Hydrocarbon identification andanalysis using NMR

Advanced FluidCharacterization

Applications■ Determination of fluid storage

volume based on lithology-independent total porosity

■ Quantification of pay based onoil, gas and water saturation

■ Oil mobility determinationbased on in-situ oil viscosity

■ Producibility calculationusing hydrocarbon-correctedbound-water volume and permeability

■ Oil viscosity versus depthmapping for perforation andcompletion design

■ Direct hydrocarbon detection● Fresh, unknown or varying

formation water resistivities● Low-resistivity, low-contrast

pay and thin beds

■ Residual oil saturation inwater-based muds

■ Residual water saturation in oil-based muds

■ Mobility calibration for MDT* Modular FormationDynamics Tester

Benefits■ Improved reserves estimates

and increased reserves fromlocation of bypassed pay

■ Optimized well completions

■ Worldwide availability using any standard CMR*Combinable MagneticResonance tool

■ Real-time answers from automated wellsite inversion

■ Independent analysis with-out need for resistivity meas-urements, R

wor Archie

parameters

Features■ Automated 3-min acquisition

integrated with wellsite inversion

■ Constituent Viscosity Model(CVM) based on fundamentalphysics

■ Measurement withoutradioactive source

What is the MRF method?The MRF* Magnetic Resonance Fluidcharacterization method is a patentedtechnique for direct identification andanalysis of hydrocarbons. The stationlog measurement can be made usingany CMR tool; special tools or modifi-cations are not necessary. A modifiedCMR-Plus* tool is required for the fast3-min data acquisition.

The MRF technique integrates down-hole data acquisition and wellsite inver-sion with a multifluid response modelto determine fluid saturations, fluidvolumes and oil viscosities. Lithology-independent formation porosity andseparate T2 distributions for brine andoil are also extracted. Hydrocarbon-corrected bound-water volume andpermeability are computed from theT2 distributions. This real-time analysisimproves prediction of the well’s pro-ducing capability and is vital for com-pletion decisions.

When is an MRF analysis needed?Viscosity, like permeability, greatlyinfluences a well’s producing capabil-ity. Viscosity can vary by orders of mag-nitude, and in many parts of the worldit determines zonal production ratesto a much greater extent than forma-tion permeability. When hydrocarbonviscosity is varying or unknown, theMRF method can provide the answersyou need.

MRF technology can also providesolutions in fresh or varying formationwaters, where Archie resistivity analy-sis is difficult. Using direct hydrocar-bon characterization, pay intervals canbe identified even in zones with lowresistivity. The MRF method can over-come problems associated with Archieanalysis, such as varying cementationexponent; dipping, thin or laminatedbeds that affect resistivity tools andunknown or varying water resistivity.This method also overcomes incorrectpermeability calculations caused byhydrocarbon effects.

0.09

0.08

0.07

0.06

0.05

0.04

0.03

0.02

0.01

0

T2 relaxation time (ms)

Signalamplitude

0.1 1.0 10 100 1,000 10,000

Water T2 distribution

Water T2 log mean

Oil T2 distribution

Oil T2 log mean

Figure 1. Example of real-time MRF analysis performed at the wellsite. The direct, user-friendly analysis provides a comprehensive formation evaluation of the near-wellbore region and includes quality control indicators.

Water porosity (%): 17.0 Oil porosity (%): 14.3 Gas porosity (%): 0.0 OBMF porosity (%): 0.0Water saturation (%): 54.3 Oil saturation (%): 45.7 Gas saturation (%): 0.0 OBMF saturation (%): 0.0Water T2LM (ms): 48.8 Oil T2LM (ms): 180 Oil viscosity (cp): 6.6 TCMR porosity (%): 31.3Free water φ (%): 14.9 Bound water φ (%): 2.1 T1/T2 ratio: 1.243 Permeability (mD): 1652.4Temperature (°C): 24.6

How does the MRF analysis work?Small or light-end hydrocarbon mole-cules move at rapid rotational andtranslational velocities as a result ofthermally induced Brownian motion.Figure 2 shows this concept at themicroscopic level. At the macroscopiclevel, the long distances small mole-cules can travel in a given time areobserved as a high molecular diffusioncoefficient. Fast molecular motionsresult in low fluid viscosity. As a resultof the low viscosity, small moleculeshave long T2 decay times.

