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34 Oilfield Review

David AllenSteve CraryBob FreedmanSugar Land, Texas, USA

Marc Andreani

Werner KlopfMilan, Italy

Rob BadryCalgary, Alberta, Canada

Charles FlaumBill KenyonRobert KleinbergRidgefield, Connecticut, USA

Patrizio GossenbergAgip S.p.A.Milan, Italy

Jack HorkowitzDale LoganMidland, Texas, USA

Julian SingerCaracas, Venezuela

Jim WhiteAberdeen, Scotland

For help in preparation of this article, thanks to GregGubelin, Schlumberger Wireline & Testing, Sugar Land,Texas, USA; Michael Herron, Schlumberger-DollResearch, Ridgefield, Connecticut, USA; James J.Howard, Phillips Petroleum Research, Bartlesville,Oklahoma, USA; Jack LaVigne, Schlumberger Wireline& Testing, Houston, Texas; Stuart Murchie and Kambiz A.Safinya, Schlumberger Wireline & Testing, Montrouge,France; Carlos E. Ollier, Schlumberger Wireline & Test-

ing, Buenos Aires, Argentina; and Gordon Pirie, Consul-tation Services, Inc., Houston, Texas.

AIT (Array Induction Imager Tool), APT (Accelerator Poros-ity Tool), CMR and CMR-200 (Combinable Magnetic Res-onance), ELAN (Elemental Log Analysis), ECS (ElementalCapture Spectrometer for geochemical logging), EPT(Electromagnetic Propagation Tool), Litho-Density, MAXIS(Multitask Acquisition and Imaging System), MDT (Modu-lar Formation Dynamics Tester), MicroSFL, RFT (RepeatFormation Tester Tool) and PLATFORM EXPRESS are marks ofSchlumberger. MRIL (Magnetic Resonance Imager Log) isa mark of NUMAR Corporation.

Nuclear Magnetic Resonance (NMR) log-ging is creating excitement in the well log-

ging community. Within the last year, twoissues ofThe Log Analyst were devotedexclusively to NMR.1 The Oilfield Reviewpublished a comprehensive article explain-ing borehole NMR technology less thantwo years ago.2 Recently, many specialworkshops and conference sessions onNMR have been held by professional log-ging societies. Today, Internet Web sitesprovide current information on NMR log-ging advances.3

Why all the excitement? The reasons areclear. First, the tools used to make high-quality borehole NMR measurements have

improved significantly. The quality of mea-surements made in the field is approachingthat of laboratory instruments. Second, thesemeasurements tell petrophysicists, reservoirengineers and geologists what they need toknowthe fluid type and content in thewell. The measurements also provide easy-to-use ways to identify hydrocarbons andpredict their producibility. Finally, despite

How to Use BoreholeNuclear Magnetic Resonance

It is a rare event when a fundamentally new petrophysical logging

measurement becomes routinely available. Recent

developments in nuclear magnetic resonance

measurement technology have widened the

scope of formation fluid characterization. One

of the most significant innovations provides

new insight into reservoir fluids by

partitioning porosity into fractions

classed by mobility.

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the mysterious nature of the NMR tech-nique, the measurement principles are rela-

tively easy to understand.Important advances have been made in

applying NMR measurements to detectingand differentiating all formation fluids, suchas free water and bound water, as well as dif-ferentiating gas from oil in hydrocarbon-bearing reservoirs. In this article, we reviewthe improvements in tool technology thatallow todays tools to measure differentporosity components in the formation (seeWhat is Sandstone Porosity, and How Is ItMeasured?, page 36).Then, we evaluate thenew, high-speed, cost-effective ways NMRcan be used with conventional logging mea-

surements to determine critical formationproperties such as bound-water saturationand permeability for predicting production.Finally, we show how NMR measurements,in combination with other logging data, pro-vide a more accurate, quantitative and there-fore profitable understanding of formationsincluding shaly gas sands and those contain-ing viscous oil.

A Rapidly Developing Technology

The first NMR logging measurements were

based on a concept developed by ChevronResearch. Early nuclear magnetic loggingtools used large coils, with strong currents, toproduce a static magnetic field in the forma-tion that polarized the hydrogen nucleiprotonsin water and hydrocarbons.4 Afterquickly switching off the static magneticfield, the polarized nuclei would precess inthe weak, but uniform, magnetic field of theearth. The precessing nuclei produced anexponentially decaying signal in the samecoils used to produce the static magneticfield. The signal was used to compute thefree-fluid index, FFI, that represents the

porosity containing movable fluids.These early tools had some technical defi-

ciencies. First, the sensitive region for reso-nance signal included all of the boreholefluid. This forced the operator to use specialmagnetite-doped mud systems to eliminatethe large borehole background signalan

expensive and time-consuming process. Inaddition, the strong polarizing currents

would saturate the resonance receiver forlong periods of time, up to 20 msec. Thisdiminished the tool sensitivity to fast-decay-ing porosity components, making earlytools sensitive only to the slow free-fluidparts of the relaxation decay signal. Thesetools also consumed huge amounts of

(continued on page 39)

1. The Log Analyst37, no. 6 (November-December,1996); and The Log Analyst38, no. 2 (March-April,1997).

2. Kenyon B, Kleinberg R, Straley C, Gubelin G andMorriss C: Nuclear Magnetic Resonance ImagingTechnology for the 21st Century, Oilfield Review7,no. 3 (Autumn 1995): 19-33.

3. The SPWLA provides an extensive bibliography ofNMR publications developed by Steve Prensky, U.S.Department of Interior Minerals Management Service,located at URL: http://www.spwla.org/, and informa-tion on the Schlumberger CMR tools can be found athttp://www.connect.slb.com.The NUMAR information Web site is located at URL:http://www.numar.com.

4. Early NMR tools did not contain permanent magnetsto polarize the spinning protons.

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36 Oilfield Review

Simply put, porosity is the void space in all rocks

where fluids accumulate. In igneous rocks, this

space is quite small because the crystallization

growth process results in dominant interlocking

grain contacts. Similar arguments can be made for

metamorphic rocks. In contrast,sandstones are

formed by the deposition of discrete particles creat-

ing abundant void space between individual particle

grains.

Obviously, hydrocarbons are found only in porous

formations. These rocks can be formed by the weath-

ering and erosion of large mountains of solid rock,

with the eroded pieces deposited by water and wind

through various processes.As the weathered parti-cles are carried farther from the source, a natural

sorting of particle or grain size occurs (right). Geol-

ogy attempts to study how variations in original

porosity created by different grain packing configura-

tions are altered by post-depositional processes,

whether they be purely mechanical or geochemical,

or some mixture of the two.

During transportation, the smallest weathered par-

ticles of rock, such as fine-grained sands and silts,

get carried the farthest. Other minerals, such as

mica, which is made of sheets of aluminosilicates,

break down quickly through erosion,and are also

carried great distances.These sheet silicates give

rise to clay minerals,which are formed by weather-

ing, transportation and deposition.Clays can also

form in fluid-filled sediments through diagenetic pro-

cesseschemical, such as precipitation induced by

solution changes; or biological, such as by animal

burrows; or physically through compaction,which

leads to dewatering of clays.The final formation

porosity is determined by the volume of space

between the granular material (next page, top).

What Is Sandstone Porosity, and How Is It Measured?

Boulders

Cobbles

Gravel

Sand

Silt

Clay

500

mm

300200

100

50

20

10

5

2

1

0.5

0.2

0.05

0.01

0.005

0.001

0.0001

0.001

0.01

0.1

10.0

Inch

1.0

fine

medium

medium

medium

medium

coarse

coarse

coarse

coarse

very coarse

very coarse

small

large

very fine

very fine

very fine

fine

fine

fine

sHow weathering and transportation cause changes in scale of grain size.The decomposition of large rocks leads tothe development of clastic sedimentary deposits.Water and wind carry the finer grained materials the farthest from theirsource. Many materials that are resistant to water and chemical alteration become sand and silt grains eventuallydeposited in sediments. Other layered-lattice minerals in the original igneous rocks,such as micas and other silicates,become transformed into fine-grained clays through degradation and hydrothermal processes.

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But, all porosity is not equivalent. Clearly, what is

special about NMR is that it not only measures the

volume of the void space, assuming that it is filled

with a hydrogenated fluid, but also allows some infer-

ences to be made about pore size from measurement

of relaxation rates. This is the ability to apportion the

porosity into different components, such as movable

fluids in large pores and bound fluids in small pores.

In sandstone formations, the space surrounding

pores can be occupied by a variety of different min-

eral grains. In the simple case of well-sorted,water-

wet sandstones, water that is adhering to the surface

of the sand grains is tightly bound by surface tension.

Frequently, in these formations,the spaces between

sand grains are filled with clay particles.Water also

attaches itself to the surfaces of clay particles, and

since clays have large surface-to-volume ratios, the

relative volume of clay-bound water is large.This

water will always remain in the formation, and is

known as irreducible water. In pure sands,this is also

known as capillary-bound water.All exposed mineral

surfaces have adsorbed water, which link particle size

with volume of irreducible water.

The NMR measurements tell us two important

things.The echo signal amplitudes depend on the

volume of each fluid component.The decay rate, or

T2 for each component, reflects the rate of relaxation,

which is dominated by relaxation at the grain sur-

face. T2 is determined primarily by the pore surface-

to-volume ratios. Since porosities are not equal

capillary-bound or clay-bound water are not

producible, but free water istwo equal zones of

porosity, but with entirely different producibilitypotential,can be distinguished by their T2 time distri-

butions (left).

Hydrogen nuclei in the thin interlayers of clay

water experience high NMR relaxation rates,

because the water protons are close to grain

surfaces and encounter the surfaces frequently.

