Interface fluidics

Leonard Kalfayan, Contributing Editor

With hydraulic fracturing, especially in unconventional wells, the industry has moved to the “well factory” approach. I used to call that the “cookie cutter” approach, which in my mind is the same thing, but as with many (or all) industries, terminology is developed to paint a positive picture or even one suggesting advancing technology rather than stagnation.

But even with the well factory or cookie cutter approach, whichever you prefer, as applied in multi-zone fracturing of horizontal, unconventional wells, for example, there are many design choices to be made: fluid volume, proppant volume and size distribution, completion design— including perforation size, number of clusters and cluster spacing—and so on. There is more hard data or information to try and optimize the combination of these factors (and others).

However, one area of design that is most difficult to grasp and make informative decisions on, and therefore easiest to avoid or to default to vendor recommendation, is fluid chemical composition. What friction reducer should be used, and in what quantity? What surfactant or other production enhancement additive to use and in what quantities and combinations, or what not to use? It is a common belief that spending money on specialized laboratory testing of different fluid designs—beyond whatever supportive data are provided by vendors on additive selections—is not especially or prudent in making such decisions.

An optimum frac fluid design is also not easily evaluated with post-stimulation performance. An operator in partnership with a pressure pumping service provider may land on a fluid design, based on some testing and field experience, that results in well production response that meets operator economic criteria, and therefore is deemed sufficiently effective. And, of course, well production results are based on many variables. But the fluid may very well not be optimized, whereas a much greater focus is on optimizing the mechanical aspects of well drilling and completion design. Nevertheless, an optimized frac fluid chemical formulation can make a significant difference.

Standard laboratory frac fluid testing. Decisions on frac fluid chemistry composition, when an effort to conduct comparative chemical evaluations is actually made, are typically dependent on laboratory testing methods that are time-consuming, are only indirect indications of performance at best, and can be costly. These include proppant pack testing, core flow testing, and basic fluid property testing. Tests are often not conducted at representative downhole conditions of temperature and pressure. And ultimately, they just will not likely provide information sufficient to distinguish between fluid additive options.

So, how can informed decisions that actually do measurably enhance frac fluid performance be made on which friction reducer (FR) to use? Or, whether a surfactant should be added or not, and which one? Is a biosurfactant better than a traditional surfactant? Is interfacial tension reduction by a surfactant most important? Wettability alteration? Is a frac fluid breaker needed? What type of breaker and how much of it should be used? Will the addition of nanoparticles or nanobubbles further enhance fracturing fluid performance and post-stimulation production response?

Custom laboratory testing. An answer to the above is a specialized laboratory, with which I have had first-hand experience – Interface Fluidics. Interface Fluidics is a Canadian laboratory service provider which, through very unique and rapidly repeatable testing methods, provides insights into the interactions and properties of fluids in porous media, including unconventional formations. They have been in existence for more than a decade. Their methods of testing can be conducted at actual reservoir conditions of temperature and pressure, up to extremely high levels, thus covering essentially all applications, realistically.

Frac fluid flowback and additive optimization. One Interface Fluidics proprietary method applicable to fracturing fluid optimization and post-stimulation flowback and production enhancement is with a heterogeneous microfluidic chip (Fig. 1) that can be designed and developed with pore geometries representing any specific formation of interest. Dual-porosity chips can be created, even with nano-size networks simulating actual unconventional formation characteristics of that nature. A fluorescent microscopy technique can be applied to visualize and quantify the performance of different friction reducers, flowback additives, and production enhancement additives during injection and flowback. Such an example of a successful testing case study was presented in SPE Paper 195880, “Nanofluidic analysis of flowback enhancers for the Permian Basin: Unconventional method for unconventional rock,” September 2019.

Proppant pack optimization. Interface Fluidics also has methodology to optimize proppant pack conductivity. Standard proppant pack testing is with sand or other proppant packed between core platelets. Such tests measure conductivity of the proppant pack, to determine damaging effects (conductivity reduction) of frac fluid designs with different friction reducers or other polymers, and loadings. Conductivity measurements are very dependent on the packing of the test cell, which can be highly variable from one lab to another, among other test variables. Tests take a significant amount of time, especially for repeat, confirmation testing, and can be expensive. Interface Fluidics’ regain conductivity method uses proprietary reservoir analogues that replicate the proppant pack (“proppant pack on a chip”). Multiple analogues can be fabricated, and are exactly the same, thereby enabling rapid, repeat testing with the same or different fluid compositions.

With respect to optimizing unconventional resource development, Interface Fluidics provides testing services, not only for chemical optimization and formation damage determination and mitigation, but also for frac fluid compatibility (e.g., water source and formation), flow assurance (e.g., chemical treatments for wax or asphaltene removal), and fluid injectivity.

Apart from fracturing-related testing, Interface Fluidics also provides specialized microfluidic test methods for EOR applications; SAGD (Steam Assisted Gravity Drainage) for heavy oil recovery; minimum miscibility pressure (MMP) and composition for gas flooding operations; rapid PVT and fluid phase behavior data measurements, including high-pressure and high-temperature analyses of oil and gas samples; and quantification of wax appearance, disappearance and coverage.

The Interface Fluidics website provides information on all of their services, with case studies and reference links: https://www.interfacefluidics.com

I encourage you to explore this unique laboratory and their specialized services, not only for unconventional well productivity enhancement but also for other energy-related services, too.