1.0

2.0

Rmfeq (ohm-m)

Rmfeq /Rweq

a w/a

mf or

Rm

fe /R

we

Rweq(ohm-m)

+50 0 –50 –100 –150 –200

ESSP, static spontaneous potential (mV)

250°C200°C150°C

100°C

50°C0°C

500°F400°F300°F

200°F

100°F

Formationtemperature

0.3

0.4

0.6

0.81

2

4

6

810

20

40

0.3

0.40.50.6

0.81

2

3

4

6

810

20

30

4050

5

Rweq Determination from ESSPClean formations SP-1

© Schlumberger

This chart and nomograph calculate the equivalent forma-tion water resistivity, Rweq, from the static spontaneouspotential, ESSP, measurement in clean formations.

Enter the nomograph with ESSP in mV, turning throughthe reservoir temperature in °F or °C to define theRmfeq/Rweq ratio. From this value, pass through the Rmfeqvalue to define Rweq.

For predominantly NaCl muds, determine Rmfeq asfollows:

a. If Rmf at 75°F (24°C) is greater than 0.1 ohm-m,correct Rmf to formation temperature using ChartGen-9, and use Rmfeq = 0.85 Rmf.

b. If Rmf at 75°F (24°C) is less than 0.1 ohm-m, useChart SP-2 to derive a value of Rmfeq at formationtemperature.

Example: SSP = 100 mV at 250°FRmf = 0.70 ohm-m at 100°F or 0.33 ohm-m at 250°F

Therefore, Rmfeq = 0.85 × 0.33= 0.28 ohm-m at 250°F

Rweq = 0.025 ohm-m at 250°FESSP = –Kc log(Rmfeq /Rweq)KC = 61 + 0.133 T°F

KC = 65 + 0.24 T°C

22/10/13


2-6

SP

Rw versus Rweq and Formation TemperatureSP-2

(English)

0.005 0.01 0.02 0.03 0.05 0.1 0.2 0.3 0.5 1.0 2 3 4 5

0.001

0.002

0.005

0.01

0.02

0.05

0.1

0.2

0.5

1.0

2.0

Rw or Rmf (ohm-m)

Rw

eq o

r Rm

feq (o

hm-m

)

500°F400°F

300°F

200°F

150°F

100°F

75°F

Saturation

400°F300°F200°F150°F100°F75°F

500°F

NaCl at 75°F

© Schlumberger

These charts convert equivalent water resistivity, Rweq, fromChart SP-1 to actual water resistivity, Rw. They may also be usedto convert Rmf to Rmfeq in saline muds.

Use the solid lines for predominantly NaCl waters. Thedashed lines are approximate for “average” fresh formationwaters (where effects of salts other than NaCl become signifi-cant). The dashed portions may also be used for gyp-base mudfiltrates.

Example: Rweq = 0.025 ohm-m at 120°CFrom chart, Rw = 0.031 ohm-m at 120°C

Special procedures for muds containing Ca or Mg in solutionare discussed in Reference 3. Lime-base muds usually have anegligible amount of Ca in solution; they may be treated asregular mud types.


2-9

SP

SP Correction Chart (Empirical)SP-4

(English)

70 50 40 30 20 15 10 9 8 7 6 5 4 3

Bed thickness, h (ft)

% E

SSP

Cor

rect

ion

fact

or

1.0

1.5

2.0

2.5

3.0

3.54.0

5.0

5

20

50

100

200

di (in.)

3035

35

4040

3030

3030

20

8-in. hole; 33⁄8-in. tool, centered

Ri

Rm

100

90

80

70

60

50

40

30

20

© Schlumberger

This chart provides an empirical correction to the SP for theeffects of invasion and bed thickness obtained by averaginga series of thin-bed corrections in Reference 37. This chartconsiders only h, bed thickness, as variable, and Ri/Rm and di asparameters of fixed value. Hole diameter is set at 8 in.

Enter the chart with bed thickness, h; go to the appropriateinvasion diameter, di, and invaded zone resistivity/mud resis-tivity ratio, Ri/ Rm. The recorded SP measurement is thencorrected by the resulting correction factor.



