SPWLA 39th Annual Logging Symposium, May 26-29, 1998 -1- A CASE STUDY DEMONSTRATING HOW NMR LOGGING REDUCES COMPLETION UNCERTAINTIES IN LOW POROSITY, TIGHT GAS SAND RESERVOIRS W. Scott Dodge, Exxon Exploration Company; Angel G. Guzman-Garcia, Exxon Production Research Company; Dave A. Noble, Exxon Company U.S.A.; Jack LaVigne, Schlumberger Well Services; Ridvan Akkurt, NUMAR ABSTRACT Nuclear Magnetic Resonance (NMR) logging in low permeability gas reservoirs has been used to assist standard formation evaluation techniques in identifying productive reservoirs from those that lead to tight tests or produce formation water. By incorporating NMR logging into the standard logging suite, improved completion decisions are made regarding perforation intervals, hydraulic fracture program design and accurate estimates of producible gas. The deep gas reservoirs of the Vicksburg trend in this study contain complex clastic mineralogy derived from igneous rocks. Transport, deposition, and diagenesis play an important role in the producing characteristics of these reservoirs. Burial and diagenesis lead to low- porosity reservoirs with permeability in the range of 0.01 to 1 mD. Diagenesis of lithic rock fragments and feldspars creates significant quantities of micro- porosity, which degrades reservoir quality. The micro- porous rock holds large amounts of non-producible formation water, yet shows up as high water saturation in standard log estimates. Therefore, when conventional logging estimates of porosity and water saturation are used, it is not clear which reservoirs will produce gas free of formation water or not produce at all because of low permeability. NMR technology provides additional information on irreducible water-filled porosity and quantitative reservoir permeability not available from standard logging tools. In cases where the wells are drilled with oil-based mud and formation water resistivity is not known accurately, NMR reduces the risk of completing zones, which produce water while identifying tight gas zones, by the absence of oil-based mud filtrate in the flushed zone. When NMR measurements are combined with log-derived measurements of porosity and water saturation, both producible porosity and permeability thickness for these reservoir sands can be quantified. This paper is a case study showing the benefits of NMR logging and core analysis in low porosity, gas-bearing sandstones. INTRODUCTION The Vicksburg trend is one of the most active plays for natural gas in the United States and is one of the most difficult formations to evaluate stratigraphically, mineralogically, and petrophysically. Determining net pay, reserve assessment and where to complete to maximize economic return on investment are challenging tasks for petroleum geologists and engineers. Figure 1 Region of interest The Lower Oligocene Vicksburg natural gas field trend, runs in a north-east to south-west direction between the Vicksburg and South May fault systems of South Texas, as is shown in Figure 1. Sands coarsen upward in deltaic sequences and are overlain by shallow marine shales. Although regional structural dip is Southeastward (toward the Gulf of Mexico), most of the Vicksburg gas fields dip westward with structural roll into large growth faults. Rapidly expanding sedimentary sand deposits form depositional wedges where natural gas reservoir sands are found. Productive gas reservoirs have been identified between 6,000 and 18,000 feet in the trend, and producible porosity ranges from 9 to 24 p.u. Water saturation in TEXAS VICKSBURG FAULT SOUTH MAY FAULT
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SPWLA 39th Annual Logging Symposium, May 26-29, 1998
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A CASE STUDY DEMONSTRATING HOW NMR LOGGING REDUCESCOMPLETION UNCERTAINTIES IN LOW POROSITY,
TIGHT GAS SAND RESERVOIRS
W. Scott Dodge, Exxon Exploration Company; Angel G. Guzman-Garcia, Exxon Production Research Company;Dave A. Noble, Exxon Company U.S.A.; Jack LaVigne, Schlumberger Well Services; Ridvan Akkurt, NUMAR
ABSTRACT
Nuclear Magnetic Resonance (NMR) logging in lowpermeability gas reservoirs has been used to assiststandard formation evaluation techniques in identifyingproductive reservoirs from those that lead to tight testsor produce formation water. By incorporating NMRlogging into the standard logging suite, improvedcompletion decisions are made regarding perforationintervals, hydraulic fracture program design andaccurate estimates of producible gas.
The deep gas reservoirs of the Vicksburg trend in thisstudy contain complex clastic mineralogy derived fromigneous rocks. Transport, deposition, and diagenesisplay an important role in the producing characteristicsof these reservoirs. Burial and diagenesis lead to low-porosity reservoirs with permeability in the range of0.01 to 1 mD. Diagenesis of lithic rock fragments andfeldspars creates significant quantities of micro-porosity, which degrades reservoir quality. The micro-porous rock holds large amounts of non-producibleformation water, yet shows up as high water saturationin standard log estimates. Therefore, whenconventional logging estimates of porosity and watersaturation are used, it is not clear which reservoirs willproduce gas free of formation water or not produce atall because of low permeability.
NMR technology provides additional information onirreducible water-filled porosity and quantitativereservoir permeability not available from standardlogging tools. In cases where the wells are drilled withoil-based mud and formation water resistivity is notknown accurately, NMR reduces the risk of completingzones, which produce water while identifying tight gaszones, by the absence of oil-based mud filtrate in theflushed zone. When NMR measurements are combinedwith log-derived measurements of porosity and watersaturation, both producible porosity and permeabilitythickness for these reservoir sands can be quantified.This paper is a case study showing the benefits of NMRlogging and core analysis in low porosity, gas-bearingsandstones.
