New viscoelastic fluid technology enhances productivity

A new fracturing system development based on new viscoelastic fluid tech-nology takes full advantage of the well-studied chemistry of guar-based poly-mers and metal ion crosslinking reac-tions.

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Changes in viscosity from linking and delinking based on pH

Frank Hartley
Drilling/Production Editor

A new fracturing system development based on new viscoelastic fluid tech-nology takes full advantage of the well-studied chemistry of guar-based poly-mers and metal ion crosslinking reac-tions. Fracture conductivity, which is an indi-cation of the ability of the propped fracture to transmit fluid to the wellbore, is of primary importance to the economic success of a frac-turing treatment. All fluid systems used for hydraulic fracturing reduce the conductivity of a proppant pack compared to the baseline situation when no fluid system is present.

Halliburton's new technology provides fracturing fluids that are robust in physical properties while dramatically reducing the conductivity-damaging properties associated with polymer-based fluids.

In developing this new fluid system, Hallibur-ton re-engineered the manufacturing process to remove conductivity-damaging insoluble residue normal in guar polymer. The new short-chain material is 25 to 30 times smaller than conventional polymer material. Linking at high pH forms high-viscosity frac fluid, and viscosity is reversed as the fluid pH drops once pumping has stopped, eliminating the need for breakers.

Overcoming problems

Water-based polymers, guar, and derivatized guar have been the mainstay fracturing fluids for many years, owing to low cost and highly controllable fluid rheology. Unfortunately, these materials can damage fracture conductivity, leading to poorer-than-expected production after fracture stimulation. Steps taken to help reduce conductivity damage caused by these fluids include application of special purification chemical processes, improving polymer breakers, formulating fluids with less polymer, and improving fluid recovery during well flowback after treatment. Each of these steps has incrementally improved conductivity; however, one-half or more of the native conductivity can be lost to fracturing fluid damage due to using guar-based polymers.

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The new micropolymer material is 25 to 30 times smaller than conventional polymer material.
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Another approach to reducing conductivity damage is the recent application of surfactant-based, polymer-free viscoelastic fracturing fluids. This technology has res-ulted in high well productivity with small fracture stimulation treatments. The downside is that these non-damaging fluids have limited application due to high fluid loss and consequent inability to generate extended fractures at a reasonable cost.

Both field and laboratory results using the new Halliburton fluid system have demonstrated this fluid system's ability to produce highly productive fractures with low conductivity damage while providing excellent fluid loss control and high proppant transport properties to generate the designed fracture geometry. This fluid has little sensitivity to temperature and salinity, and rheology is easily controlled. The fluid combines the best properties of the polymer-based and surfactant-based fluid technologies.

Polymer-based fluid history

Polymer-thickened, water-based fluids were first used in the early 1960s and by the late '60s guar gum had become the polymer of choice owing to its lower cost and viscoelastic behavior. The early 1970s saw significant growth in guar-based fracturing fluid technology. Controlled cross-linking reactions were used to provide the rheological properties requ-ired to provide low loss of fluid to the formation and adequate elasticity to transport proppant into the fracture for very large and extensive fractures.

While these fluids were robust, and large fractures could be achieved, the economic performance often did not justify the cost. In addition, the industry recognized that crosslinked guar polymer could cause dramatic losses in fracture conductivity. Laboratory measurements indicated that often less than 10% of the native fracture conductivity was achieved following fracture treatments.

During the fracturing process, a highly concentrated, gelled material is often screened out onto the faces of the newly created fracture. This material, commonly called filter cake, has been identified as very damaging to fracture conductivity, as it often plugs a significant portion of the fracture width. While filter cake is detrimental to fracture conductivity, it reduces the rate of fluid loss to the formation and provides the fluid efficiency required to place high concentrations of proppant deep within the fractures.

Gel breakers are included with fracturing fluids to degrade the polymer to quickly reduce fluid viscosity and allow efficient recovery of the fracturing fluid from the fracture. Some common breakers are acids, oxidizers, and enzymes. These breakers are quite efficient in reducing the viscosity of the bulk gel within the proppant porosity, but are not very effective in reducing or removing the filter cake.

Reducing damage

Since the 1970s, most efforts have focused on reducing the conductivity damage that guar-based polymers can cause. Steps taken include:

  • Developing derivatized guar-based polymers to provide both cleaner fluids and fluids that have more controllable crosslinking reactions
  • Reducing the amount of polymer required to accomplish fracture stimulation
  • Foaming these fluids with nitrogen or carbon dioxide to reduce the amount of polymer being used while providing the fluid rheology required for handling proppant
  • Developing computer-controlled blending equipment that enabled making ultra-low polymer gels providing "just enough" rheology.

Despite all these innovations, until recently typical fracture conductivity achieved was less than 30% of the native conductivity. Significant improvements in gel breaking and polymer degradation technology have now emerged.