Also, if the pore volumes are small enough that the

water is able to diffuse easily back and forth across

the water-filled pore, then the relaxation rates will

simply reflect the surface-to-volume ratio of the

pores. Thus, water in small pores with larger sur-

face-to-volume ratios has fast relaxation rates andtherefore short T2 porosity components (next page,

top left).

Capillary-

boundwater

Sandgrains

Clay-

boundwater

Oil

Freewater

,

,

,

,

,

,

,,

,

, ,

,

,

,

,

, ,

, ,

,

,

,

,

,

,

,

sIntergranular porosity. Thepores between these water-wet sand grains are occupiedby fluids and fine layers ofclay.The irreducible water(dark blue)is held against thesand grains by surface ten-sion and cannot be produced.Clay-bound water (shadeddark blue)is also unpro-ducible. Larger pores cancontain free water (lightblue), and in some casesthere are pockets of oil(green)isolated from thesand grains by capillarywater.The clay particles,andtheir associated clay-boundwater layer,effectively reducethe diameterof the pore throats.Thisreduces the formations abilityto allow fluids to flowper-meability.

T2s

ignal

distribution

T2

signal

distribution

Increasing relaxation time

T2time

T2time

Increasing relaxation time

Low permeability, nonproducerPorosity = 20%Permeability = 8 md

High permeability, producer

Porosity = 19.5%Permeability = 280 md

sGood water and bad water.The amplitude of the NMR T2measurement is directly proportional to porosity, and the decay rateis related to the pore sizes and the fluid type and viscosityin the pore space. Short T2 times generally indicate small pores withlarge surface-to-volume ratios and low permeability,whereas longerT2 times indicate larger pores with higher permeability.Measure-ments were made in two samples with about the sameT2 signal amplitudes, indicating similar porosity, but with consider-ably different relaxation times that clearly identify the sample withthe higher permeability.

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38 Oilfield Review

On the other hand, in large pores with smaller sur-

face-to-volume ratios, it takes longer for the hydro-

gen to diffuse across the pores. This will decrease

the number of encounters with the surface and lower

the relaxation rateleading to a longer T2 compo-

nent in the NMR measurement.Free water, found in

large pores,is not strongly bound to the grain sur-

faces by surface tension. Longer T2 time components

reflect the volume of free fluid in the formation.

Another example of long T2 time fluid components

seen by NMR is the case of oil trapped inside a

strongly water-wet pore (above right). Here the oil

molecules cannot diffuse past the oil-water interface

to gain access to the grain surface. As a result, the

hydrogen nuclei in the oil relax at their bulk oil rate,

which is usually slow depending on the oil viscosity.

This leads to a good separation of the oil and water

signals in NMR T2 distributions.1

Neutron tools have traditionally been used for

porosity measurements. The scattering and slowing

down of fast neutrons in formations lead to the

detection of either thermal or epithermal neutrons,depending on the tool design. Hydrogen has an

extremely large scattering cross section, and

because of its mass,it is particularly effective at

slowing down neutrons.Thus, the response of neu-

tron porosity tools is sensitive to the total hydrogen

concentration of the formation, which leads to their

porosity response (next page, top).

However, there are complications.Small differ-

ences in the other elemental neutron cross sections

lead to changes in the porosity response for different

minerals, called the lithology effect.There is also the

effect of thermal absorbers, especially in shales,

which cause large systematic increases in the poros-

ity response of thermal neutron tools.Fortunately,

epithermal neutron porosity tools,such as the APT

Accelerator Porosity Tool, are immune to this effect.

Finally, because the neutrons cannot discriminate

between hydrogen in the fluids or hydrogen that is

an integral part of the grain structure, neutron tools

respond to the total hydrogen content of the forma-

tion fluids and rocks. Even after all the clay-bound

water and surface water are removed, clay minerals

contain hydroxyls [OH]- in their crystal structures

kaolinite and chlorite contain [OH]8 and illite and

smectite contain [OH]4making them read espe-

cially high to neutron porosity tools.2

Density tools use gamma rays to determine poros-

ity.Gamma ray scattering provides an accurate mea-

surement of the average formation bulk density,and

if the formation grain and fluid densities are assumed

correctly, the total fluid-filled porosity can be accu-

rately determined (see Gas-Corrected Porosity from

Density-Porosity and CMR Measurements, page

54). Usually, one assumes the grain density for

sandstone or limestone and water-filled pores. Errors

occur if the wrong grain density is assumeda

lithology effector the wrong fluid density is

assumed, which occurs with gas-filled pores.

Using Porosity Logs

Comparing one porosity measurement with another

leads to new information about the makeup of the for-

mation.Traditionally, neutron and density-porosity

logs are combined,sometimes by simple averaging.

In many cases, the lithology effects on the neutron

porosity tend to cancel those on the density porosity,

so that the average derived porosity is correct. If there

are only two lithologies in a water or oil filled forma-

tion, then porosity and the fraction of each rock min-

eral can be determined using a crossplot technique. In

gas zones,neutron-derived porosity reads low, if not

zero,whereas density-derived porosity reads slightly

high. This leads to the classic gas crossover signa-

turea useful feature.

NMR T2 distributions provide for fluid discrimina-

tion. Since fluids confined to small pores near sur-

faces have short T2 relaxation times and free fluids in

large pores have large T2 relaxation times,partition-

ing the T2 distributions allows discrimination between

the different fluid components (next page,bottom).

Adding the amplitudes of the observed fluid T2 com-

ponents together gives a total NMR porosity which

usually agrees with the density porosity in water-filled

formations. In gas zones, like the neutron porosity,

sOil in the pore space of a water-wet rock.The lack ofcontact between oil and the rock grain surface allowsthe oil to take its bulk relaxation time, which for low-viscosity oils will generally be longer thanthe shortened water relaxation.

O

B

B

Oxygen Hydrogen Cations Aluminum

A

Interlayerwater

~10

~3 to 5

Silicon

sInterlayer water and hydroxyls in clay structures.Clay minerals are hydrated silicates ofaluminum which are fine grained, less than 0.002 mm.The layers are sheet structures ofeither aluminum atoms octahedrally coordinated with oxygen atoms and hydroxyls [OH]-,or silica tetrahedral groups.These octahedral (A) and tetrahedral (B) sheets link together toform the basic lattice of clay minerals,either a two layerone of each sheet (AB), or athree layer (BAB) structure.In smectite clay, these lattices sheets are then linked togetherby cations and interlayer water molecules.The hydroxyls are seen as porosity by all neu-tron tools, but not NMR tools.The interlayer water, trapped between sheets of the clay lat-tice, is not producible.

Crude oil

Water

Rock grain

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power to tip the polarized spinning hydro-gen nuclei and were not combinable withother logging tools.

Sparked by ideas developed at LosAlamos National Laboratories in NewMexico, USA, the application of NMR tech-nology in the oil field took a giant leap for-ward in the late 1980s with a new class ofNMR logging toolsthe pulse-echo NMRlogging tools. Now, polarizing fields are

produced with high-strength permanentmagnets built into the tools (see Pulse-EchoNMR Measurements, page 44).5

Two tool styles are currently available forcommercial well logging. These tools use dif-ferent design strategies for their polarizingfields. To gain adequate signal strength, theNUMAR logging tool, the MagneticResonance Imager Log (MRIL), uses a com-bination of a bar magnet and longitudinalreceiver coils to produce a 2-ft [60-cm] long,thin cylinder-shaped sensitive region con-centric with and extending several inchesaway from the borehole.6

The Schlumberger tool, the CMR Combin-able Magnetic Resonance tool, uses a direc-tional antenna sandwiched between a pair ofbar magnets to focus the CMR measurementon a 6-in. [15-cm] zone inside the forma-tionthe same rock volume scanned byother essential logging measurements (nextpage).7 Complementary logging measure-ments, such as density and photoelectriccross section from the Litho-Density tool,dielectric properties from EPT Electro-magnetic Propagation Tool, microresistivityfrom the MicroSFL and epithermal neutronporosity from the APT Accelerator Porosity

Tool can be used with the CMR tool toenhance the interpretation and evaluation offormation properties. Also, the vertical reso-lution of the CMR measurement makes itsensitive to rapid porosity variations, as seenin laminated shale and sand sequences.

NMR depends on the total hydrogen content,and

therefore reads low. This leads to an NMR gas cross-

over signature.

[OH]4

Hydroxyls

[OH]8

Hydroxyls

Interlayer

Water

Interlayer

Water

Surface

Water

Surface

Water

KaoliniteChlorite

Neutron Porosity NMR Porosity

Capillary

Water

Capillary

Water

Free Waterand Oil

Free Waterand Oil

Sand

FreeWater and Oil

Surface andClay BoundWater

Surface andClay BoundWater

FreeWater and Oil

CapillaryWater

CapillaryWater

T2

Silt

IlliteSmectite

T2

T2

T2

sWhat porosity toolsmeasure. NMR poros-ity tools can discrimi-nate between capil-lary-bound orclay-bound fluids bytheir short T2 compo-nents and free isolatedfluids with longer T2components (topright). By contrast,neutron porosity toolsare sensitive to thetotal hydrogen contentof the formation (left),and cannot distinguishbetween fluids of dif-ferent mobility.

T2Distribution

0.3

T2,msec

Capillary-boundwater

Clay-boundwater

Producible fluids

Total CMR porosity

3-msec CMR porosity

CMR free-fluid porosity

3.0 33 3000

Sandstone

sNMR T2 time distributions provide clear picture of the fluid components. Inwater-filled sandstone formations, the T2 time distribution reflects the pore sizedistribution of the formation. Shorter T2 components are from water that is close and

bound to grain surfaces.

