NMR properties of petroleum reservoir fluids

NMR well logging of petroleum reservoir require the measurement of the NMR response of water, oil, and gas in the pore space of rocks at elevated temperatures and pressures. The viscosity of the oil may range from less than 1 cp to greater than 10,000 cp. Also, the oil and gas are not a single component but rather a broad distribution of components. The log mean T1 and T2 relaxation time of dead (gas free) crude oils are correlated with viscosity/temperature and Larmor frequency. The relaxation time of live oils deviate from the correlation for dead crude oils. This deviation can be correlated with the methane content of the oil. Natural gas in the reservoir has components other than methane. Mixing rules are developed to accommodate components such as ethane, propane, carbon dioxide, and nitrogen. Interpretation of NMR logs uses both relaxation and diffusion to distinguish the different fluids present in the formation. Crude oils have a broad spectrum of components but the relaxation time distribution and diffusion coefficient distribution are correlated. This correlation is used to distinguish crude oil from the response of water in the pores of the rock. This correlation can also be used to estimate viscosity of the crude oil.     

NMR imaging of fluid dynamics in reservoir core

A medical NMR imaging instrument has been modified to image water and oil in reservoir rocks by the construction of a new receiving coil. Both oil and water inside the core produced readily detectable proton NMR signals, while the rock matrix produced no signal. Because of similar T2 NMR relaxation times, the water was doped with a paramagnetic ion, Mn+2, to reduce its T2 relaxation time. This procedure enhanced the separation between the oil and water phases in the resulting images. Sequential measurements, as water imbibed into one end and oil was expelled from the other end of a core plug, produced a series of images which showed the dynamics of the fluids. For water-wet Berea Sandstone a flood front was readily observed, but some of the oil was apparently left behind in small, isolated pockets which were larger than individual pores. After several additional pore volumes of water flowed through the plug the NMR image indicated a homogeneous distribution of oil. The amount of residual oil, as determined from the ratio of NMR intensities, closely approximated the residual oil saturation of fully flooded Berea samples measured by Dean-Stark extraction. A Berea sandstone core treated to make it partially oil-wet, did not show a definitive flood front, but appeared to channel the water around the perimeter of the core plug. The relative ease with which these images were made indicates that NMR imaging can be a useful technique to follow the dynamics of oil and water through a core plug for a variety of production processes.     

Computation of dynamic seismic responses to viscous fluid of digitized three-dimensional Berea sandstones with a coupled finite-difference method

The seismic response of saturated porous rocks is studied numerically using microtomographic images of three-dimensional digitized Berea sandstones. A stress-strain calculation is employed to compute the velocities and attenuations of rock samples whose sizes are much smaller than the seismic wavelength of interest. To compensate for the contributions of small cracks lost in the imaging process to the total velocity and attenuation, a hybrid method is developed to recover the crack distribution, in which the differential effective medium theory, the Kuster-Tokso?z model, and a modified squirt-flow model are utilized in a two-step Monte Carlo inversion. In the inversion, the velocities of P- and S-waves measured for the dry and water-saturated cases, and the measured attenuation of P-waves for different fluids are used. By using such a hybrid method, both the velocities of saturated porous rocks and the attenuations are predicted accurately when compared to laboratory data. The hybrid method is a practical way to model numerically the seismic properties of saturated porous rocks until very high resolution digital data are available. Cracks lost in the imaging process are critical for accurately predicting velocities and attenuations of saturated porous rocks.     

