Low Field NMR Tool for Bitumen Sands Characterization: A New Approach

Mirotchnik, K., Allsopp, K., Kantzas, A., Curwen, D. and Badry, R.

DOI: 10.2118/56764-MS & 10.2118/71208-PA
SPE 56764, presented at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, TX USA, 3-6 October 1999;
SPE 71208, SPE Reservoir Evaluation and Engineering, 4(2), April 2001, Pages 88-96.


The nuclear magnetic resonance (NMR) signal obtained from conventional oil,heavy oil, and bitumen formations can consist of both hydrocarbon and water signals. Each NMR signal can further characterize both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts toward lower relaxation times, the composite NMR signal for the hydrocarbon-bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cp (at natural conditions), the relaxation characteristics of bitumen become partially non-detectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to precisely recognize the hydrocarbon components.

Laboratory NMR measurements of bitumen-bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low-field NMR holds promise for the characterization of recoverable heavy oil and bitumen reserves. This new approach can be applicable for real-time monitoring of thermal extraction,including monitoring the efficiency of thermal recovery methods.


NMR logging tools are currently used for determining reservoir properties such as porosity 1,2 and permeability,1-4 as well as the presence of mobile and immobile fluids.5-8 Recent developments in NMR research offer tools for separating water, oil, and gas from the combined NMR signal.9-11 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 (viscosity>100,000 cp). The reason for this is the fact that the spectra from most heavy-oil and bitumen formations cannot be adequately detected by the NMR logging tools. This is because the shortest relaxation times (t2’s) of the spectra at normal temperature conditions (T 30°C) are lost. High-field NMR technology has solved such problems in the past but is not currently available to be used downhole.12,13

A fundamental objective of the research performed in our laboratory was to extend the use of NMR logging tools to heavy-oil and bitumen formations,particularly during thermal recovery projects. To this end, the NMR characteristics of these types of hydrocarbons in bulk volume and in porous media were investigated.8,14 The objective of this work was to investigate the NMR characteristics of these bitumens and heavy oils at elevated vs. ambient temperatures and to isolate the oil signal from the combined NMR spectrum of the formation. The hydrocarbon and water saturations were then determined. The possibility of increasing the quality of NMR data by increasing the signal-to-noise ratio and by proper reconstruction of the whole t2 spectra was also investigated.

These objectives were achieved by performing a series of experiments, which addressed the following issues:

Variable-temperature NMR spectra determination for bitumen-saturated cores to estimate different fluid components in porous media in situ.

NMR characterization of brines, conventional oils, heavy oils, and bitumen in bulk volume at different temperatures.

Estimation of the parameters of NMR tools and their applicability for monitoring thermal recovery processes.

It must be noted that La Torraca et al.15 provided laboratory data that correlate NMR properties to viscosity of heavy oils ranging from <1,000 cp to >100,000 cp. Then they combined NMR log and conventional log data to predict the in-situ oil viscosity in two heavy-oil reservoirs. This work,15 although similar in nature to the work presented here, deals with oil reservoirs having 3 to 4 orders of magnitudeless viscosity. Unfortunately, algorithms presented in the literature seem to collapse when applied to bitumen formations.

Experimental Phase

All field measurements for bitumen sands characterization were performed with a Schlumberger CMR-200™ logging tool. All measurements were done at natural in-situ conditions; the maximum recorded temperature was T=14°C.One example of these results is presented in Fig. 1.

The entire NMR laboratory testing was performed with a custom-built Numar Corespec 1000™. This is a unique system with a separate temperature control for heating the magnet and the sample. The equipment was installed and tuned at the TIPM Laboratory and operates at a frequency of 1 MHz. All the samples were tested at different temperatures and at ambient pressure with a standard methodology developed for NMR log calibration. 16 All decay data were translated into NMR spectra with algorithms developed in-house and the NUMAR standard analysis packages 6 that are included with the spectrometer. Several sets of experiments were performed to address each of the issues mentioned earlier.

Variable-Temperature NMR Spectra of Core.

Variable-temperature NMR was used to determine the fluid components in bitumen- and water-saturated cores. The first set of experiments involved the testing of native state cores at different thermal conditions. Native-state bitumen-saturated plug samples were cut from full-size core using a liquid-nitrogen-cooled cutter. Testing started with NMR measurements at the following temperatures: 1°C, 6°C, 8°C, 12°C, 16°C, 22°C, 25°C, 30°C, 40°C,45°C, 50°C, 60°C, 65°C, 70°C, 75°C, and 80°C. For all measurements, a CPMG sequence was applied with inter echo times of 0.3 and 0.6 ms. The NMR spectra were recovered.

After completion of the temperature-cycle testing, the native-state bitumen-saturated plugs were saturated under vacuum with an aqueous paramagnetic solution (2N CuSO4, T2 1ms). The fact that water entered the cores under vacuum implies that some drying occurred during core handling. This procedure was performed to eliminate the water signal from subsequent NMR testing. The samples were measured at 30°C. Following the NMR data collection with the paramagnetic solution, the sand samples were cleaned using the Dean-Stark method (thus removing all bitumen) and re-saturated with 2% NaCl brine. The brine-saturated samples were tested in the NMR again at the previous temperatures. This determined that the NMR spectrum of the sample was free of any bitumen effects, measuring only structural and mineralogical effects.

X-ray diffraction (XRD) analyses were performed to determine clay type and concentration. In accordance with these analyses, a set of artificial samples(sand + clay) was constructed. All samples were saturated with 2% NaCl brine.The brine-saturated artificial samples were tested to determine the NMR spectra, again at the temperatures mentioned above. Examples of the obtained spectra set are presented in Figs. 2 through 4.

A full version of this paper is available on OnePetro Online.