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Core and Log NMR Measurements of an Iron-Rich Glauconitic Sandstone Reservoir

Core and Log NMR Measurements of an Iron-Rich Glauconitic Sandstone Reservoir

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  • 1. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 ˝ CORE AND LOG NMR MEASUREMENTS OF AN IRON-RICH, GLAUCONITIC SANDSTONE RESERVOIR WM. SCOTT DODGE SR ESSO AUSTRALIA LTD., MELBOURNE, VICTORIA, AUSTRALIA JOHN L. SHAFER AND ANGEL G. GUZMAN-GARCIA EXXON PRODUCTION RESEARCH COMPANY, HOUSTON, TEXAS, U.S.A. ABSTRACT difficulty in determining a realistic porosity- permeability relationship. This mineralogically NMR porosity and relaxation time measurements from complex reservoir, deposited in Eocene age offshore an iron-rich, glauconitic sandstone reservoir show marine channels, contains significant amounts of iron- quantifiable effects of mineral iron content on NMR bearing detrital glauconite, matrix clays, and T2 relaxation times. This result has significant impact authigenic chlorite, dolomite cement and siderite upon measuring irreducible water pore volume where replacement. The dominant controls on reservoir the surface relaxation mechanism is nonconstant. porosity and permeability are grain size, clay matrix, Centrifuge air/brine drainage capillary pressure and the amount of microporosity in dissolving measurements show that the standard 30 msec T2 feldspars, glauconite, and clay matrix. cutoff must be lowered to calibrate irreducible water saturation computed from NMR. Although the effects The first well (Well 1) drilled into the reservoir of iron are observable on T2 distributions, permeability penetrated a 30 metre oil column. The petrophysical estimation from NMR, using either the Coates or evaluation (Figure 1) to determine porosity, water Schlumberger relationships, show excellent agreement saturation and permeability, integrated core analysis, to permeability on core plugs. mineralogy, drainage capillary pressure measurements and conventional wireline logs. Above the oil-water Quantitative mineral composition on core plugs using transition zone (i.e., above 2927 metres) the average both XRD and XRF, show iron-rich glauconite to vary total water saturation was 55 percent. Owing to the from 3 to 31 weight percent. The bulk rock total iron poor reservoir quality and high water saturation, the oxide content ranges from 1 to 17 weight percent. well was production tested, and flowed oil at 1500 bpd High iron content within this reservoir raised concern (barrels per day) with no evidence of formation water. that NMR surface relaxation would be affected, Drainage capillary pressure measurements confirmed leading to errors in irreducible water saturation and that the high water saturation was irreducible and, as producible porosity derived from NMR measurements. indicated by the production test, would not be produced. NMR measurements were acquired using a pulsed field gradient logging tool operating at 530 kHz and on core A second well in the field (Well 2) penetrated an older plugs with a 1000 kHz laboratory spectrometer. reservoir containing a similar glauconitic sandstone, Homogenous field NMR core plug measurements are underlain by a high reservoir-quality, partially used to show the accuracy of the logging tool to dolomitised sandstone with multidarcy permeability. measure NMR porosity, and permeability. This well (Figure 2) was production-tested sequentially over the two intervals, flowing water-free oil at 6640 INTRODUCTION bpd from the lower sand, and 5660 bpd from the poor- quality upper reservoir. The entire reservoir sand was Conventional methods using logs to determine net pay, conventionally cored and an extensive reservoir effective porosity, water saturation, and producibility characterisation programme was undertaken to proved ineffective in an iron-rich glauconitic accurately determine the formation mineralogy and sandstone oil reservoir recently drilled in Australia. petrophysical properties. Production tests costing in the order of A$1.5m have been required to determine the producibility owing to -1-