1. Kleinberg and Vinegar, reference 12 main text.

2.The protons,which are part of the hydroxyls found in theclays,are so tightly bound in the crystal structure that theNMR decay is much too fast to be seen by any borehole NMRlogging tool.

5. Murphy DP: NMR Logging and Core AnalysisSimplified, World Oil216, no. 4 (April 1995):65-70.

6. Miller MN, Paltiel Z, Gillen ME, Granot J and BoutonJC: Spin Echo Magnetic Resonance Logging: Porosityand Free Fluid Index Determination, paper SPE20561, presented at the 65th SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana,USA, September 23-26, 1990.

7. Morriss CE, Macinnis J, Freedman R, Smaardyk J,Straley C, Kenyon WE, Vinegar HJ and Tutunjian PN:Field Test of an Experimental Pulsed Nuclear Mag-netism Tool, Transactions of the SPWLA 34th AnnualLogging Symposium, Calgary, Alberta, Canada, June13-16, 1993, paper GGG.

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NMR in the Borehole

Borehole NMR measurements can providedifferent types of formation porosity-relatedinformation. First, they tell how much fluidis in the formation. Second, they also supplydetails about formation pore size and struc-ture that are usually not available from con-ventional porosity logging tools. This leadsto a better description of fluid mobilitywhether the fluid is bound by the formationrock or free to flow. Finally, in some cases,

NMR can be used to determine the type offluidwater, gas or oil.

The NMR measurement is a dynamic one,meaning that it depends on how it is made.Changing the wait time affects the totalpolarization. Changing the echo spacingaffects the ability to see diffusion effects inthe fluids. Transverse relaxation decay times,T2, depend on grain surface structure, therelaxivity of the surfaces and the ability ofthe Brownian motion of the water to samplethe surfaces. In some cases, when the porefluids are isolated from surface contact, the

observed relaxation rate approaches the bulkfluid relaxation rates.

The first pulsed-echo NMR logging tools,introduced in the early 90s, were unable todetect the fast components of the resonancedecay. The shortest T2 was limited to the 3-

to 5-msec range, which allowed measure-ment of capillary-bound water and free flu-ids, together known as effective porosity.8

However, clay-bound water, being moretightly bound, is believed to decay at amuch faster rate than was measurable withthese tools. Within the last year, improve-ments in these tools enable a factor-of-tenfaster decay rate measurement. Now mea-suring T2 decay components in the 0.1 to

0.5 msec range is possible. These improve-ments include electronic upgrades, moreefficient data acquisition and new signal-processing techniques that take advantageof the early-time information.

For example, NUMAR added a multi-plexed timing scheme to their standard toolsto boost the signal-to-noise ratio for fast-decay modes. This was achieved by com-bining a standard pulse-echo trainconsist-ing of 400 echoes with an echo spacing of1.2 msecand a rapid burst of short echotrainlets of 8 to 16 echoes with half the stan-dard echo spacing.9 This pulse sequence is

repeated 50 times to reduce the noise by afactor of seven. Now, this tool is sensitive totransverse decay components with T2 asshort as 0.5 msec.

The Schlumberger CMR tool has also hadhardware improvements and signal-process-ing upgrades.10 The signal-to-noise per echohas been improved by 50% in the new reso-nance receiver. Also, the echo acquisitionrate has been increased 40%, from0.32-msec spacing to 0.2 msec, increasingthe CMR ability to see fast decay times (next

page). In addition, the signal-processing soft-ware has been optimized for maximum sen-

sitivity to the short T2 decays. As a result, anew pulsed-echo tool, called the CMR-200tool, can measure formation T2 componentsas short as 0.3 msec in continuous loggingmodes and as short as 0.1 msec in stationarylogging modes.

Total Porosity

NMR measurements now have the ability tosee more of the fluids in the formation,including the sub-3-msec microporosityassociated with silts and clays, and intra-particle porosity found in some carbonates.Therefore, the measurement provided by

NMR tools is approaching the goal of alithology-independent total porositymea-surement for evaluating complex reservoirs.

Total porosity using NMR T2 decay ampli-tudes depends on the hydrogen content ofthe formation, so in gas zones, NMR poros-

Borehole wall

Antenna

Wear plate

Permanent magnet

Bowspring

eccentralizer

cartridge

CMR skid

6 in.

14ft

Permanent magnet

Sensitive zone

Electronic

sCMR tool. The CMR tool(left)is 14 ft [4.3 m] long and is combinable with many otherSchlumberger logging tools. The sensor is skid-mounted to cut through mud-cake andhave good contact with the formation. Contact is enhanced by an eccentralizing arm orby power calipers of other logging tools. Two strong internal permanent magnets providea static polarizing magnetic field(right). The tool is designed to be sensitive to a volumeof about 0.5 in. to 1.25 in. [1.3 cm to 3.2 cm] into the formation and stretches the length ofthe antennaabout 6 in. [15 cm], providing the tool with excellent vertical resolution.The area in front of the antenna does not contribute to the signal, which allows the tool tooperate in holes with a limited amount of rugosity, similar to density tools. The antennaacts as both transmitter and receivertransmitting the CPMG magnetic pulse sequenceand receiving the pulse echoes from the formation.

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ity reads low because the hydrogen densityin gas is less than in water or oil and there isincomplete gas polarization. The differencebetween total NMR porosity and densityporosity logs provides an indicator of gas.

Other applications based on NMR poros-ity discrimination are permeability logs andirreducible water saturation. In the future,the improved T2 sensitivity of NMR porositylogs may permit accurate estimates of clay-

bound-water volumes for petrophysicalinterpretation, such as the calculation ofhydrocarbon saturation through Dual-Wateror Waxman-Smits models.

A simple example from South Americaillustrates the improved sensitivity to shaleresulting from the increased ability to mea-sure fast-decay components (next page, topleft). Density-derived porosity was calculatedassuming a sandstone matrix density of2.65 g/cm3, and thermal neutron porosity wascomputed also assuming a sandstone matrix.

The CMR-200 T2 distributions shown intrack 3 were used to compute total porosity,

TCMR; a traditional CMR 3-msec effectiveporosity curve, CMRP, shown in track 2; anda 12-msec bound-fluid porosity BFV curve,based on the fast-decaying portion of the T2distribution, shown in track 1.

All the porosity logs in track 2 agree inZone B, indicating a moderately cleanwater-filled sandstone reservoir. This shale-free zone makes relatively little contributionto the relaxation time distribution below the3-msec detection limit of the early pulse-echo CMR tools. However, in the shale,Zone A, the picture changes. Here, the bulkof the porosity T2 response shifts to a much

shorter part of the T2 distribution that is eas-ily seen in track 3. In the shale zone, thenew CMR-200 total porosity curve in track 2is sensitive to the fast-decaying componentsand agrees well with the density porosity.The older CMR 3-msec porosity in track 2misses the fast-decaying components of theT2 distribution between 0.3 and 3 msec,and therefore reads 10 p.u. lower in theshale zone.

The large sub-3-msec porosity contribu-tion suggests that the shales contain clayminerals with a high bound-water content.

Depth,

m

0.3 3000

50

X160

X170

X180

X190

0 60 0

msec

p.u. p.u.

CMR CapillaryBound Fluid

Additional BFVCMR-200

Additional BFVCMR-200

CMR Small Pore Bound Fluid

CMR free fluid

CMR-200 Echospacing 0.20 msec

CMR-200 Echospacing 0.28 msec

CMR Capillary-Bound Fluid

CMR Very Small Pore Bound Fluid

T2 Distribution

CMR 3 msec Porosity

CMR Free Fluid

BFV, TE 0.2 msec

BFV, TE 0.28 msec

BFV, TE 0.32 msec

Total CMR Porosity 200 usec

Total CMR Porosity 280 usec

T2 Cutoff

Zones

A

B

CMR Echo spacing0.32 msec

sHow increased echo rate improves CMR ability to see early-time decay from small pores.CMR tool was run in a shallow Cretaceous Canadian test well at three different echospacings-0.32 msec, 0.28 msec and 0.20 msec. As echo spacings decrease, the totalobserved porosity (middle track) read by the tool increases in the shaly intervals, contain-ing small pores, because the ability to see the sub-3 msec T2components (right track)increases with echo rate. This is verified by the increased CMR-200 bound fluid volume(BFV) curves (left track). In the two sand zones A and B, the long T2components seen inthe time distributions correspond to increases in observed CMR free fluid (middle track).

8. Miller et al, reference 6.9. Prammer MG, Drack ED, Bouton JC, Gardner JS,

Coates GR, Chandler RN and Miller MN: Measure-ments of Clay-Bound-Water and Total Porosity byMagnetic Resonance Logging, paper SPE 36522, pre-sented at the 1996 SPE Annual Technical Conferenceand Exhibition, Denver, Colorado, USA, October 6-9,1996.

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The thermal neutron log is reading too highin the shale zone because of the large ther-mal absorption cross section of the shale,probably caused by some trace absorptionelements such as boron or gadolinium asso-ciated with the clays.

In track 1, there is a strong correlationbetween the gamma ray log and the bound-fluid porosity curve, BFV, obtained usingeverything below a 12-msec T2 cutoff. Thissuggests another interesting application fortotal porosity measurementsthe porosityassociated with short T2 components can

provide a good shale indicator that is inde-pendent of natural radioactivity in the for-mation. This is significant because there aremany important logging environments withclean sands that contain radioactive miner-als. In these environments, gamma ray logs

are not useful for differentiating sands andshales. At best, gamma ray logs are onlyqualitative shale indicators, and are usuallyused to estimate clay corrections used forcomputing effective porosity.

