Imbibition Oil Recovery From Tight Rocks With Dual-Wettability Networks in the Montney

Topics: Enhanced recovery Tight gas/shale gas/coalbed methane
Fig. 1—Recovered oil (yellow droplets lined up at the surface of the sample) is observed along the depositional laminations of an oil-saturated sample immersed in brine.

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Previous studies demonstrate that Montney rock samples present a dual-wettability pore network. Recovery of the oil retained in the small hydrophobic pores is uniquely challenging. In this study, the authors applied dual-core-imbibition (DCI) methods on several Montney core plugs and introduced the imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore networks.


Spontaneous imbibition of aqueous phases (water, brine, or surfactant solutions) in fractured sandstone has been studied as a possible mechanism for enhanced oil recovery. Extensive experimental and mathematical investigations have been conducted for relating the imbibition rate and total oil recovery to the capillary and gravity forces and geometrical parameters. However, rock/fluid interactions in tight and shale reservoirs are more complicated than those seen in conventional reservoirs. In addition to capillary forces, organic materials and reactive clay minerals can influence the fluid flow and storage in the small pores of low-permeability rocks. The affinity of reservoir rock to a particular fluid in such formations depends especially on rock mineralogy and properties of the organic matter that coats and fills the pores.

Previous comparative imbibition tests show that the affinity of the Montney samples to oil is significantly higher than their affinity to water. This behavior was explained by the presence of water-­repellent pores within or coated by solid bitumen or pyrobitumen. In the complete paper, the authors focus on imbibition oil recovery of samples cored from the Montney Formation and investigate the role of rock-fabric complexities, such as dual-wettability characteristics, in oil recovery by water imbibition. A detailed discussion of materials used in the spontaneous-imbibition and oil-recovery tests, including rock and fluid properties, is included in the complete paper.


The authors conducted three sets of comparative tests on five twin core plugs, which were dry cut from Montney cores. The samples are characterized by measuring mineral concentration, total-organic-carbon (TOC) content, porosity, and permeability. The methodology is fully described in the complete paper.

Results and Discussions

Contact-Angle Tests. Oil and brine droplets were equilibrated on the surface of a Montney core plug. Oil droplets completely spread on all samples, while brine droplets equilibrated with a nonzero contact angle. Similar trends were observed for all five plugs. In a liquid/liquid system, the affinity of the sample to brine is higher than its affinity to oil, and similar trends were observed for all samples. According to the results of air/liquid contact-angle tests, the samples are fully oil-wet and partially brine-wet. However, according to liquid/liquid contact-angle tests, the samples are brine-wet. The results of imbibition tests show that liquid/air contact-angle results are consistent with the results of water- and brine-imbibition tests in air-saturated samples, and that the liquid/liquid contact-angle results are consistent with the results of soaking tests that show oil production from the oil-saturated samples by spontaneous water imbibition.

Spontaneous-Imbibition Tests. By comparing imbibition curves for both oil and brine, the authors observed consistently that the oil curves reached equilibrium later than the brine curves and that the total imbibed volume of oil was significantly higher than that of brine. In general, brine imbibes faster than oil for all samples, but brine curves plateau earlier than oil curves. If one regards porous media as a bundle of tubes, the liquid flow is slower in pores with smaller diameters. Brine imbibition stops after 200 to 300 hours for all samples, while oil imbibition continues for more than 1,000 hours for all samples. This behavior suggests that there is a significant number of small pores that have low affinity to brine and high affinity to oil. The rock matrix comprises organic matter and inorganic minerals such as quartz, feldspar, dolomite, plagioclase, and clays.

There are two general observations from the results: (1) Oil imbibition continues, suggesting that oil imbibes into small-scale pores that have low affinity to water and high affinity to oil; (2) scanning-electron-microscope (SEM) images show that there are small-scale pores within large-scale pores. It can therefore be concluded that the Montney core plugs show dual-porosity and dual-wettability behavior and small-scale pores have a higher affinity to oil than to brine. Although TOC content of core plugs is small (less than 1%), organic materials cover the surface area of pores. Organic matter is known to have high affinity to oil, while inorganic matter is mostly hydrophilic, especially in the presence of clay minerals. The total clay content of all samples is 9 to 14%, and the majority of inorganic material is quartz.