  • 2. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 As part of the reservoir characterisation programme, laboratory Nuclear Magnetic Resonance (NMR) An SEM image (Figure 4) at x5000 magnification measurements were conducted on 15 core plugs from shows highly crystalline microporous chlorite. The Well 2. These measurements were undertaken to micropores range from 8 microns to sub-micron size. assess the ability of NMR to measure porosity, The maximum capillary pressure in this reservoir is 50 irreducible water saturation, and permeability in this psi air/brine equivalent corresponding to a 0.5 micron mineralogically complex reservoir. If successful, the pore-throat size, and thus much of this microporosity NMR logging tool could be used to log future wells in is accessible to hydrocarbons. Figure 5 shows a high- the development of the field to reduce the need for magnification thin-section photomicrograph of a green expensive production tests and conventional core. We glauconite grain. In the backscatter SEM image x1000 were concerned, however, by the high iron content of magnification of this same glauconite grain (Figure 6), the reservoir rocks. The laboratory measurements intragranular porosity is visible as black in the image. subsequently confirmed that NMR could be used to The micropores within this grain range in size from 10 measure valid reservoir petrophysical parameters when microns down to sub-micron. The glauconite calibrated to air/brine capillary pressure saturation. microporosity averages 21 percent grain volume as measured by MICROQUANT. The successful laboratory results in Well 2 supported the running of an NMR logging tool in the third well Fifteen core plugs from Well 2 in Figure 2 were drilled in this field. The well was conventionally analysed using MINQUANT. The results (Table 1) cored and comparisons of the log measurements with showed quartz content ranging from 77 to 44 on a NMR core plug measurements were performed in grain weight percent basis, and total clay mineral order to assess the quality of the log data. content to be as high as 34 percent. Dense iron- bearing minerals identified in these samples are CHARACTERISATION OF RESERVOIR glauconite and pyrite. The bulk iron content from XRF MINERALOGY in these samples ranges from 1.3 to 9.5 weight percent. The diagenetic iron-bearing chlorite identified in SEM Quantifying formation mineralogy was the first step to is included in the glauconite fraction determined from building a petrophysical model for this complex MINQUANT. reservoir rock. A programme was developed incorporating measurements such as Petrographic CHARACTERISATION OF RESERVOIR analysis, intragranualar microporosity PETROPHYSICS (MICROQUANT), Scanning Electron Microscopy (SEM), and quantitative mineralogy (MINQUANT). Prediction of formation productivity is difficult where MINQUANT and MICROQUANT are programmes there is a weak correlation between porosity and developed at Exxon Production Research Company. permeability as is the case in these mineralogically MINQUANT uses X-ray diffraction (XRD) and X-ray complex sandstone reservoirs. The ability to predict fluorescence (XRF) elemental chemical analysis to productivity is important in order to determine quantify mineralogy. MICROQUANT uses whether a reservoir sequence is able to deliver backscattered electron images to quantify intragranular hydrocarbons at economic rates. Figure 7a shows the microporosity. porosity to permeability relationship for Well 2. The two reservoirs in this well are represented by two The large difference between total and effective different relationships. porosity on the computed well log responses in Well 1 (Figure 1), indicated that the reservoir rocks contain In Well 2 (Figure 2), the dolomitic sandstone from significant quantities of microporous clay as well as 2840 to 2862 metres has porosity that varies from 4 to thin beds of dense siderite minerals. A thin-section 27 percent, whereas permeability remain uniformly photomicrograph (Figure 3) shows the presence of above 2000 md. Thin-sections show this reservoir to green glauconite grains which are the same size as be a quartzose sandstone with clay content less than 10 quartz grains in this sample. Additionally, clay rich percent. The multidarcy sandstone contains varying sedimentary rock fragments and diagenetic chlorite are amounts of diagenetic dolomite cement filling the present, and both contain intragranular microporosity. intergranular pore volume. The dolomitisation does The size of the intergranular pores (blue) is as large as not ensure that occluded porosity also reduces 80 microns. permeability. -2-