Finding Gas in Shaly SandsA south Texaswell illustrates the value of total CMR poros-ity logging in detecting gas in shaly sand for-mations. The interval consists of a shaleoverlying a shaly gas sand (above right).Looking for gas with the traditional thermalneutron-density crossover is unreliable or

impossible in shaly formations, becausethermal neutron absorbers in shales forcethe thermal neutron porosity tools to readtoo highas can be seen in this example.This effect on the neutron log suppresses thegas signature, which means the neutron-porosity curve never consistently dropsbelow the density-porosity curve when thelogging tools pass a gas zone.

Fortunately, total porosity NMR loggingworks well in these environments, simplify-ing the interpretation. Starting from the bot-tom of the interval, in the lower sand, ZoneC, the total CMR porosity TCMR agrees withthe density porosity. However, in Zone B atthe top of this shaly sand, the CMR-derivedporosity drops, crossing below the density-derived porosity. This is the NMR-densitylogging crossovera gas signature. TheNMR porosity signal drops in the gas zonedue to the reduced concentration of hydro-gen in the gas and long gas polarization

timeleading to incomplete polarization ofthe gas. The logged density-derived porosity,which assumed water-filled pores, readsslightly high in the gas zoneaccentuatingthe crossover effect. Since gas affects bothCMR porosity and density porosity, theCMR-based gas signature works effectivelyin shaly sands.

X520

X530

X540

X550

X560

Neutron Porosity

Density Porosity

Zone

ShaleZone

A

B

TCMR

3 msec CMRP

50 0

12 msec BFV

in.

p.u.

p.u.

Borehole

Depth,ft

Gamma Ray

API80 200

0 25

6 16

3 msec

msec0.3 3000

T2 Distribution

sTotal porosity logging with the PLATFORMEXPRESStool differenti-ates sands and shales. The porosity logs are shown in track 2 ofthe wellsite display. Both neutron and density porosity werederived assuming a sandstone matrix. Total CMR porosity(TCMR) correctly finds the tightly bound shale porosity seen inthe short T2distributions shown in track 3. The neutron porositylog reads too high in the shale interval, Zone A, due to neutronabsorbers in the shale. The gamma ray and bound-fluid porosity,BFV (all porosity with T2below 12 msec) in track 1 show that theCMR measurement provides an alternative method for identify-ing shale zones.

Gas

XX410

XX420

XX430

XX440

Vgas

Borehole

p.u.

Depth,

ft

A

B

C

Zones

API

in.

p.u.

Gamma Ray

Neutron Porosity

msec

Density Porosity

Total CMR Porosity

Gas CorrectedPorosity

0 25

16

2000

0 3000

6

30 0.3

3 msec

msec0.3 3000

T2 Distribution

sUsing total CMR porosity and density to find gas. In track 2 thedeficit between total porosity (red curve) and density porosity(blue curve) in a shaly sand can be used to identify a gas zone.The traditional neutron-density crossover is suppressed by theshaliness, which opposes the gas effect in the thermal-neutronlog (green curve). The T2time distributions show large contribu-tions from short relaxation times below 3-msec coming from theclay-bound water in the shales. The gas corrected porosity,(dashed black curve) is always less than the density porosityand greater than the total CMR porosity.

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Summer 1997 43

Based on the petrophysical responses forCMR total porosity and density porosity, anew gas-corrected porosity gas-corr, shownin track 2, and the volume of gas Vgas ,shown in track 1, are derived (see Gas-Cor-

rected Porosity from Density-Porosity andCMR Measurements, page 54).11 The newgas-corrected porosity, computed from theTCMR and density-porosity shown in track2, gives a more accurate estimate of true

porosities in the gas zones. NMR workshere, where the traditional neutron tooldoesnt, because NMR porosity respondsonly to changes in hydrogen concentration,and not to neutron absorption in the shales.

In the shale, Zone A, the total CMR and gas-corrected porosities again agree with thedensity-porosity curve, as expected.

Finally, in the lowest interval, Zone C,below the gas sand, there is a transition intopoorer-quality sand with lower permeability

as evidenced by the short relaxation timesseen in the T2 distributions. This zone showslittle indication of gas because the totalCMR porosity, gas-corrected porosity anddensity-porosity logs are in agreement.

Another striking example, from a BritishGas well in Trinidad, shows how the CMR-derived total porosity was used with density-derived porosity to detect gas in shaly sands(left). The interval contains shaly water

zones at the bottom, Zone C, followed by athin, 6-ft [2-m] clean sand, Zone B, toppedby a section of shale, Zone A. There is a gas-water contact at XX184 ft in the lower partof the clean sand in Zone B. The CMR totalporosity curve, shown in track 2, overliesthe density-porosity curve throughout thewater-filled shaly sand intervals. In the cleansand, which contains gas, there is a largeseparation between the CMR total porosityand the density-porosity curves. Again, thereduction in the CMR porosity response isdue to the reduced concentration of hydro-gen in the gas. The large crossover of these

two logs provides a clear flag for finding gasin the reservoir.The NMR logs shown in this example were

obtained with the early pulse-echo CMRtool. Comparing the early tools 3-mseceffective porosity log with the new totalporosity log demonstrates the improvementprovided by the new CMR total porosityalgorithms. The total porosity and effectiveporosity curves, shown in track 2, are similarin the clean sand, but the 3-msec porositylog misses the fast-decaying porosity in theshale zones. Similarly, the bound-fluidporosity log based on the early tools 3-msec

limited T2 distributions, shown in track 3, ismuch noisier and misses most of the bound-fluid porosity in the shale zones. The newCMR T2 distributions in track 4 show largecontributions from the fast-decaying shalewith bound-fluid components between 0.3and 3 msec. Like the previous example, thenew total porosity-derived bound-fluid lognow correlates well with the gamma ray, andcan be used as a improved shale indicator.As commercial CMR tools are upgraded toCMR-200 hardware, logging data and inter-pretation results, like those in this example,will improve.

XX200

XX175

Zone

A

GasB

C

Maxis

Amplitudes

0.33 30003000

Reconstruction

Amplitudes

CMR 3 msec Porosity

T2 Distributions

msec

Total CMR Porosity

Neutron Porosity

p.u.50 0

Depth,

ft

Hole Size

in.4 14

BFV 3 msec

p.u.0 40

Total BFV

p.u.0 40

Gamma Ray

API75 200

Density Porosity

sDetecting gas using total porosity logging with the PLATFORMEXPRESStool. A dramaticimprovement in agreement between the CMR-200 total porosity (solid black), comparedto the 3-msec CMR porosity (dotted black), and density porosity (red), shown in track 2, isobtained by including the fast-decaying shale-bound porosity components from the newCMR-200 T2distribution shown in track 4. This enhances the ability to use the CMR total

porosity and density-porosity crossover as a flag to detect gaspink-shaded area in track2. Improvements in the signal processing are obvious when the CMR-200 total bound-fluid log (solid black) is compared to the old 3 msec CMR bound-fluid log (dotted black)shown in track 1.

(continued on page 46)

10. Freedman R, Boyd A, Gubelin G, Morriss CE andFlaum C: Measurement of Total NMR Porosity AddsNew Value to NMR Logging, Transactions of theSPWLA 38th Annual Logging Symposium, Houston,Texas, USA, June 15-18, 1997, paper 00.

11. Bob Freedman, personal communication, 1997.

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44 Oilfield Review

A feature common to second-generation NMR logging

tools is the use of an advanced pulse-echo spin flip-

ping scheme designed to enhance the measurement.

This scheme, first developed nearly fifty years ago

for laboratory NMR measurements,works in the fol-

lowing way.1

The SourceAll hydrogen nuclei in water [H2O];

gas such as methane [CH4]; and oil [CnHm] are sin-

gle,spinning, electrically charged hydrogen nuclei

protons. These spinning protons create magneticfields,much like currents in tiny electromagnets.

Proton AlignmentWhen a strong external mag-

netic fieldfrom the large permanent magnet in a

logging toolpasses through the formation with flu-

ids containing these protons, the protons align along

the polarizing field, much like tiny bar magnets or

magnetic compass needles.This process, called

polarization, increases exponentially in time with a

time constant,T1.2

Spin TippingA magnetic pulse from a radio fre-

quency antenna rotates, or tips, the aligned protons

into a plane perpendicular to the polarization field.The protons, now aligned with their spin axis lying in

a plane transverse to the polarization field, are simi-

lar to a spinning top tipped in a gravitational field,

and will start to precess around the direction of the

field. The now-tipped spinning protons in the fluid

will precess around the direction of the polarization

field produced by the permanent magnet in the log-

ging tool (above).

The Effects of PrecessionThe precession fre-

quency, or the resonance frequency, is called the

Larmor frequency and is proportional to the strength

of the polarization field.The precessing protons,still

acting like small magnets, sweep out oscillating

magnetic fields just as many radio antennas trans-

mit electromagnetic fields. The logging tools have

receivers connected to the same antennas used to

induce the spin-flipping pulses. The antennas and

receivers are tuned to the Larmor frequencyabout

2 MHz for the CMR tooland receive the tiny radio

frequency signala few microvoltsfrom the pre-

cessing protons in the formation.

A Faint Signal from the FormationIn a perfect

world, the spinning protons would continue to pre-

cess around the direction of the external magnetic

field, until they encountered an interaction that would

change their spin orientation out of phase with others

in the transverse planea transverse relaxation pro-

cess.The time constant for the transverse relaxation

process is called T2, the transverse decay time.Mea-suring the decay of the precessing transverse signal

is the heart of the NMR pulse-echo measurement.