2-6

SP

Rw versus Rweq and Formation TemperatureSP-2

(English)

0.005 0.01 0.02 0.03 0.05 0.1 0.2 0.3 0.5 1.0 2 3 4 5

0.001

0.002

0.005

0.01

0.02

0.05

0.1

0.2

0.5

1.0

2.0

Rw or Rmf (ohm-m)

Rw

eq o

r Rm

feq (o

hm-m

)

500°F400°F

300°F

200°F

150°F

100°F

75°F

Saturation

400°F300°F200°F150°F100°F75°F

500°F

NaCl at 75°F

© Schlumberger

These charts convert equivalent water resistivity, Rweq, fromChart SP-1 to actual water resistivity, Rw. They may also be usedto convert Rmf to Rmfeq in saline muds.

Use the solid lines for predominantly NaCl waters. Thedashed lines are approximate for “average” fresh formationwaters (where effects of salts other than NaCl become signifi-cant). The dashed portions may also be used for gyp-base mudfiltrates.

Example: Rweq = 0.025 ohm-m at 120°CFrom chart, Rw = 0.031 ohm-m at 120°C

Special procedures for muds containing Ca or Mg in solutionare discussed in Reference 3. Lime-base muds usually have anegligible amount of Ca in solution; they may be treated asregular mud types.


2-9

SP

SP Correction Chart (Empirical)SP-4

(English)

70 50 40 30 20 15 10 9 8 7 6 5 4 3

Bed thickness, h (ft)

% E

SSP

Cor

rect

ion

fact

or

1.0

1.5

2.0

2.5

3.0

3.54.0

5.0

5

20

50

100

200

di (in.)

3035

35

4040

3030

3030

20

8-in. hole; 33⁄8-in. tool, centered

Ri

Rm

100

90

80

70

60

50

40

30

20

© Schlumberger

This chart provides an empirical correction to the SP for theeffects of invasion and bed thickness obtained by averaginga series of thin-bed corrections in Reference 37. This chartconsiders only h, bed thickness, as variable, and Ri/Rm and di asparameters of fixed value. Hole diameter is set at 8 in.

Enter the chart with bed thickness, h; go to the appropriateinvasion diameter, di, and invaded zone resistivity/mud resis-tivity ratio, Ri/ Rm. The recorded SP measurement is thencorrected by the resulting correction factor.


22/10/13

Gen

Basic Material

Resistivity of NaCl SolutionsSchlumberger

Gen-9

1-5

°F 50 75 100 125 150 200 250 300 350 400°C 10 20 30 40 50 60 70 80 90 100 120 140 160 180 200

Temperature (°F or °C)

Res

istiv

ity o

f sol

utio

n (o

hm-m

)

ppm

10

8

65

4

3

2

1

0.8

0.60.5

0.4

0.3

0.2

0.1

0.08

0.060.05

0.04

0.03

0.02

0.01

200

300

400

50060070080010001200140017002000

3000

4000500060007000800010,00012,00014,00017,00020,000

30,00040,00050,00060,00070,00080,000100,000120,000140,000170,000200,000250,000280,000

Conversion approximated by R2 = R1 [(T1 + 6.77)/(T2 + 6.77)]°F or R2 = R1 [(T1 + 21.5)/(T2 + 21.5)]°C

300,000

NaC

l con

cent

ratio

n (p

pm o

r gra

ins/

gal)

Gra

ins/

gal a

t 75°

F

10

15

20

25

30

40

50

100

150

200

250

300

400

500

1000

1500

2000

25003000

40005000

10,000

15,00020,000

© Schlumberger

Gen

Basic Material

Resistivity of NaCl SolutionsSchlumberger

Gen-9

1-5

°F 50 75 100 125 150 200 250 300 350 400°C 10 20 30 40 50 60 70 80 90 100 120 140 160 180 200

Temperature (°F or °C)

Res

istiv

ity o

f sol

utio

n (o

hm-m

)

ppm

10

8

65

4

3

2

1

0.8

0.60.5

0.4

0.3

0.2

0.1

0.08

0.060.05

0.04

0.03

0.02

0.01

200

300

400

50060070080010001200140017002000

3000

4000500060007000800010,00012,00014,00017,00020,000

30,00040,00050,00060,00070,00080,000100,000120,000140,000170,000200,000250,000280,000

Conversion approximated by R2 = R1 [(T1 + 6.77)/(T2 + 6.77)]°F or R2 = R1 [(T1 + 21.5)/(T2 + 21.5)]°C

300,000

NaC

l con

cent

ratio

n (p

pm o

r gra

ins/

gal)