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Transitory linking technology allows creation of a transitory pseudo polymer in-situ by combining short molecular units with a reversible-linking component. The short chain molecules can align with the shear field and then as the linking chemistry takes effect, build a fluid with a high level of 3D stability.
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These chemical improvements allow very aggressive but delayed attack on the polymer after completion of a fracturing treatment. Improvements result in fracture conductivity in the range of 40%.

Short-chain polymer viscoelastic fluid

Short-chain technology takes full advantage of the well-studied chemistry of guar-based polymers and metal ion crosslinking reactions. Polymer-like fluid rheology and fluid loss control are easily obtained with this new technology, although there are no high molecular weight polymer chains present to cause pore throat plugging or persistent conductivity losses. This is accomplished through transitory linking technology by actually creating a transitory pseudo polymer in-situ by combining short molecular units with a reversible-linking component.

The transitory nature of the linking reaction makes chain dynamic restructuring feasible. This leads to high elasticity in the fluid properties resulting in improved proppant transport properties. The short chain molecules can easily align with the shear field and then as the linking chemistry takes effect, build a fluid with a high level of three-dimensional stability. This is a unique fracturing fluid in that it behaves like a polymer, but because of its transitory nature, generally does not require any chemicals to break the polymer chain.

The solution pH and the metal ion selected determine the strength of the transitory linkages. The freshly fractured formation quickly alters the injected fracturing fluid to the pH that it wants to naturally buffer, delinking the transitory linkages.

It is also possible to control the linking time by adjusting the starting pH of the fluid before the linker is added, which provides increased control for long pumping time treatments. The short-chain molecules are high-ly concentrated and require only simple dilution with water to prepare the fracturing fluid. That is, no hydration time is required as with conventional polymer-based fracturing fluids. In addition, other necessary fracturing fluid additives, such as potassium chloride and non-emulsifiers, are included in the concentrate thus simplifying the number of additives that must be managed during a fracture stimulation treatment.

In addition to the beneficial physical properties of this fluid system, it also inherently reduces environmental risk several ways:

  • The principle ingredients are classified as highly biodegradable and water soluble
  • Only fresh water is required to be stored and used on the wellsite, helping reduce opportunity for spillage and helping reduce brine disposal cost for unused water
  • The total number of liquid additives required on a wellsite is dramatically reduced from that of conventional fracturing fluids since most of the additives are supplied in short-chain molecule concentrate
  • Premixing reduces the chance for site contamination and helps improve the quality assurance for the treatment in that monitoring and metering fewer liquid additives inherently results in fewer mistakes.

Real-time rheology control

The ability to control fluid properties in real-time is a significant advancement in fracture stimulation technology. It allows the fracturing fluid formulation to be changed based on observed treating responses, e.g., surface pressure, and should be ramped based on formation cool-down response.

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The micropolymer fluid develops viscosity almost instantly and remains stable at bottom hole temperature, whereas the viscosity of the conventional fracturing fluid declines continuously.
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Advanced blending equipment delivers the short-chain molecule concentrate directly to the blender so that it can be diluted to a designed viscosity. This property makes real-time rheology control feasible. On typical fracturing treatments, a fluid formulation change can reach the formation in the pipe pump time rather than the 20-60 min that conventional fluids require.

Three primary factors govern the performance of this fluid system: base fluid viscosity, linker concentration, and pH. By changing these in the proper combination, the desired fluid properties of link time, stabilized linked viscosity, and fluid loss are controlled resulting in maximum conductivity.

With appropriate blending equipment, the fluid formulation parameters can be varied easily at the surface allowing real-time fluid property changes. Testing shows that a wide range of desired linked viscosities can be dialed-in to achieve a given fluid formulation. Since polymer breakers are not used with this fluid, the fluid rheology is stable as long as pumping is underway.

Once pumping stops, delinking begins. When combined, these controls give the analyst a powerful set of tools for optimizing fracturing treatments and consequently, well performance.

Field test results indicate Halliburton's new fluid system significantly out performs the conventional borate fluid system. This conductivity can translate into improved production from the fracture placed with the new fluid system. Additionally, the excellent conductivity associated with the material does not depend on a breaker package.

Initial field testing of this new fluid system has confirmed that:

  • A fluid can be manufactured on-the-fly by the simple dilution of the single concentrate composed of short chain molecules
  • Computer control of this blending process can provide high quality in delivery
  • It is the most robust available and easily allows dramatic reduction of pad volumes and treatment rates
  • The use of gel breakers is not required, which results in a stable fluid during pumping.

Over one hundred wells have been fractured with this fluid. According to Halliburton, typical results include 75% increase in fluid recovery, 50% increase in effective frac length with 10% increase in vertical distribution with 32% less proppant.

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