Imbibition Oil-Recovery Tests. The authors place the oil-saturated samples in imbibition cells filled with brine. The oil expelled by brine imbibition is collected at the top of the cells. The volume of produced oil is measured at different times. Brine-saturated samples were also immersed in oil, but brine production for all samples was not observed. This observation is consistent with liquid/liquid contact-angle tests. Fig. 1 above shows recovered-oil droplets for Rock Sample MT4. As the imbibition process continues, oil droplets detach from the rock surface and accumulate at the top of the cell. In order to obtain accurate data, cells need to be shaken to help the recovered-oil droplets to detach from the rock surface or prevent them from sticking to the bottleneck of the cell. 

To analyze the oil-recovery results, the authors introduced IR trios. Each IR trio consists of three curves: oil- and brine-imbibition curves related to dry samples and oil-recovery curves related to oil-saturated samples immersed in brine. One immediate observation was that oil-recovery curves follow the trend of brine-imbibition curves. Brine curves reach equilibrium at 200 to 300 hours. Recovery curves reach equilibrium almost at the same time, unlike oil-imbibition curves, which reach equilibrium at 1,000 to 2,000 hours. Moreover, the amount of recovered oil is always less than the amount of brine imbibed during the imbibition tests on dry samples.

All five IR trios for the five sets of twin plugs were studied. The authors observed three similar trends for all sets of twin plugs:

These observations suggest that the oil produced during the soaking tests mainly comes from the hydrophilic part of the pore network. The nonrecovered oil may be trapped in small-scale pores that tend to be water repellent on the basis of the imbibition-test results or in parts of the hydrophilic pores because of the snap-off mechanism. The similarities between oil-recovery and brine-imbibition curves suggest that capillarity is the main driving force for oil recovery. Fluid displacement during spontaneous imbibition is dominated by two main driving forces: capillary force and gravity force.

A discussion of parameters affecting recovery, such as porosity, permeability, and wettability, is provided in the complete paper.


In this study, the authors applied the DCI technique to five sets of twin plugs cored from the Montney Formation. First, ­contact-angle tests were performed. Next, spontaneous-imbibition tests were conducted; in these, one plug of each pair was placed in oil and the other was placed in brine; the weight gain of each was measured during the spontaneous-imbibition process until equilibrium was reached. Finally, the oil-saturated samples from the previous stage were placed in brine and the volume of recovered oil was measured with respect to time. The oil-recovery profiles were compared with the imbibition profiles of oil and brine obtained from the imbibition tests. The results can be summarized as follows:

According to air/liquid contact-angle tests, the samples are fully oil-wet and partially brine-wet, consistent with the results of imbibition tests on dry core plugs. According to liquid/liquid tests, the samples are brine-wet, consistent with the results of countercurrent imbibition tests on oil-saturated samples.

In general, brine imbibes faster than oil into the dry samples, but the brine-imbibition profiles reach the equilibrium state faster than the oil-imbibition profiles. Furthermore, the final imbibed volume of brine is significantly lower than that of oil, suggesting that a significant part of the pore network is water repellent. Analysis of the imbibition profiles and SEM images indicates that the water-repellent pores are smaller than water-wet pores.

In general, the shape of imbibition oil-recovery profiles is similar to that of water-imbibition profiles for dry samples. This indicates that the oil recovered during water imbibition into oil-saturated samples comes from the water-wet part of the pore network, which can be accessed by water when the samples are soaked in water. In addition, the results suggest that there is an approximate porosity threshold of 0.025 below which oil can hardly be produced by spontaneous imbibition of water.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185076, “Imbibition Oil Recovery From Tight Rocks With Dual-Wettability Pore Networks: A Montney Case Study,” by Ali Javaheri and Hassan Dehghanpour, SPE, University of Alberta, and James Wood, SPE, Encana, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.

Imbibition Oil Recovery From Tight Rocks With Dual-Wettability Networks in the Montney

01 October 2017

Volume: 69 | Issue: 10