INTRODUCTION
The Vicksburg trend is one of the most active plays fornatural gas in the United States and is one of the mostdifficult formations to evaluate stratigraphically,mineralogically, and petrophysically. Determining netpay, reserve assessment and where to complete tomaximize economic return on investment arechallenging tasks for petroleum geologists andengineers.
Figure 1 Region of interest
The Lower Oligocene Vicksburg natural gas field trend,runs in a north-east to south-west direction between theVicksburg and South May fault systems of SouthTexas, as is shown in Figure 1. Sands coarsen upwardin deltaic sequences and are overlain by shallow marineshales. Although regional structural dip isSoutheastward (toward the Gulf of Mexico), most ofthe Vicksburg gas fields dip westward with structuralroll into large growth faults. Rapidly expandingsedimentary sand deposits form depositional wedgeswhere natural gas reservoir sands are found.
Productive gas reservoirs have been identified between6,000 and 18,000 feet in the trend, and producibleporosity ranges from 9 to 24 p.u. Water saturation in
TEXAS
VICKSBURG FAULT
SOUTH MAY FAULT
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high-quality reservoirs may be as low as 30 s.u. butrecent development drilling in the trend is identifyingpay with water saturation as high as 60 s.u. Energycompanies are currently pursuing lower qualityVicksburg reservoirs with permeability of 0.01 to 1.0mD.
Massive hydraulic fracture stimulation of one hundredthousand to four million pounds of proppant are used toenhance flow rates and increase the total recoverablegas reserves. The difficult mineralogy, high watersaturation, and low permeability make the economicsand mechanics of completion decisions complicated.
This paper reviews quantitative petrographic coreanalysis results prior to the NMR case study to showthe complexity of these reservoir sands.
APPLICATION OF NMR IN FORMATIONEVALUATION
NMR can provide information to the petrophysical-logging suite formerly available only from coremeasurements. Basic NMR measurements used in thisstudy are:
Producible Porosity (Free Fluid Index)Bulk Volume Irreducible Porosity (BVI)PermeabilityPore size distribution (T2 distribution)Fluid Identification (gas vs. producible water)
BACKGROUND
Nuclear Magnetic Resonance measures the fluid-filledporosity of rocks by stimulating the hydrogen atomsassociated with water and hydrocarbon in the porespace. The hydrogen atoms are stimulated with astrong magnetic field and a series of radio-frequencypulses. Removal of the radio-frequency stimulationgenerates a measurable decay of hydrogenmagnetization, known as a CPMG spin-echo train(Carr, et. al., 1954; Meiboom, et. al., 1958), asillustrated in Figure 2. The decay of the magnetizationprovides information on the amount, type, anddistribution of fluids filling the pore space.
INTERPRETING THE NMR SIGNAL
The maximum amplitude of the spin-echo trainrepresents the relaxation decay of the NMR signal. Theamplitude envelope of the NMR signal exhibits anexponential decay that can be deconvolved to obtain thefollowing information:
T2 AND PORE SIZE
The relaxation-time constant (T2) associated with theexponential decay of the magnetization is an indicatorof pore-size distribution.
Each NMR signal has initial amplitude that isproportional to the total amount of hydrogen. TheNMR signal coming from hydrogen in a single smallpore results in a low amplitude response at a short T2.The signal from hydrogen in a single large poreprovides a higher amplitude response at a long T2.
Figure 2 NMR CPMG spin-echo response
20 40 60 80 1000
Am
plitu
de (
mV
)
Time (msec)
T2 DISTRIBUTION
The NMR signal amplitude provides a relativeindication of the hydrogen content having a givenrelaxation time, T2. The T2 amplitude distribution for afully water-saturated sample is analogous to a pore-sizedistribution.
Figure 3 shows an amplitude distribution where half ofthe NMR signal is associated with small pores, or lowT2 values; and the remainder of the signal is attributedto hydrogen residing in larger pores, or large T2 values.
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POROSITY
NMR measures fluid-filled porosity without the need toknow anything about the rock matrix. The amplitude ofa proton NMR measurement is directly proportional tothe amount of fluid in the material investigated, andcorresponds to the total area under the curve Figure 3.
BOUND AND PRODUCIBLE FLUIDSATURATIONS
The producible-porosity or free-fluid index (FFI) isdetermined by applying a cut-off to the T2 amplitudedistribution. Free fluids are represented by that part ofthe distribution to the right of the vertical cut-off line,as shown in Figure 3. The T2 cut-off was determined bycorrelating the free-fluid volume with the volume offluid centrifuged from a sample. For this sandstonesample, a T2 cut-off of 40 milliseconds was determined.For carbonate samples the cut-off value is generallyhigher, e.g., 92 milliseconds (Straley, et. al., 1991;Chang, et. al., 1994).
The bound-fluid volume is the area under the T2
distribution to the left of the cut-off in Figure 3.
PERMEABILITY
NMR does not directly measure permeability; but NMRdoes measure petrophysical parameters that can be usedto predict permeability. Using these parameters,empirical permeability models have been developed;these simple models are valid for single-phase poroussystems with low clay content and without secondaryporosity (Prammer, et. al., 1994).
At the current time, such empirical permeabilityequations are not applicable to all formations. Theequations should be used semi-quantitatively and aftercalibration with core.
NMR LOG JOB PLANNING
Candidate screening and pre-job planning are twocritical components identified by Exxon to obtain asuccessful NMR log (Akkurt, et. al., 1996; Morriss, et.al., 1996). Starting with a well-defined set of formationevaluation objectives, the process involves optimizationof the acquisition parameters and requires closecooperation between the energy and service companies.
