NMRborehole.pdf

7/27/2019 NMRborehole.pdf

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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 EXPRESSare 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 A n a l ys twere devo t e de xclu sively to NMR.1The Oil field Rev iew

published a comprehensive article explain-ing borehole NMR technology less thant wo years ago.2 R e c e n t l y, many specialworkshops and conference sessions on

NMR have been held by professional log-ging societies. To d ay, Internet Web sitespr ovide current information on NMR log-ging advances.3

Why all the excitement? The reasons arec l e a r. 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 tok n owthe fluid type and content in thewell. The measurements also provide easy-to-use ways to identify hydrocarbons andpredict their producibility. Fi n a l l y, despite

How to Use Borehole

Nuclear 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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Summer 1997 35

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

tively easy to understand.Important advances have been made inapplying 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 review

the improvements in tool technology thatallow todays tools to measure differentporosity components in the formation (seeWhat i s Sandstone Porosity, and How Is It

Measured?, 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 Rapi dly 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 magnetic

field, 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, Oilf ield 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, porosi ty 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 interl ocking

grain contacts. Simil ar arguments can be made

for metamorphi c rocks. In contrast, sandstones

are formed by the deposition of discrete particles

creating abundant void space between individual

particle grains.

Obviously, hydrocarbons are found only in

porous formation s. These rocks can be formed by

the weathering and erosion of large mountains of

solid rock, with the eroded pieces deposited by

water and win d through various processes. As theweathered particles are carried farther from the

source, a natural sorting of particle or grain size

occurs (right). Geology attempts to study how vari-

ations in original porosity created by different

grain packing configurations are altered by post-

depositional processes, whether they be purely

mechanical or geochemical, or some mixture of

the two.

During transportation, the smallest weathered

particles of rock, such as fine-grained sands and

silts, get carried the farthest. Other minerals, such

as mica, which i s made of sheets of aluminosili -cates, break down quickly through erosion, and

are also carried great distances. These sheet sili-

cates give rise to clay minerals, which are formed

by weathering, transportation and deposition.

Clays can also form in fluid-fill ed sediments

through diagenetic processeschemical, such as

precipitation induced by solution changes; or bio-

logical, such as by animal burrows; or physically

through compaction, which leads to dewatering of

clays. The final formation porosity i s determined

by the volume of space between the granular

material (next page, top).

Wha t Is Sandstone Porosity , and How Is It Measured?

sHow weathering and transportation cause changes in scale of grain size. The decomposition of large rocks leadsto the development of clastic sedimentary deposits. Water and wind carry the finer grained materials the farthestfrom their source. Many materials that are resistant to water and chemical alteration become sand and silt grainseventually deposited in sediments. Other layered-lattice minerals in the original igneous rocks, such as micas andother silicates, become transformed into fine-grained clays through degradation and hydrothermal processes.


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Summer 1997 37

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 i t is

fill ed with a hydrogenated fluid, but also allows

some inferences to be made about pore size from

measurement of relaxation rates. This is the abil -

ity to apportion the porosity into different compo-

nents, 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 mi n-

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

water-wet sandstones, w ater that is adheri ng to the

surface of the sand grains is ti ghtly bound by sur-

face tension. Frequently, in these formati ons, the

spaces between sand grains are fil led wi th clay

particles. Water also attaches itself to the surfaces

of clay particl es, and since clays have large sur-

face-to-volume ratios, the relative volume of clay-

bound water is large. This water will always

remain i n the formation, and is known as irre-

ducibl e water. In pure sands, this i s also known as

capi l lary-bound water. All exposed mi neral sur-

faces have adsorbed water, which li nk particle size

with volume of irreducible water.

The NMR measurements tell us two im portant

things. The echo signal amplitudes depend on the

volume of each fluid component. The decay rate,

or T2 for each component, refl ects the rate of

relaxation, which i s dominated by relaxation at the

grain surface. T2 is determined primaril y by the

pore surface-to-volume ratios. Since porosities are

not equalcapil lary-bound or clay-bound waterare not producible, but free w ater istw o equal

zones of porosity, but with entirely different pro-

ducibility potential, can be distinguished by their

T2 time distributions (left).

Hydrogen nuclei i n the thin interlayers of clay

water experience high NMR relaxati on rates,

because the water protons are close to grai n

surfaces and encounter the surfaces frequently.

Also, if the pore volumes are smal l enough that

the water is able to diffuse easil y back and forth

across the water-fil led pore, then the relaxation

rates will simply reflect the surface-to-volumeratio of the pores. Thus, water in smal l pores

with l arger surface-to-volume rati os has fast

relaxation rates and therefore short T2 porosity

components (next page, top left) .

sIntergranular porosity. Thepores between these water-wet sand grains are occu-pied by fluids and fine layersof clay. The irreducible water(dark blue) is held againstthe sand grains by surfacetension and cannot be pro-duced. Clay-bound water(shaded dark blue) is alsounproducible. Larger porescan contain free water (lightblue), and in some casesthere are pockets of oil(green) isolated from thesand grains by capillarywater. The clay particles,and their associated clay-bound water layer, effec-tively reduce the diameterof the pore throats. Thisreduces the formations abil-ity to allow fluids to flowpermeability.

sGood water and bad water. The amplitude of the NMR T2measurement is directly proportional to porosity, and the decayrate is related to the pore sizes and the fluid type and viscosityin the pore space. Short T2 times generally indicate small poreswith large surface-to-volume ratios and low permeability, whereaslonger T2 times indicate larger pores with higher permeability.Measurements were made in two samples with about the sameT2 signal amplitudes, indicating similar porosity, but with consid-erably different relaxation times that clearly identify the samplewith the higher permeability.


