Adjusting Fluid Properties Maximizes Shale Recovery

?Although slickwater is considered the “fluid of choice” for shale fracture stimulation, it is far from ideal for that purpose. Its low viscosity creates narrow fractures thought to be ideal for creating the complex fracture networks required to stimulate economic gas production from shales. However, its proppant-carrying capability is minimal, which allows settling in surface equipment and long horizontal well bores.

In addition to wasting proppant that should be propping open created fractures, this settling can create significant erosion problems. The resulting damage to surface equipment can lead to higher treatment costs and nonproductive time and can reduce stimulation effectiveness if a job must be shut down mid-treatment.

The new BJ ShaleXcel fluid from Baker Hughes Inc. significantly improves proppant transport through surface equipment and long horizontals without affecting complex fracturing performance. The result is a more efficient use of both fluid and proppants and a more effective stimulation treatment.

Avoiding proppant settling

Surface equipment and downhole problems have been common when using high-rate slickwater systems, presumably due to both the abrasive nature of proppants and the propensity of dense proppants to settle rapidly in low-viscosity slickwater fluid systems.

Slickwater is a near-Newtonian fluid that does not effectively suspend and transport the proppant or support proppant placement within the fractured formation unless injected at high rates. Cross-sectional flow areas vary in the fluid path from the frac blender through the perforations and into the created hydraulic fracture, resulting in varying fluid velocities and flow regimes within the surface equipment and tubular goods.

In addition, excessive proppant settling in the lateral section of the well bore can result in higher surface treating pressures due to the occluded cross-sectional flow area and, ultimately, loss of continued access to the perforations followed by premature treatment termination. Within the hydraulic fracture, inadequate transport manifests as proppant duning at the bottom of the fracture, resulting in smaller-than-expected effective (propped) fracture height and length.

For conventional, non-densified fluids and sand proppants, the settling rate is determined largely by the size of the proppant particle, proppant density, fluid velocity, and fluid viscosity. Settling rate is proportional to the square of the proppant diameter, so smaller grains settle less than larger ones. However, the proppants most commonly used in shale fracturing are approaching the smallest mesh size that can provide useful fracture conductivity; thus, further proppant size reduction is not considered practical. Ceramic proppants, typically required in high-stress environments such as the Haynesville shale, settle up to 40% more rapidly than similarly sized sands due to higher particle density, necessitating much higher slurry velocities for comparable transport.

Settling rate is directly proportional to the reciprocal of fluid-apparent viscosity, so a proppant particle will fall 10 times slower in a 20-cp fluid such as a linear gel than in a 2-cp fluid such as slickwater. Similarly, to use flow velocity instead of viscosity to maintain proppant transport, velocity must be 10 times higher for the slickwater than for the linear gel fluid.

Ultimately, the ideal fluid for tight gas applications would combine the simplicity of slickwater with the proppant-carrying capability of a more viscous fluid without significant impact on economics or formation permeability.

A frac as two operations

Fracture width and closure models are compared for three fluids in a typical Haynesville shale well. The new fluid (middle) combines the best aspects of a typical crosslinked fluid (top) and slickwater (bottom). (Image courtesy of Baker Hughes Inc.)

To achieve this “best of both worlds” scenario, engineers decoupled a conventional shale fracture treatment into two operations. The first carries proppant to the formation; the second creates, extends, and props open the fracture in the formation. Considered as two operations, the ideal fluid for a fracture stimulation treatment would be viscous at the surface and in the horizontal lateral and nearly linear in the formation. This higher initial viscosity and lower viscosity at the perforations turns conventional frac design on its head but is imperative to the success of the treatment.

The result of this new paradigm of shale fracturing is ShaleXcel fluid, an aqueous-based fluid with a high-efficiency hydratable polymer, such as a guar gum, and a suitable agent for crosslinking the polymer to form a viscous fluid.

On surface and in the horizontal lateral, the new fluid has enough viscosity to transport proppant at rates ranging from very low to high. As the fluid enters the perforations and formation, temperature and breaker technology degrade the crosslinks until the fluid recovers a base fluid viscosity.

The efficient natural (guar-based) polymer is added at loadings of 8 to 16 lb/1,000 gal and hydrates quickly. Adding an instant borate surface crosslinker creates a fluid more like a linear gel system than a crosslinked system. The system can be modified to achieve wellhead viscosity between 10 and 120 cp with programmed viscosity degradation by exposure to breakers and temperature. The system is compatible with freshwater, salts and KCl, and KCl substitutes, with only slight viscosity degradation.

Engineers have approached this solution previously using linear gel, crosslinked pads, and slickwater proppant stages, and they even increased the friction reducer ratio to achieve surface viscosity. These solutions typically resulted in formation damage in the nanodarcy rock due to the high polymer and chemical loadings required to achieve the necessary viscosity and limited fracture creation because the viscosity does not break early enough downhole. For example, a treatment with a 20-lb/1,000 gal linear gel loading yields a surface viscosity of 14 cp at surface temperatures and retains viscosity at the perforations between 6 and 10 cp.

Independent laboratory testing on Haynesville shale cores indicated the regained conductivity of the new fluid system compares favorably with slickwater systems currently used in shale treatments.

New fluid is a model of efficiency

To compare the new fluid with conventional crosslinked and hybrid (slickwater followed by linear gel and crosslinked fluid) fluid designs on a typical Haynesville shale well, three jobs were modeled. Modeling used conventional bi-wing geometry for simplicity (the industry believes that shale fracturing creates a complex grid rather than a conventional shape). Without better modeling technology available in the industry, these plots are nevertheless instructive for comparing fluid and proppant performance.

The fluid and proppant control of the crosslink job focuses the treatment on limited fluid and proppant placement by creating width in a contained frac. The hybrid treatment is less effective in transporting proppant, but the low viscosity and larger volume of treatment fluid accesses more of the formation area (but leaves it largely unpropped) as there is less fracture growth control.

Identifying and exploiting the best aspects of these treatments in ShaleXcel fluid provides a mechanism for proper proppant transport and a near-base fluid viscosity fluid to create and develop the discreet fracture network. Because the fluid is designed to be unstable at formation temperatures, engineers can ensure that the fracture network is established while ensuring the fractures are propped.

The transport viscosity of the fluid from the surface through the perforations assists in the proppant transport, similar to the function of the crosslink treatment at approximately the same fluid volumes (without the excess fluid used in the hybrid system because of the expected leakoff). Hydraulic horsepower requirements generally are lower as the ShaleXcel system has similar friction reduction qualities as the slickwater and linear gel stages of the hybrid treatment.