Unfortunately, it is not a perfect world. The polar-

ization field is not exactly uniform, and small varia-

tions in this polarization field will cause correspond-

ing variations in the Larmor precession frequency.

This means that some protons will precess at differ-

ent rates than others. In terms of their precessional

motion, they become phase incoherent and will get

out of step and point in different directions as they

precess in the transverse plane (next page). As the

protons collectively get out of step,their precessing

fields add together incoherently, and the resonance

signal decays at an apparent rate much faster than

the actual transverse relaxation rate due to the

dephasing process described above.3

Spin-Flipping Produces Pulse EchoesA clever

scheme is used to enhance the signal and to mea-

sure the true transverse relaxation rate by reversingthe dephasing of the precessing protons to produce

Pulse-Echo NMR Measurements

Magnetic field

Precessional motion

Gravitational field

Spinning motion

sPrecessing protons.Hydrogen nucleiprotonsbehave like spinning bar magnets. Once disturbed from equilib-

rium, they precess about the static magnetic field (left)in the same way that a childs spinning top

precesses in the Earths gravitational field (right).

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Summer 1997 45

what is called a spin echo. This is done applying a

180 spin flippingmagnetic pulse a short timeat

half the echo spacingafter the spins have been

tipped into the transverse plane and have started todephase. By flipping the spins 180, the protons con-

tinue to precess, in the same transverse plane as

before, but now the slowest one is in first and the

fastest one last. Soon the slowest ones catch up with

the fastest, resulting in all spins precessing in phase

again and producing a strong coherent magnetization

signal (called an echo) in the receiver antenna.Thisprocess, known as the pulse-echo technique, is

repeated many times; typically 600 to 3000 echoes

are received in the CMR tool.

The T2Resonance DecayThe pulse-echo tech-

nique used in todays logging tools is called the

CPMG sequence, named after Carr, Purcell, Mei-

boom and Gill who refined the pulse-echo scheme.4

It compensates for the fast decay caused by

reversible dephasing effects. However, each subse-

quent echo will have an amplitude

that is slightly smaller than the previous one

because of remaining irreversibletransverse relax-

ation processes.

Irreversible Relaxation Decay RatesMeasuring

echo amplitudes determines their transverse magne-

tization decay rate.The time constant T2 character-

izes the transverse magnetization signal decay. The

decay comes from three sources;

intrinsic the intrinsic bulk relaxation

rate in the fluids,

surface the surface relaxation rate,

a formation environmental effect

diffusion the diffusion-in-gradient

effect, which is a mix of environmental

and tool effects.

Bulk-fluid relaxation is caused primarily by the

natural spin-spin magnetic interactions between

neighboring protons.The relative motions of two

spins create a fluctuating magnetic field at one spin

due to the motion of the other.These fluctuating

magnetic fields cause relaxation.The interaction is

most effective when the fluctuation occurs at the Lar-

mor frequency, 2 MHz for the CMR toola very slow

motion on the molecular time scale.

Molecular motions in water and light oils are

much more rapid, so the relaxation is very inefficientwith long decay times.As the liquids become more

viscous, the molecular motions are slower,and

therefore are closer to the Larmor frequency.Thus

viscous oils relax relatively efficiently with short T1

6b. Somespins dephased:echo amplitude

reduced

6a. Spinsreturn at the

same rate theyfanned out

Spin echoes

Free induction

decay

Echopulseamplitude

3. Spinsfan out

4. 180pulse

reverses

2. Spins inhighest staticfield precess

fastest

1. 90 pulsestarts spinprecession

or

3 4 5

6a

6b

2

1

Time,sec

5. Spins inhighest staticfield precess

fastest

CPMG Pulse Sequence

Pulsed

magneticfield

Start nextCPMGsequence

Time,msec0.16

90 pulse

180 pulses

21 3 4

0.32 0.32

600

sPulse-echo sequence and refocusing. Each NMR measurement comprises a sequence of transverse magnetic

pulses transmitted by an antennacalled a CPMG pulse-echo sequence (middle). Each CPMG sequence starts

with a pulse that tips the protons 90 and is followed by several hundred pulses that refocus the protons by flipping

them 180. This creates a refocusing of the dephased spins into an echo.The reversible fast decay of each echo

the free induction decayis caused by variations in the static magnetic field (top). The irreversible decay of the

echoesas each echo peak decays relative to the previous oneis caused by molecular interactions and has acharacteristic time constant of T2transverse relaxation time.The circled numbers

correspond to steps numbered in the race analogy.

Imagine runners lined up at the start of a race (bottom). They are started by the 90 pulse (1).After several laps,

the runners are spread around the track (2, 3).Then the starter fires a second pulse of 180 (4, 5) and the runners

turn around and head in the other direction. The fastest runners have the farthest distance to travel and all of them

will arrive at the same time if they return at the same rate (6a).With any variation in speed, the runners arrive back

at slightly different times (6b).Like the example of runners, the process of

spin reversals is repeated hundreds of times during an NMR measurement.Each time the echo amplitude is less

and the decay rate gives T2 relaxation time.

1. Hahn EL: Spin Echoes,Physical Review80,no.4 (1950):580-594.

2.The time constant for this process,T1, is frequently known asthe spin-lattice decay time.The name comes from solid-stateNMR,where the crystal lattice gives up energy to the spin-aligned system.

3.The observed fast decay due to the combined components ofirreversable transverse relaxation decay interactions and thereversable dephasing effect is frequently called the free induc-tion decay.

4.Carr HY and Purcell EM: Effects of Diffusion on FreePrecession in Nuclear Magnetic Resonance Experiments,Physical Review94,no.3 (1954): 630-638.

Meiboom S and Gill D: Modified Spin-Echo Method for Mea-suring Nuclear Relaxation Times, The Review ofScientific Instruments29,no.8 (1958): 688-691.

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46 Oilfield Review

Total Porosity for Better PermeabilityAnswersIn the North Sea, micaceoussandstones challenge density-derived poros-ity interpretation and permeability analysis,because grain densities are not well-known.Here, CMR-derived total porosity provides amuch better match to core porosity thanconventional porosity logging tools (next

page, top). In addition, permeability dataderived from CMR measurements are of

considerable value. Other sources of mea-suring this critically important reservoirparameter, such as coring and testing,invoke high cost or high uncertainty.

Experience in these environments showsthat wellsite computations of CMR porosityand permeability using the default parame-ters agree well with core data in at least75% of wells. Typically, default parametersassume a fluid-hydrogen index of unity (forwater) and the Timur-Coates equation with a33-msec T2 cutoff is used for computing thebound-fluid log.12 In most of these wells,the CMR tool is now being used to replace

some of the coring, especially in frontier off-shore drilling operations where coring cancost up to $6000 per meter.

An offshore Gulf of Mexico gas well,drilled with oil-base mud on the flank of alarge salt dome, provided an opportunity toevaluate fluid contacts in an established oiland gas field and determine hydrocarbonproductivity in low-resistivity zones. Previ-ous deep wells on this flank encountereddrilling difficulties leading to poor-to-fairboreholes and degraded openhole log qual-ity. This resulted in ambiguous petrophysi-cal analysis and reservoir characterization.

The combination of CMR measurementsand other logs provides a straightforwarddescription of the petrophysics in this well(next page, bottom). These logs show manyhigh-resistivity zones in track 2 and density-neutron crossovers in track 3, which signalthese intervals as potentially gas-producing.Total CMR porosity is low in the gas inter-vals. There are some low-resistivity intervalsthat could produce free water. Of specialinterest are the low-resistivity zones at thebase of the gas sand in Zone C, which mayindicate a water leg, and the low-resistivitysand in Zone D. The CMR bound-fluid

porosity increases in these zones.An ELAN Elemental Log Analysis interpre-

tation, which combines resistivity and CMR

Small pore

Amplitude

Time, msec

Large pore

Amplitude

Time, msec

Rock grain

Rock

Rock

Hydrogen proton

sGrain surface relaxation. Precessing protons diffuse about the pore space colliding with other protons and with

grain surfaces (left). Every time a proton collides with a grain surface there is a possibility of a relaxation interac-

tion occurring. Grain surface relaxation is the most important process affecting relaxation times. Experiments show

that when the probability of colliding with a grain surface is highin small pores (center)relaxation is rapid and

when the probability of colliding with a grain surface is lowin large pores (right)relaxation is slower.

0.001

0.01

0.1

1

10

0.1 1 10 100 1000

T1

orT

2,s

ec

T1

T2

TE=0.32 msec

TE=Echo spacing

Viscos ity , cp

T2

TE=1 msec

T2

TE=2 msec

T2

TE=0.2 msec

sRelaxation time versus viscosity.The bulk relaxation of

crude oil can be estimated from its viscosity at reservoir

conditions.T2 values are shown for various echo spac-

ings and have been computed for the CMR tool with a

20 gauss/cm magnetic field gradient. Diffusion-in-gradi-

ent effects,which depend on echo spacing,TE, dominateT2 rates for low viscosity liquids.

and T2 decay times (right). It should be noted that

for liquids with viscosity less than 1 cp,T2 does not

change muchand even decreases for low viscos-

ity.This is due to the diffusion-in-gradient mecha-

nism, which is strongest for liquids with the largest

diffusion coefficientlowest viscosity.This effect is

also enhanced by long echo spacing. The diffusion-

in-gradient mechanism does not affect T1.5

Fluids in contact with grain surfaces relax at a

much higher rate than their bulk rate. The surface

relaxation rate depends on the ability of the protons in

the fluids to make multiple interactions with the sur-

face. For each encounter with the grain surface, there

is a high probability that the spinning proton in the

fluid will be relaxed through atomic-level electromag-

netic field interactions. For the surface process to

dominate the overall relaxation decay, the protons in

the fluid must make many random diffusion (Brownian

motion) trips across the pores in the formation

(above).They collide with the grain surface many

times until a relaxation event occurs.