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38 Oilfield Review

On the other hand, in l arge pores with smaller

surface-to-volume ratios, it takes longer for the

hydrogen to diffuse across the pores. This will

decrease the number of encounters with the sur-

face and lower the relaxation rate leading to a

longer T2 component in the NMR measurement.

Free water, found in large pores, is not strongly

bound to the grain surfa ces by surface tension.

Longer T2 time components reflect the volume of

free fluid in the formation.

Another example of long T2 time flui d compo-

nents 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 gai n access to the grain surface. As a

result, the hydrogen nuclei in the oil r elax at their

bulk oil rate, which is usually slow depending on

the oil vi scosity. This leads to a good separation of

the oil and water signals i n NMR T2 distributions.1

Neutron tools have traditionally been used for

porosity measurements. The scattering and slow-

ing 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 m ass, it is particularly effective at

slowi ng down neutrons. Thus, the response of

neutron porosity tools is sensitive to the total

hydrogen concentration of the formation, which

leads to their porosity response (next page, top) .

However, there are compli cations. Small differ-

ences in the other elem ental neutron cross sec-

tions l ead to changes in the porosity response for

different minerals, called the l ithology effect.

There is also the effect of thermal absorbers,

especiall y in shales, which cause large systematic

increases in the porosity response of thermal neu-

tron tools. Fortunately, epithermal neutron poros-

ity t ools, such as the APT Accelerator Porosity

Tool, are immune to this effect.

Finally, because the neutrons cannot discrimi-

nate between hydrogen in the fluids or hydrogen

that is an integral part of the grain structure, neu-

tron tools respond to the total hydrogen content of

the formation flui ds and rocks. Even after all the

clay-bound water and surface water are r emoved,

clay mi nerals contain hydroxyls [OH] - in their

crystal structureskaolinite and chlorite contain

[OH]8 and ill ite and smectite contain [OH]4making them read especiall y high to neutron

porosity tools. 2

Density tools use gamma rays to determine

porosity. Gamma ray scattering provi des an accu-

rate measurement of the average formation bulk

densi ty, and if the formation grain and fluid densi-

ties are assumed correctly, the total fluid-fill ed

porosity can be accurately 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 assumed a li thology effector the

wrong fluid density is assumed, whi ch occurs with

gas-filled pores.

Using Porosity Logs

Comparing one porosi ty measurement wi th another

leads to new informati on about the makeup of the

formati on. Traditional ly, neutron and density-

porosity logs are combined, sometimes by simple

averaging. In many cases, the lithol ogy effects on

the neutron porosity tend to cancel those on the

density porosity, so that the average derived poros-

ity is correct. If there are only two lithologies in a

water or oil filled formation, then porosity and the

fraction of each rock mineral can be determi ned

using a crossplot technique. I n gas zones, neutron-

derived porosity reads low, i f not zero, w hereas

density-derived porosity reads slightly high. This

leads to the classic gas crossover signaturea

useful feature.

NMR T2 distributions provide for flui d discrimi-

nation. Since fluids confined to smal l pores near

surfaces have short T2 relaxation times and free

fluids in large pores have large T2

relaxation

times, partitioning the T2 distributions allows dis-

crimination between the different fluid compo-

nents (next page, bottom) . Adding the amplitudes

of the observed fluid T2 components together gives

sOil in the pore space of a water-wet rock. The lackof contact between oil and the rock grain surfaceallows the oil to take its bulk relaxation time, whichfor low-viscosity oils will generally be longer thanthe shortened water relaxation.sInterlayer water and hydroxyls in clay structures. Clay minerals are hydrated sili-

cates of aluminum which are fine grained, less than 0.002 mm. The layers are sheetstructures of either aluminum atoms octahedrally coordinated with oxygen atoms andhydroxyls [OH]-, or silica tetrahedral groups. These octahedral (A) and tetrahedral (B)sheets link together to form the basic lattice of clay minerals, either a two layeroneof each sheet (AB), or a three layer (BAB) structure. In smectite clay, these latticessheets are then linked together by cations and interlayer water molecules. The hydrox-yls are seen as porosity by all neutron tools, but not NMR tools. The interlayer water,trapped between sheets of the clay lattice, is not producible.


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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 areproduced with high-strength permanentmagnets built into the tools (seePulse-Echo

NMR 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.

a total NMR porosity which usually agrees with the

density porosity in water-filled formations. In gas

zones, like the neutron porosity, NMR depends on

the total hydrogen content, and therefore reads

low. This l eads to an NMR gas crossover signature.

sWhat porosity toolsmeasure. NMRporosity tools candiscriminate betweencapillary-bound orclay-bound fluids bytheir short T2 compo-nents and free iso-lated fluids withlonger T2 compo-nents (top right). Bycontrast, neutronporosity tools aresensitive to the totalhydrogen content ofthe formation (left),and cannot distin-guish between fluidsof different mobility.

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 boreholeNMR logging tool.

5. Murphy DP: NM R 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,Transacti ons of the SPWLA 34 th AnnualLogging Symposium, Calgary, Alberta, Canada, June13-16, 1993, paper GGG.


