Summary Multistage plug and perforation (plug-n-perf) fracturing is commonly used for horizontal well completion in unconventional reservoirs. Uniform distribution of proppant across all clusters in each stage has proved to be challenging with low viscosity slickwater owing to its limited transport capability. Computational fluid dynamics (CFD) has been used to model proppant transport in wellbore to improve perforation and fracturing design for achieving uniform proppant placement. However, traditional CFD modeling of a full-scale stage is computationally expensive, which limits its applicability in the completion design optimization. A new approach was developed in this paper to efficiently predict proppant placement along a multicluster stage based on a machine learning (ML) model trained with extensive CFD modeling results. Its high computational efficiency permits quick sensitivity analyses to optimize perforation and fracturing designs. The new approach was validated against full-stage CFD modeling results as well as post-treatment field diagnostics. Sensitivity analyses show that proppant inertia effect is a key factor affecting proppant placement in heel clusters with higher slurry flow rates, allowing more proppant carried to the toe owing to its higher density in comparison with fluid. Proppant settling allows bottom perforations to accept more proppant than top perforations. This gravitational effect is not negligible near the heel at high flow rates and becomes more dominant near toe clusters where the flow rate is reduced. Near-uniform proppant placement is achievable via perforation design optimization by taking advantage of these two key mechanisms controlling proppant transport in horizontal wellbores. It is demonstrated that in-line perforating designs with all perforations having the same orientation in each cluster or the entire stage, especially with perforations at the bottom or on the side of the wellbore, improve the proppant placement uniformity. However, it is recommended that the optimum perforation design should be identified case by case depending on specific input parameters. The ML-based model developed in this study has overcome some of the limitations from existing models in the literature and is able to provide quick and yet reliable solutions to proppant placement prediction and design optimization.

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Effective fracture treatment distribution to stimulate and obtain production from all perforation clusters is a key goal for success in unconventional reservoirs. The objectives of this work were to assess the impacts of multi-cluster stage perforating design parameters and execution uncertainties on treatment slurry distribution, production, ultimate recovery, and offset well interference for unconventional reservoirs. A stochastic perforation breakdown and slurry injection model and a conceptual reservoir simulator were used to investigate treatment slurry distribution, production, and ultimate recovery impacts. The design parameters in the analysis were clusters per stage, cluster spacing, maximum proppant concentrations, perforation diameter, and number of perforations per cluster for both fixed- and variable-shot cluster designs. Uncertainties evaluated included perforation breakdown percentage, perforation shot phasing for non-oriented carriers, perforation hole diameter growth from erosion, and formation permeability. As part of the analysis, the authors defined and used a new dimensionless quantity—the Slurry Distribution Number (Nsd)—that potentially fills a gap as no standard industry definition exists for perforation cluster efficiency. Nsd successfully correlated perforating design changes with slurry distribution outcomes. The authors used the results to identify strategies to mitigate uncertainty impacts, obtain more predictable outcomes, and achieve improved production results. Novel information is presented that can assist perforating design optimization for unconventional reservoirs. In addition to introducing Nsd, the authors show perforation carrier phasing and shot phasing within the casing are generally not the same for decentralized carrier systems. The authors demonstrate how to model the perforation breakdown and stage stimulation process using a combination of published geomechanics, perforation erosion, and perforation flow resistance models. Lastly, the authors describe future study opportunities for perforating uncertainties and design parameters.

Nitrogen (N2) and Carbon Dioxide (CO2) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The Pilot-scale Foam Test Facility (PFTF) used in these investigations is first described. The PFTF is capable of generating foamed fluids at pressures up to 7,500 psig and at temperatures in excess of 300°F. Then, results from several investigations aimed at proving NG foam at conditions relevant to the field are presented. NG foam was characterized using rheology measurements and flow visualization techniques. Experiments were performed to investigate the texture and stability of NG foam generated by two different mixing methods: one using a custom designed tee to match mixing velocities in the field where the gas phase is jetted into the aqueous stream, and another to ensure comprehensive mixing for laboratory analysis. Parametric studies were conducted to explore the effects of flow rate, foam quality, and temperature on the stability of NG foam. Moreover, different fluid preparations were used to investigate the effect of base fluid and additive concentrations on the stability of NG foams. Additional laboratory studies that investigated foam stability with produced water and multicomponent NG mixtures are also reported. The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N2- and CO2-based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.

Saudi Arabian Chevron (SAC) partnered with the Texas A&M University Petroleum Engineering Department and Reservoir Productivity Geomechanics Team of Chevron's Energy Technology Center (ETC) to perform acid fracturing conductivity tests on the Ratawi Limestone core samples. These tests were also performed on an analog limestone from an onshore USA field and Indiana Limestone samples for comparison with the results from the Ratawi Limestone samples. This paper shows the results of the acid fracture conductivity tests using various acid treatment systems on three different limestone formations and compares the acid etching and conductivity responses between homogeneous and heterogeneous mineralogy. The success of acid fracturing treatment depends on the creation and sustainability of fracture conductivity under reservoir conditions. The fracture conductivity depends on the reservoir rock & acid reactivity, acid-etched pattern, closure stress on the fracture face and the pore pressure depletion. Laboratory testing shows that acid fracturing is a viable option for large-scale development of the Ratawi Limestone. Its heterogeneous mineralogy plays an important role for sustaining the fracture conductivity after acid injection. Composed primarily of calcite and dolomite, limestone dissolves positively in acid. However, the insoluble minerals, such as the clay streaks with higher mechanical properties, acted as pillars to partially prop the fractures open as closure stress was applied. Essentially, the heterogeneous mineralogy of this formation assists with sustaining fracture conductivity as the reservoir pressure depletes.