Annular flow of non-Newtonian fluids remains a ubiquitous phenomenon in drilling operations but accurately estimating the frictional pressure loss with drill pipe rotation still poses a great challenge. Since annular frictional pressure losses increases the equivalent circulating density (ECD), it becomes imperative to accurately estimate the annular pressure loss in order to keep the ECD above the pore pressure and below the fracture gradient especially in deep offshore drilling where the pore pressure and fracture pressure are so close together. When annular flows are encountered, a common practice is to calculate an effective diameter such that the flow behavior in a circular pipe would be roughly equivalent to the flow behavior in the annulus. This equivalent diameter definition replaces the diameter term in the friction factor, effective Reynolds number and Taylors number equations used for pipe flow thus resulting in different frictional pressure loss estimation. As a result, the selection of appropriate correlation for the respective fluids, flow regimes and putting into consideration pipe rotation has become important but has received very little attention. In this study, the seven different equivalent diameter definitions used for estimating frictional pressure losses in an annulus were reviewed and theoretical analysis were performed on experimental data obtained from literatures to determine the effect of these definitions on wellbore hydraulics. Pressure loss ratios (PLR) which relates pressure loss with pipe rotation to pressure loss without pipe rotation weredevelopedfor each equivalent diameter definitionusing dimensional analysis techniques. These hydraulic models combined with conventional frictional pressure loss estimation were tested with experimental measurements to determine the model with an equivalent diameter definition that best predicts frictional pressure losses for power law fluids.

The variability of reservoir properties across the lateral section of horizontal shale wells remains a prevalent phenomenon that has been observed in the development of numerous unconventional plays. However, the majority of wells in these plays are completed geometrically without account for the heterogeneity present across the wellbore thereby resulting in non-uniform production profiles along the length of the wellbore. This assertion is further validated by production logs from over 250+ horizontal shale wells which show that only about 60% of perforation clusters contribute to production in these wells, meaning 40% of the wellbore are not effectively stimulated. In recent years, operators have improved upon the geometric completion technique using an engineered approach which has resulted in better completion efficiency and production performance. This paper presents a case study of a horizontal well drilled in the Marcellus shale and equipped with a permanent fiber optic cable to investigate the effectiveness of the engineered completion approach compared to the standard geometric method. For this evaluation, the lateral length of the horizontal study well was divided into different sections. One section of the lateral employed geometric perforation placement while the perforations on another section were designed using an engineered approach. To address the challenges of perforation placement introduced by the fiber-optic cable, an enhanced perforation design methodology was implemented which leveraged the available geomechanical properties along with the wellbore and fiber-optic configurations, perforation gun specifications, and stimulation treatment design parameters to predict perforation breakdown pressures along the wellbore. Using the predicted breakdown pressures, the limited entry technique was then applied to engineer the perforation strategy for each of the stages to improve the likelihood of initiation from all of the perforation clusters. The distributed temperature and acoustic measurements from the fiber optic cable were then analyzed during the fracturing treatment to provide insight into which of the perforation clusters were initiating hydraulic fractures and being effectively stimulated. Observations from the fiber optic data consistently showed that all perforation clusters were immediately initiated for the engineered stages with uniform acoustic energy distributions occurring across all clusters which further indicated uniform stimulation across all of perforation clusters. For the geometric stages, only about 40% to 60% of the perforation clusters became activated with intermittent acoustic energy distributions being observed across all clusters throughout the treatment stages. The case study discussed in the paper presents and validates a novel approach for improving the wellbore stimulation coverage in an unconventional development. Through the characterization and incorporation of reservoir heterogeneity into the engineered completion design workflow, completion efficiency can be improved leading to enhanced well performance and project economics.

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The value of data can be greatly enhanced if the data are available at the right location and in a timely fashion. This can be a particular challenge for the often considerable volume of data collected using distributed measurements such as Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS). In this paper we describe a novel solution using multiple levels of data reduction yielding data of different sizes and fidelity. These are then transmitted for viewing at the wellsite, in real time at a remote location, or subsequently for post-job evaluation. This approach is demonstrated using a case study of a well stimulation operation from the United States.

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