  • 3. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 ˝ reduce the intergranular pore space upon compaction The glauconitic sandstone from 2825 to 2840 metres with burial. in the same well shows a more linear trend of porosity with permeability. The opposite phenomena to the EFFECT OF IRON ON NMR T2 RELAXATION deeper sand occurs in this reservoir in that minor AND IRREDUCIBLE WATER SATURATION changes in porosity can correspond to two orders of magnitude change in permeability. The two reservoirs NMR T2 relaxation measurements were taken on the exhibit dramatically different porosity-permeability fifteen core plugs whose porosity and permeability relationships, and it is this uncertainty that can lead to characteristics are shown in Figure 7b. A laboratory significant errors in estimating permeability. NUMALOG CORESPEC spectrometer operating at 1000 kHz recorded the CPMG pulse train echoes Fifteen core plugs were selected to represent both (Farrar, 1971) of hydrogen protons in the field of reservoir facies for NMR measurements (Figure 7b). transverse magnetisation, T2. These amplitude versus Core analysis for each of these plugs (Table 2) show time measurements were acquired in an applied the variability of porosity and permeability in these oil- homogeneous magnetic field with an inter echo bearing sandstones. The majority of the samples have spacing of 0.5 milliseconds and a range of repetition an average grain density greater than that of quartz times from 1 to 20 seconds. A sandstone with variable (2.65 g/cc) because of the presence of denser minerals: pore size yields a T2 relaxation decay curve that is the e.g. glauconite (2.85 g/cc), dolomite (2.85 g/cc), and sum of single exponentials with each term pyrite (4.99 g/cc). corresponding to a particular pore size (Equation 2). Centrifuge air/brine drainage capillary pressure was A(t) = Aie (-t/T2i) (2) measured using 222 x 254 millimetre core plugs. The samples were spun at a centrifuge speed equivalent to Where Ai is proportional to the proton population of the 50 psi air/brine capillary pressure in the 30 metre pores having a relaxation time of T2i. The T2 oil column. The water saturation obtained at this amplitude spectra for five of the fifteen core plugs, pressure is defined to be equivalent to the irreducible shown in Figure 10, represent a range of permeability water saturation in the reservoir. Coincidentally this from 3.4 md to 4235 md. As permeability increases, 50 psi air/brine capillary pressure is the same as that T2g also increases from a low of 4.3 msec for the low used by Timur (1969) to define producible porosity. permeability sample, up to 90 msec for the high Timur's relationship was used (Equation 1), with permeability sample. Integration of the amplitude substitution of the irreducible water saturation as spectra yields NMR porosity (Equation 3). determined at the maximum capillary pressure in the reservoir, to define the pore volume containing mobile fluids (hydrocarbons and connate water). φNMR = K Σ Ai (3) The impact of mineral iron content is reflected in the φp = φt (1-Swi) (1) surface relaxivity term (ρ) which relates T2 relaxation Table 2 shows that the centrifuge irreducible water time to pore surface area and pore volume (Equation saturation ranges from 0.12 to 0.78. Figure 8 shows 4). that irreducible water saturation is closely related to permeability (r2=0.96) and can be used as an estimate T2-1 = ρ (S/V) (4) of reservoir permeability. If the surface relaxivity is nonconstant, then the ability Increasing iron content is associated with lower of T2g to purely reflect surface to volume permeability samples illustrated in Figure 9. When characteristics (i.e. mobile vs non-mobile fluids) is not iron content exceeds 4 percent, the minerals valid. An increase of surface relaxation will directly contributing the most to high iron content are siderite, impact T2g by shifting the relaxation distribution to glauconite and chlorite. Chlorite is a diagenetic pore- shorter times. Integration of the T2 amplitude filling clay which directly impacts fluid flow through distribution may still reflect porosity, although the the pore system. The glauconite is a detrital framework selection of a T2 cutoff for partitioning Bulk Volume grain which does not impact permeability as severely Irreducible (BVI) fluid from producible fluid may as chlorite. The glauconite, however, is ductile and can change. It has been shown in several studies of -3-
