Evaluating Clay/Shale Stabilizers for your Shale Reservoir using Bentonite? Here’s why you shouldn’t.

May 1, 2018

The effectiveness of clay stabilizers in the prevention of formation damage has typically been evaluated by simple filtration tests or simple slurry settling tests.  Unfortunately, not only do these tests lack sophistication, they are often performed with off-the-shelf mineral standards like silica and bentonite because actual reservoir rock is not available.  Furthermore, brine has been observed to mitigate formation damage as well as any clay control chemistry in these tests.  Based on these results, is the use of a stabilizer even necessary?

Instead of relying on simple tests using bentonite, actual reservoir rock should be tested with more advanced methods such as the following:

  • Roller Oven Stability: demonstrates core stability and fines migration.
  • Nano-Indentation: measures change in rock mechanics on the shale surface which shows the potential for rock to soften when exposed to untreated water.
  • Proppant Embedment: measures change in fracture face surface properties and loss of frac width as proppant is embedded.

Conventional clay control chemistries are no longer relevant with shales, produced brine waters are being used with increasing frequency, and new chemistries that prevent damage are now available.  The more test types (such as those above) that can be run, the more confidence you will have in your clay control additive selection and the advantages it can provide to shale reservoir rock!

CleanTRACK goes head to head with Calcium Chloride

April 26, 2018

This summer, ChemTerra has teamed up with Trican to put CleanTRACKTM dust control to the test in a side-by-side comparison with Calcium Chloride (CaCl2).

CleanTRACK differs from CaCl2 in a few distinct ways. CleanTRACK requires no dilution or mixing and is ready to apply as is.  It is also applied to a dry road, so no need for extra water trucks during application (reducing cost of operations).  It is moisture-repelling, ensuring it does not get slippery in wet conditions and reduces water/snow pooling on road surfaces year-round. These features along with being chemically inert, non-toxic, non-corrosive, odourless and colourless make it a great choice for any road or site application.

5 bases have been selected where the dust control will be applied, and monitored this season: Medicine Hat, Red Deer, Whitecourt, Hinton and Grande Prairie. Each yard will be treated on the same day, with 50% of the area covered in CleanTRACK and 50% of the area covered in CaCl2 at the recommended loadings for each product.

Before and after pictures/videos will be posted on the CleanTRACK website (www.cleantrack.ca). We will be looking to compare ease of application as well as a direct comparison for effectiveness and longevity in the same weather conditions and with the same traffic conditions.

Paper Presentation on a Novel Fracturing Fluid

April 26, 2018

One of our ChemTerra colleagues, Harvey Quintero, will be in California this week to present his latest paper – Enhanced Proppant Suspension in a Fracturing Fluid Through Capillary Bridges. This paper describes a novel fracturing fluid where through inducing capillary bridges proppant sands become part of the fluid structure rather than being a burden to be carried by the fluid system. This new fracturing fluid offers a unique and superior proppant transport mechanism, under a wide range of shear stress and rate conditions, without the need for conventional polymers and/or cross-linkers. Harvey will present the field cases that show the successful proppant placement where other conventional fracturing fluids have failed/screened-out. The paper also shows lab analysis that indicated >100% regained permeability. In proppant settling tests, there was no proppant settling in a 5-hour period with 4.17 lb/gal (500 kg/m3) of 30/50 U.S mesh size proppant at a simulated BHT of 158°F (70°C). In addition, there was a 33% increase in sand pack volume when compared to a borate-XL guar slurry equivalent. ChemTerra is excited to share this pioneering technology at the SPE Western Regional Meeting, but if you are not able to attend you can find Harvey’s paper at – https://lnkd.in/giUzwA8

Why the Simple Demulsification Test is NOT Enough to Select a Surfactant

April 19, 2018

Do you expect your stimulation surfactant to deliver greater well performance? You should.  So, why are surfactants typically only optimized to prevent water-oil emulsions? Preventing emulsions only reduces potential formation damage; it does not increase oil recovery from your well.

Often, the only surfactant test being performed at the field level is a basic demulsification test.  Although this test demonstrates the surfactant’s ability to prevent a water-oil emulsion, it does not always indicate why a surfactant should be used.  In fact, this test sometimes shows that no surfactant at all is needed. In reality, however, the right surfactant can increase your load recovery and, more importantly, increase your well productivity.

To determine the correct surfactant and loadings to be used in your stimulation fluid, several tests should be carried out. The difference between running no surfactant vs. an optimized surfactant in oil recovery tests can be dramatic and the recommended tests outlined below will reveal the value of surfactants, especially with regard to enhanced post frac oil recovery.

  • Interfacial Tension Reduction (IFT) between the oil and stimulation fluid.
  • Column Drainage – tests the flow of stimulation fluid and oil through a column packed with shale cuttings and sand.
  • Amott Cell Spontaneous Imbibition – stimulation fluid imbibition/oil displacement and recovery testing.

The more tests that can be performed, the more confidence you will have in your surfactant selection!

Micro-Fluidics – A Novel Approach to Optimize Stimulation Fluids

April 16, 2018

Chemterra has utilized a new technique known as “Micro-Fluidics” where the pore structure and mixed wettability of shales can be synthesized on a microchip.

Conventional core flood experiments are not useful with nano-Darcy permeability shales. Alternate lab techniques have been employed to optimize stimulation fluids for hydraulic fracturing such as column drainage and Amott cell oil recovery.

Using Micro-Fluidics, regain permeability studies can be performed across the chip while using a microscope to visualize the fluid flow. Reservoir pressure and temperatures are also simulated on the chip without the need for large/expensive high-pressure equipment.

The key advantage of adding a visual aspect is to measure total fluid displacement, observe phase trapping, and measure contact angle of fluids real-time.