Finally, there is relaxation from diffusion in the

polarization magnetic field gradient. Because protons

move around in the fluid, the compensation by the

CPMG pulse-echo sequence is never complete.Some

protons will drift into a different field strength during

their motion between spin flippingpulses, and as a

result they will not receive correct phase adjustment

for their previous polarization field environment.Thisleads to a further,though not significantly large,

increase in the T2 relaxation rates for water and oil.

Gas, because of its high diffusion mobility, has a large

diffusion-in-gradient effect.This is used to differenti-

ate gas from oil.6

The pulse-echo measurements are analyzed in

terms of multiple exponentially decaying porosity

components. The amplitude of each component is a

measure of its volumetric contribution to porosity.

5.Kleinberg RL and Vinegar HJ: NMR Properties of Reservoir

Fluids,The Log Analyst37, no.6 (November-December,1996): 20-32.

6.Akkurt R, Vinegar HJ,Tutunjian PN and Guillory AJ: NMRLogging of Natural Gas Reservoirs, The Log Analyst37, no. 6(November-December,1996): 33-42.

12. The hydrogen index is the volume fraction of freshwater that would contain the same amount of hydro-gen. The Timur-Coates equation is a popular formulafor computing permeability from NMR measurements.Its implementation uses ratio of the free-fluid tobound-fluid volumes. It was first introduced in CoatesG and Denoo S: The Producibility Answer Product,The Technical Review, 29, no. 2 (1981): 54-63.

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Density Porosity

Gas

GR Core Permeability

CMR Permeability

Depth, ft

Total CMR Porosity

CMR Free FluidAPI Neutron Porosity

0 150

45

XX450

XX500

XX600

XX550

30 01 10,000-15 T2 Cutoff

msec

p.u. p.u.

0.3 3000

T2 Distribution

Bound FluidsPermeability logging using CMR total

porosity in North Sea micaceous sandstones.A good match (track 2), between core- andCMR-derived permeability using the defaultTimur-Coates equation, is common in manyNorth Sea reservoirs. This example is from anoil zone drilled with oil base mud.

Gas

Total CMR Porosity

Bound Water

Bound Fluid Volume

Density Porosity

Neutron Porosity

60 0

Resistivity-30 in.

Resistivity-60 in.

Resistivity-90 in.

0

6 16

150 0.2 20

Resistivity-20 in.

XX700

XX800

XX900

in.

ohm-m

Resistivity-10 in.

Borehole

API

Gamma Ray Depth,

ftZones

B

C

D

E

A

T2 Cutoffp.u.

msec0.3 3000

T2 Distribution

Gas

sGas production in the Gulf of Mexico.Bimodal CMR T2distributions in track 4 showeffects of oil-base mud invasion with long T2and large bound-fluid components below the33-msec T2cutoff. Neutron-density crossoverclearly shows gas zones. The low CMR signalis due to the low hydrogen content and long

polarization time of the gas. The bound-fluidmeasurement was used with the resistivitydata to determine movable water in thelower resistivity zones.

47

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48 Oilfield Review

data, shows that there is little free water inthis entire interval (left). Most of the watercontained in these zones appears irre-ducible because the CMR bound-fluid vol-ume matches the total water volumederived from the resistivity logs. The upperthree sands were completed and the CMRtotal porosity, bound-fluid and permeabilitylogs allowed the operator to confidentlyperforate Zones A, B and C.13 The initial

production from the upper three sand zoneswas 20 MMcf/D, 780 B/D [124 m3/d] ofcondensate with less than 1% water, con-firming the CMR interpretation. The lowersands, Zones D and E, have not been com-pleted because of downdip oil production.However, the interpretation results fromthese zones have been included in theoverall well reserves analysis.

Another Gulf of Mexico example from aninfill development well in a faulted anticlinereservoir helped the operator determine if azone, believed to be safely updip from thewaterdrive in a mature low-resistivity oil-

and gas-producing zone, would producesalt water or hydrocarbons. The CMRporosities and T2 distributions have beenadded to the standard density neutronPLATFORM EXPRESS wellsite display (next page).

Several sandstone intervals, Zones A, Band C, are easily identified by their longerT2 distributions that may correspond tohydrocarbons isolated in water-wet rocks orlarge water-filled pores. Zone C is moreconductiveindicating water, but the CMRtotal porosity reads less than the density-porosityindicating gas. There are high-resistivity sands in Zones A and B that are

difficult to interpret from raw logs alone. Thepicture is confusing.

A petrophysical analysis, combining CMRand PLATFORM EXPRESS data over this interval,reveals the nature of the reservoir complex-itieslithologic changes and the presenceof a waterdrive flood front (page 50, top).This interpretationincluding the CMR-derived permeability, verified by subse-quent core analysisalong with irreduciblewater analysis, shows that the upper resis-tive sand, Zone A, is productive and con-tains oil with little free water. The middle,less resistive sand, Zone B, contains less oil

with a significant amount of potential pro-ducible water. The low-resistivity sand,Zone C, appears to contain some oil, butwith a large amount of free water mostlikely coming from the waterflood.

XX800

XX900

XX700

6 16

050

0.3 3000

0

0.1 1000

150

Depth,

ft

A

B

C

D

E

Zone

Borehole

CMR

Permeability

Neutron

Porosity

Total CMR

Porosity

Density

Porosity

BFV

Sand

Gas

Gas

Free water

Irreducible water

Clay

Gamma

Ray

Gas

md

p.u.

in.

API

WaterT2 Cutoff

msec

T2

Distribution

sELAN interpretation analysis. The CMR-resistivity interpretation suggests that there is nomovable water in the entire logged interval. The top three sand zones A, B and C, all withhigh permeability determined by the CMR tool, track 2, produced 20 MMcf/D of gas with780 B/D condensate and no water. The reserves indicated in the lower sand Zone E willbe completed at a later time.

13. Whenever oil-base mud is used in water-wet rocks,it is easy to identify bound versus free fluid. Bound-fluid water has a short T2, and oil-base mud flushinginto the free-fluid pore space has a long T2. TheT2 cutoff is obvious, making free fluid and boundfluid easy to distinguish for Timur-Coates perme-ability calculations.

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Summer 1997 49

The operator, hoping that the logs mighthave been affected by deep invasion, com-pleted and tested the lower sand, Zone C.However, it produced only salt water, con-sistent with the petrophysical interpretation.After a plug was set above this zone, theupper sands were completed and produce100 BOPD [16 m3/d] with only a 10%water cut, which is also in agreement withthe expectations from the ELAN interpreta-

tion. It is clear that combining the porositydiscrimination and permeability informationfrom CMR measurements with other logs,such as resistivity and nuclear porosity,helps explain what is happening to thewaterdrive and hydrocarbons in pay zonesin this common, but complex, reservoir.

Logging for Bound-Fluid

Bound-fluid logging, a special applicationof NMR porosity logging, is based on theability of NMR to distinguish bound-fluidporosity from free- or mobile-fluid porosity.Bound-fluid porosity is difficult to measure

by conventional logging methods. A fullNMR measurement requires a long waittime to polarize all components of the for-mation, and a long acquisition time to mea-sure the longest relaxation times. However,experience has shown that the T2 relaxationtime of the bound fluid is usually less than33 msec in sandstone formations and lessthan 100 msec in carbonate formations. Infast bound-fluid NMR logging, it is possibleto use short wait times by accepting lessaccuracy in measuring the longer T2 com-ponents. In addition, a short echo spacingand an appropriate number of echoes

reduce the acquisition time and ensure thatthe measurement volume does not changesignificantly because of the faster toolmovement. This logging mode can acquireNMR data at speeds up to 3600 ft/hr[1100 m/hr] because of the short relaxationtimes of the bound fluid.

The bound fluid volume can be used inconjunction with other high speed loggingmeasurements to calculate two key NMRanswerspermeability and irreduciblewater saturation, Swirr. Typically, the densitylog is used in shaly sands, and the density-neutron crossplot porosity log is used in gas

sands, carbonates and complex lithologies.The epithermal neutron porosity from the

Bound Fluid Volume

Neutron Porosity

Density Porosity

RXO

Resistivity-10 in.

Resistivity-30 in.

Resistivity-60 in.

0.2

Resistivity-90 in.

ohm-mZonesDepth,

ft

A

B

C

6 16

Hole Size

in.

p.u.

0 150

Gamma Ray

API

60 0

Resistivity-20 in.

20

Total CMR Porosity

Bound Water

XX900

T2 Cutoff

msec0.3 3000

T2 Distribution

sWellsite PLATFORMEXPRESSdisplay. This example shows long T2components in the low-resistivity pay sand, Zone C. This appears to the CMR tool to contain mostly free water inlarge pores, but could contain isolated hydrocarbons with long T2. The upper two zones

have high resistivity and potentially contain hydrocarbons. The total CMR porositymatches the density porosity except in the lower sections of Zones A and C, due to incom-

plete polarization (with a 1.3 sec wait time) of the hydrocarbons.

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sSolving the mystery with ELAN interpre-tation. High permeability derived from theCMR tool, track 2, with water saturation,track 3, and irreducible water analysis,track 4, show that the low-resistivity paysand in Zone C will produce only water,

probably from the flood drive. The uppersand, Zone A, contains oil with only a littlefree water. Zone C tested 100% salt water,whereas the upper zone is producing100 BOPD with a low water cut. Note theexcellent agreement between the CMR

permeability and core-derived permeabil-ity (black circles) in track 2.

