NMR Logging Tool Research Articles

UTILIZING CORE AND NMR DATA TO IDENTIFY ROCK-TYPE AND PORE THROAT RADIUS FOR MISHRIF FORMATION IN WEST QURNA OILFIELD

The middle Cretaceous Mishrif Formation represents the main carbonate reservoir in southern Iraq, charactered by heterogeneity and complexity vertically and laterally, this reservoir encompasses six facies that graduated from mid-ramp facies to supratidal facies. Mishrif Formation in West Qurna oilfield consists of three main reservoir units namely mA, mB1 and mB2 with two cap rocks units CRⅠ and CRⅡ. Rock type and pore throat radius govern the relationship between porosity and permeability. Porosity and permeability are important petrophysical parameters for reservoir evaluation and can be determined directly from core analysis or indirectly using the NMR logging tool. Core data from four wells and NMR data from one well were used to determine the rocks type and the pore throat radius. In this study, Lucia rocks type plot between the porosity and permeability was used to define the classes of Mishrif units’ characteristics. Rocks type of Mishrif Formation was wackestone and packstone in mB2 unit. The mB1unit exhibits increasing in the grain dominated class1. Whereas, unit mA showed a mud-dominated class 3 again. Winland plot was utilized to determine the pore throat radius depending on the mercury injection test with 35% mercury saturation. The unit mB2 marked as mesopores and macropores. Megapores and macropores attribute increased in mB1in the northern part of West Qurna oilfield unit due to increasing shoal and rudist bioherm facies, the mA unit revealed increasing in meso-porous and decreasing in mega-porous. NMR data was correlated with core data and the results supported this reservoir characteristic.

Corrections for downhole NMR logging

Nuclear magnetic resonance logging (NMR) is an open well logging method. Drilling mud resistivity, formation resistivity and sodium ions influence its radio frequency (RF) field strength and NMR logging signals. Research on these effects can provide an important basis for NMR logging data acquisition and interpretation. Three models, water-based drilling mud—water bearing formation, water-based drilling mud—oil bearing formation, oil-based drilling mud—water bearing formation, were studied by finite element method numerical simulation. The influences of drilling mud resistivity and formation resistivity on the NMR logging tool RF field and the influences of sodium ions on the NMR logging signals were simulated numerically. On the basis of analysis, RF field correction and sodium ion correction formulae were proposed and their application range was also discussed. The results indicate that when drilling mud resistivity and formation resistivity are 0.02 Ω·m and 0.2 Ω·m respectively, the attenuation index of centric NMR logging tool is 8.9% and 9.47% respectively. The RF field of an eccentric NMR logging tool is affected mainly by formation resistivity. When formation resistivity is 0.1 Ω·m, the attenuation index is 17.5%. For centric NMR logging tools, the signals coming from sodium ions can be up to 31.8% of total signal. Suggestions are proposed for further research into NMR logging tool correction method and response characteristics.

Nuclear-Magnetic-Resonance Petrophysics in Thin Sand/Shale Laminations

Summary We discuss the use of nuclear-magnetic-resonance (NMR) logging in the petrophysical evaluation of thin sand/shale laminations. NMR helps detect thin beds, determine fluid type, establish the hydrocarbon type and volume if hydrocarbon is present, and, finally, determine the permeability of the sand layers (as opposed to that of the sand/shale system). Experiments were conducted on samples of 100% sand, 100% clay, and sand/clay layers with an NMR-logging tool at surface to verify the characteristic T2 bimodal relaxation distribution often observed in NMR logs that are acquired in thin beds. From the bimodal distribution, it is often possible to determine a cutoff to separate the productive sand layers from the shale layers and, with it, the porosity fraction of each component. Subsequently, the sand fraction, or net/gross ratio, can be estimated assuming that the 100%-sand porosity is known. Because gas, oil, and water have different NMR properties, fluid-typing techniques such as 2D NMR offer useful insights into the fluid type and properties in thin-layer sands. Because the laminations thickness is often less than the antenna aperture, the estimated permeability of the sand/ shale system will undercall the true permeability of the sand layers only. In this case, their permeability can be estimated quickly from Darcy's fluid-flow model. We show examples of thin sand/shale laminations that are oil-bearing and gas-bearing. In each case, the NMR detection was verified against borehole-imaging logs, and the fluid type in the sands was determined from multidimensional NMR analysis. The derived hydrocarbon volume was then compared with the results estimated from a triaxial induction tool. Permeability of the sand layers was also computed and compared to that of nearby thick sands. Core data in one well was used to validate NMR detection, porosity, permeability, and net sand thickness.