Development of the Miniature NMR Apparatus for Edible Oil Quality Control

Edible oils are necessary in daily cooking; therefore, it is significantly important to find an efficient scheme for its quality control. In this work, a miniature nuclear magnetic resonance (NMR) apparatus was set up for the identification of edible oils with different qualities. Experimental results show that the total transverse relaxation time of the commercial refined edible oil is shorter than the poor quality edible oil. Further data processing was performed with inverse Laplace transformation for transverse relaxation time distribution analysis. The spectra of the distribution of transverse relaxation times of different qualities edible oils are also significantly different, among which, the refined edible oil has two peaks whereas the poor quality edible oil has three peaks. The experimental results are well agreed with the theoretical analysis. As the miniature NMR apparatus was employed to analyze three suspected illegal cooking oils which were seized at the scene of inspection, the three oils were all confirmed to be poor quality edible oils. The apparatus can also detect refined edible oils adulterated with illegal cooking oils. In conclusion, the presented miniature NMR apparatus could be a potential tool for edible oil quality control.     

A global inversion method for multi-dimensional NMR logging

We describe a general global inversion methodology of multi-dimensional NMR logging for pore fluid typing and quantification in petroleum exploration. Although higher dimensions are theoretically possible, for practical reasons, we limit our discussion of proton density distributions as a function of two (2D) or three (3D) independent variables. The 2D can be diffusion coefficient and T(2) relaxation time (D-T(2)), and the 3D can be diffusion coefficient, T(2), and T(1) relaxation times (D-T(2)-T(1)) of the saturating fluids in rocks. Using the contrast between the diffusion coefficients of fluids (oil and water), the oil and water phases within the rocks can be clearly identified. This 2D or 3D proton density distribution function can be obtained from either two-window or regular type multiple CPMG echo trains encoded with diffusion, T(1), and T(2) relaxation by varying echo spacing and wait time. From this 2D/3D proton density distribution function, not only the saturations of water and oil can be determined, the viscosity of the oil and the gas-oil ratio can also be estimated based on a previously experimentally determined D-T(2) relationship.     

Nonlinear and nonequilibrium dynamics in geomaterials

The transition from linear to nonlinear dynamical elasticity in rocks is of considerable interest in seismic wave propagation as well as in understanding the basic dynamical processes in consolidated granular materials. We have carried out a careful experimental investigation of this transition for Berea and Fontainebleau sandstones. Below a well-characterized strain, the materials behave linearly, transitioning beyond that point to a nonlinear behavior which can be accurately captured by a simple macroscopic dynamical model. At even higher strains, effects due to a driven nonequilibrium state, and relaxation from it, complicate the characterization of the nonlinear behavior.     

Probing the analogy of the proton relaxation in biological tissues and porous media

Summary Experimental data are reported that show the analogy of longitudinal and transverse proton relaxation in heterogeneous systems as different as biological tissues and water-saturated rocks. Published data on the τ-dependence of the transverse-relaxation rate for biological tissues with magnetite grains, used as a contrast agent in MRI, are discussed in the light of our recent results on water-saturated porous media, and give for the liver another case of a behaviour parallel to that in rocks. There are enough similarities between NMR relaxation in tissues and in other porous media that, for work in either area, attention to the other is likely to be fruitful. Work supported by Italian CNR and MURST grants     

二维核磁共振观测岩石润湿性

润湿性是反映储层中油水分布状况的一个重要表征参数,因此研究储层岩石的润湿性对原油开采有着重要的意义. 扩散弛豫二维谱可展示扩散系数与弛豫时间的相关性,并可以对油水的弛豫时间、扩散系数分别进行研究,与核磁共振一维弛豫谱相比极大地提高了区分油水的能力. 该文首先通过多组实验验证扩散-弛豫二维谱可以很好地观测到油水共存状态下玻璃珠表面的润湿性,继而通过对3组人造岩心表面润湿性的测量,获得了人造岩心表面润湿性的信息,解决了此时单独用一维弛豫谱方法难以区分油水的问题. 利用二维谱观察岩石润湿性的研究对油田提高采收率的研究有较大的参考价值.     