Gra

ins/

gal a

t 75°

F

10

15

20

25

30

40

50

100

150

200

250

300

400

500

1000

1500

2000

25003000

40005000

10,000

15,00020,000

© Schlumberger

22/10/13

A-4

Appendix A

2

2.5

3

3.5

4

4.5

5

6

7

8910

121416

20

2530

4050

100

200

50010002000

∞

500

400

300

250

200

150

100

50

40

30

20

10

5

0

Resistivity scale may bemultiplied by 10 for usein a higher range

Con

duct

ivity

Res

istiv

ity

t, ρb

φ

FR

For FR = 1φ2

Water Saturation Grid for Porosity Versus Resistivity

Appendix A

A-3

0.20

0.25

0.30

0.35

0.40

0.45

0.50

0.60

0.70

0.800.901.0

1.21.41.61.82.0

2.53.0

4.05.06.08.0101520304050100200

∞

5000

4000

3000

2500

2000

1500

1000

500

400

300

200150

100

50

2510

0

Resistivity scale may bemultiplied by 10 for usein a higher range

Con

duct

ivity

Res

istiv

ity

t, ρb

φ

FR

For FR = 0.62φ2.15

Water Saturation Grid for Porosity Versus Resistivity

22/10/13

105

© 2006–2007 Weatherford. All rights reserved.

Shale Volume from Radioactivity Index

8-10

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Sha

le V

olum

e (V

sh)

Radioactivity Index

Clavier, et. al.

Larionov (older rocks)Stieber

Larionov (tertiary rocks)


3

Gas

Date:

1. Complete the sections above but do not seal until the examination is finished.

2. Insert in box on right the numbers of the questions attempted.

3. Start each question on a new page.

4. Rough working should be confined to left hand pages.

5. This book must be handed in entire with the top corner sealed.

6. Additional books must bear the name of the candidate, be sealed and be affixed to the first book by means of a tag provided

Subject:

INSTRUCTIONS TO CANDIDATES

8 Pages

PLEASE READ EXAMINATION REGULATIONS ON BACK COVER

No. Mk.

NAM

E: REGISTRATION N

O.:

COURSE:

YEAR:

SIGNATURE:

Complete this section but do not

seal until the examination

is finished

FORMATION EVALUATION

Examination and Model Solutions

22/10/13

Course:- 28117 Class:- 289FEHERIOT WATT UNIVERSITYDEPARTMENT OF PETROLEUM ENGINEERING

Examination for the Degree ofMeng in Petroleum Engineering

Formation Evaluation Section A

Monday 7th January 200209.30 - 11.30

NOTES FOR CANDIDATES

1. This is a Closed Book Examination.

2. 15 minutes reading time is provided from 09.15 – 09.30.

3. Examination Papers will be marked anonymously. See separate instruction for completion of Script Book front covers and attachment of loose pages. Do not write your name on any loose pages which are submitted as part of your answer.

4. Attempt ALL Questions. Answer in the blue books provided.

5. Return all logs with your Answer Books.

6. Marks for each Question are given in brackets.

7. This examination represents 100% of the Class assessment.

8. State clearly any assumptions used and intermediate calculations made in numerical questions. No marks can be given for an incorrect answer if the method of calculation is not presented. When the result is obtained using a chart book figure, give the number of the figure (eg, Rint-2a, CP-18, Gen-7).

22/10/13

This exam is in two main parts, Section A (closed-book), a series of general questions on formation evaluation and Section B (open-book), a specific log based problem.

Section A

The questions in this section require a short answer, which may be numerical. Be clear and concise. If you consider a question ambiguous, please record this in the form of notes. Alternatively, clarification may be sought from the invigilator.

A1.In a wellbore, we ran a logging string consisting of resistivity logs and both neutron and density porosity devices. What physico-chemical properties of the clay minerals present in the sandstone formation of interest may influence the formation evaluation and why? Give an example in each case.

(4)

A2.The porosity measured in a formation is dependent upon the physical properties of the rock fabric making up the formation. Detail the principal controls on porosity (3)

In the same formation, detail how porosity and permeability might be affected by the presence of fractures.

(3)

A3. The minerals that make up reservoir rocks give off Natural Gamma radiation. What are the three radioisotopes that we commonly detect using the spectral gamma method?

(3)

What minerals may be principally responsible for these responses? Name two of the commonest sources of radiation of each spectral type.

