Because of the recent introduction of dissolvable fracture plugs, this technology has a short history compared to the lengthy historical success of composite fracture plugs. As a result, a fundamental question arises: What type of fracture plug and completion method should be used to increase the production from the wellbore and to decrease the overall cost of a completed wellbore? The benefit of the plug-andperf style of hydraulic fracturing is that it allows the operator flexibility to address this question with several different variations.

Completion approaches using fracture plugs

The choice of composite or dissolvable fracture plugs enables different approaches for completing a stimulation treatment.

One method of hydraulic fracturing uses only composite fracture plugs in the full wellbore. Composite plugs have been used for two decades, and well over 1 million stages have been successfully completed. However, using composite fracture plugs involves not only the cost of the composite tools but also the cost to mill out the plugs after stimulation, the associated delays in production attributable to the milling process and the inability for milling to reach extended laterals, reducing the number of available pay zones.

A second method of hydraulic fracturing uses only dissolvable fracture plugs in the wellbore. The use of only dissolvable technology is a new approach in the energy industry, and it is currently gaining momentum with many stages completed to date. When only dissolvable fracture plugs are used, there are no materials remaining in the wellbore for milling. A lower-cost cleanup run might be needed to remove residual proppant from the wellbore. The cost of using dissolvable technology includes not only the cost of the dissolvable fracture plugs but also the potential cost of making a tubing run for sand cleanout. Dissolvable technology enables extended-reach lateral lengths, fracturing at zones in the lateral where composites could not reliably be milled out.

The third approach to hydraulic fracturing is a hybrid method that uses a combination of composite and dissolvable fracture plugs in the wellbore. The hybrid method is commonly used in some regions for hydraulic fracturing in long laterals. Composite plugs are used in the conventional lateral length, and dissolvable plugs are used in the extended lateral portion of the wellbore. Many of the same cost-benefit considerations from the first two methods also apply to this hybrid approach.

Using the hybrid approach provides the flexibility of not having to decide the type of fracture plug or completion method to use beforehand, which enables operators to adjust day-to-day economics rather than having to preplan the entire stimulation program. This rapid response is particularly important when the costs of tools and the value of production are rapidly evolving.

A hybrid approach for extended-reach laterals uses composite fracture plugs in the conventional lateral and dissolvable fracture plugs in the extended lateral. (Source: Halliburton)

 

Creating a tool cost model

The relative value of hydraulic fracturing with composite plugs versus dissolvable plugs is based on a tool cost model. The relative value does not include the costs associated with proppant, water or pressure services because those supply costs are the same for composite and dissolvable fracture plugs. The tool value equals the production minus the tool costs and risk.

The value of the fracturing tools is a function of the tool costs, risk costs and the 30-day IP from the wellbore. The tool costs are the summation of any associated costs such as the cost of the plugs, cost to mill out, cost to clean out, etc. The risk is any mitigation cost multiplied by the probability of that type of mitigation being necessary. A 30-day IP is used in this cost model to show the relative value of the fracture plugs in a quick-return scenario. Any delayed early production is subtracted from the 30-day IP to calculate production.

The revenue from early production reflects the trend that a wellbore cleanup run is faster than milling composite plugs. This result leads to an earlier production and faster realization of the 30-day IP. The net present value of that earlier production is accounted for in this lost earlier production variable. The production values are a function of production rate from each zone, the total number of zones, the price of oil, the daily cost of capital and the number of days spent milling or on cleanout.

The tool cost is a function of the cost of the fracture plugs, cost of installing the plugs and cost of removing the plugs. The costs are broken down into the cost of the composite fracture plug, the cost of the dissolvable fracture plug, and the cost of the mill run or the cleanup run. The risk of prematurely setting a fracture plug is a good example of how to understand the risk cost profile.

The risk cost of prematurely setting a fracture plug is the product of the likelihood of prematurely setting the plug and the cost of removing that prematurely set fracture plug. The likelihood of prematurely setting a composite and dissolvable fracture plug is approximately the same. The mitigation cost, however, is different because the composite plug must be milled out, whereas the dissolvable plug can be removed by means of dissolution, such as with spotting acid or through dissolution in the wellbore fluids.

Risk factors

The cost-value model for hydraulic fracturing must incorporate the costs associated with a variety of risk factors. The cost of the risk is the weighted likelihood of occurrence multiplied by the mitigation cost. The data are still being collected for the value of these risk factors because dissolvable fracture plugs are new technology, and the cost of contingencies is highly variable with recent energy market fluctuations, between operators and in different locations.

The risk factors that should be considered when the operator is conducting a cost-value analysis include

  • Potential formation damage arising from milling operation;
  • Coiled tubing becoming stuck during milling;
  • Potential inability to circulate cuttings out of the wellbore;
  • Potential for premature setting of the fracture plug; and
  • The dissolvable fracture plug might not completely dissolve in wellbore fluids.

The tool cost model provides a framework for calculating the economic trade-offs when addressing the differences of hydraulic fracturing tools from field to field, operator to operator and market cycle to market cycle.

Conclusion

Dissolvable technology for hydraulic fracturing enables new stimulation methods for shale reservoirs. This new dissolvable technology is changing the costs and risks associated with completing the reservoir. Equally important, the dissolvable technology is expanding the opportunities to minimize mill time and to extend the lateral length of the wellbore. A framework for a cost-benefit model has been proposed to enable realization of the full value of this technology.