The NMR log objectives for the South Texas wellswere the determination of bound-fluid, free-fluid andpermeability. The most important acquisitionparameter was the wait time (Tw). Logging in oil-basedmud at high temperatures required Tw varying from 3 to
9 seconds, resulting in logging speeds between 200 and300 ft/hr.
Despite logging in a high-pressure, high temperatureenvironment (325 oF), the formation evaluationobjectives were easily met.
PETROPHYSICS PROGRAM DESIGN (LOGAND CORE)
A comprehensive petrophysics program was designedso that the clastic gas reservoirs with complexmineralogy and low permeability could accurately beevaluated for producibility and identification ofcompletion intervals. Wells drilled in the pastencountered severe borehole washouts that degradedlog quality for most porosity measuring devices. Thefirst well in the recent drilling program was drilled withsynthetic oil-based mud (OBM) to improve boreholestability. This was very successful, resulting in little tono borehole enlargement through the primaryreservoirs.
PETROPHYSICS LOGGING PROGRAM
The petrophysical wellbore logging program consistedof the following tools with a description of themeasurement objectives of each in Table 1.
Table 1 Petrophysical well logsLOGGING TOOL MEASUREMENTArray Induction High resolution resistivityLitho-Density Bulk densityAccelerator PorositySonde
Epithermal neutronporosity, Capture X-sect
Natural GR Spectroscopy Potassium, Thorium,Uranium
Array Sonic Compressional SlownessFormation Micro-scanning Imager
To interpret reservoir quality and producibility fromwireline logs, 160 feet of whole core and 48 rotarysidewall cores were cut in the first NMR logged well.A core analysis program was designed to quantifyformation petrography, petrophysics and reservoirengineering rock properties.
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PETROGRAPHY AND NMR PETROPHYSICALRESULTS FROM CORE ANALYSIS
MINERALOGY, MORPHOLOGY AND MICRO-POROSITY OF RESERVOIR SANDS
A petrographic study including thin-sectionphotomicrographs, point count analysis, scanningelectron microscope images (SEM), grain-size analysis,X-ray diffraction/X-ray fluorescence, MINQUANT andSEM MICROQUANT were performed on end-cutsfrom all core plugs that underwent NMR core analysis.A significant number of detrital and diagenetic mineralswere identified that contained micro-porosity.
An example of a good-quality reservoir rock isdescribed in detail in the following analyses. Thissample is from the Well C at a depth of xx208 ft, whichis shown on the logs of Figures 13 and 14. The coreplug sample permeability was 1.3 mD and porosity was16 p.u. A thin-section photomicrograph from thissample is shown in Figure 5. The sample is describedas arkosic sandstone containing 3 percent quartz, 31percent feldspar, and 27 percent rock fragments withthe remainder as pore filling cement and clay. Thethin-section shows good porosity with significantquantities of yellow-stained feldspars and dark brownvolcanic rock fragments. A unique property of thesesands is the high concentration of diagenetic feldsparovergrowths, with 14 volume percent in this sample.
An SEM photomicrograph shown in Figure 6 illustratesabundant diagenetic pore-filling chlorite as well asfeldspar overgrowths. MINQUANT (Chakrabarty, et.al., 1997), a quantitative bulk rock mineral analysisbased on XRD/XRF measurements and a techniquedeveloped at Exxon Production Research Company,shows the mineral concentration in weight percent ofthis same sample in Table 2. The contribution of bothpotassium feldspar and albite makes up 51 weightpercent of the rock while the total clay content is 9percent.
Although the visible porosity point counted in thissample is only 3 p.u. the measured core porosity is 16p.u. This discrepancy between point-count porosity andcore-helium porosity suggests there is significantmicro-porosity in this sample. An accurate method,which measures intra-granular micro-porosity,developed at Exxon Production Research Company, iscalled SEM MICROQUANT. A thin-sectionphotomicrograph from the same sample is shown in
Figure 7. Grains labeled a, b, and c are felsic volcanicrock fragments, grains d and e are clay-rich rockfragments, and grain f is plagioclase feldspar. Theback-scattered electron SEM image of the same thin-section is shown in Figure 8.
A gray scale image analysis technique is performed oneach individual grain to measure the micro-porosity.Once a database of micro-porosity by grain type isdeveloped, the results can be used in a forwardpetrophysical mineral model to measure total micro-porosity from well logs.
Corrected thin-section porosity compares well to corehelium porosity by adding the product of the measuredmicro-porosity for each grain type times the fractionalamount of that grain present in a sample Figure 4.
Figure 4 Thin-section correction for micro-porosity
NUCLEAR MAGNETIC RESONANCE CALIBRATIONOF IRREDUCIBLE WATER AND PERMEABILITY
One of the strengths of NMR in formation evaluation isthe ability to simulate logging conditions in thelaboratory using NMR spectrometry on core. Whenmaking NMR measurements on core, it is important todesign the experiments to have the same acquisitionparameters as the logging tool if the goal is core-to-logcalibration. Specifically magnetic field strength(homogeneous or gradient), echo spacing, recoverytime and the CPMG pulse sequence should beequivalent.
A laboratory T2 relaxation distribution for the samplefrom xx208 feet fully saturated with OBM filtrate andformation water is shown in Figure 3. The bi-modal T2
distribution indicates that this sample with 9 percentclay contains both large pores and small pores. Thesignal amplitude represents clay and capillary boundirreducible water less than 40 msec.