Large molecules have small rota-tional and translational velocities andtherefore move shorter distancesthrough the fluid. This slow molecularmotion results in a low diffusion coef-ficient for the fluid and a high viscosityvalue. As a result of the high viscosity,large molecules have short T2 times.

A pure fluid composed of a singlemolecular species has a single diffusioncoefficient value, a single viscosityvalue and a single value for its T2decay. The fluid can be represented as a narrow peak in the T2 and diffusion spectra.

A mixture containing both small-and large-molecule fluids exhibits one T2 value for the small moleculesand another for the large molecules.However, individual T2 values in themixture differ from those of the con-stituent pure fluids. The same resultoccurs with the diffusion rates. Com-ponents in the mixture retain theirseparate identities while their individ-ual properties are modified. Crude oilsare a complex mixture of many differ-ent hydrocarbon species with a broadrange of molecular sizes. The CVMrelates the T2 and diffusion propertiesof mixtures to molecular composition.Based on fundamental physics, theCVM properly accounts for the broaddiffusivity and T2 spectra of bulk crudeoils. The CVM has been empirically validated for both live and dead crude oils.

Constituent viscosity is a phenome-nological link between the T2 relax-ation and the diffusion coefficient of each molecular species in a hydro-carbon mixture. The bulk viscosityobserved with a viscometer reflectsthe broad distribution of microscopicor constituent viscosities.

Amplitude

Large hydrocarbon molecule slow rotation leads to slow diffusion

Small hydrocarbon molecule fast rotation leads to fast diffusion

10–6 10–5 10–4

Diffusivity (cm2/s)

Pure C6

Mixture of C6and C30

Pure C30

Figure 2. Small or light-end member molecules move quickly; heavier long-chain molecules movemore slowly. Hydrocarbon molecule relaxation rates and diffusion coefficients are related to the molecule size. With their wide range of molecular sizes, crude oils have a broad distribution ofnuclear magnetic resonance (NMR) relaxation times and molecular diffusion coefficients. TheConstituent Viscosity Model (CVM) relates molecular diffusivity and T2 relaxation of the individualcomponents to bulk viscosity.

The CVM predicts an inverse rela-tionship between the geometric meanof the bulk oil T2 distribution and thebulk oil viscosity. This relationshiphas long been observed in laboratorydata (Fig. 3).

Pore size information is availablefrom T2 distributions measured in waterzones. Brine T2 distributions are broadas a result of the range of pore sizesfound in reservoir rocks. In an oilzone, the brine distribution typicallyoverlaps with the broad T2 distributionof the oil to form the total T2 distribu-tion seen on a standard log (right sideof Fig. 4). This overlap often makesstandard T2 interpretation difficultbecause the contributions of waterand hydrocarbon are indistinguishable.Pore size information is mixed withhydrocarbon viscosity information.Largely because of this overlap of oiland water T2 distributions, previoushydrocarbon detection techniqueshave not been reliable.

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1

0.1

0.01

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0.00010.1 1.0 10 100 1,000 10,000 100,000

Viscosity (cp)

T2 (s)

Light oilAPI: 45–60Density ~ 0.65–0.75 g/cc

Medium oilAPI: 25–40Density ~ 0.75–0.85 g/cc

Heavy oilAPI: 10–20Density ~ 0.85–0.95 g/cc

Figure 3. For bulk crude oils, an inverse relationship exists between the geometric mean of the T2 distribution and the viscosity.

Brine T2 Distributions Oil T2 Distributions Total Distribution

Pore size

Clay-bound waterCapillary-bound waterFree water

TarHeavy oilIntermediate oilLight oil

Tar plus clay-bound waterHeavy oil plus capillary bound waterIntermediate oil plus free waterLight oil plus free water

Constituent viscosity

+ =

Figure 4. In a formation with no hydrocarbons, brine-filled porosity produces T2 distributions representative of pore-size distributionswith associated bound and free fluids (left). The broad T2 distribution of a typical bulk crude is shown in the center. Because the rockis not present, the bulk crude oil T2 distribution is a function of molecular composition only. In a typical T2 log, the addition of the twodistributions results in a mixed response that can be difficult to interpret (right).

The MRF method incorporates thefundamental physical principles of theCVM and a multifluid inversion algo-rithm to reliably extract oil and watersignals from NMR data. To achieve thisseparation, the MRF method exploitsmolecular diffusion in the field gradi-ent generated by the tool magnet. Thisprocess leads to an additional NMRdecay proportional to the square ofthe echo spacing and to the diffusionconstant of each fluid component gov-erned by the simple equation shownin Fig. 5.

