Thousands of wells require 10,000-psi rated fracture plugs that can be installed in the wellbore so that cluster perforating operations can be carried out prior to hydraulic fracturing. Today’s operators can select from myriad low-cost composite plugs that are milled after the fracture or from several types of higher cost plugs composed of materials designed to dissolve at downhole temperatures in a variety of completion fluids.

Research conducted by Qittitut Consulting with 10 U.S. operators and consultants who have expertise in plug-and-perf (PNP) completions reveals composite fracture plugs have a proven track record of continuous improvement in pumpdown speeds, drill-out time and water usage. Dissolvable plugs, however, have not yet lived up to their initial promise to reduce the total cost of completion operations, and some experts are skeptical of claims that these high-tech plugs always do disappear without impeding flowback or production.

A typical dissolvable fracture plug design (left) vs. a composite fracture plug (right) is shown. (Source: Qittitut Consulting)

 

Composite fracture plugs the standard

Composite fracture plugs have been used since the late 1980s. Initial composite plug designs were based on legacy cast iron bridge plugs installed in vertical wells that were completed in one or two zones. The first plugs had many component parts, including cast iron and tungsten components and metal rings, in addition to the composite material, which was frequently made from layered sheets of composite. With the advent of multistage horizontal fracturing, easily drillable composite fracture plugs became essential components of unconventional well completions.

Operators and service companies with experience in U.S. shale plays estimate that 80% of wells are completed in stages using the PNP method. A plug, setting tool and perforating gun string are lowered on wireline and then pumped down into the well; a plug is set, the stage is perforated in several places called clusters, and the wireline is removed so pumping operations can commence to fracture through the perforations into the adjacent rock. This process is repeated a few times in a vertical well and from 20 to 70 times in a horizontal well. After the fracture the plugs are drilled out with a bit on jointed pipe or by coiled tubing (CT) with a downhole motor and bit. The debris from the milling operation is circulated out of the well, and flowback and production begins.

For efficient PNP operations, the plugs, setting tool and guns must be run quickly without “presetting” before reaching target depth. Water volume and horsepower for pumping the plugs downhole should be minimized. Plugs should hold 8,000 psi to 10,000 psi during fracturing. To minimize overall completion costs, the plugs should drill out quickly and leave only small cuttings that do not cause the CT to stick so that time-consuming short trips are minimized.

In the past few years a few composite plug suppliers have improved their designs to meet these goals by introducing shorter plugs with better composite materials; fewer parts and less metal content; and fluid propulsion rings that accelerate running times, minimize or eliminate presets, improve pressure ratings, and reduce drillout time. In one operator’s wells studied in the Permian Basin these improvements have reduced PNP and fracture completion times from eight days to four days.

Completion engineers and consultants said high-performance plugs require less water and can be safely pumped down at speeds exceeding 24 m/min (80 ft/min) without risk of a preset. Drill-out times with these plugs are highly predictable and range from 7 to 12 minutes per plug.

Dissolvable plugs viewed as promising but unproven

Four large service companies and a few smaller specialized suppliers have released disintegrating metal alloy fracture plugs that promise to disappear entirely after the well is fractured. Most designs feature a highstrength dissolvable metal that is formulated to dissolve in completion or formation fluid. These plugs are five to 10 times more costly than composite plugs, but their value would be considerable if they created reliable zonal isolation and truly did dissolve into dust or flakes from toe to heel prior to flowback. When the plugs perform well, they dissolve within 72 hours, allowing longer laterals to be completed and eliminating CT millouts.

Results experienced by nine operators and one completion consultant in major U.S. shale plays demonstrate that dissolvable plugs don’t always disintegrate quickly and in some cases take 10 to 15 days to fully dissolve. Delays like this defer production, so the loss in revenue is greater than any potential savings from reducing millout runs. Well-publicized successes also have been documented in technical papers and press releases, but the majority of operators interviewed in the study are using composites and only running dissolvable plugs in a limited number of wells. On these wells, the operators still require a CT cleanup run to remove proppant and residual debris from the well.

Of great concern to some operators is the lack of understanding of the impact of dissolving plugs on the effectiveness of the fracturing process. Questions that must be resolved prior to wider adoption include:

  • Will dissolvable plugs withstand 150,000 lb/ft to 200,000 lb/ft of force during fracturing operations?
  • What tests have been conducted to ensure zonal isolation?
  • How do these dissolving plugs compare to conventional bridge plugs?
  • If the dissolving plugs are as dependable as bride plugs over a day or two, how fast would they really dissolve in the varying temperature, pressure and fluid conditions of different fields?
  • When the plugs do dissolve, do they always dissolve completely prior to flowback?
  • If the stages at the toe end are fully dissolved, what happens if the stages in the middle of the lateral and toward the heel are less and less dissolved?
  • If a well flows back at 2,000 bbl/d, at what point do the partially dissolved slugs or clumps of materials from undissolved plugs flow together?
  • Does dissolvable slug material cause packoff in the well, no longer allowing fluid to pass and creating a situation where the flow is coming from a limited number of perforations? Would this condition cause excessive sand in flowback or production that would require a cleanout trip, reduce the effectiveness of the fracture or cause issues with separators?

Since the answers to these questions are not yet well understood and the dissolvable materials are much more costly than composite plugs, the use of dissolvable plugs might have a slow adoption rate and be limited to toe-end sections of longer laterals.