(3)

A4. Array Acoustic or Sonic tools can capture the full-waveforms of compressional, shear and Stoneley arrivals. What are the three principal uses of these waveform data?

(3)

A5. The invasion of the drilling fluid into the formation results in a fluid distribution profile when we log a well. Sketch the resultant resistivity profile in terms of its distance away from the well bore, and show the relative resistivity of deep, medium and shallow investigation logs, when run in the following fluids:

Fresh mud, Salt-water zone. Salty mud, Hydrocarbon zone

(4)

A6.Given:

Rw = 0.04 ohm-m at FTRt = 27 ohm-m at FT in the zone of interest∆t = 84 µsec/ft in the zone of interestρb = 2.31 g/cm3

ρma = 2.67 g/cm3

ρf = 1.00 g/cm3

In a sandstone matrix, with an acoustic velocity of 5400 ft/sec in the fluid and 18,000 ft/sec in the matrix, calculate porosity using the two weighted average equations provided, one for density one for acoustics, (Wyllie).

φ ρ ρρ ρ

φ

t tt t

ma b

ma f

log ma

f ma

= −−

=−

−∆ ∆

∆ ∆

(4)

continued

22/10/13

A6. continuedIs the value for porosity about the same for both the density and acoustic models?

Using the calculated density porosity, calculate fluid saturation from the Archie relationship where ‘a’ = 1.37, ‘m’ = 1.80 and ‘n’ = 1.65. If the critical Sw is 45% is this zone hydrocarbon productive? (4)

Sw a Rw

Rtmn= ⋅ ⋅φ

1

(1)

A7. We have drilled a well into an apparent water bearing formation of moderate porosity. The drilling fluid is fresh water based and an SP run shows a deflection of -71 millivolts (i.e. to the left). Rmf is 0.55 ohm.m at the formation temperature of 140°F. Determine the Rw of the formation from the relationships:

SSP T F RmfeqRweq

Rmfeq Rmf

Rw Rweq

Rweqor chart SP

T F

T F

= − + ⋅ °

= ×

= − + ×

− +

°

−

°

( . ) log( )

.

.

.

log( / . )

.log( / . )

61 0 133

0 85

0 131 10

0 5 102

119 9

2

0 042650 8

Use Chart Gen-9 to determine the NaC1 equivalent ppm

(5)

Now propose the most appropriate logging tool suite for this well to obtain lithology, porosity and formation fluid saturations. Minimise cost while maximising information. Justify your choice.

(5)

A8.The T2 response of the NMR log has been correlated with what aspect of the pore space? What use would you make of NMR data in an appraisal well?

(5)

(Enclosures: Gen-9 and SP-2)

22/10/13

22/10/13

Course:- 28117 Class:- 289FEHERIOT WATT UNIVERSITYDEPARTMENT OF PETROLEUM ENGINEERING

Examination for the Degree ofMeng in Petroleum Engineering

Formation Evaluation Section B

Monday 7th January 200212.30 - 14.30

NOTES FOR CANDIDATES

1. This is a Open Book Examination.

2. 15 minutes reading time is provided from 12.15 – 12.30.

3. Examination Papers will be marked anonymously. See separate instruction for completion of Script Book front covers and attachment of loose pages. Do not write your name on any loose pages which are submitted as part of your answer.

4. Attempt ALL Questions. Answer in the blue books provided.

5. Return all logs with your Answer Books.

6. Marks for each Question are given in brackets.

7. This examination represents 100% of the Class assessment.

8. State clearly any assumptions used and intermediate calculations made in numerical questions. No marks can be given for an incorrect answer if the method of calculation is not presented. When the result is obtained using a chart book figure, give the number of the figure (eg, Rint-2a, CP-18, Gen-7).

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Section B

This Section deals with a suite of down-hole logs, attached. The information you re-quire is as follows:

You have a suite of logs comprising, CALI (Caliper in inches), GAPI (Gamma ray), SONI (Sonic/acoustic), DENS (Bulk Density), CNL (Neutron Porosity), LL9S (Later-olog Shallow), LL9D (Laterolog Deep), RXO (Flushed zone - shallow resistivity)

The bit-size is 8.5 inches and the mud is water-based. The zones of interest are from 11,430 - 12,190 feet. The Bottom Hole temperature at 12,924 ft is 240˚ F,Mean surface temperature is 60(F Mud properties are:Mud Density is 11.0 ppg,Rm = 0.248 ohm.m @60˚ FRmf = 0.159 ohm.m @60˚ FRmc = 0.355 ohm.m @60˚ F

B9Zone the log putting the zone boundaries in track 1. Indicate:

(a) The possible/probable lithology and,(b) Where permeable, the potential/probable fluid contents. Mark a maximum of 5 zones, including shales and hand this log back with your answer book.