Because water molecules are typi-cally smaller and more mobile thanthe hydrocarbon molecules in crudeoils, the water signal decays fasterthan the oil signal for long-echo spac-ings. By inverting a specially designedsuite of NMR measurements with dif-ferent echo spacings, the MRF methodseparates brine and oil signals evenwhen the T2 distributions completelyoverlap. After separation, the individ-ual T2 distributions are used to com-pute the volumes of water, gas andoil. Oil viscosity and hydrocarbon-corrected bound-fluid volume are calculated. In addition to providingdirect and resistivity-independent saturations and volumes, the T2 distri-bution of reservoir oil derived duringthe MRF inversion helps in interpret-ing the CMR depth log. X655 m

X700 mAmplitude

X708 m

0.3 10 100T2 (ms)

1000

45 cp

44 cp

86 cp

Brine and Oil T2 Distributions

Molecular Diffusion in Field Gradient

Water Oil

Echo spacing = TE1

TE2

TE3

1122

2 2

TG TE

D= ( )D γ

Figure 5. Schematic of the MRF data suite and simultaneous inversion to extract brine and oil volumes,oil viscosity, and T2 distributions. The equation describes the decay time of measured NMR signals( T2D) caused by molecular diffusion (D) in the tool gradient (G). The diffusion decay increases withincreasing echo spacing ( TE).

In what range of viscosities will the MRF method work?The MRF method works in viscositiesfrom less than 1 cp to more than 200 cp(Fig. 6). For viscosities below thisrange, the DMR* Density-MagneticResonance method should be usedbecause hydrocarbons that are verylight (such as gas and condensate)result in porosity deficits. Above 200 cpthere is a lack of diffusion sensitivity.The shape of the T2 distribution mustbe analyzed using the CMR-Plusenhanced precision mode (EPM).

For the highest viscosities, hydrocar-bons become invisible to NMR tools,which measure fluid only. The DMRmethod can be used to quantify tarcontent.

Has the method been tested?Schlumberger has validated the MRFmethod in the laboratory using a broadrange of live and dead crude oils androck types. Its reliability and range ofapplications have been confirmed byextensive worldwide field tests indiverse environments.

Where is the MRF method available?Advanced fluid characterization usingthe MRF method is available world-wide. Any CMR tool can be used fordata acquisition; specially equippedtools or modifications are not neces-sary. To achieve the fast 3-min stationlog measurement and perform the real-time wellsite inversion, a modifiedCMR-Plus tool and special softwarekit are required.

Low-MRF Sensitivity Low-MRFSensitivityMRF-Sensitive Regime

DMR DMREPM

Viscosity (cp)

100,000 10,000 1,000 100 10 1 0.1

100 cp10 cp

2 cp

0.5 cp

Transverse relaxation time T2 (ms)

0.1 1 10 100 1,000 10,000

1000 cp

MRF

Figure 6. The MRF method works within the range of approximately 1 to 200 cp. Outside this range, the indicated method should be used.

CMR-Plus Tool Specifications

Physical specificationsLength 15.6 ftWeight 413 lbmMeasure point 23 in. above bottom of toolMin hole size 57⁄8 in.Max hole size No limitMax tension limit 50,000 lbfMax compression limit 50,000 lbf

Operational ratingsMax pressure 20,000 psi (25,000 psi with modified tools)Max temperature 350°FMud type and salinity Unlimited

Measurement specificationsMax logging speed

Long T1 environment 800 ft/hrShort T1 environment 2700 ft/hrBound fluid mode 3600 ft/hr

Vertical resolutionStatic 6-in. measurement apertureDynamic (high-resolution mode) 9 in., three-level averagingDynamic (standard mode)) 24 in., three-level averaging

Min echo spacing 0.2 msMeasurement range

Porosity 0–100 p.u.T2 distribution 0.3 ms–3.0 s

PrecisionTotal CMR porosity 1-p.u. standard deviation, three-level averaging at 75°FCMR free-fluid porosity 0.5-p.u. standard deviation, three-level averaging at 75°F

Depth of investigationAll hole sizes 0.5-in. blind zone

1.1-in. 50% point1.5-in. 95% point

SMP-5905 ©Schlumberger

September 2002 *Mark of Schlumberger

www.connect.slb.com