  • 4. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 sandstones (Morriss, 1993, Kleinberg, 1993) that a T2 After a review of these data we can suggest the cutoff time of approximately 30 msec, when applied to following general guidelines for appropriate T2 cutoff T2 distributions, reflects the irreducible water times in iron-bearing glauconitic-rich sandstones. saturation as measured by drainage capillary pressure. Fe (wt%) T2 cutoff (msec) NMR irreducible water saturation was computed from 0 < 4 30 the T2 distribution curve by selecting a T2 cutoff time 4 - 6 20 at 10, 20, 30 and 40 msec (Table 2). The ratio of the > 6 10 area under the curve below the T2 cutoff, to the total area under the curve, is the irreducible water NMR CORE PLUG IRREDUCIBLE saturation from NMR. Figure 11 shows NMR SATURATION COMPARED TO LOG irreducible water saturation, and 50 psi air/brine SATURATION capillary pressure water saturation for each T2 cutoff. It is apparent that the low permeability samples with Following the evaluation of iron content and effect on high irreducible water saturation (above 0.40) have a the NMR T2 cutoff in Well 2 we decided to proceed significant proportion of their pore volume in the with using the standard 30 msec T2 cutoff for analysis range of 10 to 40 msec. As the T2 cutoff changes, a of irreducible water saturation and permeability while large change is observed in Swi. The high acknowledging that in iron-rich rocks, the irreducible permeability samples have very few small pores in the water saturation could be high by 0.19. Figure 2 range of 10 to 40 msec, with the majority of the pores shows in track 2 a comparison of the total water at higher T2 times. saturation derived from logs, capillary pressure Air/Brine Swi and NMR Swi. It can be seen that in IRON CONTENT, T2 CUTOFF AND THE the low clay content dolomitic sandstone below 2840 ERROR ON NMR IRREDUCIBLE WATER metres, NMR Swi agrees well with core and log SATURATION saturations. Above 2840 metres, in the glauconitic sandstone reservoir, NMR Swi overestimates Air/Brine Figures 12 through 14 show the difference between Swi as expected. NMR Swi and Air/Brine Swi as a function of iron content for a T2 cutoff of 30, 20, and 10 msec. Figure Permeability estimation from NMR was derived from 12 shows for a T2 cutoff of 30 msec, the error is 0.01 the relationship between irreducible water saturation in NMR Swi for samples with less than 4 percent iron. and permeability shown in Figure 8. This relationship For samples with higher iron content, the error in takes the form shown in Equation 5 (Timur, 1969). NMR Swi is as much as 0.19. These data places an upper bound on the error in NMR Swi in these kNMR = B βt (5) glauconitic sandstones when using the standard T2 cutoff of 30 msec. where B and t are empirical constants 0.15 and 2.5. The NMR parameter, β is defined by The iron content increases NMR surface relaxation, which in turn shifts the T2 distribution to lower times. β = Swi-2 (6) Therefore the T2 cutoff would have to shift to lower times to maintain calibration of NMR Swi to Air/Brine Core plug permeability compares well to NMR Swi. Figure 13 shows that with a 20 msec T2 cutoff estimated permeability (Figure 2, track 4). It is the error in NMR Swi is -0.03 for samples with iron important to note that the relationship of irreducible content less than 4 percent. The majority of the water saturation to permeability is independent of the samples with higher iron content contain an error of depositional facies, which was not the case observed less than 0.05. for the porosity-permeability relationships (Figure 7a). By reducing the T2 cutoff to 10 msec (Figure 14), most NMR LOG MEASUREMENTS COMPARED TO samples underestimate Air/Brine Swi, with errors CORE ranging from -0.03 to -0.10. It would be reasonable to use a T2 cutoff of 10 msec for reservoir rocks with Following successful validation of NMR T2 relaxation more than 6 percent iron. to measure irreducible water saturation and estimate permeability in mineralogically complex sandstones, -4-