(15)

B10 Determine the probable lithology within the intervals 11,410; 11,510,11,655 and 12,165 feet by plotting 1 data point per depth on both a Neutron-Density cross-plot and a M&N Plot. (Blank plots attached)

If any ambiguity is seen, suggest potential causes and at least one solution.

(25)

B11 Determine the appropriate Rw at 12,165 feet using simplified Archie’s equation, Humble formula and Tornado chart’. Determine a neutron-density porosity. Highlight any possible sources of error (3)

B12 Determine the invasion profile and Rt from the attached Tornado chart and the resistivity profile between 11,590 and 11,600 feet.

(5)

B13 Determine the Gamma ray shale index (IGR ) at 11,890, using a “clean” value at 12,180 feet and your choice of the most appropriate maximum shale value on the log. What implications does this have for the choice of water saturation equation and the calculation of Rw from Rwa?

(5)

(Enclosures: Logs, 2 pages, N - D X-plot template, M & N Plot template, and tornado chart, also Gen-9 and SP-2)

Page 1 of 2

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22/10/13

Gamma Ray (GR)0 150 (GAPI)

Caliper (CALI)6 1 6 (in)

M. D

EPTH (ft)

11450

11500

11550

11600

11650

11700

11750

SONI140 40 (us/f)

Compensated Neutron Log (CNL)45 -15 (%)

DENS1.95 2.95 (g/cc)

LL9S0.2 2000 (ohmm)

LL9D0.2 2000 (ohmm)

Flushed zone resistivity (RX0)0.2 2000 (ohmm)

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11800

11850

11900

11950

12000

12050

12100

12150

12200

Model Solutions to Examination

1

Date:

1. Complete the sections above but do not seal until the examination is finished.

2. Insert in box on right the numbers of the questions attempted.

3. Start each question on a new page.

4. Rough working should be confined to left hand pages.

5. This book must be handed in entire with the top corner sealed.

6. Additional books must bear the name of the candidate, be sealed and be affixed to the first book by means of a tag provided

Subject:

INSTRUCTIONS TO CANDIDATES

8 Pages

PLEASE READ EXAMINATION REGULATIONS ON BACK COVER

No. Mk.

NAM

E:REGISTRATION N

O.:

COURSE:Y

EAR:SIGNATURE:Complete this section but do not

seal until the examination

is finished

FORMATION EVALUATION

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2


A1.

a. Clays have a wide range of densities (2.2 - 2.65 g/cc). Presence of

clay in the pores of a sandstone could therefore result in

misinterpretation of the matrix density and therefore the porosity of

the sandstone.

b. The bound water and OH groups on clay minerals will result in an

overestimation of porosity when using the neutron log.

c. Bound water will also have an effect on resistivity measurements.

d. The electrostatic charges on the surface of clay minerals present in

the sandstone affects the conductivity of the sandstone and

therefore the resistivity. Smectites will have the greatest effect,

withIlliteandfinallyKaolinitehavingthelowesteffect.

A2.

a. The principal controls on porosity of a formation depend on the type

of porosity: intergranular porosity and/or secondary porosity. The

intergranular porosity of a granular rock such as sandstone is a

function of stacking and sorting of the rock grains. The denser the

packing the lower the porosity. Stacking can result in porosities of

between 47.6% (for particles of the same size stacked on top of each

other to 25.9% for particles of the same size with the particles

sitting in troughs between layers. A variety in size (poorly sorted) and

shape of particles will result in a reduction of porosity.

Secondary porosity is caused by dissolving of limestone or dolomite

causing vugs and caverns. Fracturing also creates secondary porosity.


3

b. Permeability is heavily dependant on fracture aperature and density.

The denser the fracture population the greater the permeability.

Porosity is rarely affected by fractures since the fractures generally

contributes less than 1% to the porosity.

