“Water, water, everywhere, Nor any drop to drink.”
–The Rime of the Ancient Mariner, Samuel Taylor Coleridge
Many topics of conversation among oil and gas industry professionals are predictable – oil price trends, the “great shift change” imperiling the available workforce, and production quotas and caps from OPEC. Yet one pressing topic among those developing unconventional shale reservoirs would likely be eye-opening to an outsider—the pressures of sourcing and disposing of water to pursue hydraulic stimulation.
“Water is perhaps the most misunderstood and undervalued aspect of the impediments that the industry could face.”
–Tim Dove, President and CEO, Pioneer Natural Resources
Slickwater Trend Compounds Water Demand and Disposal Issues
The dominant trend in the industry (at least in the United States) has been to move to larger and larger slickwater fracture programs. The payoffs of these programs are clear to many E&P operators: slickwater provides excellent fracture complexity, minimal reservoir damage, and strong economics even in an era of lower oil and gas prices. Yet as hydraulic fracturing activity rises, so does the demand for the freshwater, that is the base of most fracturing fluid, and the need to treat and dispose of flowback/produced water.
Fresh Water Harder and More Complex to Source
For now, fracturing completions in many areas can be sustained by water sourced from ponds, wells, rivers or from nearby municipalities. As demand grows, however, more of this water must come from sources farther and farther away, complicating logistics and increasing prices. Additionally, the heavy demand for “fresh” water has put the oil and gas industry in competition with farmers and ranchers, with cities, and with other industries— as lengthy droughts in areas of the western United States have resulted in water shortages for power generation. Other environmental challenges also make water a desirable and potentially scarce resource.
A New Vision for Produced Water
The flip side of this issue is what to do with water after the frac. The injected water flows back, as the non-potable water alongside the desired hydrocarbon is produced. This low-quality water has become the oil and gas industry’s largest on-going waste stream. For years, the industry has sought environmentally responsible and inexpensive ways to deal with this waste stream, settling largely on disposal wells or centralized facilities for treatment and release. However, the evolving view on produced/flowback water is to see it not as a waste stream at all but instead to create a beneficial use for it that would allow the oil and gas industry to be a better community neighbor.
Re-using High-TDS Water is a Worthy Goal
Significant technology challenges exist in fulfilling the desire to use flowback/produced water to ease the water demands of hydraulic fracturing. Unlike the water being used now, produced and flowback waters have extremely high levels of total dissolved solids (TDS). TDS is a measure of dissolved matter (salts, organic matter, minerals, etc.) in water. Inorganic constituents (e.g., sodium, calcium, and chloride picked up from the rock formation) contribute most of the total concentration of TDS. Where most water contaminants, like sediments, barium, strontium, and other metals can be easily filtered out of water, the salts that compose the majority of TDS are difficult and expensive to remove. For conventional cross-linked fracture fluids and many common fracturing additives, a low TDS water is a must, forcing operators to choose between the desire to reduce waste and water demands against the costs of their water usage.
Refining Proppant Transport Technology for High-TDS Water
Yet what if a hydraulic fracturing fluid system could tolerate high TDS water? Suddenly, the dilemma disappears, as operators could eliminate a waste stream and the challenges of water sourcing. Fairmount Santrol has been working on ways to achieve this goal. One focus of our work has been our Propel SSP proppant transport technology system, which was limited to TDS levels of 1,000 ppm and hardness of 500 ppm until January of 2017. Many operators have asked if this transport technology could become feasible with much higher-TDS water. Lab and field work led to a variation on the coating technology that hydrates quickly in high-salinity or high-TDS waters, tolerating TDS levels of up to 350,000 PPM and water hardness of 40,000 PPM.
Improved Proppant Transport for Greater Penetration and Stacked Height
Like the freshwater version of Propel SSP, the new Propel SSP 350 proppant transport technology allows for a slickwater-style hydraulic fracture without the detrimental issues of poor proppant transport. Like its predecessor, this new coating chemistry reduces the effective density of the propping sand, driving greater horizontal penetration into fractures and allowing the sand to “stack” in the fracture to improve propped height. It also maintains an inherent friction-reducing quality that eliminates the need for friction reducer at moderate to high proppant concentrations* while exhibiting exceptionally low fluid viscosity.
A New, Value-Added Way to Think About Produced Water
Using this technology, operators have new flexibility in how they view their need for water. Rather than competing with others for a limited supply of freshwater or investing in expensive recycling facilities, a new opportunity exists to move wastewater from one pad to another and immediately reuse it with minimal pre-treatment, reducing transportation costs, disposal costs, and freshwater costs. It is a technology that manages the risks of tomorrow while creating better wells today.