The Honorary Chairman’s Prize at Best Innovators 2016
MRsat is an alternative solution for measuring the oil and water content of shale rock. This patented innovation is able to measure rock saturation five times faster and with ten times the precision of existing solutions, all with no risk of toxicity or destruction of samples.
Shale poses a number of challenges for the oil industry. For a full petrophysical assessment of this rock type to be carried out, we need to know its porosity, permeability, hydrocarbon content, and friability. However, measuring these parameters has turned out to be much more difficult than for conventional reservoirs.
Two methods are commonly used to measure hydrocarbon and water saturation in shale samples: solvent extraction (Dean Stark) or thermal extraction (Retort). The main disadvantage of using these methods is that they lack precision. They can also lead to destruction of the rock sample, and the use of solvents carries with it the risk of exposing workers to toxic fumes.
We therefore decided to begin investigating for more effective alternative techniques.
Specific oil/water signatures in NMR
While working with rock samples from the Vaca Muerta geological formation in Argentina, we noticed that the acquisition from a high-resolution 2 MHz T1-T2 NMR card yielded two separate signals.
In conventional rock types, magnetic resonance measurements can be used to show diffusion contrast between water and oil. In shale though, the rock pores are so small that a diffusion coefficient is impossible to detect. Yet here we were faced with two separate signals, just when we were looking to identify two different liquids - water and oil. We therefore decided to investigate this coincidence further by launching a “technological innovation project” in collaboration with Total’s unconventionals team.
In this, several experiments involving the imbibition of water, oil and heavy water (invisible to NMR) enabled us to show that the different signals observed in NMR did indeed correspond with water and oil. This meant there was a contrast between the magnetic resonance signatures of these liquids in shale. Evidence in hand, we patented the concept of measuring oil saturation in shale with a T1-T2 NMR card.
Increasing fluid contrast with high frequencies
Next, an academic-corporate partnership (established with the backing of the Group’s science division) granted us access to a multi-frequency NMR measurement device and allowed us to propose a comprehensive theory on NMR relaxation in nanopores. Based on our predictions, the NMR contrast between water and oil would intensify in line with the NMR frequency. Generating a higher frequency would therefore have two significant advantages:
- Net improvement in the signal/noise ratio, resulting in faster experiment times;
- Better separation of water and oil signals.
In order to validate this hypothesis, we equipped ourselves with a 23 MHz NMR spectrometer. We compared these results with the ones we obtained using another high-precision lab technique for quantifying water content: thermogravimetric analysis coupled with mass spectrometry (TG-MS). The excellent concordance between the results from both methods effectively validated the MRsat protocol.
Our discovery was the subject of one of the best SCA 2015 papers, and was featured on the cover of Petrophysics in February 2016.
MRsat: quicker, more precise and more reliable saturation measurements
Compared with traditional methods, the saturation measurements obtained by nuclear magnetic resonance with MRsat are ten times more precise than the industry standard, and cost a fifth in terms of laboratory costs and processing times. The analysis is also non-destructive, meaning the rock sample can be reused for other measurements. Furthermore, there is no longer any need for toxic solvents, eliminating safety and environmental risks. This invention is currently patented and held exclusively by Total.
Beyond the technical advantages, the potential gains in investment and operational costs are enormous, because greater knowledge of the rock itself improves control of operational resources. This innovative assessment method will therefore have a strategic impact on the future development of shale rock fields, and also showcases Total’s knowledge and expertise in non-conventional operations to new potential partners.
Unlike conventional rock, shale has low porosity and a dual network of pores (mineral and organic), which makes it more difficult to take measurements.
A comparison of saturation results obtained from Dean Stark and Retort testing of shale samples, demonstrating the inconsistencies of using traditional techniques. Graph constructed using data from Simpson SCA 2015.
Excerpt from the cover of Petrophysics Journal on February 2016 showing our images. Left: NMR T1-T2 signals obtained from an “as received” sample; center: NMR signals obtained from a sample imbibed with water; right: NMR signals obtained from a sample imbibed with oil.
Cross-validation of the MRsat and TG-MS results. The excellent concordance of the two measurements validates the approach.
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