  • 5. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 ˝ Well 3 was drilled and logged with an NMR tool. This The NMR well log and core data are shown in Figure was the first new-generation, pulsed NMR tool to be 15. Both total porosity from forward modeling and run in Australia. The entire reservoir was NMR plug porosity compare well to core porosity conventionally cored, and additional NMR core plug (track 2). The NMR log porosity varies between measurements were taken to validate the accuracy of forward modeled log total and effective porosity. In as the log measurements. The NMR log along with core much as the NMR log inter echo spacing is 2.0 msec, plug measurements from Well 3 are shown in Figure some fraction of the clay microporosity will not be 15. measured, and the log should be similar to effective porosity as is the case between 2856 to 2862 metres. The reservoir interval encountered at first appeared to Above 2862 metres, however, the log measures closer be of similar quality to that in Well 1 (Figure 1). Oil to forward modeled log total porosity. Permeability shows in the core indicated that this sandstone was oil was estimated using both the Coates and Schlumberger bearing and it was known that a common field oil- T2 relationship in Equations 7 and 8. water contact should be present at 2859 metres. Computed porosities were similar to Well 1, but the kce = (φNMR/10)4 (FFI/BVI)2 (7) calculated water saturation was 0.80 as compared to kse = 4.6 (φNMR/100)4 (T2g)2 (8) 0.55. A production test was originally planned to test the productivity of the glauconitic sand because of the Track 3 shows the excellent match between computed uncertainty in reservoir quality. Thus, significant cost permeabilities from the NMR log and NMR core plugs savings could be realised if NMR log measurements and measured core permeability. The permeability, could be confidently used to quantify producible which is below 1 md in this reservoir, is an order of porosity and permeability. magnitude lower than that measured in Well 1 which production tested 1500 bpd oil. This information, in In the case under discussion, operational problems addition to wellsite core plug permeability and contributed to marginal NMR log quality with poor formation tester pressures, supported the decision to repeatability. Although the NMR log quality was poor, abandon the planned production test on this well. the log data could still be used on a zone-average basis for comparison to core NMR. Even though the NMR Reservoir average values of forward modeled log total tool was logged in a 12.25 inch wellbore, the low and effective porosity, core porosity, NMR log operating frequency (530 kHz) placed the sensitive porosity, and NMR core porosity are shown in Figure measurement volume at an 18 inch diameter. Only in a 16. Both the core porosity and NMR core porosity are severe washout below 2860 metres (Figure 15) did the measured at ambient surface pressure. We would log record mud readings, with corresponding invalid expect these values to be around 5 percent lower at high NMR porosity and permeability measurements. overburden confining pressure and would give better agreement to log total porosity. Ten core plugs were measured using the same NMR spectrometer as was used for the Well 2 plugs. The T2 EFFECT OF IRON ON SURFACE RELAXATION experiments were repeated 3 times using the following inter echo spacings and magnetic field: 0.5 msec Measurements of high-pressure (60,000 psi) Mercury Homogeneous, 0.5 msec Gradient, and 2.0 msec Injection Capillary Pressure (MICP) provides the Gradient. The purpose of the three experiments was to surface to volume data necessary in computing NMR measure the maximum porosity in the core plug using surface relaxation. Equation 4 shows the relationship the shortest inter echo spacing available at 0.5 msec, of surface relaxation in microns/second derived from while replicating the logging tool which operates at a NMR T2 relaxation and the surface to volume ratio 2.0 msec inter echo spacing in a gradient field. The from core samples. Table 3 show these measurements 0.5 msec NMR porosity should replicate core porosity performed on core plugs from Well 2 and Well 3. by measuring the fast T2 relaxing components in the clay microporosity (Borgia, 1994) while the 2.0 msec NMR surface relaxivity is seen to be a function of porosity data should be less than total porosity (minus sandstone iron content (Figure 17). The surface clay microporosity). Only the 0.5 msec homogeneous relaxivity varies from 1.0 micron/sec for a low iron field NMR core plug measurements are reviewed in content sandstone to 3.9 microns/sec for a glauconitic this paper (Table 2). sandstone with 14 percent iron. The scatter in surface relaxivity is consistent with the fact that it is not bulk -5-
