A New NMR Method of Fluid Characterization in Reservoir Rocks: Experimental Confirmation and Simulation Results

Freedman, R.; Sezginer, A.; Flaum, Michael; Matteson, A.; Lo, Sho-Wei; Hirasaki, George J.

doi:10.2118/63214-ms

Cited by 33 publications

(42 citation statements)

References 12 publications

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“…These innovations are the MRF characterization method and DE pulse sequences. [1][2][3][4] The innovations are discussed in detail in the following sections.…”

Section: Introductionmentioning

confidence: 99%

Wettability, Saturation, and Viscosity From NMR Measurements

et al. 2003

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This paper discusses a new nuclear magnetic resonance (NMR) method that can provide wettability, saturation, and oil viscosity values in rocks partially saturated with oil and brine. The method takes advantage of two new technological advances in NMR well logging-the MRF* Magnetic Resonance Fluid Characterization Method and NMR "diffusion-editing" (DE) pulse sequences. We discuss the principles underlying the fluid characterization method and the pulse sequences. The fluid characterization method is used to provide robust inversions of DE data suites acquired on fully brine-saturated and partially saturated rock samples. The outputs of the inversion are separate diffusion-free brine and oil T 2 distributions for the fluids measured in the rocks.NMR measurements on partially saturated rocks are sensitive to wettability because of surface relaxation of the wetting-phase fluid. The surface relaxation rate, however, must be significant compared to the bulk relaxation rate in order for wettability to noticeably affect the NMR response. We present results showing that the surface relaxation rate at lower wetting-phase saturations is enhanced compared to that measured at higher saturations. The consequence of wetting-phase saturation on NMR-based wettability determination is discussed. Wettability affects the relaxation rates of both the wetting and nonwetting phases in partially saturated rocks. Surface relaxation of the wetting phase in a rock results in shorter relaxation times than would otherwise be observed for the bulk fluid. The nonwetting-phase fluid molecules do not come into contact with the pore surfaces, and therefore their relaxation rate in the rock is the same as in the bulk fluid.We present accurate and robust computations of diffusion-free T 2 relaxation time distributions for both the wetting and nonwetting phases in four rocks that include two sandstones and two dolomites. A DE data suite was acquired on each rock, measured in two different partial saturation states and also fully brinesaturated. Wettability is determined by comparing the oil and brine T 2 relaxation-time distributions measured in the partially saturated rocks with the bulk oil T 2 distribution and with the T 2 distribution of the fully brine-saturated sample. The brine and oil T 2 distributions are used to compute saturation and oil viscosity values.A general discussion elucidating the sensitivity range and T 2 limits of diffusion-based NMR methods is given in the appendix. The appendix also derives and displays the gain in signal-to-noise ratio that is achieved by using DE data sequences for fluid characterization in place of Carr-Purcell-Meiboom-Gill (CPMG) data suites.

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“…These innovations are the MRF characterization method and DE pulse sequences. [1][2][3][4] The innovations are discussed in detail in the following sections.…”

Section: Introductionmentioning

confidence: 99%

Wettability, Saturation, and Viscosity From NMR Measurements

et al. 2003

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“…43 or 44. Recent presentations have recognized the importance of the methane content in NMR well logging and fluid sampling [24][25][26]. …”

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confidence: 99%

Mixing Rules and Correlations of NMR Relaxation Time With Viscosity, Diffusivity, and Gas/Oil Ratio of Methane/Hydrocarbon Mixtures

