In Situ Viscosity of Heavy Oil: Core and Log Calibrations
Authors: Bryan J. , Kantzas A. , Badry R. , Emmerson J. , Hancsicsak T. 
Published: March 2010

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.