Effective Gradients in Porous Media Due to Susceptibility Differences

In porous media, magnetic susceptibility differences between the solid phase and the fluid filling the pore space lead to field inhomogeneities inside the pore space. In many cases, diffusion of the spins in the fluid phase through these internal inhomogeneities controls the transverse decay rate of the NMR signal. In disordered porous media such as sedimentary rocks, a detailed evaluation of this process is in practice not possible because the field inhomogeneities depend not only on the susceptibility difference but also on the details of the pore geometry. In this report, the major features of diffusion in internal gradients are analyzed with the concept of effective gradients. Effective gradients are related to the field inhomogeneities over the dephasing length, the typical length over which the spins diffuse before they dephase. For the CPMG sequence, the dependence of relaxation rate on echo spacing can be described to first order by a distribution of effective gradients. It is argued that for a given susceptibility difference, there is a maximum value for these effective gradients,g_max, that depends on only the diffusion coefficient, the Larmor frequency, and the susceptibility difference. This analysis is applied to the case of water-saturated sedimentary rocks. From a set of NMR measurements and a compilation of a large number of susceptibility measurements, we conclude that the effective gradients in carbonates are typically smaller than gradients of current NMR well logging tools, whereas in many sandstones, internal gradients can be comparable to or larger than tool gradients.     

Molecular dynamics of n-dodecylammonium chloride in aqueous solutions investigated by 2H NMR and 1H NMR relaxometry

Molecular dynamics in n-dodecylammonium chloride/water solutions for concentrations of 34 and 45 wt% was studied by 2H NMR and by 1H NMR dispersion of spin-lattice relaxation in the 2 kHz-90 MHz frequency range. The system exhibits a number of lyotropic liquid crystalline phases, which differ in symmetry and involve motions characterized by a wide frequency scale. The analysis of 2H NMR lineshapes of selectively deuterated DDACl molecules gave us an evidence for local trans-gauche conformational changes in the chains, whereas the dispersion of spin-lattice relaxation times T1 explored by fast field cycling method revealed fast local motions, translational diffusion and collective molecular dynamics of the chains. In particular, we have found that the order director fluctuation mechanism in smectic and nematic phases dominates spin-lattice relaxation below 1 MHz and that local motions and translational diffusion are responsible for the spin-lattice relaxation in the higher Larmor frequency range.     

In SituNMR Analysis of Fluids Contained in Sedimentary Rock

Limitations of resolution and absorption in standard chemical spectroscopic techniques have made it difficult to study fluids in sedimentary rocks. In this paper, we show that a chemical characterization of pore fluids may be obtainedin situby magic angle spinning (MAS) nuclear magnetic resonance (NMR), which is normally used for solid samples.¹H MAS–NMR spectra of water and crude oil in Berea sandstone show sufficient chemical shift resolution for a straightforward determination of the oil/water ratio.     

Nuclear magnetic resonance of some oils

The author subjected some oils to nuclear magnetic resonance in order to obtain information on their structure and to compare their behaviour at NMR. Saturation curves were obtained and the longitudinal and transverse relaxation times of the resonance of these oils were investigated. Relations were derived for calculating the number of resonating hydrogen nuclei per unit volume of oil, both by direct study of the signals on a cathode ray oscilloscope and by recording the differential of the absorption curve of NMR. The number of hydrogen nuclei per unit volume and mass of the oils was calculated. Equations were derived for the longitudinal relaxation time of glycerine and castor oil. Relations were also found from which qualitative conclusions could be drawn as to the average molecule mass of the oils and the mean distance of the resonating hydrogen nuclei of the different oils. Castor oil, bearing oil 207, paraffin oil, transformer oil B, one lubricating oil of commercial quality and methyl silicon oil were investigated and glycerine was used as the normal of the relaxation time and signal intensity. In addition, the intensities of the NMR signals of some naphtha oils, immersion oil and some polymer oils were measured.The author used an arrangement for observing and recording the NMR signal with an autodyne detector, which has been described in another paper. The sensitivity curve of the autodyne detector was measured and respected in the calculations.     