CorePermeability

Water

Sand

Oil GR

Neutron Porosity Resistivity 90-in.

Resistivity 10-in.Density Porosity

Hole

in.CMR

Permeability

50 p.u. 0

Core

Water Volume

Sw

CMR BFV

ohm-m p.u.p.u.

0

3 13

150

0.2 0

20 00.3 3045 -1510,000

Depth,ft1

XX550

XX650

XX750

XX850

T2 Cutoff

msec3 3000

T2 Distribution

Sand

Oil

Free Water

Irreducible Water

Moved Hydrocarbon

10 0

Water

Saturation

p.u.

Oil

Water

1 10,000

Permeability

md

6 16

Hole Size

in.

0 150

GR

API

Depth, ft

Zones

Dry Clay

XX900

A

B

C

T2 Cutoff

msec0.3 3000

T2 Distribution

sBound-fluid logging with water-free pro-

duction in a long oil-water transition zone.CMR readings indicate water-free produc-tion above XX690 ft, where the water vol-ume, Sw, computed from resistivity logsmatches the bound-fluid volume (BFV) fromthe CMR tool. Even though bound-fluid log-ging speeds are fast, long T2componentsare seen in the CMR T2distributions.

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APT tool is especially accurate because it isimmune to the thermal neutron absorbereffects frequently found in shales.14

Bound-fluid logging can also be used todetect heavy oil, since many high-viscosityoils have T2 components below the 33-msecor 100-msec cutoffs and above the 0.3-msecdetection limit of the CMR-200 tool. Theseoils will be properly measured in a bound-fluid log.

Our first example of bound-fluid loggingcomes from the North Sea, where long tran-sition zones and zones of low-resistivity payoften lead to uncertainty about the mobilefluid being oil or water, or both (previous

page, bottom). One method of predictingmobile water is to compare the bound-fluidvolume, BFV, seen by the CMR tool withSwthe volume of water computed fromthe resistivity measurement. If the totalwater from the Swcalculation exceeds theBFV measurement, then the excess waterwill be free fluid and therefore producible.15

In this example, the CMR bound-fluid tool

was run with the standard triple comboneutron and density for total porosity and anAIT Array Induction Imager Tool for satura-tionat 1500 ft/hr [460 m/hr]. The fast-log-ging CMR tool was run with a short waittime of 0.4 sec and 600 echoes. This wellwas drilled with an oil-base mud, whichcreated a large signal at long T2 times due toinvasion of oil filtrate. To fully capture theselong T2 components for a total CMR poros-ity measurement, wait times of 6 sec wouldhave been required, at a correspondinglyslower logging speed of 145 ft/hr [44 m/hr].

An interpretation based on density, neu-

tron and resistivity logs yields the lithologyand fluid content. The T2 distributions showsignificant oil-filtrate signal seen at latetimes despite the short wait time. The lithol-ogy analysis shows little or no clay, consis-tent with the lack of T2 data below 3 msec.

In this well, a 100-msec cutoff was used todifferentiate the bound-fluid volume from thefree fluids; this is verified by excellent agree-ment with core permeability using the defaultTimur-Coates equation. Ideally, the T2 cutoffshould be confirmed independently, forexample by careful sampling with the MDTModular Formation Dynamics Tester tool

around the oil-water transition depths.In another example, a real-time wellsite

quicklook display was developed for com-bining CMR bound-fluid logging with thePLATFORM EXPRESS acquisition at 1800 ft/hr[550 m/hr] in the Gulf of Mexico. In offshorewells, with hourly operating expenses thatfar exceed logging costs, fast logging andimmediate answers are critical for timely

decision-making at the wellsite. The fieldquicklook incorporates the CMR measure-ments into a Dual-Water saturation compu-tation. The results are total porosity from theneutron-density and water saturation fromthe AIT induction tools (above). The wellsitepermeability computation, track 2, uses theCMR bound-fluid results in a Timur-Coatesanalysis with two estimates of total poros-ityone from the traditional neutron-densitycrossplot porosity, and the other from a den-sity-derived porosity.16

The first porosity estimate is more accuratein the shaly sections but requires free- andbound-water resistivity and wet-clay porosityparameters and is limited by the vertical reso-lution of the neutron measurement. The sec-ond porosity estimate has the advantages ofnot requiring any parameter picks for theshaly intervals and also has the higher verti-

cal resolution inherent in the density mea-surement. The field-derived results show bothsand Zones, A and B, with good productionpotential and with low water cut. These log-ging results agree well with the sidewall corepermeabilities and porosities measured later,shown as circles in tracks 2 and 4.

Repeatability of Fast BFV LoggingThisexample shows that accurate and repeatablebound-fluid volumes and permeabilities can

Depth,

ft

Gamma Ray

150.00.0 API

Hole Size

16.06.0 in.

Neutron Density

Permeability

Density

Permeability

10,0001 md

Resistitivity 90-in.

RXO

10000.1 ohm-m

Density

Porosity

Neutron

Porosity

CMR BFV

050 p.u.

Porosity

Analysis

050 p.u.

ClayBound

Hydro-carbon

Free

Water

Irreducible

Water

XX200

XX100

T2 Cutoff

msec3 3000

T2 Distribution

Zone

A

B

sPLATFORMEXPRESS-CMR wellsite quicklook. The field interpretation results from high-speedCMR logging enable the operator to quickly identify that hydrocarbon pay Zones A andB, have high permeability, track 2, and high potential for water-free production becauseall the water in the interval, as shown in track 4, is either clay-bound or irreducible. Thewellsite interpretation results also compared well with core analysis obtained later.

14. Scott HD, Thornton JL, Olesen J-R, Hertzog RC,McKeon DC, DasGupta T and Albertin IJ: Responseof a Multidetector Pulsed Neutron Porosity Tool,Transactions of the SPWLA 35th Annual LoggingSymposium, Tulsa, Oklahoma, USA, June 19-22,1994, paper J.

15. The BFV log measures the capillary-bound and non-mobile water.

16. LaVigne J, Herron M and Hertzog R: Density-Neu-tron Interpretation in Shaly Sands, Transactions ofthe SPWLA 35th Annual Logging Symposium, Tulsa,Oklahoma, USA, June 19-22, 1994, paper EEE.

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be measured at high logging speeds(above). Three runs were made through aseries of sand-shale zones, where freshwater makes producibility evaluation diffi-cult and high-precision bound-fluid deter-mination is important. The three CMRpasses were made with 0.2-sec wait time,

200 echoes at 3400 ft/hr [1040 m/hr]; 0.3sec wait time, 600 echoes at 1800 ft/hr[549 m/hr]; and finally at 2.6 sec wait time,1200 echoes at 300 ft/hr [92 m/hr]. The datawere processed with total CMR porosity togive T2 distributions from 0.3 msec to 3 sec,shown in tracks 3, 4 and 5 for each run. Thethree bound-fluid BFV logs, computed with

default 33-msec T2 cutoff and five-levelstacking, are shown in track 1. They agreewell with each other, having a root-mean-square error on the bound-fluid volumesabout of 1.2 p.u., which is comparable tothe typical statistical error found in othernon-NMR porosity logs. The BFV curvescorrelate well with the gamma ray except inZones A and B, with the shortest T2 values,where the relaxation may be too rapid to be

seen by the CMR tool.Permeability estimates, in track 6, werebased on the standard Timur-Coates equa-tion. CMR bound-fluid logs and a robust totalporosity estimator based on the minimum ofthe density and neutron-density porositieswere used to compute the free-fluid and thebound-fluid volumes used in this permeabil-ity equation.17 At these logging speeds, allthree permeability estimates overlie oneanother, typically within a factor of 2.

Integrated Answers

Bound-fluid logging is one example of how

CMR measurements combine with otherlogging measurements to provide a simple,more accurate picture of the formation in afast, more efficient manner. The CMR toolcan be combined with the MDT tool to givebetter producibility answers. The in-situ,dynamic MDT measurements complementthe CMR continuous permeability log, andhelp verify the presence of produciblehydrocarbons. Wellsite efficiency is substan-tially increased when MDT sampling depthsare guided by CMR results.

Reservoirs often exhibit large vertical het-erogeneity due to the variability of sedi-

mentary deposition, such as in laminatedformations. In vertical wells, formationproperties can change over distances smallcompared to the intrinsic vertical resolutionof logging tools. In horizontal wells, thedrainhole can be located near a bedboundary with different formation proper-ties above and below the logging tools. It isimportant that all logging sensors face thesame formation volume.

Two logging measurements that investigatethe same rock and fluid volume in a forma-tion are said to be coherent. Conventionallog interpretation methods can be limited by

a lack of volumetric coherence betweenlogs. For example, when subtracting thebound-fluid porosity response of an NMRtool from the total porosity response of anuclear tool to compute a free-fluid index,care must be taken to ensure that the

XX000

XX050

XX100

Depth,

ft

Zones

A

B

CMRP

3400 ft/hr

GammaRay

API25 175

BFV

3400 ft/hr

BFV

1800 ft/hr

BFV

300 ft/hr

p.u.0 25

0.3 3000 0.3 30000.3 3000

CMRP

1800 ft/hr

T2 Distribution T2 Distribution T2 Distribution

Permeability

CMRP

300 ft/hr

Density Porosity

50 0p.u.

3400 ft/hr

1800 ft/hr

md

300 ft/hr300 ft/hr3400 ft/hr 1800 ft/hr

0.1 1000

sRepeatability of bound-fluid logging. Logs and T2distributions from three runs at 300,1800 and 3400 ft/hr in the same well show how well the bound-fluid volumes, track 1,agree even at fast logging speeds. The permeability results, track 6, from CMR bound-fluid logging overlie even at the highest logging speeds. The T2distributions are similar,though the peaks in the sands seem to change somewhat, because there are not enoughechoes in the fast logging measurement to completely characterize the slower relax-

ations. The longest T2components disappear in the fast-logging mode.