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40 Oilfield Review

NMR in the Borehole

Borehole NMR measurements can providedifferent types of formation porosity-relatedinformation. First, they tell how much fluid

is 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 spacing

affects 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 e ffe ctivepor osity.8

H ow e ve r, clay-bound wa t e r, being moretightly bound, is believed to decay at amuch faster rate than was measurable withthese tools. Within the last ye ar, improve-ments in these tools enable a factor-of-tenfaster decay rate measurement. Now mea-suring T2 de c ay components in the 0.1 to0.5 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-dec ay modes. This was ach ieved 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.9This pulse sequence is

repeated 50 times to reduce the noise by afactor of seven. Now, this tool is sensitive tot ra n s verse decay components with T2 a sshort as 0.5 msec.The Schlumberger CMR tool has also had

hardware improvements and signal-process-ing upgrades.10The 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(nextpage). 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 t o tal poro s itym e a-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-

sCMR tool. The CMR tool (left) is 14 ft [4.3 m] long and is combina ble wit h ma ny otherSchlumberger logging tools. The sensor is ski d-mounted to cut through m ud-cake a ndhave good contact w ith the formation. Contact is enhanced by a n eccentralizing arm orby p ower cali pers of other loggi ng tools. Two strong internal perm anent m agnets 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 forma tion and stretches the length ofthe antennaabout 6 in. [15 cm ], providi ng the tool w ith excellent vertical resolution.The area in front of the antenn a does not contribute to the signal, w hich a llow s the tool tooperate in holes w ith a lim ited am ount of rugosity, simila r to density tools. The antennaacts as both transmitter and receivertransm itting the CPMG m agn etic pu lse sequenceand receivin g the pu lse echoes from t he 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 improvedT2 sensitivity of NMR porositylogs may permit accurate estimates of clay-b o u n d - water volumes for petrophy s i c a linterpretation, such as the calculation ofhydrocarbon saturation through Dual-Water

or Waxman-Smits models.A simple example from South A m e r i c a

illustrates 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 in

track 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 tra ck 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-e cho CMR tools. How e ve r, 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 the

T2 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.

sHow increased echo rate improves CMR ability to see early-time decay from small pore s.CMR tool w as run in a shallow Cretaceous Canadia n test w ell at th ree different echospacing s-0.32 msec, 0.28 msec and 0.20 msec. A s echo spac ing s decrease, the tota lobserved porosity (midd le track) read by the tool increases in the shaly int ervals, contain-ing small pores, because the ab ili ty to see the sub-3 msec T2 components (right track)increases with echo rate. This is verified by the increased CMR-200 bound flu id v olum e(BFV) curves (left track ). In th e tw o sand zones A and B, the long T2 components seen inthe tim e distributi ons correspond to increases in observed CMR free fluid (m idd le 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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42 Oilfield Review

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 tra ck 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 ( a b o ve right).Looking for gas with the traditional thermalneutron-density crossover is unreliable or

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

Fo r t u n a t e l y, 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 at

the top of this shaly sand, the CMR-derivedporosity drops, crossing below the density-d e r ived porosity. This is the NMR-densitylogging crossovera gas signature. Th eNMR 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,wh i ch assumed wa t e r-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.

sTotal porosity loggi ng w ith the PLATFORM EXPRESS tool differenti-ates sand s and shales. The porosity logs are shown in track 2 ofthe w ellsite display. Both neutron and density p orosity werederived assumi ng a sandstone ma trix. Total CMR porosity(TCMR) correctly finds the tightly bound shale porosity seen inthe short T2 distribu tions show n in track 3. The neutron porositylog reads too high in the shale interva l, Zone A, due to neutronabsorbers in the shale. The ga mm a ray and b ound-fluid porosity,BFV (all porosity with T2 below 12 msec) in track 1 show that theCMR m easurement provid es an al ternative m ethod for identify-ing shale zones.

sUsing total CMR porosity and d ensity to find gas. In track 2 th edeficit betw een total porosity (red curve) and density porosity(blue curve) in a shaly sand can b e used to identify a g as zone.The traditional neutron-density crossover is suppressed by theshaliness, which opposes the gas effect in the therm al-neutronlog (green curv e). The T2 tim e distribut ions show l arge contribu-tions from short relaxat ion tim es below 3-msec com ing from theclay -bound w ater in the shales. The gas corrected porosity,(dashed b lack curve) is alw ays less than the density porosityand greater than the total CM R 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 tra ck 2, and the volume of gas Vga s,shown in track 1, are derived (see Gas-Cor -

rected Po ro s i ty from Density-Po ros i ty andCMR Measurements, page 54).11The 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 wo r k shere, where the traditional neutron toold o e s n t, 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.

Fi n a l l y, 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( l e f t ). The interval contains shaly wa t e rzones 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, over l iesthe 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-msec

e f f e c t ive porosity log with the new totalporosity log demonstrates the improvementp r ovided 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, the

new 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.

sDetecting g as using total porosity loggin g w ith the PLATFORM EXPRESS tool. A dram aticimprovem ent in agreement b etween the CM R-200 total p orosity (solid bla ck), comp aredto the 3-msec CMR porosity (dotted b lack), and density porosity (red), shown in trac k 2, isobtained by in cluding the fast-decaying shale-bound porosity com ponents from the newCMR-200 T2 distribut ion show n in track 4. This enhances the abil ity t o use the CMR totalporosity and density-porosity crossover as a flag to detect gaspink -shad ed a rea in track2. Improvem ents in the signa l processing are obvious wh en the CMR-200 total b ound-fluid log (solid b lack ) is com pa red to the old 3 msec CM R bound-fluid log (dotted bla ck)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, Transactio ns of theSPWLA 38 th 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 log-

ging tools i s the use of an advanced pulse-echo

spin flipping scheme designed to enhance the

measurement. This scheme, first developed nearly

fifty years ago for laboratory NMR measurements,

works in the follow ing way.1

The Source Al l hyd rogen nucl ei in wate r

[H2O]; gas such as methane [ CH4]; and oil [CnHm]

are single, spinnin g, electricall y charged hydro-

gen nuclei protons. These spinning protons cre-ate magnetic fields, m uch like currents in tiny

electromagnets.