页岩油气层核磁共振评价技术综述

对于常规储层,核磁共振是一项十分有效的解释-评价技术,它既能评价岩石物性与孔隙结构,又能评价孔隙流体分布与饱和度,且具有快速、无损、经济等特点;而对于页岩储层,其核磁共振受纳米级孔隙、复杂矿物成分、特殊孔隙结构、较高有机质含量、超低渗透性及内部梯度和受限扩散等因素的影响,面临探测分辨率低、解释模型不适用等瓶颈．为了发挥该项技术在页岩油气勘探开发中的作用,将国内外的页岩油气层核磁共振分析、评价技术与相关的页岩油气层实验室微观分析成果相结合,进行了系统梳理,从探测分辨率的提高、孔隙结构与岩石物性评价模型的建立、孔隙流体分布与识别模型的建立等方面进行了综述,提出需加强纳米孔的核磁共振弛豫机理和提高 D-T₂二维谱分辨率两个基础研究,在此基础上,进一步完善岩石物理及孔隙流体两个评价模型．
     

CPMG relaxation by diffusion with constant magnetic field gradient in a restricted geometry: numerical simulation and application

Carr-Purcell-Meiboom-Gill (CPMG) measurements are the primary nuclear magnetic resonance (NMR) technique used for evaluating formation properties and reservoir fluid properties in the well logging industry and laboratory sample analysis. The estimation of bulk volume irreducible (BVI), permeability, and fluid type relies on the accurate interpretation of the spin-spin relaxation time (T(2)) distribution. The interpretation is complicated when spin's self-diffusion in an inhomogeneous field and restricted geometry becomes dominant. The combined effects of field gradient, diffusion, and a restricted geometry are not easily evaluated analytically. We used a numerical method to evaluate the dependence of the free and restricted diffusion on the system parameters in the absence of surface relaxation, which usually can be neglected for the non-wetting fluids (e.g., oil or gas). The parameter space that defines the relaxation process is reduced to two dimensionless groups: D* and tau*. Three relaxation regimes: free diffusion, localization, and motionally averaging regimes are identified in the (log(10)D*, log(10)tau*) domain. The hypothesis that the normalized magnetization, M*, relaxes as a single exponential with a constant dimensionless relaxation time T*(2) is justified for most regions of the parameter space. The numerical simulation results are compared with the analytical solutions from the contour plots of T*(2). The locations of the boundaries between different relaxation regimes, derived from equalizing length scales, are challenged by observed discrepancies between numerical and analytical solutions. After adjustment of boundaries by equalizing T*(2), numerical simulation result and analytical solution match each other for every relaxation regime. The parameters, fluid diffusivity and pore length, can be estimated from analytical solutions in the free diffusion and motionally averaging regimes, respectively. Estimation of the parameters near the boundaries of the regimes may require numerical simulation.     

NMR in well logging and hydrocarbon exploration

Nuclear magnetic resonance (NMR) has become a versatile tool for the evaluation of underground hydrocarbon reservoirs. Formation attributes such as rock porosity and rock pore size distributions, as well as the relative concentrations of water, oil and gas, can be inferred from subsurface NMR. The hydrogen NMR signal encodes porosity as amplitude, pore sizes as relaxation times and fluid properties as a mixture of relaxation and diffusion rates. The paper describes the basic operating principles for NMR on cable (wireline), NMR on a drill string (logging-while-drilling) and NMR for downhole fluid sampling. The geometry of the borehole requires a magnet that projects its field into the surrounding rock, implying a grossly inhomogeneous field distribution. Experience shows that even under these circumstances, saturation-recovery and Carr-Purcell-Meiboom-Gill sequences can work well and yield meaningfulT ₁ andT ₂ information.     