0
5
10
15
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0 5 10 15 20 25
THIN-SECTION (TS) POROSITY (p.u.)
PLU
G P
OR
OS
ITY
(p.
u.)
.
TS + MICQ POROSITY
TS POROSITY
micro-porosity
1:1
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Figure 6 SEM photo-micrograph shows pore-filling 5% diagenetic chlorite and 13% feldsparovergrowths.
Figure 7 Thin-section photomicrograph of ahighly micro-porous volcanic, clay-rich rock.
Figure 8 Backscatter SEM image used in SEMMICROQUANT analysis.
Figure 5 Thin-section photomicrograph of a 1.3mD arkosic sandstone. Quartz 3%, Feldspar31%, Lithics 27%, Cements and Clay 26%.
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Air-brine drainage capillary pressure measured at 50 psiyields an irreducible water saturation of 49 s.u. for thissample. NMR irreducible water saturation measured oncore plugs containing OBM filtrate and connate waterobtained a calibration to capillary pressure by using a40 msec T2 cut-off (Shafer, et. al., 1998). Calibration ofNMR T2 cut-off time to drainage capillary pressurebrings equivalence of NMR FFI to producible porosity.Producible porosity is defined as the pore volumeavailable to hydrocarbon emplacement (Dodge, et. al.,1996).
NMR permeability has been calibrated to airpermeability at net confining pressure with a modifiedCoates relationship,
...................... (1)
so that the split between FFI and BVI for the purposesof permeability calibration are obtained with a 10ms T2
cut-off which is discussed by Shafer, 1998.
CASE STUDY EXAMPLES
This section presents nine different reservoir examplesfrom South Texas. Some examples contain known ortested water sands, six of the examples were productiontested and contain NMR logs. Test results from thewells in this case study are shown in Table 3.
Well A, drilled and tested in a different reservoir thanthe other examples, illustrates the difficulties inidentifying productive gas reservoirs from thosecontaining mobile water. The conventional logs shownin Figure 9 indicate the reservoir to be gas bearingbecause of the good resistivity response and mud logshows in 10 to 15 p.u. sands. Because the formation
water is fresh, it is difficult to discriminate water fromgas based on resistivity.
The well was first completed over a 14-ft interval in the30HL reservoir. A 100,000-lb. proppant frac waspumped with 300 bbls of frac fluid. The well on testproduced 750 Mcf/d and 800 BWPD.
The 30HL sand was deemed to be uneconomic and wasisolated by a bridge plug. The 30HU reservoir sandwas then completed over a 27-ft interval. A 50,000-lb.proppant frac was pumped and the well was flow testedat a rate of 370 Mcf/D and 70 BWPD. To be economic,these wells must produce upward of 2 MMcf/d withlittle to no associated formation water.
WELL B, H390 RESERVOIR, CORED GAS SAND
Well B is drilled in an up-dip structural position toknown gas production and contains 92 ft ofconventional core as shown in Figure 10. Drilling tookplace before NMR logging in this field. The H390reservoir is a primary successful gas producer and willbe shown in the next three well examples with NMRlogs.
The reservoir has been characterized previously bypetrography, SEM, MINQUANT and SEMMICROQUANT data and shown to be highly micro-porous because of diagenetic processes occurring in this
7.1
10
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=
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msNMR BVI
FFIk
φ
x100
x000
30HL
x100
x000
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0.25
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90 in Resisitivity
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30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
x950
750Mcf/D
800BWPD
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30HU
370Mcf/D
70BWPD
Figure 9 Well A produced significant watervolume from two separate test intervals.
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reactive feldspar and lithic-bearing sandstone.Significant amounts of clay, feldspar and carbonatecement precipitate in pore throats and bodies, reducingporosity and permeability. The porosity shown in track3 ranges from a high of 22 p.u. with 48 mDpermeability at xx826 ft in a very fine grained sand, to alow of 4 p.u. and 0.002 mD at xx817 ft in a very finegrained calcareous sand.
Air-brine centrifuge primary drainage capillary pressuremeasurements on two samples from the H390 reservoirare shown in Table 4 and Figure 11. These samplesrepresent the better quality Vicksburg reservoirs. It isshown from core analysis (Shafer, et. al., 1998) thatpermeability and irreducible water saturation arehighly correlated, which is a pre-requisite of formationpetrophysical properties for NMR permeability loggingto be successful.
Table 4 Well B, H390 reservoir core analysisDEPTH
(ft)PERM(mD)
POROSITY(p.u.)
Swirr
(s.u.)xx790.4 4.6 16.4 29xx788.5 1.0 13.9 38
Gas column heights can be as great as 200 feet;however, these low permeability reservoirs are almostentirely in the gas-water transition zone as defined bycapillary pressure. For wells penetrating the reservoir
within 50 feet of the gas-water-contact, water saturationis significantly high. This will be apparent in thefollowing examples as measured by both conventional
xx900
xx850
xx900
xx850
0.25
Density Porosity
0.25
Neutron Porosity1 100
90 in Resisitivity
1 100
30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
xx800
H390
xx800
xx750
Figure 10 Well B H390 good quality reservoirconventionally cored containing good gas shows.
Figure 11 Well B, H390 reservoir, primarydrainage air-brine centrifuge capillary pressurewater saturation correlates with permeability.
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resistivity-based water saturation and NMR irreduciblewater saturation.