Proton Alignment When a s trong ex terna l

magnetic field from the large permanent magnet

in a l ogging tool passes through the formation

with fl uids containing these protons, the protons

align along the polarizing field, much li ke tiny bar

magnets or magnetic compass needles. This pro-

cess, called polarization, i ncreases exponentiall y

in time wi th a time constant, T1.2

Spin Tipping A m agne ti c pu lse fr om a radi o

frequency antenna rotates, or tips, the alignedprotons into a pla ne perpendicular to the polariza-

tion field. The protons, now aligned with their

spin axis lyi ng in a plane transverse to the polar-

ization field, are simi lar to a spinning top tipped

in a gravitational fiel d, and will start to precess

around the direction of the field. The now-tipped

spinning protons in the flui d wil l precess around

the direction of the polarization fiel d produced by

the permanent magnet in the logging tool (above).

The Effects of Pre cession The prec essi on f re-

quency, or the resonance frequency, is called the

Larmor frequency and is proportional to the

strength of the pol arization fi eld. The precessing

protons, stil l acting like small m agnets, sweep

out oscillating magnetic fields j ust as many radio

antennas transmit el ectromagnetic fi elds. The

logging tools have receivers connected to the

same antennas used to i nduce the spin-flipping

pulses. The antennas and receivers are tuned to

the Larmor frequency about 2 MHz for the CMR

tool and receive the tiny radio frequency sig-

nal a few mi crovoltsfrom the precessing pro-

tons in the formation.

A Faint Signal from the Formation In a per fec t

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

wi th others in the transverse plane a transverse

relaxation process. The time constant for thetransverse relaxation process is called T2, the

transverse decay time. Measuring the decay of the

precessing transverse signal i s the heart of the

NMR pulse-echo measurement.

Unfortunately, it is not a perfect world. The

polarization field i s not exactly uniform, and small

variations in this polarization field wi ll cause cor-

responding variations in the Larmor precession

frequency. This means that some protons will pre-

cess at different rates than others. In terms of their

precessional motion, they become phase incoher-

ent and will get out of step and point in different

directi ons as they precess in the transverse plane

(next page). As the protons collectively get out of

step, their precessing fields add together incoher-

ently, and the resonance signal de cays at an

apparent rate much faster than the actual trans-

verse relaxation rate due to the dephasing process

described above. 3

Spin-Flippi ng Produces Pulse Echoes A cl ever

scheme is used to enhance the signal and to m ea-sure the true transverse relaxation rate by revers-

ingthe dephasing of the precessing protons to pro-

Pulse-Echo NM R Measurem ents

sPrecessing protons. Hydrogen nucleiprotonsbehave like spinning bar magnets. Once disturbed fromequilibrium, they precess about the static magnetic field (left) in the same way that a childs spinning top

precesses in the Earths gravitational field (r ight).


12/24

Summer 1997 45

duce what is called a spin echo. This is done

applying a 180 spin flippingmagnetic pulse a

short tim eat half the echo spacinga fter the

spins have been tipped into the transverse planeand have started to dephase. By fli pping the spins

180, the protons contin ue to precess, in the same

transverse plane as before, but now the slowest

one is in fi rst 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 anecho) in the recei ver antenna. This process,

known as the pulse-echo technique, is repeated

many times; typically 600 to 3000 echoes are

received i n the CMR tool.

The T2 Resonance Decay The p ul se- echo

technique used in todays logging tools i s called

the CPMG sequence, name d after Carr, Purcell,

Meiboom and Gill who refined the pulse-echo

scheme. 4 It compensates for the fast decay

caused by reversible dephasing effects. However,

each subsequent echo will h ave an amplitude

that is slightly smal ler than the previous one

because of remai ning irreversibletransverse

relaxation processes.

Irreversible Relaxation Decay Rates Measur-

ing echo amplitudes determines their transverse

magneti zation decay rate. The time constant T2

characterizes the transverse magnetization signal

decay. The decay comes from three sources;

i ntrinsic 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 mi x of environmental

and tool effects.

Bulk-fluid relaxation is caused primarily by the

natural spin-spin magnetic i nteractions 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 fluctuat-

ing magnetic fi elds cause relaxation. The interac-

tion is most effective when the fluctuation occurs

at the Larmo r frequency, 2 M Hz for the CMR tool

a very slow motion on the molecular time scale.

Molecular moti ons in water and li ght oils are

much more rapid, so the relaxation is very ineffi-cient with l ong decay times. As the liqui ds

become more viscous, the molecular mo tions are

slower, and therefore are closer to the Larmor fre-

quency. Thus viscous oils rel ax relatively effi-

sPulse-echo sequence and refocusing. Each NMR measurement comprises a sequence of transverse mag-netic 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 pro-

tons by flipping them 180. This creates a refocusing of the dephased spins into an echo. The reversible fast

decay of each echothe 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 molec-ular interactions and has a characteristic 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 knownas the spin-lattice decay time. The name comes from solid-state NMR, where the crystal lattice gives up energy to thespin-aligned system.

