[Editor's note: This story originally appeared in the April 2020 edition of E&P. Subscribe to the magazine here.]
Over the last decade, there has been a significant amount of work performed in the development of shale formations, typically low permeability sandstone and carbonate formations. Many of these formations have low matrix porosity but are naturally fractured to varying degrees, which helps boost overall hydrocarbon mobility within the formation. During fracturing operations, these natural fractures are activated and/or intersected by the primary active hydraulic fractures, and additional small hydraulic fractures (fissures) also can be created. Initially, these microfractures (natural and hydraulic) enhance well productivity but eventually seal up and close under stress as the well is drawn down.
This is evidenced by wells that have high initial productivity (higher than can be characterized using matrix permeability alone) followed by steep production declines a few months into the well’s producing life—a common signature in shale wells. Microproppants were developed to enter these microfractures, propping them open so they may contribute to production over the life of the well, much the same as unpropped fractures contribute to production in some shale reservoirs.
Both silica and ceramic-based microproppants have been around for several years. Unfortunately, microproppants were always difficult to incorporate into fracturing operations because they required preblending into a gelled slurry system, which added a large expense and logistical complications. Therefore, the development of a microproppant that can be blended dry (similar to a standard proppant) makes it significantly easier and less expensive to incorporate microproppant on any fracture treatment at any stage.
The development of any new product usually starts with requests from customers to address certain production challenges. In this case, it was about how to prevent microfractures of wide-ranging sizes from closing with a product that can endure formation stresses during the productive life of a well. The technical research team worked to develop a process to make small mesh ceramic proppant. The result was a 325 mesh (45-μ) mean particle diameter, which is approximately 30% of the size for standard 100 mesh proppant. In addition, the microproppant was designed to range primarily between 150 and 635 mesh, allowing the propping of many sizes of microfractures.
Microproppant has greater strength compared to sand because it is ceramic. This enables it to maintain an open fracture, particularly in a partial monolayer setting, which is achieved when a single grain must experience high stress and hold the fracture open. Therefore, the microfractures that contain even a small amount of microproppant will remain open for the life of the well. In addition, the microproppant is designed to be pumped dry, with most applications now being deployed using today’s “box” type proppant delivery systems.
Effect on production
There have been published articles documenting 15% to 20% increased production that was attributed to microproppant. Several operators have incorporated microproppant into their standard completions due to the increased production. The incremental cost is not significant due to the low volumes required for the narrow microfractures. Some operators also have used the ceramic microproppant to obtain a reduction in treating pressure that is attributed to better fracture conditioning or even reduced screenouts.
This leads to fewer horsepower charges or shorter frac stage times, both of which reduced the cost of the fracture treatment. Furthermore, the small mesh size of the microproppant has a settling rate of 10 to 15 times slower than 100 mesh proppant. This significant improvement in proppant transportability not only applies within the fractures but also within the pipe, allowing the microproppant to be transported to the farthest perforation cluster in a stage, cleaning and conditioning the perforations and establishing a hydraulic fracture. The result is a better distribution of the fluid and proppant into all of the clusters, meaning all clusters can be effectively stimulated. Recent pipe flow studies have shown that proppant physical properties can significantly impact flow distribution through multiple perforation clusters.
As with all fracture treatments, the proppant needs to be placed where the hydrocarbon pay zone is located and where it will achieve the largest increase in production. This is also true of placing microproppant into the microfractures. Using commercially available software is possible to analyze standard drilling data to estimate the magnitude of natural fractures along the lateral. With these data, the incorporation of microproppant can be engineered for each treatment stage of the well to maximize well economics.
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