To say things have changed in North American well stimulation over the last decade is an understatement almost as large as the scope of the changes themselves. Permeability of the typical reservoir has gone down by roughly three orders of magnitude. At the same time, the industry is focusing three orders of magnitude more material on a fracturing work site.
In this changing landscape, the habits of fracturing fluid optimization have had to catch up to a new reality where the reservoir has rewritten the rules and market forces mandate better evidence-based tools to drive decisions about what is pumped.
A new dominant work practice
Service companies and E&P companies have put considerable effort into understanding how to chemically modify and enhance the properties of water so that it can be injected into a reservoir to complete the well and connect it to the producing reservoir efficiently and effectively. The chemical engineering objectives of a fracturing fluid fall into three categories:
- Initiate and propagate a hydraulic fracture;
- Convey a propping agent into the fracture; and
- Ensure the proppant pack and formation connect efficiently to the wellbore with minimal damage.
Most optimization has historically concerned the first two points. The dominant work practice has become the use of friction reducers based on high-molecularweight synthetic polymers. These distribute smaller proppant grains within a complex and unpredictable fracture network using the turbulence resulting from high pump rates (occasionally exceeding 120 bbl/min). Given the increase in job volumes, it has become clear that polymer emulsion costs need to be optimized (which they largely have) and the preferred propping agent is a friction reducer that disperses and hydrates within seconds of injection.
The new high-viscosity friction reducers are seeing increased usage due to their ability to affect proppant distribution. However, it is not clear from field application that higher viscosity always connects to completion success. These products appear to perform differently in different basins, irrespective of the viscosity measurements performed. Further, the industry is beginning to understand that there is a sense of diminishing returns at higher product loadings, where production impairment can set in from too much polymer use. The oilfield solution to this situation has been to run an oxidative breaker to reduce fluid viscosity.
Myths and science of breakers
While it is true that breakers will reduce viscosity in a laboratory test, the water that is returned on initial flowback is typically salinated by contact with reservoir rock that has not seen water for millions of years. This salinity can have a stronger effect on solution viscosity by shrinking the polymer’s hydrated radius than breakers have on the polymer’s molecular weight. Further, it is puzzling that breakers applied to degrade polymer in the subterranean environment are the same class of chemicals used to assemble the polymers from their monomers. There is no clear argument that breakers selectively degrade polymer, and the unpredictable nature of breaker chemistry includes possibilities where gelation and even adventitious crosslinking of the polymer can occur.
Operators in infill drilling campaigns have the choice to evaluate these chemical issues as they move through a field. First, practical operational evaluation of the minimal required amount of high-viscosity friction reducers to execute a job design can be explored safely by working down from roughly 1 gpt per ppa to a basin-specific baseline level that places proppant to design (gpt = gallons per thousand gallons; ppa = pounds of proppant added per gallon).
Second, the question of breaker efficacy can be assessed directly by comparing offsets with and without breaker. Single-well operators are pooling their information to make these decisions, harvesting publicly available information to support these decisions. Flowback surfactants are another area where the industry has lacked a good prescriptive model to drive rational product selection and application until recently.
Flowback surfactants assist in dewatering the proppant pack and, perhaps more importantly, the fine cracks and small features that retain fluid within the distal portion of the fracture network where the capillary pressures are highest.