3. The observed fast decay due to the combined componentsof irreversable transverse relaxation decay interactions andthe reversable dephasing effect is frequently called thefreeinduction 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 forMeasuring Nuclear Relaxation Times, The Review ofScientific Instruments29, no. 8 (1958): 688-691.


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46 Oilfield Review

To tal Po ro s i ty fo r Bett er Pe r m e a b i l i ty

A n sw e r sIn 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 am u ch better match to core porosity thanc o nventional porosity logging tools ( n ex tpag e , t o p ). In addition, permeability datad e r ived from CMR measurements are ofconsiderable value. Other sources of mea-suring this critically important reservo i rp a ra m e t e r, such as coring and testing,

invoke high cost or high uncertainty.Experience in these environments shows

that 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 a

large salt dome, provided an opportunity toevaluate fluid contacts in an established oiland gas field and determine hyd r o c a rb onproductivity in low-resistivity zones. Previ-ous deep wells on this flank encountereddrilling difficulties leading to poor- t o - f a i rboreholes 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 stra i g h t f o r wa r ddescription 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 wa t e r. 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

sGrain surface relaxation. Precessing protons diffuse about the pore space colliding with other protons andwith grain surfaces (left). Every time a proton collides with a grain surface there is a possibility of a relaxation

interaction occurring. Grain surface relaxation is the most important process affecting relaxation times. Exper-

iments 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 (r ight)

relaxation is slower.

sRelaxation time versus viscosity. The bulk relaxationof crude oil can be estimated from its viscosity at

reservoir conditions. T2 values are shown for various

echo spacings and have been computed for the CMR

tool with a 20 gauss/cm magnetic field gradient. Diffu-

sion-in-gradient effects, which depend on echo spac-ing, TE, dominate T2 rates for low viscosity liquids.

ciently wi th short T1 and T2 decay times (right). It

should be noted that for liquids w ith viscosity less

than 1 cp, T2 does not change muchand even

decreases for low viscosity. This i s due to the dif-

fusion-in-gradient mechanism, which i s strongest

for liqui ds with the largest diffusion coefficient

lowest viscosity. This effect is also enhanced by

long echo spacing. The diffusion-in-gradient

mechanism does not affect T1.5

Fluids in contact wi th grain surfaces relax at a

much higher rate than their bul k rate. The surface

relaxation rate depends on the ability of the pr otons

in the fluids to make mult iple interactions with the

surface. For each encounter with the grain surface,

there is a high probabilit y that the spinni ng proton

in the fluid wil l be relaxed through atomic-level

electromagnetic field interactions. For the surface

process to dominate the overall relaxation decay,

the protons in the fluid must m ake many random

diffusion (Brownian moti on) trips across the pores

in the formation (above). They colli de with the grain

surface many times until a rel axation event occurs.

Final ly, there is rela xation from diffusi on in the

polarization magnetic fi eld gradient. Because pro-

tons move around in the fluid, the compensation by

the CPMG pulse-echo sequence i s never compl ete.

Some protons will drift into a different field

strength during their motion between spin flipping

pulses, and as a result they wi ll n ot receive correctphase adjustment for their previous polarization

fiel d environment. This le ads to a further, though

not significantly large, increase in the T2 relaxation

rates for water and oil. Gas, because of its high di f-

fusion mobility, has a large diffusion-in-gradient

effect. This is used to differentia te gas from oi l. 6

The pulse-echo measurements are anal yzed in

terms of multiple exponentially decaying porosity

components. The amplitude of each component is

a measure of its volumetric contributi on to porosity.

5. Kleinberg RL and Vinegar HJ : NMR Properties of Reser-

voir 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.


14/24

Summer 1997

sPermeabili ty logg ing using CMR totalporosity in North Sea m ica ceous sand stones.A g ood m atch (track 2), between core- andCMR-derived perm eability using the defaultTimur-Coates equation, is common i n m anyNorth Sea reservoirs. This exam ple i s from anoil zone drilled with oil base mud.

sGas production in the Gulf of Mexico.Bim odal CM R T2 distribut ions in track 4 showeffects of oil-base mud invasion with long T2and l arge bound-fluid com ponents below the33-msec T2 cutoff. Neutron-density crossoverclearly show s gas zones. The low CMR sign alis due to the low hydrogen content and longpolarization time of the gas. The bound-fluidmeasurement was used with the resistivitydata to determine movable w ater in thelower resistivity zones.

47


15/24

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 vo l u m ederived from the resistivity logs. The upperthree sands were completed and the CMRtotal porosity, bound-fluid and permeabilitylogs allowed the operator to confidentlyp e r f o rate Zones A, B and C.1 3The initialproduction 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 lowe rsands, Zones D and E, have not been com-pleted because of downdip oil production.H ow e ve r, 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 thewa ter d r ive in a mature low - r e s is t ivity oil-

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

S e ve ral sandstone intervals, Zones A, Band C, are easily identified by their longerT2 distributions that may correspond tohydrocarbons isolated in water-wet rocks orlarge wa t e r-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 CMR

and 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-d e r ived 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 wa t e r. The low - r e s i s t ivity sand,Zone C, appears to contain some oil, butwith a large amount of free water mostlikely coming from the waterflood.

sELAN interpretation analysis. The CMR-resistivity interpretation suggests that there is nomova ble w ater in th e entire logged i nterval. The top th ree sand zones A, B and C, all w ithhigh p ermeabil ity determin ed by the CMR tool, track 2, produced 20 MMcf/ D of gas with780 B/ D condensate and no water. The reserves ind ica ted in th e lower sand Zone E w illbe 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. The

T2 cutoff is obvious, making free fluid and boundfluid easy to distinguish for Timur-Coates perme-ability calculations.