WELL B, H250 WATER RESERVOIR
The last example of wells drilled before NMR logs isshown for Well B in Figure 12. The H250 reservoirsand was drilled with poor mud-log shows and no tripgas. A fresh WBM with viperlube oil additive wasused and the contrast between fresh mud filtrate andsaline formation water can be seen by the large invasionprofile on the resistivity log. Also, observe theapparent separation of the density/neutron porositymeasurements in what appears to be high quality sand.The next example shows the log responses for thisreservoir when it is bearing gas.
WELL C, H250 GAS-BEARING RESERVOIR
This example is the first well to have an NMR log runin the development of the Vicksburg gas reservoirs.Well C contained an extensive formation-evaluationprogram which entailed extensive core, core analysis,and synthetic OBM drilling fluid to improve logmeasurements and the first integrated NMR core andlog program. The conventional logs for the H250reservoir in Well C are shown in Figure 13.
Reservoir H250 is known to be gas bearing despiteformation resistivity as low as 1.5 ohmm. The H250reservoir has not been production tested to date;however, a formation test sample containing 18.2 cf of
gas was recovered at xx266 ft. Comparison of thedensity/neutron separation between the two wells inFigures 12 and 13 reveals a gas effect in Well C,although due to the complex mineralogy, no gascrossover occurs.
WATER SATURATION
The NMR log in Figure 14 shows an interval of 160 ftin the H250 reservoir of conventional core porosity andpermeability measurements compared to NMR. Track1 shows the result of NMR-calibrated permeability tocore permeability at reservoir stress. Track 2 containsthe conventional resistivity-derived total watersaturation (Swt) using a dual-water saturation model.Additionally, NMR irreducible water saturation (Swirr) isderived from the following relationship,
where NMR measured BVI and φ are taken on a totalpore volume basis using total porosity data acquisitionand processing (Prammer, et. al., 1996; Freedman, et.al., 1997). This is essential when making thecomparison of Swt to Swirr. The very basic application ofNMR for determination of mobile formation water isthe premise that when the following condition applies,
Figure 13 Well C H250 reservoir updip of WellB. Less density/neutron shale response causedgas effect.
xx350
xx300
xx350
xx300
0.3 3000
T2 Cutoff
T2 Distribution0.25 0
Total Porosity
0.25 0
NMR Porosity
NMR Bound Fluid
NMR Free Fluid
1 0
NMR Swirr
1 0
Swt
Free Water
0.001 10Core Perm
0.001 10
NMR Perm
xx250
xx200
H250
xx250
xx200
Figure 14 NMR log across conventional coreinterval. Good NMR permeability and porositycalibration shown.
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the water saturation in the reservoir is above irreducibleconditions and that the relative permeability to water isgreater than zero. When these two independentlyderived water saturation are equivalent, the water is atirreducible conditions and is immobile. In the H250reservoir, the NMR Swirr is equivalent to Swt derivedfrom resistivity measurements; hence, the water in thereservoir is immobile, except for the high permeabilitysand at xx275 ft, which will be avoided in thecompletion.
POROSITY
A comparison of core porosity to total porosity derivedfrom conventional logs is shown in track 3.Additionally, NMR porosity is shown partitioned intotwo components: bound fluid and free fluid. Both logtotal porosity and NMR porosity compare well to coreporosity in the H250 reservoir. The free fluid portion isequivalent to producible porosity from calibrating thecore NMR measurements to capillary pressure.
The NMR derived T2 distribution is shown in track 4.Sands containing macro-porosity filled with OBMfiltrate are seen by large amplitudes to the right of theT2 cut-off between xx250 and xx280 ft.
WELL C, H390 GAS-BEARING RESERVOIR
Figure 15 shows the first NMR log in the H390 gasreservoir discussed previously in the Well B, H390,
example. Throughout the reservoir formationresistivity is observed as low as 2 ohmm and increasesto 8 ohmm in better quality sands. Above xx850 ft, thedensity/neutron porosity measures as high as 20 p.u.,but the formation resistivity is only 2 to 4 ohmm.
The NMR log, with completion data, is shown in Figure16. Laboratory-measured core permeability andporosity obtained from rotary sidewall core plugcompares well with NMR log measurements. In thin-bedded sands below xx900 ft, the agreement is poor.Throughout the reservoir, both NMR and resistivity-derived water saturation agree, leading to theinterpretation that the reservoir does not containmoveable water. The significant fraction of NMRbound fluid in the pore space in track 3 is supported bycore petrographic measurements that these sandscontain significant quantities of micro-porosity.
The well was perforated over three short intervals topromote a more effective hydraulic fracture consistingof a 240,000-lb. proppant frac job. The well flowed gasat a rate of 4.8 MMcf/d with no formation water duringthe production test.
WELL C, H454 TIGHT-GAS RESERVOIR
The H454 gas reservoir in Well C is shown in Figure17, is characterized by resistivity in the 3 to 4 ohmmrange and porosity between 10 and 15 p.u. One of the
xx950
xx900
xx950
xx900
0.25 0
Density Porosity
0.25 0
Neutron Porosity1 100
90 in Resisitivity
1 100
30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
xx850
xx800
H390
xx850
xx800
Figure 15 Well C H390 primary producing gasreservoir. 24,000 lb. frac proppant.
xx950
xx900
xx950
xx900
0.3 3000
T2 Cutoff
T2 Distribution0.25 0
Total Porosity
0.25 0
NMR Porosity
NMR Bound Fluid
NMR Free Fluid
1 0
NMR Swirr
1 0
Swt
Free Water
0.001 10Core Perm
0.001 10
NMR Perm
xx850
xx800
H390
4.8MMcf/D
xx850
xx800
Figure 16 Good flow rate from 150 ft grossinterval. Note high amount of NMR bound fluid.