  • 6. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 iron concentration but surface iron concentration that in significant savings by reducing the need for is the control on relaxation. As rock iron content expensive production well tests and/or coring. increases, a well defined trend in increasing surface relaxivity is observed. A four fold increase in surface relaxivity will reduce T2g to one quarter its original value. This change in T2g will reduce the permeability that is computed using the Schlumberger or Coates relationships which are dependent on T2g and BVI respectively. However, the NMR permeability estimates in Figure 15 show good match to core permeability. CONCLUSIONS Measured NMR surface relaxivity ranges from 1 micron/sec in low iron content sandstones to 3.9 microns/sec in glauconitic sandstones with as much as 14 percent iron. Nonconstant surface relaxivity has the effect of reducing NMR T2g relaxation times by as much as one quarter the value of a low iron content sample. Lowering of the T2 cutoff is required for correct partitioning of irreducible fluid from producible fluid. If this factor is not taken into account, reduction of T2 relaxation times increases the computed irreducible water saturation relative to measured drainage capillary pressure water saturation. The T2 cutoff required adjustment from 30 msec to 20 msec to match capillary pressure water saturation when iron content was greater than 4 percent. Another adverse effect of high iron content is that permeability will be under-estimated when using the Schlumberger (dependent on T2g) or Coates relationship (dependent on T2 cutoff). The significant iron-bearing minerals in these sandstones were glauconite, chlorite, pyrite, and siderite. Using a 30 msec T2 cutoff, the NMR saturation error was 0.19 saturation high compared to Air/Brine Swi in the highest iron content glauconitic sandstones, with the error approaching zero as iron content decreases. In general, however, core measurements of NMR porosity, irreducible water saturation, and permeability agree well with core analysis porosity, air/brine drainage capillary pressure, and permeability. The ability of NMR to measure the surface to volume ratio of reservoir rocks leads to good estimation of permeability when a core calibration set is available. We have shown that both Coates and Schlumberger permeability relationships perform well for estimating permeability from core NMR. This information is necessary to estimate well productivity and can result -6-
  • 7. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 ˝ NOMENCLATURE Morriss, C.E., etal, 1993, "Field Test of an experimental pulsed nuclear magnetism tool", SPWLA A total NMR T2 echo signal amplitude, (mv) 34th Annual Logging Symposium, June 13-16, paper Ai relative amplitude of relaxation time T2i GGG. BVI NMR bulk volume irreducible fluid, (p.u.) FFI NMR log free fluid index, (p.u.) Timur, A., 1969, "Pulsed Nuclear Magnetic Resonance i ith pore Studies of Porosity, Moveable Fluid and Permeability K NMR porosity calibration constant of Sandstones", SPE Journal of Petroleum Technology, kce NMR Coates permeability, (md) June, pp 775-786. kNMR NMR permeability estimate, (md) kse Schlumberger permeability estimate, (md) ABOUT THE AUTHORS microns 10-6 metres φNMR NMR porosity, (p.u.) Scott Dodge, presently a Senior Petrophysicist with φp producible porosity, (p.u.) Esso Australia Ltd. in Melbourne, Australia received a φt total interconnected porosity, (p.u.) BSc. degree in Mechanical Engineering from Kansas ρ NMR surface relaxivity, (microns/sec) State University in 1979 and a MSc. degree in p.u. porosity units, percent bulk volume Petroleum Engineering from the University of S pore surface area, (micron2) Southern California in 1982. He has been with Exxon Swi irreducible water saturation, (fraction) for the past 13 years as a Formation Evaluation T2 transverse relaxation time, (msec) Specialist. T2co T2 cutoff, (msec) T2g geometric mean T2, (msec) John Shafer presently is a Senior Research Specialist V pore volume, (micron3) in the Reservoir Division of Exxon Production Research in Houston, Texas. He