16/24

Summer 1997 49

The operat o r, 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,

s u ch 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 wa i ttime 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 ech o e s

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 NMRa n swerspermeability 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

sWellsite PLATFORM EXPRESS display. This exam ple shows long T2 comp onents in the low -resistivity pay sand, Zone C. This appears to the CMR tool to contain mostly free water inlarge pores, but could contain i solated hy drocarbons with long T2. The upper tw o zones

have hig h resistivity and potentially c ontain hy drocarbons. 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 wa it tim e) of the hyd rocarbons.


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50 Oilfield Review

sSolving the mystery with ELAN interpre-tation. High permeability d erived from theCMR tool, track 2, with w ater satu ration,track 3, and irreducibl e water anal ysis,track 4, show that the low-resistivity p aysand in Zone C will p roduce only water,probably from the flood d rive. The uppersand, Zone A, contain s oil w ith only a littl efree wa ter. Zone C tested 100% sal t w ater,w hereas the upper zone is producing100 BOPD with a low water cut. Note theexcellent agreement between the CM Rpermeability and core-derived perm eabil-

ity (black circles) in track 2.

sBound-fluid logg ing w ith wa ter-free pro-duction in a long oil-wat er transition zone.CMR readin gs indicate w ater-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 l og-gin g speeds are fast, long T2 componentsare seen in the CMR T2 distributions.


18/24

Summer 1997 51

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 pay

often lead to uncertainty about the mobilefluid being oil or water, or both (prev io u spag e, botto m). 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 wa t e rwill 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 wa it

time of 0.4 sec and 600 echoes. This wellwas drilled with an oil-base mud, wh i chcreated 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 wouldh ave 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 to

differentiate 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 thePL AT FORM EXP R E S S 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 from

the 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 core

permeabilities and porosities measured later,shown as circles in tracks 2 and 4.

Re p e a ta b i l i ty of Fast BFV Lo g g i n g Th i sexample shows that accurate and repeatablebound-fluid volumes and permeabilities can

sPLATFORM EXPRESS-CMR wellsite quicklook. The field interpretation results from high-speedCMR loggin g enab le the operator to qui ckly id entify that hydrocarbon pa y Zones A andB, have high permeability, track 2, and high potential for water-free production b ecauseall t he wa ter in the interval, a s shown i n track 4, is either clay-bound or irreducib le. Thewellsite interpretation results also compa red well w ith core ana lysis obtained l ater.

14. Scott HD, Thornton JL, Olesen J-R, Hertzog RC,McKeon DC, DasGupta T and Albertin IJ: Responseof a Multidetector Pulsed Neutron Porosity Tool,Transactio ns of the SPWLA 35th An nual Logging

Symposium, 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, Transactio ns ofthe SPWLA 35 th Annual Logging Symposium, Tulsa,Oklahoma, USA, June 19-22, 1994, paper EEE.


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52 Oilfield Review

be measured at high logging speeds(abo ve). 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. The

three bound-fluid BFV logs, computed with

default 33-msec T2 cutoff and five - l e ve lstacking, are shown in track 1. They agreewell with each other, having a root-mean-square error on the bound-fluid vo l u m e sabout of 1.2 p.u., which is comparable tothe typical statistical error found in othernon-NMR porosity logs. The BFV curve scorrelate well with the gamma ray except inZones A and B, with the shortest T2 values,where the relaxation may be too rapid to beseen by the CMR tool.

Permeability estimates, in tra ck 6, werebased on the standard Tim u r-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 give

better 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, thed rainhole 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 investigate

the 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

sRepeatabi lity of bound-fluid loggi ng. Logs and T2 distributions from three runs at 300,1800 and 3400 ft/ hr in the sam e well show how w ell the bound-fluid volum es, track 1,agree even at fast logging speeds. The permeabil ity results, track 6, from CM R bound-fluid loggi ng overlie even at t he highest logging speeds. The T2 distributions are sim ilar,though th e peaks in the sands seem to cha nge somew hat, becau se there are not enoughechoes in the fast logging measurem ent to comp letely cha racterize the slower relax-

ati ons. The longest T2 comp onents disappear in th e fast-logging mode.

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


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Summer 1997 53

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 A g i p .1 9 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 ther o ck formation. Fine silt dra s t i c a l l ydecreases permeability and the ability of a

reservoir 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.

A c cu ra cy in determining silt volume, as

well as a host of other parametersperme-a b i l i t y, 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-

sAvoiding water production in thinly layered gas sands with CMR data combined withother coherent loggin g m easurements. There are nearly 20 ga s pay-sand s showi ng in th isinterval , all showing sim ilar log p rofile charac teristicsseparati on of the EPT dielectricpropagati on tim e TPL, and attenuation EATT, logs in track 1 and the free-fluid volum esfrom CM R and epitherma l neutron porosity, in track 4. The interpretation results identifythree Zones (A, C and the lower pa rt of Zone F) that contain free w ater in t he reservoirs.The CMR tool respond s w ell to thi n b eds (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,Transacti ons 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 O ffshore Medi terraneanConference, Milan, Italy, March 19-21, 1997,paper 993.