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problems encountered in some wells is completing low-permeability gas sands that flow at uneconomic rates.
The NMR log in Figure 18 compares well to rotaryside-wall core porosity and permeability above xx200ft, while the NMR log permeability is underestimatedrelative to the core permeability below this depth. Coreand NMR permeability measurements are in the 0.02 to0.07 mD range. In track 2, Swt based on resistivity islower than NMR Swirr. This is an artifact of either theNMR Swirr or the resistivity-based Swt is determinedincorrectly and cannot occur as indicated by Equation3. If NMR Swirr is not in error, then NMR can assist incalibrating electrical resistivity saturation parameters.This is a similar process to calibrating log-based watersaturation to capillary pressure water saturation.
Two perforation intervals were tested separatelyfollowing a 240,000-lb. proppant frac. On the lowerperforated interval below xx200 ft, the well flowed at800 Mcf/D, whereas the upper interval tested at 900Mcf/D. These rates were sub-economic and thereservoir was abandoned due to recompletion problems.
WELL D, H390 GAS-BEARING RESERVOIR
In Well D and Well E the Vicksburg reservoirs are in adown-thrown fault block adjacent to Wells B and C.Figure 19 shows the H390 reservoir has low resistivity(2 to 10 ohmm) while the more porous reservoir
interval above xx970 ft has a high GR response causedby the higher feldspar content in these sands.
NMR porosity measures too high when affected by holeenlargement, which is observed over the interval fromxx960 to xx980 ft in Figure 20. The caliper in Figure19 shows a washout over this interval. The NMR T2
distribution in track 4 exhibits the trait of highamplitude at early time caused by this enlarged holesize. Hence, high NMR porosity and T2 amplitude atearly time are reliable indicators of invalid NMRmeasurements.
Over the H390 reservoir interval from xx900 to xx960ft good permeability and low water saturation are seenin tracks 1 and 2. Increased NMR free fluid and higheramplitude at later time in the T2 distributions indicatesthat this interval contains the highest reservoir quality.Comparison of Swt to Swirr indicates that no mobilewater is present over the major portions of thepermeable gas sands. The reservoir is at irreduciblewater saturation.
This well flowed at a rate of 6.2 MMcf/d on a 16/64-inch choke with no formation water from five discrete6-ft perforated intervals after pumping a 300,000-lb.proppant frac.
xx250
xx200
xx250
xx200
0.25 0
Density Porosity
0.25 0
Neutron Porosity1 100
90 in Resisitivity
1 100
30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
xx150
H454
xx150
Figure 17 Well C H454 reservoir containinggood porosity. Pumped 240,000 lb. frac proppant
xx250
xx200
800Mcf/D
xx250
xx200
0.3 3000
T2 Cutoff
T2 Distribution0.25 0
Total Porosity
0.25 0
NMR Porosity
NMR Bound Fluid
NMR Free Fluid
1 0
NMR Swirr
1 0
Swt
Free Water
0.001 10Core Perm
0.001 10
NMR Perm
xx200
xx150
H454
900Mcf/D
xx200
xx150
Figure 18 Low gas flow rates measured from twointervals containing low perm and high Swirr.
SPWLA 39th Annual Logging Symposium, May 26-29, 1998
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WELL D, H454 GAS AND WATER RESERVOIR
The deeper, lower-quality H454 reservoir showsstratified porosity from xx220 to xx370 ft in Figure 21.Resistivity ranges from 1 to 4 ohmm and porosity from10 to 15 p.u. in the reservoir sand. The NMR log inFigure 22 shows the majority of the interval contains nofree fluid except in a small interval above xx300 ft. Theimprovement in reservoir quality can be seen in theNMR permeability, Swirr, free fluid and increasedamplitude at later time in the T2 distributions.
The well was perforated over three 7-ft intervals fromxx222 to xx342 ft and fracture stimulated with 300,000-lb. proppant. On test, the well flowed 1.3 MMcf/D and158 BWPD. Although not easily apparent in track 2,the resistivity derived Swt is greater than NMR Swirr inthe primary sand above xx300 ft indicating the presenceof both gas and mobile formation water. The thin 0.1-mD sand measured by the NMR log is verified by thelow flow rates.
WELL E, H390 GAS-BEARING RESERVOIR
Well E is approximately 100 ft down-dip of Well D,presenting a greater risk that reservoir H390 is water-bearing or contains mobile water associated with thegas. Figure 23 shows low resistivity over the porousreservoir sands, none the less, there is a small amountof density/neutron gas crossover in track 3.
The NMR log in Figure 24 shows good permeability,low water saturation, high free fluid and stronger T2
signal amplitude at late times above xx060 ft. Well Ewas completed over seven intervals from xx991 toxx197 ft and fracture stimulated with 300,000-lb.proppant. A zone that has the potential to producewater was not perforated at xx100 ft. The sand appearsto contain a reasonable porosity of 12 p.u., with a lowamount of free fluid, but there is some indication thatmobile water exists in this pore space with Swt greaterthan NMR Swirr. On test, the well produced gas at 5.6MMcf/D with no formation water.