17. Singer JM, Johnson L, Kleinberg RL and Flaum C:Fast NMR Logging for Bound-Fluid and Permeabil-ity, Transactions of the SPWLA 38th Annual LoggingSymposium, Houston, Texas, USA, June 15-18,1997, paper PP.

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nuclear tool does not sample a different vol-ume than the NMR tool.18

An interesting example of combining CMRlogging with other coherent measurements,is the method of determining formation siltvolume developed with Agip.19 Silt is animportant textural component in clasticrocks because it relates to the dynamic con-ditions of transportation and deposition ofsediments. The quality of a reservoir is deter-

mined by the amount of silt present in therock formation. Fine silt drasticallydecreases permeability and the ability of areservoir to produce hydrocarbons. The siltcan be of any lithology; and, since it isrelated only to grain size, its volume anddeposition properties can be determinedwith the help of CMR logging, in combina-tion with EPT measurements.

Dielectric propagation time and attenua-tion increase with silt volume. These twologs, coupled with the APT epithermal neu-tron porosity, provide a porosity interpreta-tion unaffected by the large thermal

absorbers typically associated with silts andshales in formations, and are thereforeappropriate in determining silt volume incomplex lithologies.

Accuracy in determining silt volume, aswell as a host of other parametersperme-ability, fluid volumes and mobilitydepends upon a high coherence betweenlogging measurements.

The CMR measurements ability to charac-terize grain size, using the T2 distributions,coupled with other complimentary logs,was successfully used to understand a com-plex reservoir sequence of thinly laminated

sands, silt and shales in the presence ofwater and gas (right). The well was drilledwith fresh water-base mud. The EPT dielec-tric attenuation and propagation timecurves, showing high bed resolution in track1, cross each otherclearly identifying thesequence of silty sands and shales. Perme-

Capillary Bound Water

Clay BoundWater

Clay

Reservoir

Depth,

mZone

A

B

D

C

F

G

CMR-Permeability

MicroSFL

CMR Free Fluid

3-msec Porosity

Density porosity

Neutron Porosity

md

ohm-m

RFT-Permeability

EPT-EATT

EPT-TPLdb/m

nsec/m

Silt Non Reservoir

Silt Reservoir

Sand

p.u.

Gas

Free Fluid

BFV

Total Hydrocarbon

Free Water

Irreducible Water050

0.2

0.2

20,000

20,000

100

XX50

XX100

XX150

20

600

10Resistivity-90 in.

sAvoiding water production in thinly layered gas sands with CMR data combined withother coherent logging measurements. There are nearly 20 gas pay-sands showing in thisinterval, all showing similar log profile characteristicsseparation of the EPT dielectric

propagation time TPL, and attenuation EATT, logs in track 1 and the free-fluid volumesfrom CMR and epithermal neutron porosity, in track 4. The interpretation results identifythree Zones (A, C and the lower part of Zone F) that contain free water in the reservoirs.The CMR tool responds well to thin beds (Zones B, D and G).

18. An example of an incoherent result would be thecase in which a nuclear tool is sampling a fewinches of formation, and an NMR tool is samplingseveral feet of formation, or vice versa. Then thenet free fluid could be distorted and incorrectlycomputed by large porosity changes within thesample volume caused by shale laminations in theformation. If the nuclear and NMR tools are sam-pling the same volume of rock, then the combined

results will always be correct because the differentmeasurements will be volume matched.

19. Gossenberg P, Galli G, Andreani M and Klopf W: ANew Petrophysical Interpretation Model for ClasticRocks Based on NMR, Epithermal Neutron and Elec-tromagnetic Logs, Transactions of the SPWLA 37thAnnual Logging Symposium, New Orleans,Louisiana, USA, June 16-19, 1996, paper M.

Gossenberg P, Casu PA, Andreani M and Klopf W:A Complete Fluid Analysis Method Using NuclearMagnetic Resonance in Wells Drilled with Oil BasedMud, Transactions of the Offshore MediterraneanConference, Milan, Italy, March 19-21, 1997,paper 993.

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ability curves were computed from the CMRbound-fluid log using both the Timur-Coatesequation and the Kenyon equation with thelogarithmic mean of T2.20 Both give reason-able agreement with permeability resultsderived from core and the RFT Repeat For-mation Tester tool.

The dry sand, silt and clay volume inter-pretation model, shown in track 3, includesclay-bound water, capillary-bound water (or

irreducible water), and movable water (nextpage, top). By subtracting the irreduciblewater measured directly by the CMR bound-fluid log from total volume of water, Sw,computed from Rt after clay corrections, allfree water zones within the reservoirs areclearly determined. For example, Zone Fcannot be perforated without risk of largewater production. Apart from Zones A andF, most of the other reservoirs show dry gas.The epithermal neutron and density porositylogs are shown along with NMR logs intrack 4. There are intervals with clear exam-ples of gas crossover between the density-

neutron porosity curves. Also, the separationbetween the APT neutron porosity and CMRporosity provides a good estimate of clay-water volume.

The logs show excellent correlationbetween the EPT and CMR curves. Thesequence of fining-up grain size in the sandsthrough Zone F is displayed on the logs asan increasing silt index. This is confirmed byincreasing attenuation and propagationtimes on the EPT logsbecause of increas-ing conductivity in the silt, and an increasein bound-water porosity in the CMR logsimplying a decrease of movable fluid. The

profile on other pay reservoirs between bothtools shows similar characteristics, especiallyin the EPT curve separation and the free-fluidvolumes from the CMR measurements.

The CMR measurements complement othercoherent logging measurements, such asdielectric, Litho-Density, microresistivity,neutron capture cross sections and epither-mal neutron porosity, in providing a criticalevaluation and complete interpretation inthese complex formation environments. TheLitho-Density tool is needed for lithologytodetermine the T2 cutoff for CMR bound-fluid

In zones containing unflushed gas near the borehole,

total CMR porosity logTCMRunderestimatestotal porosity because of two effects: the low hydro-

gen concentration in the gas and insufficient polar-

ization of the gas due to its long T1 relaxation time.

On the other hand, in the presence of gas, the den-

sity-derived porosity log DPHI, which is usually

based on the fluid being water, overestimates the

total porosity because the low density of the gas

reduces the measured formation bulk density.Thus,

gas zones with unflushed gas near the wellbore can

be identified by the deficit or separation between

DPHI and TCMR logsthe NMR gas signature.The

method of identifying gas from the DPHI/TCMRdeficit does not require that the gas phase be polar-

ized.1

The advantages of this method of detecting gas

include:

faster logging in many environments since the gas

does not have to be polarized2

more robust gas evaluation since the deficit in

porosity is often much greater than a direct

gas signal

total porosity corrected for gas effects.

As an aid to interpreting gas-sand formations, the

gas-corrected porosity, gas-corr, and gas bulk-vol-

ume, Vgas, equations are derived from a petrophysi-

cal model for the formation bulk density and total

CMR porosity responses.

The mixing law for the density log response is:

and for the total CMR porosity response:

.

In these equations,bis the log measured bulk-

formation density, mais the matrix density of the

formation, f is the density of liquid phase in the

flushed zone at reservoir conditions, gis the density

of gas at reservoir conditions,and is the total for-

mation porosity.

TCMR =Sg (HI)g Pg +(1-Sg)(HI)f

b=ma(1-) +f(1-Sg) +gSg

(HI)gis the hydrogen indexthe volume fraction

of fresh water that would contain the same amount ofhydrogenof gas at reservoir conditions, and (HI)f

is the hydrogen index of fluid in the flushed zone at

reservoir conditions. Sg is the flushed zone gas satu-

ration.

accounts for the polar-

ization of the gas,where Wis wait time of the CMR

tool pulse sequence, and T1,gis the longitudinal relax-

ation time of the gas at reservoir conditions.

To simplify the algebra, a new parameter,

, is introduced,and formation bulk

density is eliminated by introducing densityderived

porosity, .

Solving these equations for the gas-corrected

porosity, gas-corr, one gets:

,

and for the volume of gas,one gets:

The gas saturation can be obtained from these

equations by simply dividing the latter by the former.

Note that the gas-corrected porosity, gas-corr, is the

NMR analog of the neutron/density log crossplot

porosity, and is always less than DPHIand greater

than TCMR/(HI)f.

Bob Freedman

Vgas= .

DPHI TCMR

(HI)f

1 (HI)g*Pg

(HI)f

+

gas-corr=

DPHI*(1 ) + (HI)g* Pg *TCMR

(HI)f (HI)f

1 +(HI)g * Pg

(HI)f

DPHI = maf

maB

=fg

maf

Pg= 1 exp( )W

T1,g

Gas-Corrected Porosity from Density-Porosity andCMR Measurements

20. Kenyon WE, Day PI, Straley C and Willemsen JF: AThree-Part Study of NMR Longitudinal RelaxationProperties of Water-Saturated Sandstones, SPE For-mation Evaluation 3 (1988): 622-636.

21. Freedman et al, 1997, reference 10.

22. Bass C and Lappin-Scott H: The Bad Guys and theGood Guys in Petroleum Microbiology, OilfieldReview9, no. 1 (Spring 1997): 17-25.

1.To be able to attribute this deficit to gas, the wait time for the

logging sequence must be sufficiently long to polarize all theliquids, including formation water and mud filtrate.

2. Oilbase muds are the ex