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54 Oilfield Review

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 (orirreducible water), and movable water (nextp age, t o p ). By subtracting the irreduciblewater measured directly by the CMR bound-

fluid log from total volume of water, Sw,computed fromRtafter 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 correlation

between the EPT and CMR curves. Th esequence 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 other

coherent logging measurements, such asdielectric, Litho-Density, microresistiv i t y,

neutron capture cross sections and epither-mal neutron porosity, in providing a criticale valuation and complete interpretation inthese complex formation environments. TheLitho-Density tool is needed for lithologytodetermine the T2 cutoff for CMR bound-fluid

In zones containi ng unflushed gas near the bore-

hole, total CMR porosity log TCMR underesti-

mates total porosi ty because of two effects: the

low hydrogen concentration in the gas and insuffi-

cient polarization of the gas due to its long T1

relaxation time. On the other hand, in the pres-

ence of gas, the density-derive d 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 logs the

NMR gas signature. The method of identifying gasfrom t he DPHI/TCMR defici t does not require that

the gas phase be polari zed.1

The advantages of this m ethod of detecti ng gas

include:

faster l ogging in m any environments since the

gas does not have to be polari zed2

m ore 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 porosit y, gas-corr, and gas bulk-

volume, Vgas, equations are derived from a petro-

physical m odel for the formation bul k 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, b is the l og measured bulk-

formation density, ma is the matrix density of the

formation, f is the density of li quid phase in the

flushed zone at reservoir conditions, g is the den-

sity of gas at reservoir conditions, and is the

total formation porosity.

(HI)g is the hydrogen indexthe volume fraction

of fresh water that would contain the same amount

of hydrogen of 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 saturation.

accounts for the polar-

ization of the gas, where Wis wait ti me of the CMR

tool pulse sequence, and T1,g is the l ongitudinal

relaxation tim e of the gas at reservoir conditions.

To simplify the algebra, a new parameter,

, is i ntroduced, and formation bulk

density is elim inated by introducing density

derived porosity, .

Solving these equations for the gas-corrected

porosity, gas-corr, one gets:

,

and for the volume of gas, on e gets:

The gas saturati on can be obtained from these

equations by sim ply dividing the latter by the for-

mer. Note that the gas-corrected porosity, gas-corr,

is the NMR analog of the neutron/density log

crossplot porosity, and is always less than DPHI

and greater than TCMR/(HI) f.

Bob Freedm an

Gas-Corrected Porosity from Density-Porosity andCMR Measurem ents

20. Kenyon WE, Day PI, Straley C and Willemsen JF: AThree-Part Study of NMR Longitudinal RelaxationProperties of Water-Saturated Sandstones, SPE For-mation Evaluation3 (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 polarizeall the liquids, including formation water and mud filtrate.

2. Oilbase muds are the exception and require long wait timesdue to the long T1 relaxation time of oil filtrate.


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Summer 1997 55

loggingand the salinity independent CMRwater volume is used to correct the dielectricand resistivity logsused for fluid saturation.

Identi f icat i on of O i l V i s c o s i ty and Ta r

DepositsA trend to produce heavy-oil froms h a l l ow reservoirs is creating the need todetect high viscosity oil and tar deposits. Fre-quently, due to the shallow depths and thecomplex filling history of the structures, reser-voirs were charged, then later breached andrecharged. This results in significant changesin the properties of the hy d r o c a r b o n s

throughout the reservoir sections. One way todistinguish and identify these oils is to mea-sure their viscosity in situ using bulk relax-ation times from the CMR data. The bulkrelaxation rates of different oils can be mea-sured with reasonable accuracy, between 2and 10,000 cp, using the CMR tool.21

Field examples show that CMR log-d e r ived viscosities match drillstem test-derived values. It is important to determinewh ich part of the T2 signal distribution is

from the oil bulk relaxation decay. In clean,coarse sands containing high-viscosity oil,this is a straightforward process, because theoil, having a fast decay, is isolated from thewater-wet rock having a slower decay, and

surface relaxation has little effect on the fastbulk oil decay. For low-viscosity oils in fine-grained rocks, the bulk oil relaxation ratesare much slower and can easily be sepa-rated from the water-saturated rock signal.

In some settings, over geological time, oilshave come into contact with wat e r-b or nebacteria that produce impermeable sealstar deposits at oil-water contacts.22Th es e

reservoirs may receive a further oil charge,wh i ch encases a tarry zone inside thehydrocarbon zone. In such a position, thetar zone could have a dramatic effect on themanagement of the field during production.The tar, surrounded by other hy d r o c a r-

bons, appears similar to the surrounding flu-

ids when logged with non-NMR techniques.Even when cored intervals are available, thetar may be overlooked if the core samplesare cleaned, as they traditionally are, beforeanalysis. However, the CMR signature in atar zone is quite clear and distinct from thatof more mobile hydrocarbons or wa te r. It

has been suggested that long hydrocarbonchains within the tar cause it to behavealmost like a soliddramatically shorteningthe T2 response. Tar is detected by thereduction in NMR porosity.