received a BSc. ACKNOWLEDGEMENTS degree in Chemistry from Allegheny College in 1963, a Ph.D. degree in Chemistry from University of The authors are grateful to the following persons for California at Berkeley in 1971, and a MSc. degree in their contributions to this paper. Hans Thomann and Petroleum Engineering from the University of Houston Marco Duran, Exxon Research and Engineering. Bob in 1992. John has been with Exxon for the past 16 Klimentidis, Dave Pevear, and John Longo, Exxon years. Production Research. Dale Fitz, Esso Production Malaysia. Duncan Mardon, NUMAR Corporation. Angel G. Guzman-Garcia received his Ph.D. degree in Chris Straley, Schlumberger Doll Research. Adem Chemical Engineering from Tulane University. He Djakic, Andy Mills, and John Phillips of Esso joined Exxon Production Research in 1990 and has Australia. Special thanks to Esso Australia Ltd., modeled SP and resistivity tools in shaly sands. His Exxon Production Research Company, Exxon current assignment is in the acquisition and Exploration Company, and BHPP Pty. Ltd. for interpretation of NMR for estimation of petrophysical permission to publish this paper. parameters. REFERENCES Borgia G.C., 1994, "A new Un-free fluid index in sandstones through NMR studies", SPE 69th Annual Conference, September, SPE 28366. Farrar, T.C., Becker, E.D., 1971, "Pulse and Fourier Transform NMR introduction to theory and methods", Academic Press, New York, pp 22-28. Kleinberg, R.L., etal, 1993, "Nuclear Magnetic Resonance of Rocks", SPE 68th Annual Conference, October, SPE 26470. -7-
  • 8. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 Table I MINQUANT MINERAL XRD/XRF ANALYSES (wt%) PLUG # QUARTZ CARBONATE PYRITE GLAUCONITE KAOLINITE ILLITE SMECTITE TOTAL CLAY Well 2 *Note Carbonate in Well 2 is primarily Dolomite. 1 71 4 0 13 1 2 2 18 2 56 1 1 15 1 8 4 28 3 74 0 1 6 1 1 1 8 4 48 1 0 16 3 11 4 34 5 54 0 2 12 3 9 4 28 6 49 1 7 11 5 10 3 29 7 60 1 1 8 2 8 3 21 8 66 0 2 12 1 3 2 18 9 44 1 8 15 3 11 2 32 10 55 0 3 12 0 9 5 26 11 58 0 3 14 0 7 2 23 12 77 0 0 6 1 0 1 8 13 71 1 0 6 0 2 2 10 14 70 14 0 3 0 0 2 6 15 61 22 0 5 0 1 1 7 Well 3 *Note Carbonate in Well 3 is primarily Siderite (Iron carbonate). 2 53 1 0 22 3 6 4 35 6 36 26 0 18 3 6 6 33 12 49 3 5 21 2 8 4 35 13 50 2 0 30 3 1 4 38 14 47 4 0 26 6 2 4 38 17 49 7 1 20 0 9 5 34 22 50 1 0 20 1 5 7 33 25 53 4 0 31 2 4 4 41 28 52 5 1 31 1 3 4 39 34 52 12 0 29 0 2 3 34 Table 2 Petrophysical Properties of NMR Care Plugs PLUG # AMS BUOYANT AMB NMR 0.5ms AIR/BRINE T2oo 10ms T2oo 20ms T2oo 30ms T2oo 40ms PERMEABILITY POROSITY POROSITY (1) Swi @ 50 PSI NMP Swi NMR Swi NMR Swi NMR Swi Well 2 (md) (p.u.) (p.u.) (frac) (frac) (frac) (frac) (frac) 1 134.00 23.6 23.3 0.46 0.39 0.45 0.50 0.55 2 3.40 23.1 22.9 0.56 0.53 0.62 0.71 0.78 3 2540.00 28.0 27.7 0.12 0.07 0.09 0.12 0.14 4 0.90 25.9 25.6 0.70 0.66 0.74 0.81 0.85 5 0.56 22.4 22.1 0.65 0.56 0.66 0.74 0.80 6 0.12 18.9 18.7 0.78 0.73 0.83 0.91 0.97 7 905.00 30.8 30.5 0.25 0.16 0.20 0.24 0.27 8 1024.00 31.1 30.7 0.23 0.18 0.22 0.26 0.28 9 0.17 23.1 22.8 0.77 0.78 0.89 0.96 0.99 10 4.54 26.8 26.6 0.46 0.36 0.45 0.54 0.62 11 14.80 23.6 23.4 0.42 0.42 0.60 0.74 0.82 12 4235.00 26.4 26.1 0.12 0.07 0.10 0.13 0.14 13 2413.00 30.0 29.6 0.13 0.08 0.10 0.12 0.14 14 2231.00 20.5 20.3 0.12 0.09 0.10 0.12 0.13 15 262.00 9.2 9.1 0.27 0.21 0.25 0.27 0.28 -8-
  • 9. SPWLA 36th Annual Logging Symposium, June 26-29, 1995 ˝ Well 3 13 1.97 22.1 23.1 n.m. 0.64 0.75 0.80 0.93 14 0.04 18.5 19.4 n.m. 0.82 0.91 0.95 0.97 17 0.41 20.7 21.9 n.m. 0.73 0.83 0.86 0.89 22 0.02 21.5 21.1 n.m. 0.84 0.89 0.91 0.94 25 0.04 21.2 20.9 n.m. 0.84 0.92 0.93 0.94 28 0.02 20.3 21.4 n.m. 0.88 0.93 0.94 0.95 34 0.01 17.6 18.7 n.m. 0.87 0.94 0.95 0.96 NOTE (1): NMR rescaled for sample calibration. Table 3 Surface Relaxivity and Iron Content PLUG # Fe203 Surf / Vol T2 Surface XRF MICP Geom Relaxivity Well 2 (wt %) (1 / microns) (msec) (microns/sec) 1 4.8 64.6 7.2 2.1 2 5.3 83.8 4.3 2.8 3 2.0 9.4 115.0 0.9 4 4.5 110.0 5.8 1.6 5 4.3 75.1 6.1 2.2 6 7. 8 96.5 2.7 3.8 7 3.0 26.1 46.5 0.8 8 4.0 29.9 40.4 0.8 9 9.5 109.4 2.4 3.8 10 5.1 65.9 9.7 1.6 11 5.6 61.9 8.9 1.8 12 1.7 10.7 90.5 1.0 13 1.9 10.4 96.0 1.0 14 1.3 15.0 111.0 0.6 15 1.4 26.4 38.4 1.0 Well 3 2 5.8 108.60 6.3 1.5 6 17.3 174.24 3.4 1.7 12 9.7 132.64 5.0 1.5 25 9.8 157.31 3.3 1.9 34 13.8 149.94 1.7 3.9 -9-
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