SUMMARY
Nuclear Magnetic Resonance is shown to improvecompletion decisions in mineralogically complexreservoirs having high irreducible water saturation.Understanding the petrophysical controls on thesereservoirs was achieved through up-front planning of acomprehensive formation evaluation program whichincluded cutting conventional core, core analysis and arigorous wireline logging program including NMR.
Through integration of core analysis and quantitativepetrographic analysis of reservoir core, it was identifiedthat high irreducible water saturation was caused byhigh levels of micro-porosity within the arkosicsandstones that also contained large amounts of reactive
xx050
xx000
xx050
xx000
0.25
Density Porosity
0.25
Neutron Porosity1 100
90 in Resisitivity
1 100
30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
xx950
H390
xx950
Figure 19 Well D H390 reservoir has goodporosity opposite high GR zone. 300,000 lb. frac
xx050
xx000
MMcf/D
xx050
xx000
0.3 3000
T2 Cutoff
T2 Distribution0.25 0
Total Porosity
0.25 0
NMR Porosity
NMR Bound Fluid
NMR Free Fluid
1 0
NMR Swirr
1 0
Swt
Free Water
0.001 10
NMR Perm
xx950
xx900
H390
6.2MMcf/D
xx950
xx900
Figure 20 Good flow rates over 150 ft reservoir.NMR high porosity due to washout at xx975 ft.
SPWLA 39th Annual Logging Symposium, May 26-29, 1998
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rock fragments. Micro-porosity was quantified usingSEM MICROQUANT and showed that feldspars,chlorite cement, felsic, mafic-volcanic and clay-richsedimentary rock fragments contain as much as 15 to45 percent micro-porosity.
Laboratory NMR Swirr measurements on as-receivedcore samples containing both OBM mud filtrate andconnate water required a T2 cut-off of 40 msec tocalibrate to primary drainage capillary pressure Swirr. NMR permeability based on the Coates relationshipwas calibrated to core permeability measured at net-confining pressure. It was shown in Well C that whencalibrated to core, NMR log permeability, porosity andirreducible water saturation provide good estimates ofthese reservoir petrophysical parameters.
Using conventional logs numerous wells werecompleted and either produced formation water, or gasat uneconomic rates. This study shows that the highlevels of micro-porosity result in high irreducible watersaturation from 50 to 70 s.u. Even at this highsaturation, gas wells can flow water-free rates as highas 6 MMcf/D. NMR logs have identified severalreservoirs that contain mobile formation water and werenot included in the completion program.
Production in these Exxon fields has tripled since theadvent of NMR logging and quantitative reservoiranalysis. Finally, it is important to note that identifying
mobile formation water using NMR is dependent uponaccurate computation of resistivity-based watersaturation or bulk volume water. Errors can result inNMR estimates of mobile formation water if electricalproperties of the rocks or connate water are uncertain.
NOMENCLATURE
BVI bulk volume irreducible pore volumeBWPD barrels water per dayFFI free-fluid indexMcf/d thousand cubic feet per dayMMcf/d million cubic feet per daymD milli-Darcy
φ porosityp.u. porosity units (percent of bulk volume)s.u. saturation units (percent of pore volume)Sw water saturationSwirr irreducible water saturationSwt total water saturationTw wait time between CPMG echo train (msec)T2 relaxation time constant (msec)
ACKNOWLEDGEMENTS
We want to acknowledge the following peopleresponsible for permitting the authors time to write thispaper and to others who made valuable contributions:Donal Mageean, Fritz Merz and Khushari Zainun ofExxon Exploration Company; Quinn Passey, Lee Esch,
xx350
xx300
xx350
xx300
0.25
Density Porosity
0.25
Neutron Porosity1 100
90 in Resisitivity
1 100
30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
xx250
H454
xx250
Figure 21 Well D H454 reservoir, contains thinlybedded sands. 300,000 lb. frac
xx350
xx300
MMcf/D
158BWPD
xx350
xx300
0.3 3000
T2 Cutoff
T2 Distribution0.25 0
Total Porosity
0.25 0
NMR Porosity
NMR Bound Fluid
NMR Free Fluid
1 0
NMR Swirr
1 0
Swt
Free Water
0.001 10
NMR Perm
xx250
xx200
H454
1.3MMcf/D
xx250
xx200
Figure 22 Low gas flow rate with little NMR freefluid porosity or permeability. Swt > Swirr
SPWLA 39th Annual Logging Symposium, May 26-29, 1998
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Bob Klimentidis, Ken Dahlberg, John Shafer, and BillReese of Exxon Production Research Company; NealDesmarais and Amy Omar of Exxon Company U.S.A.;Dale Logan and Jack Horkowitz of SchlumbergerWireline; and Dwayne Weaver of NUMAR. Specialthanks to Exxon Company U.S.A., Exxon ExplorationCompany, Exxon Production Research Company,Schlumberger Wireline and NUMAR for permission topublish this paper.
REFERENCES CITED
Akkurt, R., Prammer, M.G., Moore, M., 1996,"Selection of Optimal Acquisition Parameters forMRIL Logs", SPWLA 37th Annual LoggingSymposium.
Carr, H.Y., Purcell, E.M., 1954, "Effects of diffusion onfree precession in NMR experiments", PhysicalReview, Vol. 94, p630.
Chakrabarty, T., Longo, J., 1997, "A New Method forMineral Quantification to aid in HydrocarbonExploration and Exploitation", Journal of CanadianPetroleum Technology, December, Vol. 36, No. 11, pp.15-21.