An example from the North Sea shows theclear tar detection signaturemissing poros-ity and short T2 decays (left). The well wasdrilled with an oil-base mud through several

oil and water zones identified in track 2.

sSil t volume interp retat ion using EPT, APT an d CM R logs. The dat ain the crossplots come from a m ixtu re of sands, m ica a nd feldspar.EPT attenuation, EATT, and propag ation tim e, TPL, are crossplotted(left) along with the difference between APT epit herma l neutronporosity and CMR 3-msec effective porosity, shown as a Z-axis dis-crim inator. There are tw o clusters of points. One is for the silty sandw here ga s is present (lower c luster). There is a depart ure from thesandstone line when silt increases. The second cluster is in severalnonpa y reservoirs w here clay m ineral s, associated w ith fi ne silt,form the shales. The APT-CMR effecti ve porosity di fferenceincreases in proportion to the clay content due to the cla y-boundw ater. Since the ga s content is properly contr olled on th e EPT cross-plot, the dielectric data are used to apply accurate gas corrections

on the CMR porosity logs. On the CMR stand-alone crossplot (right),the silt in dex i ncreases wi th the boun d-fluid values. The scatter inthe CMR data is a gas effect induced by low polarization an d v ari-ation i n hy drogen ind ex. The APT-CMR difference porosity is usedag ain for Z-ax is discrimi nation a nd the tw o clusters are identified.Fine silt in the shales follows the 45clay trend line dow nw ards tothe clay endpoint at th e origin. Except for the ga s scatter on CMRporosity, the crossplot confirm s the hig h coherence exi stingbetw een the three logs.

sTar zonesdetected by theCMR tool. Inw ater, gas or oil,

the CMR tool ha sa clear tar signa -ture as seen inZone Ca sup-pression of thelong T2 compo-nents (track 5)and a reducedtotal porosity(track 4). In thiswell the CMR toolis able to con-firmby the pres-ence of large T2contributions fromoil and no reduc-tion in total CMR

porositythat thelower oil zone(Zone E) is not tar,but m obile oil,wh ich could betrapped by alocal stratigraphicclosure.


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56 Oilfield Review

When the tar is in a conductive water zone,as it is in this example, it can be easily identi-fied by resistivity measurements. However,tar is frequently located in hy d r o c a r b o nzones, where there is no resistivity contrastbetween tar and nontar hydrocarbon inter-vals. In such cases, NMR is the only routinelogging measurement that can identify the tar.

Like tar, heavy oil has a short T2 relaxationdecay time, so detecting heavy oil is similarto detecting tar, except that the heav y - o ilrelaxation times are sufficiently long to becaptured by the total porosity response of

the CMR-200 tool. Essentially, the heavy-oilT2 contribution shifts the signal below the3-msec T2 cutoff, but not below the 0.3-msecdetection limit of the CMR-200 tool (right).This example is from a heavy-oil reservoir

in California. The low-gravity (12 to 16API)oil is produced by a steam-soak injectionmethod. The logs show that all porositylogstotal porosity, 3-msec effective poros-ity, density and neutron porosityagree inthe lower wet Zone B. The CMR porosities

agree in the wet zone because the formationdoes not have T2 values below 3-msec asso-ciated with clay-bound porosity or microp-o r o s i t y. In the upper oil-bearing Zone A ,total CMR-porosity reads about 5 p.u. higher

than the 3-msec porosity over most of thisinterval, because the heavy oil has consider-able fast relaxing components below the3-msec T2 s e n s i t ivity limit of the early3-msec porosity measurement. The differentresponses of the two CMR porosity measure-ments to the heavy oil provide a clear delin-eation of the oil zone and show the oil-water contact between Zones A and B.

Logging Saves Dol larsCombining geo-chemical logs with CMR-derived permeabil-ity and free-fluid data, a major oil companywas able to select only productive zones fors t i m u l a t i o n s aving $150,000 in a SouthTexas well.23The objective was to complete,

including fracture simulation, three high-resistivity potential pay zones at the bottomof the well. Total porosity from CMR isapproximately 10 to 15 p.u. in all zones,where free fluid varies from 1 to 10 p.u.

However, spectral data from the ECS Ele-mental Capture Spectrometer sonde indi-

cate significant differences in clay and car-

bonate cement volumes between zones( n ex t page).2 4The two Zones, A and C,exhibit lower clay and higher carbonatecalcite cementcontent than Zone B.

Resistivity measurements and CMR-derivedbound fluid and permeability correlatewith the lithology changes. Increased clayvolumes in Zone B represent shales thatare clay - r i chsuggesting a lower deposi-tional rate.These important lithological differences

have significant influence on the electrical,mechanical and fluid flow properties of thereservoir intervals. Bound fluid and free flu-

ids, measured by the CMR tool, vary widelyfor any given porosity, and have a largeimpact on the permeability.

Based on the logging results, Zone C was

p e r f o rated and fracture stimulated and iscurrently producing gas at a rate of6 MMcf/D with a very low water cut of10 BWPD. The pessimistic estimates of freefluid volumes and permeability from the

sHow to see a heavy -oil w ater contact w ith t otal CMR porosity. Theoil-bearing Zone A and the oil-water contact b etween Zones A andB are clearly d elineated by the separa tion between the total CM Rporosity log, TCMR, and t he 3-m sec porosity log , CMRP, shown intrack 3. The oil-water contact is confirm ed by the resistivity logs intrack 2. The large heavy oil contrib ution to the total porosity ca n beseen by short relax ation d ecay com ponents above the oil-wa ter

contact in th e T2 distribution in track 4.

23. Horkowitz JP and Cannon DE: Complex ReservoirEvaluation in Open and Cased Wells,Transactions

of the SPWLA 38 th Annual Logging Symposium,Houston, Texas, USA, June 15-18, 1997, paper W.

24. Herron SL and Herron MM: Quantitative Lithology:An Application for Open- and Cased-Hole Spec-troscop

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