Hirasaki

House

et al. 2002

SPE Journal

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Viscosity, diffusivity, relaxation time, and gas/oil ratio are important properties in the characterization of reservoirs by nuclear magnetic resonance (NMR) well logging and in prediction of production performance. For the past few years, NMR well logging has been used to estimate formation properties and hydrocarbon liquid/ vapor characterization. Previous work has shown that pure alkanes, alkane mixtures, viscosity standards, and stock tank crude oils have NMR relaxation times that vary linearly with viscosity/ temperature and diffusivity on a log-log scale. However, pure methane at some temperatures and pressures does not follow the same trend. Thus, the linear correlation may not be valid for live crude oils that contain a significant amount of methane. Therefore, the study of methane-hydrocarbon mixtures is of interest.An NMR spectrometer equipped with a high-pressure probe was used to study the relationship between NMR T 1 relaxation time and viscosity/temperature, diffusivity, and gas/oil ratio of methane-hydrocarbon mixtures. Relaxation time and diffusivity measurements of three mixtures were made: methane-n-hexane, methane-n-decane, and methane-n-hexadecane. It was found that unlike stock tank oil, relaxation times do not depend linearly on viscosity/temperature on a log-log scale. Each of the mixtures forms a different curve.Generalized correlations between viscosity, diffusivity, gas/oil ratio, and NMR relaxation times were developed. First, the relaxation time mixing rule was developed by studying the theory of NMR relaxation mechanism. From the mixing rule, it was found that departure of relaxation times of methane-n-alkane mixtures from linear correlations on a log-log scale can be correlated with the proton fraction of methane, expressed as gas/oil ratio. Thus, correlations between relaxation time, viscosity/temperature, and gas/oil ratio were developed. Correlations between relaxation time, diffusivity, and gas/oil ratio were also developed. There is a linear relation between diffusivity and viscosity/temperature that is independent of composition. From these correlations, viscosity and gas/oil ratio can be estimated from NMR T 1 relaxation time and diffusivity.

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“…In theory, if the fluids in the reservoir can be distinguished on a D-T2 map, then the relative fluid volumes (i.e., water, oil, and gas saturations) can be determined from the data, along with an estimate of oil viscosity made from the assumed diffusion-free oil T2 distribution extracted from the measurement (Freedman and Heaton 2004;Freedman et al 2000Freedman et al , 2001. Partially to test this procedure, an effort was made (especially in Aishwariya) to collect wireline crude oil samples at points in the borehole at or near the MRF stations.…”

Section: Viscosity From Mrf Station Measurementsmentioning

confidence: 99%

Reservoir Crude Oil Viscosity Estimation From Wireline NMR Measurements - Rajasthan, India

Zittel¹,

Beliveau²,

O’Sullivan³

et al. 2008

SPE Reservoir Evaluation &Amp; Engineering

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In 2004, the Mangala, Aishwariya, and Bhagyam fields were discovered in Rajasthan, India. In these high-permeability paraffinic reservoirs, viscosity is one of the main factors controlling performance. Pressure, volume, and temperature (PVT) data show areal and vertical variations in crude properties. Meter-by-meter geochemical core analyses corroborate vertical variations in oil composition. Continuous wireline measurements of nuclear magnetic resonance (NMR) properties and station NMR properties from wells drilled with both water-based muds (WBM) and synthetic oil-based muds (OBM) were also used to calculate a viscosity profile. This paper correlates results from all techniques and shows how NMR measurements can provide oil viscosity profiles in compositionally complex pools.Black-oil PVT samples typically test several meters of reservoir, while Rajasthan geochemical data are available at meter scale. NMR logs provide continuous data, and calibrated to PVT and geochemistry, they can provide the most detailed picture of in-situ viscosity variations.Results were used to construct a detailed spatial description of the reservoir's in-situ oil viscosity. The NMR data helped to define a zone of biodegraded oil up to ∼25 m thick above the oil-water contact (OWC) and showed thin accumulations of higher-viscosity oil on top of minor shale layers within oil columns. The major conclusion is that detailed in-situ oil viscosity profiles can be developed from conventional wireline T2 measurements.

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A New NMR Method of Fluid Characterization in Reservoir Rocks: Experimental Confirmation and Simulation Results

Cited by 33 publications

References 12 publications

Wettability, Saturation, and Viscosity From NMR Measurements

Wettability, Saturation, and Viscosity From NMR Measurements

Mixing Rules and Correlations of NMR Relaxation Time With Viscosity, Diffusivity, and Gas/Oil Ratio of Methane/Hydrocarbon Mixtures

Reservoir Crude Oil Viscosity Estimation From Wireline NMR Measurements - Rajasthan, India

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