A3.

a. ThesourcesofGammaradiationare:PotassiumK40, Uranium U238,

and Thorium Th232

b. K40 is present in illitic shales and clays, feldspar and micas

U238 is present in phosphates and uranium salts

Th232 is present in phosphates and shales

A4.

a. Compressional wave velocities provide porosity information

b. Shear and compressional wave velocity waves are used to calculate the

mechanical properties of rocks such as Poissons ratio for sand control

and borehole stability in drilling

c. Stonley waves are used to predict permeability and the presence of

open fractures.

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A5.

a.

D M SSalt

Fresh MudFresh MudSystem

Resi

stiv

ity,

R

Salt MudSystem

Resi

stiv

ity,

R

WaterZone

R*

S M DR*

R0

Rwincreasing

RtSo

Rx0

Rx0

A6.

a. The density method:

φ = maρ − bρ

maρ − fρ

φ = 2.67 − 2.312.67 − 1.0

= 0.216

b. The Acoustic method:

φ = Logt − mat

ft − mat

φ = 84 − 55.56185.2 − 55.56

= 0.219


5

The values from the two techniques are similar. The differences could

beduetoerrorsinassumedfluidandmatrixdensitiesandtravel

times. The difference could also be due to dispersed clays in the pore

space affecting the log readings.

c. The saturation of the rock is given by:

wS =a

mϕn ⋅ wR ⋅

1tR

wS =1.37

1.850.216⋅ 0.04 ⋅

127

1.65 Therefore:

wS =a

mϕn ⋅ wR ⋅

1tR

wS =1.37

1.850.216⋅ 0.04 ⋅

127

1.65

Sw = 0.124

The saturation is 12.4%. This is less than the critical saturation of

45% and therefore the zone will be productive.

A7.

a. The Rw is determined from the following:

Since Rmfeq = Rmf x 0.85

= 0.55 x 0.85

= 0.468 ohm.m

SSP = -71 = (61 + 0.133 x 140) log(0.468/Rweq)

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6


Rweq = 0.468/1071/79.62 = 0.468/7.79 = 0.06 ohm.m

From SP-2:

Rweq = 0.06 => Rw = 0.075

b. The logging suite would be:

Spectral GR - for basic correlation

- identify anomalous high GR zones which are not shale

-aidlithologyidentification

Neutron Density - for lithology and porosity information

- also Pe log from density for lithology

Induction log – When Rmf / Rw exceeds 2.5 and Rw is below 1 ohm.m

then an induction log should be used in place of a laterolog. Since Rmf /


7

Rw is around 7.5 (See graphic opposite) we run the induction log for Rt

determination.

SonicLog -Lithologyidentification

- help characterise porosity type

- An Array sonic can be used for fracture

identification.VpandVsdatacanbeusefulfor

rock mechanics studies.

A8.

a. The T2 response is a function of the pore size distribution and can

therefore be correlated to permeability.

TheNMRmeasuresthefluidfilledporosity.HowevertheNMRcan

resolve the bound or capillary trapped water saturation from the

moveable water saturation.

In an appraisal well a correlated permeability can be coupled with the

BVFtogivelikelyfluidproductionandpotentialrates.

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8


B9.

a. The following zones can be seen on the log (See log):

Zone Depth

1 11400 - 11468 Limestone2 11468 - 11542 Shaley sandstone, possibly gas bearing

possibly oil bearing

3 11542 - 12115 Shaley sandstoneGas bearing down to GWC at 12115

4 11930 - 1215 Shaley sandstone

5 12115 - Shaley sandstone

Depth ρb φ n t M N

1 11410 2.60 0.04 57 0.83 0.602 11510 2.18 0.23 91 0.83 0.653 11655 2.15 0.22 94 0.83 0.684 12165 2.20 0.235 85 0.87 0.64

Depth ρb - φ n M-N

1 11410 Low φ Sandstone Limestone2 11510 Sandstone Low φ Sandstone3 11655 Sandstone with gas High φ sandstone4 12165 Sandstone Ambiguous – Sandstone but

with secondary porosity

Point

Point

B10.

a.

