Swellable-Nanogel-Injection Pilot in Mendoza Norte, Argentina

Schematic of dosing system.

Despite the increasing attention paid to nanogels, there has been little research about the transfer of their properties to field pilots. The authors of the complete paper, SPE 184586, observe that nanogels increase their size faster than expected or produce aggregation leading to serious blocking problems at the sandface. This was observed in both coreflooding experiments and field pilot tests regardless of water composition. The addition of a certain concentration of surfactant slightly improves injectivity.


The authors refer to a Chinese commercial system whose manufacturers describe the purpose of the treatment as the following:

  1. To form a certain degree of injection resistance in the existing high-permeability water channels, to create a more-homogeneous reservoir

  2. To displace the oil in the relatively low-permeability (oil-containing) regions by enlarging sweep area

  3. To increase oil production and decrease water cut for the long term.

The key message is that nanospheres divert water flow deep in the reservoir from high-permeability to low-permeability regions.

The commercial system is a precrosslinked polymer that is commercialized as a nano-inverse emulsion (the continuous phase is oil). The precrosslinked polymer stays inside water drops that are stabilized by a surfactant and an external phase (oil).

The product application in the field is very simple. It consists of adding the nanogel emulsion to the injection water, which is an advantage because specific facilities are not needed.

To prepare the dispersion (2,000 ppm) of nanogel in the laboratory, the product is added to water under stirring at 700 rev/min at room temperature. A description of the product’s characteristics is provided in the complete paper.

Swellable-Nanogel-Injection Pilot

Reservoir Characteristics. Barrancas is a high-temperature (100°C) and medium-salinity reservoir. The reservoir is under waterflooding; currently, the recovery factor is approximately 27% at less than one pore volume of injected water. The reservoir is formed by conglomerates and sandy conglomerates. The trap is of the structural/stratigraphic type. The reservoir has four intervals (Green, Purple, Blue, and Red), with the following average properties:

  • Gross thickness: 60 m

  • Net pay: 25–20 m

  • Porosity: 17%

  • Permeability:           

    • Green: 60 md

    • Purple: 30 md

    • Blue: 8 md

    • Red: 120 md

Injection Pilot. The nanogel-injection pilot began in December 2013 in the Barrancas Formation on injector Well B-342. The original design was the injection of 0.2 pore volumes in the array (1 year of injection, 30–40% active matter) to obtain a recovery factor increase of 6%.

The facilities are compact and easy to implement (Fig. 1; see image above). The dosing system placed in the well location has two high-pressure pumps (200 kg/cm2). There is a digital high-pressure flowmeter to control the nanogel injection.

There were two attempts to inject nanogel emulsion. In the first case, the rate was approximately 100 m3/d and the pressure 155 kg/m3. After the nanogel injection, the injectivity rate decreased very quickly. The strategy to prevent injectivity impairment was to diminish the product concentration. The first period lasted approximately 4 days and the pressure rode up to 190 kg/cm2, with an injection rate of 40 m3/d (in the same period, there were several injection downtimes). It was then decided to stop nanogel injection because of low injectivity. Later, several cleanups were carried out with chlorine dioxide, but the damage was not easily removed. Mud acid was subsequently employed to clean up the well.

In the second attempt, the injection rate was 140 m3/d and the pressure 135 kg/cm2. The same phenomenon occurred. After 5 days, the flow rate decreased to 35 m3/d and the pressure rose to 195 kg/cm2. The investigators failed to recover injectivity conditions previous to nanogel injection, and, during the intervention, produced gel flock from downhole.   

Possible Causes of Injectivity Loss

The injectivity loss was highly influenced by the nanogel; the other wells in the area did not lose injectivity in the same proportion.

  • High nanogel concentrations were injected for a couple of hours because there were several injection downtimes in the injection.

  • The well never recovered the initial injectivity, even after the acid job, which may indicate that the damage was not easily removed.

  • The investigators suspected that the product did not meet specifications.

  • Even though the nanogel was designed to be compatible with the water salinity of Barrancas field, the water quality was not properly defined as the TSS (total suspended solids) and the total oil content.


Step 1. The objective of this step was to validate the quality of product (nanogel emulsion). The conditions and the values of the product were the following:

  • The samples of stored emulsion were validated according to the manufacturer’s specifications. The average initial size was 60 nm at 25°C.

  • The viscosity of emulsion was within the manufacturer specified range.

  • The thermal stability test was good. No obvious changes were observed compared with initial properties.