Two-dimensional nuclear magnetic resonance petrophysics

Two-dimensional nuclear magnetic resonance (2D NMR) opens a wide area for exploration in petrophysics and has significant impact to petroleum logging technology. When there are multiple fluids with different diffusion coefficients saturated in a porous medium, this information can be extracted and clearly delineated from CPMG measurements of such a system either using regular pulsing sequences or modified two window sequences. The 2D NMR plot with independent variables of T2 relaxation time and diffusion coefficient allows clear separation of oil and water signals in the rocks. This 2D concept can be extended to general studies of fluid-saturated porous media involving other combinations of two or more independent variables, such as chemical shift and T1/T2 relaxation time (reflecting pore size), proton population and diffusion contrast, etc.     

Wettability alteration of sandstones by silica nanoparticle dispersions in light and heavy crude oil

Unlike conventional oil production methods, enhanced oil recovery (EOR) processes can recover most oil products from the reservoir. One method, known as wettability alteration, changes the hydrophilicity of the reservoir rock via decreased surface interactions with crude oils. The mitigation of these attractive forces enhances petroleum extraction and increases the accessibility of previously inaccessible rock deposits. In this work, silica nanoparticles (NPs) have been used to alter the wettability of two sandstone surfaces, Berea and Boise. Changes in wettability were assessed by measuring the contact angle and interfacial tension of different systems. The silica NPs were suspended in brine and a combined solution of brine and the Tween®20 nonionic surfactant at concentrations of 0, 0.001, and 0.01 wt% NP with both light and heavy crude oil. The stability of the different nanofluids was characterized by the size, zeta potential, and sedimentation of the particles in suspension. Unlike the NPs, the surfactant had a greater effect on the interfacial tension by influencing the liquid-liquid interactions. The introduction of the surfactant decreased the interfacial tension by 57 and 43% for light and heavy crude oil samples, respectively. Imaging and measurements of the contact angle were used to assess the surface-liquid interactions and to characterize the wettability of the different systems. The images reflect that the contact angle increased with the addition of NPs for both sandstone and oil types. The contact angle in the light crude oil sample was most affected by the addition of 0.001 wt% NP, which altered both sandstones’ wettability. Increases in contact angle approached 101.6% between 0 and 0.001 wt% NPs with light oil on the Berea sandstone. The contact angle however remained relatively unaffected by addition of higher NP concentrations, thus indicating that low NP concentrations can effectively be used for enhancing crude oil recovery. While the contact angle of the light crude oil plateaued, the heavy crude oil continued to increase with an increase in NP concentration; therefore indicating that a maximum contact angle in heavy crude oil was not yet achieved. The introduction of NPs in light and heavy crude oil samples altered both the Berea and Boise sandstone systems’ wettability, which in turn indicated the efficacy of the silica NPs and surfactants in generating a more water-wet reservoir. Consequently, silica NPs and surfactants are most promising for EOR across the range of oil types.     

In situ fluid typing and quantification with 1D and 2D NMR logging

In situ nuclear magnetic resonance (NMR) fluid typing has recently gained momentum due to data acquisition and inversion algorithm enhancement of NMR logging tools. T(2) distributions derived from NMR logging contain information on bulk fluids and pore size distributions. However, the accuracy of fluid typing is greatly overshadowed by the overlap between T(2) peaks arising from different fluids with similar apparent T(2) relaxation times. Nevertheless, the shapes of T(2) distributions from different fluid components are often different and can be predetermined. Inversion with predetermined T(2) distributions allows us to perform fluid component decomposition to yield individual fluid volume ratios. Another effective method for in situ fluid typing is two-dimensional (2D) NMR logging, which results in proton population distribution as a function of T(2) relaxation time and fluid diffusion coefficient (or T(1) relaxation time). Since diffusion coefficients (or T(1) relaxation time) for different fluid components can be very different, it is relatively easy to separate oil (especially heavy oil) from water signal in a 2D NMR map and to perform accurate fluid typing. Combining NMR logging with resistivity and/or neutron/density logs provides a third method for in situ fluid typing. We shall describe these techniques with field examples.