In Situ Viscosity of Heavy Oil: Core and Log Calibrations

Abstract Having knowledge of oil viscosity variation within reservoirs would be of considerable benefit when producing from heavy oil fields. Previous work has demonstrated that low field NMR bench-top instruments can be used to perform measurements of in situ viscosity. Ideally, if these measurements could be performed on NMR logging tools, viscosity characterization studies could be carried out using fewer core samples. In this paper, data is presented for a heavy oil reservoir in northern Alberta. A methodology is presented for tuning NMR viscosity estimates to the field in question, and core analysis results are collected, showing that in situ viscosity predictions are possible in the laboratory. NMR spectra measured in the laboratory are compared to NMR logging tool spectra, in order to determine if results obtained using bench-top instruments can be extrapolated to logging tool data. Introduction Canada has significant proven reserves from the oil sands in Saskatchewan and northern Alberta, which constitute some of the largest resource bases in the world. With the decline of conventional oil reserves in Canada, interest is shifting rapidly to the production of this heavy oil. Heavy oil and bitumen are characterized by high fluid viscosity and density values similar to that of water. The high oil viscosity is the single greatest impediment to the successful recovery of this resource, and the viscosity is directly related to both the technical success of any chosen recovery scheme and the economic value of the oil. As a result, oil viscosity information is key when estimating reserves and developing recovery options from heavy oil and bitumen formations. In many heavy oil and bitumen reservoirs in Alberta, and likely all over the world, viscosity may vary significantly with depth and location(1,2). This may be due to biodegradation of the bitumen(2), along with other factors such as supply of micro-organisms to the oil and the solution gas-oil ratio. A result of this viscosity variation is that any chosen thermal or non-thermal enhanced oil recovery option will vary in effectiveness in different parts of the reservoir. Therefore, being able to map viscosity variations, along with proper characterization of rock properties, will also significantly affect the economics and recovery from heavy oil projects. Viscosity is conventionally measured by two different methods(3). Samples are either taken from the produced fluid from the wellhead, or oil sand samples are taken into the laboratory and oil is extracted in order to measure its viscosity. The difficulty in making measurements on wellhead samples is that the oil may have been contaminated by diluents or drilling fluid(3), or may contain significant emulsified water from thermal operations. This means that viscosity values obtained from wellhead oil samples must be used carefully and should be analyzed in order to ensure that they are truly representative of the oil viscosity in the formation. Measurements on bitumen that has been extracted from core samples are generally more accurate, but also tend to be more expensive. Care must be taken to ensure that enough samples are taken to properly characterize the fluid viscosity in the reservoir.

A time‐domain induced‐polarization method for estimating permeability in a shaly sand reservoir

ABSTRACTIt is known that the time‐domain induced‐polarization decay curve for a shaly sand reservoir depends on the pore structure of the reservoir, and this curve can be used to estimate permeability, which is a determining factor in making production decisions in the petroleum industry. Compared with NMR logging tools, induced polarization has several advantages, such as a deep depth of investigation and a high signal‐to‐noise ratio. The purpose of this paper is to establish an appropriate model using induced polarization to estimate the permeability. The curve can be modelled as a weighted superposition of exponential relaxations. The plot of weight versus the relaxation time constant is defined as the relaxation time spectrum.Induced‐polarization decay‐curve measurements were performed on 123 samples from the Daqing oilfield using a four‐electrode technique. A singular‐value decomposition method was used to transform the induced‐polarization decay data into a spectrum. Different models to estimate the permeability were discussed. The results of the research indicate that the induced‐polarization measurements greatly improve the statistical significance of permeability correlations. Compared with the traditional forms, AφC and AFC, the forms, ATBφC and ATBFC, have lower error factors, where T, Φ and F are the geometric mean time constant of the induced‐polarization relaxation time spectrum, the porosity and the resistivity formation factor, respectively, and A, B and C are constants. The mean time constant is the decisive parameter in the permeability estimation and it is not completely independent of the resistivity formation factor. The additional use of the porosity and the resistivity formation factor leads to an appreciable improvement. It is concluded that this new model will make it possible to estimate the permeability of a shaly sand reservoir downhole.

A New Method for Group Analysis of Petroleum Fractions in Unconsolidated Porous Media

Abstract A fast and accurate method for the group analysis of crude oils in porous media that describes petroleum components (especially heavy fractions) has been developed. NMR structure group analysis is used as the tool for the characterization of crude oils. This method is proposed as an alternative to existing complicated and laborious methods of characterization of extracted oil samples. Currently, group analysis of heavy fractions of crude oils is being investigated by means of chromatographic methods, such as the SARA (saturates-aromatics-resinsasphaltenes) test. These methods are usually expensive, and require considerable work from qualified personnel. Furthermore, these methods cannot be used for estimating the oil components in situ. The basis of determining crude oil components using NMR is the difference of the nuclei mobility in the different hydrocarbons during the NMR testing period. A combination of solvent extraction, NMR testing and data processing gives a series of NMR terms that are then used to specify hydrocarbon mixtures and their components both in the bulk phase and in unconsolidated porous media. Introduction NMR logging tools are currently used for determining reservoir properties such as porosity(1, 2), permeability(1-4), as well as mobile and immobile fluids(5-7). Recent developments in NMR research offer tools for separating water, oil, and gas from the combined NMR signal(7, 8). Very little is known about the use of NMR logging tools for the in situ characterization of crude oils(1). With respect to heavy oil and bitumen formations, NMR logging has not been very successful in characterizing crude oil. The reason for the lack of such success is the fact that the NMR logging tools cannot detect the spectra from most heavy oil and bitumen formations. It should be noted that high field NMR technology has solved such problems in the past, but such technology cannot be used downhole. A fundamental objective of the research performed in our laboratory is to extend the use of NMR logging tools to all heavy oil and bitumen formations. To this end, the NMR characteristics of heavy oils in porous media were investigated(9, 10). The objective of our work is to isolate the oil signal from the combined NMR spectrum of the formation, and then shift it towards the relaxation time range that can be detected by the conventional NMR logging tools. Once this goal is achieved, NMR logs of heavy oil and bitumen formations can become successful in the analysis of oil downhole. This objective was accomplished in the material presented in this paper through a series of experiments that addressed the following issues:Relaxation interactions in mixtures of simple organic liquids with water.Relaxation interactions in mixtures of simple organic liquids. Relaxation interactions in mixtures of simple organic liquids with solvents.Relaxation times of conventional crude oils with and without solvents present.Relaxation times of heavy crude oils and bitumen with and without solvents present.Relaxation times of heavy crude oils and bitumen with and without solvents in unconsolidated sands and with variable connate water saturation.

A high resolution NMR logging tool: concept validation

A high resolution NMR logging tool: concept validation