Step 2. Although the product passed the quality test, it was important to evaluate what happened when the nanogel emulsion is dispersed into water.

  • The measured size for laser scattering was consistent with that observed on the microscope.

  • Although the product had an initial size of the nanometer order, the dispersion of nanogel, as was injected in the field, immediately increases its size to approximately the micrometer order. This behavior indicated that the size of the product had increased, the particles of nanogel were aggregated, or that the oil had remained dispersed in the water, interfering with the measurement.

Step 3. According to the manufacturer’s specifications for measuring the nanogel size, it is necessary to separate the oil phase with an organic solvent. Thus, the investigators added 2,000 ppm of the product in synthetic injection water and then put the aqueous solution in contact with the solvent (n-hexane) in a separating funnel.

  • The product, once dispersed and with its oil phase extracted, increases its size 3.5 times after 24 hours.

  • An appreciable change of size distribution was detected from Day 10.

  • The first dispersion with oil phase has larger sizes in the size distribution; this might be because of the oil drops’ contribution.

Step 4. Six coreflood experiments were carried out to evaluate the injectivity of product with different types of water. Five of them were performed on Berea sandstones (gas permeability = 100–200 md), and the sixth was performed on Bentheimer sandstone (gas permeability = 1.7 darcy). The coreflood tests were carried out with a constant flow rate at 70°C.

Berea 1. The pressure on the inlet increased 6 times over the reference value (filtered synthetic injection water) after being swept with 4 pore volume (PV). The pressure transducer located on the first tap did not show changes, indicating that the product was accumulating on the inlet face.

Berea 2. The pressure on the inlet increased 3.5 times over the reference value after being swept with 12 PV. The pressure transducer located on the first tap did not show changes, indicating that the product was accumulating on the inlet face.

Berea 3. The pressure on the inlet increased 16 times over the reference value after being swept with 16 PV. The pressure transducer located on the first tap showed a small increase after being swept with 11 PV. The water injection that followed in the flux direction tends to stabilize the pressure. The sweep is more unstable because of the interactions between the nanogel and suspended solids in the injection water.

 Fig. 2—Inlet face of Bentheimer sandstone
 after being swept with nanogel.

Berea 4. It was thought that the injectivity loss is caused by dispersed oil or the nanogel’s aggregates, so it was decided to perform a flow test that added surfactant. The pressure on the inlet increased 19 times over the reference value after being swept with 12 PV. The pressure transducer located on the first tap showed a small increase after being swept with 5 PV. The water injection that followed in the flux direction tends to stabilize the pressure and helps to reduce the inlet pressure approximately 20%.

Berea 5. A coreflood with the nanogel dispersion (having extracted the oil phase) was carried out in order to evaluate the influence of the oil in the injectivity loss. The pressure on the inlet increased 4.5 times over the reference value after being swept with 11 PV. The nanogel product without oil phase went through the porous media after 12 PV were injected. The pressure in the intermediate taps increased also 4.5 times; therefore, the oil phase contributed to the plugging.

Bentheimer. This sandstone was used to evaluate the injectivity of the nanogel product on a porous media of high permeability. The pressure on the inlet increased 12 times over the reference value (filtered synthetic injection water) after being swept with 8 PV. The inlet of the sandstone is shown in Fig. 2. The plugging caused by the product is clearly visible.


  1. The size of preformed nanogel increases immediately when the nanogel emulsion is added to water. This issue must be considered to select and design a pilot in the field.

  2. The oil in the nanogel dispersion (as small drops) interferes and increases the dispersion particle size.

  3. The preformed nanogel increases its size over time and aggregates.

  4. The inlet pressure raise was observed in every coreflood test, no matter the type of water. The sandstones were plugged, generating damage during the laboratory test.

  5. The addition of surfactant improved the displacement on Berea sandstone slightly. This indicates that the surfactants in the formulation of nanogel product are not efficient enough to keep the nanogel dispersed by itself.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 184586, “Swellable-Nanogel-Injection Pilot in Mendoza Norte, Argentina,” by Diana M.A. Masiero, María I. Hernández, Isabel N. Vega, Ariel Lucero, José Peltier, and Juan Juri, YPF, and Mariano Clérici, Consultant, prepared for the 2017 SPE International Conference on Oilfield Chemistry. Montgomery, Texas, USA, 3–5 April. The paper has not been peer reviewed.

Swellable-Nanogel-Injection Pilot in Mendoza Norte, Argentina

04 April 2018

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