Zone Depth

1 11400 - 11468 Limestone2 11468 - 11542 Shaley sandstone, possibly gas bearing

possibly oil bearing

3 11542 - 12115 Shaley sandstoneGas bearing down to GWC at 12115

4 11930 - 1215 Shaley sandstone

5 12115 - Shaley sandstone

Depth ρb φ n t M N

1 11410 2.60 0.04 57 0.83 0.602 11510 2.18 0.23 91 0.83 0.653 11655 2.15 0.22 94 0.83 0.684 12165 2.20 0.235 85 0.87 0.64

Depth ρb - φ n M-N

1 11410 Low φ Sandstone Limestone2 11510 Sandstone Low φ Sandstone3 11655 Sandstone with gas High φ sandstone4 12165 Sandstone Ambiguous – Sandstone but

with secondary porosity

Point

Point


9

b. Ambiguities:

11655 - N-D plot shows gas indications but M-N does not. Gas is

supported by resistivity separation

12165 - N-D indicates sandstone, M-N plot is ambiguous.

It is possible that the shale and gas effect are affecting the

interpretation.

B11.

a. The Humble Equation is:

F = 0.62

φ2.15

or,

F = 0.81

φ2

At 12165 :

Neutron - Density cross plot gives a porosity of φ = 0.275

Hence,

F =

0.620.2752.15 = 9.95

or

F = 0.81

φ2 = 10.7

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10


Since,

Rxo = 0.71

RLLS = 0.31

RLLD = 0.31

Hence,

RLLD /RLLS = 1 (implies no invasion correction)

RLLD/RXO = 0.44

From Rint-9b

Rt / RXO = 0.41

Therefore,

Rt = 0.291 (Approximately equal to RLLD)

Simplifiedarchie’sequationin100%SwzoneRw = Rt /F

Therefore,

Rw = 0.291/9.95 = 0.030

or

Rw = 0.291/10.7 = 0.027


11

B12.

Since,

Rxo = 2.5

RLLS = 17

RLLD = 45

RLLD /RLLS = 2.65

RLLD/RXO = 18

From Rint-9b

Rt / RLLD = 1.35

Therefore,

Rt = 60.75 ohm.m

di = 38 inches

38 inches

60

Resistivity

Rx0 = 2.5

Rt

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12


B13.

a. Itisdifficulttoidentifyamaximumshalevalue:

The biggest shale peak is at 11543. This is 112 GAPI

Hence this will be used :

GR @ 11890 = 80

GRsand = 52

GRshale = 112

GRI = GR − sandGRshaleGR − sandGR

GRI = 80 − 52112 − 52

= 0.53

Hence the volume of shale at 11890 using the “Older Rocks” model

is approx. 38%.


13

The whole interval below 11468 is very shaley. The m and a assumed

for the Rwa equation assumes a clean sand. The value of m will

decrease in a shaley sand due to the conductivity of the shale, and

the value of Rwa calculated represents a minimum

To correct for the shales, one of the shale saturation equations may

be needed.

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14


3

LightOil


15

5

Oil

Water

Boundaryb/w lightto relativelyheavy oil

OWC

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16



17

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Tutorial


22/10/13

2

Depth (ft.)

11840

11820

11800

11860

11880

11900

A

LOG SECTION

B

C


Tutorial

Formation Evaluation – Example of Section B Exam

You have a section which shows results from a suite of downhole logs which include CALI (Caliper in inches), GAPI (Gamma Ray in API), ILM and ILD (Medium and Deep Induction Resistivity in ohm-metres), PEF (Photoelectric Factor in barns per electron), RHOB (Bulk Density in g/cc), NPHI (Neutron Porosity, fraction), and DT (Long Spaced Sonic in sec/ft).

Answer the following questions related to the log section. Remember you will need to show your methodology. You will need to refer to certain charts (as indicated), which you will have in your notes.

(1) Zone the section into probable / possible lithologies. Indicate the hydrocarbon bearing zones.

(2) Calculate the density porosity at depths A, B, and C (using the bulk density log results). Use an appropriate matrix density for your chosen lithology, and use a fluid density of 1.00 g/cc. (3) Determine the acoustic porosity at depths A, B and C using the sonic log DTLN (Delta-T Long Spacing Near). Use the Empirical equation from Chart Por-3 for your chosen lithology.

(4) Determine M and N at depths A, B, and C using the data from the porosity logs, and plot the results on an M-N plot (Chart CP-8; also look at the simplified plot in your notes). Use a fluid transit time of 189 sec/ft, and a fluid neutron porosity of 1.

