Curable resin-coated proppant prevents proppant flowback

Proppant flowback, whether raw frac sand or resin-coated sand, can occur immediately with fluid flow-back at the time of pressure release or throughout the well life during hydrocarbon production. This is an undesirable condition for two primary reasons: The interruption of hydrocarbon flow decreases revenue in the short term, and potential equipment damage increases intervention cost.

Intervention cost to repair damage to tubulars, wellhead assemblies, and valves, for example, can be quite costly, according to two operators’ data reviewed by Santrol. The data sources are a 3,048-m (10,000-ft) vertical pumping well and a 4,878-m (16,000-ft) measured depth horizontal well producing from the same formation in South Texas. Typical intervention service averages US $65,000 for the vertical well and $100,000 for the horizontal well.

The significance of frac sand flowback has been documented by operators. Pope et al. examined this situation in south Texas. In the Big Wells field in Dimmit and Zavala counties, an operator compared the failure rates of 31 wells fractured with 100% sand and 31 wells fractured with a resin-coated tail-in. The vertical wells were rod-pumped at an average depth of 1,646 m (5,400 ft). The resin-coated sand tail-in wells had a 0.19 failure frequency rate per well annually compared with a 1.25 annual failure rate for the 100% sand wells. Downhole failures were stuck pump plungers, eroded pump valves, sucker rod failures, stuck tubing, and sand fill.

As far as hydrocarbon production goes, proppant that flows back reduces the proppant volume in the fracture and can significantly reduce production. In the long term, reduced conductivity can cause the fracture to close, disconnecting the hydrocarbon flow path and production.

FIGURE 1. Bonded curable resin-coated sand was tested at 1,000 psi closure stress for 24 hours at 121°C. (Image courtesy of Santrol)

This situation negates the purpose of the fracturing process and causes a loss of some or all of the fracturing investment. In the worst-case scenario, the well may have to be refractured.

Flowback control

Resin-coated proppant was developed in 1976. Curable resin-coated proppant remains the industry standard to prevent flowback. Curable resin-coated proppant can be included with the fracturing fluid at 100% or as tail-in in the range of 15% to 30% of the total proppant amount.

Curable resin-coated proppant in the presence of pressure, temperature, and moisture is pressed together. The resin that is coated onto the proppant begins to cure and bond, forming a proppant pack. Neither sand nor ceramic proppant alone can prevent proppant flowback because these elements cannot bond (Table 1).

After shut-in, the pumping company flows back the hydraulic fracturing fluid. Because the individual curable resin-coated proppant particles have bonded to each other, these particles are unable to flow back into the well-bore. The pumping company working on behalf of the operator has prevented proppant flowback and the damaging effects of that condition.

TABLE 1. Proppant flowback recommendations are shown for low, moderate, and high closure stress conditions.

Proppant manufacturing

Resin-coating uniformity coupled with engineered resin-curing characteristics that fit a desired curing profile are critical to proppant performance, specifically strength, conductivity, and flowback control. A reputable proppant manufacturer adopts highly optimized processes and strict quality control procedures for raw materials to create a better resin-coated proppant.

With good manufacturing processes, the curable resin builds bond strength quickly, enabling a short shut-in time. The proppant pack bond strength is maintained during the well life.

All of these steps are designed for an operator to achieve maximized flowback control to ensure optimal conductivity for increased hydrocarbon production and well net present value. As the final quality control step, a reputable proppant company frequently applies two tests to determine prop-pant flowback performance – the unconfined compressive strength (UCS) test and the proppant flowback test.

Flowback testing

A typical UCS test subjects the proppant pack to 1,000 psi closure stress at 121°C (250°F), based generally on well shut-in time after six hours, 12 hours, 18 hours, and 24 hours. The proppant particles set and bond into a disk-shape specimen. The specimen’s UCS value is a measure of the proppant’s bond strength (Figure 1). The associated bond strength of the proppant pack is reported in psi.

The proppant flowback test can be performed at temperatures up to 204°C (400°F) and closure stress up to 12,000 psi with stress-cycling options. The cell rig can be used to simulate liquid, gas, or multiphase flow. A laboratory technician can measure the amount of proppant grains dislodged from the pack, another measure of the proppant’s bond strength.

If there is low proppant grain dislodging in the flowback test, coupled with an adequate UCS value, an operator can be confident the curable resin-coated prop-pant will offer superior proppant flow-back prevention.

Choosing the best proppant

In certain formations, proppant flow-back control is critical to producing a better well. Flowback control depends on choosing the right curable, which is based on resin-coating uniformity and engineered characteristics verified by rigorous testing. A reputable proppant manufacturer follows these guidelines to ensure a superior product that prevents the potential cost exposure caused by flowback, equipment damage, and refracturing.

References available on request.