New downhole fracturing fluid works without polymers
Competition skeptical about need, limitations
Schlumberger is in the midst of rolling out a new viscoelastic surfactant based frac fluid that does not have any polymers. Traditionally, polymers presented one of the biggest challenges to clean up after a frac job. The polymers invade the formation clogging it and thereby not maximizing the effectiveness of the hydraulic fracture treatment by inhibiting formation conductivity.
There has been an overall trend in the industry away from polymer-based fluids toward low-guar systems to reduce this residue build up. While the polymer-free system is not necessarily new, Schlumberger has extended the temperature range in which the fluid can work and reduced the cost.
With the elimination of polymers Schlumberger has also done away with need for breakers, used to remove polymers from the formation after creating the fracture and injecting the proppant. These breakers are expensive and Schlumberger touts their elimination as a cost saving, in some cases offsetting the high price of the polymer-free fluids.
Adding surfactant to brine results in a viscous fluid. The micelles formed by the viscoelastic surfactant molecules form a network structure that helps the transport of proppant even at a low viscosity state. Schlumberger says the unique rheological characteristics of its viscoelastic surfactant fluid is such that leak off is far less than with a conventional frac fluid, especially at low perm situations. The filtrate viscosity of ClearFRAC is a lot higher than that for polymer fluids. Since the efficiency of the fluid is very high it requires only lower fluid volumes compared to polymer-free fluids. If true this translates to lower fluid volumes for the same size job. Other service companies have said just the opposite. Because of the low rheology, viscoelastic fluids have a greater leak off than polymers in high-permeability formations and Schlumberger offers several fluid loss additives (FloSAVER) to control this leakoff. The low viscosity of the fluid helps minimizing the unwanted fracture height growth. Since the fracture is solids free, better effective frac length and production can be achieved by using much less fluid volume and proppant. In any case, Schlumberger showed that the fluid is also simple to assemble. Where a polymer-based frac fluid would require as many as a dozen additives, including breakers, the ClearFRAC fluid is composed of brine and the ClearFRAC surfactant. The fluid is broken using well fluids or any hydrocarbons so it flows back with the well leaving no solids in the proppant pack.
Guar vs no guar
Rather than competing head-to-head with a polymer-free fracturing fluid, BJ Services is advocating its low polymer line of fluids called Vistar. Manager of Research Harold Brannon said the system (Vistar) contains about one-half the polymers of a conventional fracturing (frac) fluid.
He said the fluid, to date, has been used on over 400 jobs and has been getting good frac lengths and clean-up rates. Currently, BJ is not looking at developing a viscoelastic surfactant gel, but rather focusing on providing clean proppant packs that are economically viable for a wide range of applications.
Brannon said the polymer-free fluids cost five times as much as a typical frac fluid. Also, he pointed out that higher volumes of polymer-free fluids are needed because they do not have as good leak-off control as a traditional frac fluid. This claim seems contrary to a competitor's (Schlumberger) claim of lower volumes and tight leakoff control.
The cost advantages of using fewer additives and no breakers may offset some of the price difference, but in most cases, a low polymer fluid will clean-up just as well at a lower cost. Low-guar frac fluids like Vistar require a 20-lb gel, compared with a 40-lb gel required for a traditional frac fluid. Brannon said his company would use twice as much breaker per pound and get a much better clean-up. He says the client gets a better frac length with these low polymer fluids, which are cheaper than the polymer-free fluids and clean up better than a conventional cross-linked guar.
Harvey Fitzpatrick, Halliburton Solutions Department said Halliburton considered developing polymer-free fluid, but found a number of key drawbacks it could not overcome at the time. Chief among Halliburton's concerns is that these surfactant gels typically were cationic, and would thus plate out on the formation leaving the sandstone oil wet. This affected the relative permeability of the formation.
Silicate sandstones or clays have negative charges on the surface, attracting a layer of water, which is much more chemically polar than oil. The water adheres to the pore surface of the formation.
These surfactant molecules have a positively charged end and a negatively charged end. When the cationic surfactant contacts the sand surface, the positively charged end adheres to the surfactant surface, leaving the non-polar tail sticking out into the pore space. This non-polar tail attracts oil or gas, which will try to adhere to the surface of the pore. This process effectively reduces the permeability of the formation to oil or gas. The oil can no longer move through the center of the pore, but only along the sides of the pore.
Halliburton saw this as a major drawback to viscoelastic surfactant fluids and did not pursue marketing their own polymer-free fluid. "We looked at this stuff and we said 'Hey, this is really no good and we don't want to go out and sell this.' " Fitzpatrick said.
The polymer-free fluid still has high leakoff in high permeability formations, meaning the service company must pump a large pad to place the same amount of proppant. In tight formations, the fluid efficiency of the viscoelastic systems improves because the viscous leakoff is able to control the frac fluid leakoff. The fluid, which contains no polymers, is not a wall-building fluid.
Halliburton says it has found that some customers who have used ClearFRAC are not happy with the flow they get. If the service company pumps a treatment containing a mutual solvent, it can improve these results because such a treatment helps to dissorb the surfactant from the sand phase.
Recently, Halliburton used its Delta Frac pack, designed for offshore frac-pack work in a direct comparison to ClearFRAC. Fitzpatrick said the logs of the two wells were very similar and they were both run through 3.5-in.tubing. The perforation zone of the Clear FRAC well was 54 ft, where it was 35 ft in the Delta Fracpack well. The initial rate on the Clear FRAC well was 2.8 MMcf/d, which later cleaned up to 3.4 MMcf/d with a 1,100-psi total drawdown. The Delta Fracpack well initially made 7.5 MMcf/d, then cleaned up to 7.8 MMcf/d with a total draw down of 1,300 psi. The proppant amounts were the same - within 10,000 lb, Fitzpatrick said.
Halliburton had good results with the Delta system, which Fitzpatrick said is a more efficient fluid than ClearFRAC. Its higher fluid efficiency means Halliburton doesn't have to pump as much foreign materials into the formation. "We don't really see a reason to come out with a surfactant gel," he said.