Chang, D., Vinegar, H., Morriss, C., and Straley, C.,1994, "Effective Porosity, Producible Fluid and
Permeability in Carbonates from NMR Logging",SPWLA Transactions, Paper A.
Dodge, W.S., Shafer, J.L., Klimentidis, R.E., 1996,"Capillary Pressure: The Key to Producible Porosity",SPWLA 37th Annual Logging Symposium, Paper J.
Freedman, R., Boyd, A., Gubelin, G., McKeon, D.,Morriss, C.E., Flaum, C., 1997, “Measurement of TotalNMR Porosity adds new value to NMR Logging”,SPWLA 38th Annual Logging Symposium, Paper OO.
Meiboom, S., Gill, D., 1958, "Compensation for pulseimperfections in Carr-Purcell NMR experiments", Rev.Sci., Instrum., 29, p688.
Morriss, C.E., Deutsch, P., Freedman, R., McKeon, D.,Kleinberg, R.L., 1996, "Operating Guide for theCombinable Magnetic Resonance Tool", The LogAnalyst, November-December.
Prammer, M. G., 1994, "NMR Pore Size Distributionand Permeability at the Well Site", SPE 69th AnnualTechnical Conference, Paper SPE 28368.
Prammer, M.G., Drack, E.D., Bouton, J.C., Gardner,J.S., Coates, G.R., Chandler, R.N., Miller, M.N., 1996,"Measurements of Clay-Bound Water and TotalPorosity by Magnetic Resonance Logging", SPE 36522,
xx200
xx150
xx100
xx200
xx150
xx100
0.25
Density Porosity
0.25
Neutron Porosity1 100
90 in Resisitivity
1 100
30 in Resisitivity
1 100
10 in Resisitivity
5 15
Caliper
0 150
Gamma Ray
xx050xx050
H390
Figure 23 Well E H390 reservoir, good porositydevelopment. 300,000 lb. frac
xx200
xx150
xx100
xx200
xx150
xx100
0.3 3000
T2 Cutoff
T2 Distribution0.25 0
Total Porosity
0.25 0
NMR Porosity
NMR Bound Fluid
NMR Free Fluid
1 0
NMR Swirr
1 0
Swt
Free Water
0.001 10
NMR Perm
xx050
H3905.6MMcf/D
xx050
Figure 24 High gas flow rate albeit small NMRfree-fluid. Fair permeability in upper zone.
SPWLA 39th Annual Logging Symposium, May 26-29, 1998
Shafer, J.L., Dodge, W.S., Noble, D.A., 1998, "A CaseStudy: NMR Core-to-Log Calibration for Tight GasSand Reservoirs", SPWLA 39th Annual LoggingSymposium.
Straley, C., Rossini, D., Vinegar, H., Tutunjian, P., andMorriss, C., 1991, "Core Analysis by Low Field NMR",Society of Core Analysts Symposium, Paper 9406.
ABOUT THE AUTHORS
Scott Dodge is a senior exploration geologist withExxon Exploration Company in Houston, Texas. Heholds a BSc. Degree in Mechanical Engineering fromKansas State University and MSc. Degree in PetroleumEngineering from University of Southern California.He has served as President of the Formation EvaluationSociety of Victoria Australia, as well as SPWLADistinguished Lecturer during 1996 to 1998. Scottjoined Exxon in 1982 and has worked in the U.S.A.,Canada and Australia as a Formation EvaluationSpecialist. He is a member of the SPWLA, SPE,AAPG and Society of Core Analysts.
Angel Guzman-Garcia has a PhD. Degree in ChemicalEngineering from Tulane University. Since 1990, hehas been working at Exxon Production Research in thearea of petrophysics. His current assignment is in thefundamentals of NMR and applications to petrophysicalinterpretation. After verification of NMR principles inthe laboratory, he is involved in the design, witnessing,and processing of NMR well-log data. He is a memberof SPWLA, SPE, and AIChE.
Dave Noble is a senior exploitation geologist withExxon Company, USA. He received a BSc. Degree inGeology at Brigham Young Univeristy. Dave startedwith Exxon Exploration in 1978, working in EastTexas, South Texas, and the Gulf of Mexico. In 1984he transferred to the South Texas productiondepartment which is now the Houston ProductionOrganization where Dave is now located. He has spentthe past 15 years as a geologist working the Vicksburgand Frio formations.
Jack LaVigne is the lead petrophysicist for the HoustonArea. He holds a BSc. Degree in ElectricalEngineering from the University of Minnesota,graduating in 1971. Jack joined Schlumberger in 1975as a field engineer and log analyst in the Permian BasinDivision. Prior to joining the Houston Area, he workedas a development engineer in the Interpretation
Engineering Department of Schlumberger in Houston.In this position, Jack was responsible for thedevelopment of Schlumberger's petrophysicalinterpretation software.
Ridvan Akkurt prior to founding NMRPlus Inc. workedfor NUMAR, Shell Offshore Inc., SchlumbergerOverseas, Schlumberger-Doll Research and GSI, in avariety of field and research assignments in geophysicsand petrophysics. He has a BSc. Degree in ElectricalEngineering from Massachusetts Institute ofTechnology and a PhD. Degree in Geophysics from theColorado School of Mines. Dr. Akkurt has severalpublications in the area of NMR logging and has servedas a Distinguished Lecturer for SPWLA. He is amember of SPWLA and SPE.