(5) Calculate the water saturation at depths A, B and C. Do this by using the Humble formula together with the density porosity to calculate the formation resistivity factor F. Obtain Rt , the true formation resistivity, from the ILD log (deep induction), and assume the values given on the log are corrected for invasion, borehole, bed thickness etc. Note that the scale for the ILD log at these depths runs from 20-2000 ohm-m.

Also assume n=2, and Rw the resistivity of the formation water is 0.045 ohm-m.

222/10/13

4


3-3

Por


(English)

30 40 50 60 70 80 90 100 110 120 130

t, interval transit time ( µsec/ft)

vf = 5300 ft/sec

50

40

30

20

10

0

50

40

30

20

10

0

φ, p

oros

ity (p

.u.)

φ, p

oros

ity (p

.u.)


1.1

1.2

1.3

1.4

1.5

1.6

Dolomite

Calcite

(limestone)

Quartzsandstone

26,000

23,000

21,000

18,000

19,500

vma(ft/sec)

B cp

© Schlumberger

These two charts (Por-3) convert sonic log interval transit time,t, into porosity, φ. Two sets of curves are shown. The blue setemploys a weighted-average transform. The red set is based onempirical observation (see Reference 20). For both, the saturat-ing uid is assumed to be water with a velocity of 5300 ft/sec(1615 m/sec).




3


Tutorial

422/10/13

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Formation Evaluation – Example of Section B Exam Solutions

(1) Main zonations :

• Relatively clean quartz sandstone units at approximate depths 11804 – 11833 ft, 11845 – 11869 ft (with possibly a short muddy sand interval at 11855 – 11857 ft), 11877 – 11879 ft.

• Main muddy sand units at approximate depths 11833 – 11841 ft, 11869 – 11880 ft, 11879 – 11880 ft.

• Shale units at approximate depths 11790 – 11804 ft and 11880 – 11910 ft.

• Cemented zone at approximate depths 11841 – 11845 ft, and also some possible partially cemented zones at approximate depths 11817 – 11819 ft, 11822 – 11825 ft and 11873 – 11877 ft.

The main hydrocarbon bearing zones are between the following approximate depths: 11804 – 11841 ft, 11845 – 11869 ft, 11877 – 11880 ft.

(2) Density Porosity = (ρma – ρb) / (ρma – ρf)

If we make the assumption that the lithology is relatively clean quartz sandstone in each case (in reality at depth B we have a slightly muddy sand) so that the matrix density ρma is about 2.65 then:

Depth A: Porosity = (2.65 – 2.39) / (2.65 – 1.00) = 0.158 or 15.8 %

Depth B: Porosity = (2.65 – 2.36) / (2.65 – 1.00) = 0.176 or 17.6 %

Depth C: Porosity = (2.65 – 2.43) / (2.65 – 1.00) = 0.133 or 13.3 %

(3) Assuming again that the lithology is clean quartz sandstone, the Empirical equation (using Chart Por-3) gives acoustic porosities of:

Depth A: 13.5 % Depth B: 17.8 % Depth C: 12.0 %

(4) M = 0.01 [(tf – t) / (ρb - ρf)]

Depth A: M = 0.01[(189 – 70) / (2.39 – 1)] = 0.856Depth B: M = 0.01[(189 – 75) / (2.36 – 1)] = 0.838Depth C: M = 0.01[(189 – 68) / (2.43 – 1)] = 0.846

N = (ϕNf – ϕN ) / (ρb – ρf)

5


Tutorial

Depth A: N = (1 – 0.12) / (2.39 – 1) = 0.633 Depth B: N = (1 – 0.15) / (2.36 – 1) = 0.625 Depth C: N = (1 – 0.08) / (2.43 – 1) = 0.643

(5) Formation factor F (using the Humble formula) = 0.62 /ϕ 2.15

Depth A: F = 0.62 / 0.1582.15 = 32.98 Depth B: F = 0.62 / 0.1762.15 = 26.05 Depth C: F = 0.62 / 0.1332.15 = 47.33

Sw = √ [ (F Rw ) / (Rt) ] assuming the saturation exponent n = 2

Depth A: Sw = √ [ (32.98 x 0.045) / (100) ] = 0.122 or 12.2 % Depth B: Sw = √ [ (26.05 x 0.045) / (24) ] = 0.221 or 22.1 % Depth C: Sw = √ [ (47.33 x 0.045) / (300) ] = 0.084 or 8.4 %

622/10/13

Form Eval Complete 2013 14

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Transcript of Form Eval Complete 2013 14