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The PDF file of this paper is in Russian.
In the article presented 2 years of experience gained during multi-stage hydraulic fracturing (MSF) on 17 wells, by means of coiled tubing (CT) without lifting it to the surface, performed in years 2017 – 2018 on Vinogradova oilfield, KhMAO, Russia. In 2017 it was successfully implemented innovative technology, where fracturing operations are combined with coiled tubing (CT) operations and are run together with CT inside the well. Current method is based on operating reusable fracturing ports, where opening and closing is carried out using coiled tubing with subsequent performace of MSF along the CT/Tubing annulus. During these jobs, considerable experience was gained, the technologies were optimized and raised issues solved, including excessive abrasive wear of the coiled tubing pipe, leaks, etc.
Vinogradova oilfield is a unique oil-saturated low-permeable reservoir with a small effective thickness, characterized by considerable stratification and gas-saturated porous layers.
MSF technology demonstrated high efficiency and proved its reliability. Starting from February 2017 till June 2018 it was 17 wells accomplished, where 246 fracturings were carried out. All the wells were successfully commissioned. The implementation of innovative approaches to multi-stage hydraulic fracturing while coiled tubing remains in the well, resulted in 2-fold work time reduction, while the amount of frac ports doubled per well. The time frame of CT work between fracturing stages was minimized from 4 to 1.5 hours. During the job on one of the wells, it was encountered a leak in the completion (liner) in the shoe area, in order to continue MSF job, the isolation packer was run and temporary installed, which allowed to accomplish the operation.
The performance of MSF technology without lifting coiled tubing to the surface proved its efficiency and economic feasibility, becoming more and more popular among operating companies, it has great potential for future implementation both in Russia and in the rest of the world. The area of distribution and application of MSF using CT is growing every year, the most relevant technology found in oil fringe with a gas cap or bottom water. The accumulated experience in this project creates the basis for the wide introduction and application of technology on other projects
Abstract Coiled tubing shear history effects on the rheological and hydraulic properties of various fracturing fluids are investigated using the experimental equipment available at the Fracturing Fluid Characterization Facility (FFCF), located at the University of Oklahoma. The primary investigation includes tubing curvature effects on the frictional pressure losses using various lengths of coiled tubing and on the fracturing fluids apparent viscosities, over a range of selected linear and crosslinked fluids, using a unique High Pressure Simulator (HPS), capable of operating at elevated temperatures and pressures. To ensure a comprehensive understanding of the curvature effects on the rheological and hydraulic properties of the selected fracturing fluids, both coiled and straight tubings are investigated. The results show that coiled tubing curvature increases the frictional pressure losses for fluids such as water, linear guar gum and Hydroxypropyl guar (HPG), and borate-crosslinked guar and HPG fluids. Also, the study shows that frictional pressure losses within a coiled tubing are dependent of coiled tubing shear history for borate-crosslinked HPG gels and are independent of coiled tubing shear history for borate-crosslinked guar gels. On the effects of coiled tubing shear on the rheological properties of the fracturing fluids, the study indicates that apparent viscosities of borate-crosslinked gels are a function of shear history, pH, and temperature. Furthermore, the results show that for certain fluids, there exist an optimum pH, where shear history does not affect fluid's apparent viscosity.
Chaplygin, Dmitry (Salym Petroleum Development) | Khamadaliev, Damir (Salym Petroleum Development) | Yashnev, Victor (Salym Petroleum Development) | Gorbachev, Yaroslav (Salym Petroleum Development) | Chernyshev, Alexey (Shell)
The PDF file of this paper is in Russian.
After hydraulic fracturing treatment, wellbore clean-out takes significant amount of time, and therefore, the commissioning of the well is delayed. In addition to production losses, production companies CAPEX and OPEX are also increasing proportionally to frac fleet activity. As a common practice, in western Siberia fracturing treatment is underflushed by about 0.5 cubic meters. This is supposed to prevent unintentional overflush and, as a result, hydraulic fracture closure at the wellbore. The loss of contact between the propped fracture and the perforated section of the well can neutralize the effect of hydraulic fracturing. This can happen in the first days of production after the operation or in a long-term perspective.
On the other hand, overflush during hydraulic fracturing is common practice for unconventional formations. It allows to use various well completion technologies with the cemented liners and significantly reduces time required to complete multistage fracturing treatment.
The objective of this paper is to show the approach and experience of the company "Salym petroleum development" (SPD). Positive result was obtained with proppant slurry overflush operation during treatment of conventional reservoirs.
Abstract Estimating the perforation pressure loss is an essential part in the design and analysis of hydraulic fracturing treatments. Accurate determination of perforation pressure loss for the rheologically complex fracturing fluids being used today can best be achieved through experimental study. Investigation of the perforation pressure loss for linear polymer solutions, crosslinked gels, and fracturing slurries has been conducted at the Fracturing Fluid Characterization Facility (FFCF) since 1994. Using the data acquired from these experiments, new correlations are developed to estimate the coefficient of discharge used in the orifice equation that governs the perforation pressure loss. The correlations can be used to accurately predict the coefficient of discharge for linear polymer solutions and titanium/borate-crosslinked gels. In addition, the slurry correlation can be utilized to determine the dynamic change in the coefficient of discharge for fracturing slurries due to erosion. The presented correlations are developed such that they can easily be incorporated into current fracturing simulators. Introduction Determining the pressure loss across the perforation is an essential part of the design and execution of hydraulic fracturing treatments. The accurate knowledge of perforation pressure becomes critical to the success of the treatment when the wellbore is connected to the formation through a limited number of perforations. This situation is encountered when fracturing multiple zones simultaneously (i.e., limited-entry treatment) or when reducing the perforated interval to inhibit the growth of multiple fractures (i.e., point source fracturing). In these cases, the pressure loss across the perforation is large enough to be a significant factor through out course of the treatment. Thus, prediction of perforation pressure loss becomes a key input in treatment simulation, execution, and analysis. Yet, the task of correctly estimating the perforation pressure loss is complicated by the flow mechanics of exotic modern fracturing fluids. Furthermore, the perforation erosion that takes place during the proppant placement stages of the treatment significantly affect the pressure loss estimation. A combined, theoretical and experimental, approach has to be used in understanding the perforation pressure loss under field conditions. Currently, the industry is using a sharp-edged orifice equation to estimate the pressure drop across the perforation. This equation includes a kinetic energy correction factor, commonly known as the "coefficient of discharge," which is used in calculating the perforation pressure loss as follows: (1) Although the coefficient of discharge depends on fluid type and restriction (orifice) size, it is common practice to assume a fixed value for all fluids and perforation sizes. However, recent studies have shown that the coefficient of discharge can vary significantly with fluid viscosity and perforation size. Thus, a rough estimate for the coefficient of discharge can introduce a serious error in the predicted perforation pressure loss. For instance, an error of 10 % in the coefficient of discharge will result in a 25% error in the predicted pressure loss across the perforation. Luckily, for clean fracturing fluids, reliable estimates of the coefficient of discharge can be obtained from available experimental data. For fracturing slurries, on the other hand, good quality data and a robust approach for analysis are not available. Laboratory data of perforation pressure loss for various slurries and different perforation sizes have been reported. Also, this study has included a discussion on the effects of flow rate, perforation size, and sand concentration on perforation erosion rate. P. 225^
With the increase in horizontal wellbore lengths, effective hole cleaning and efficient milling practices play a critical role in coiled tubing (CT) extended reach applications. Multistage hydraulic fracturing of unconventional reservoir plays has focused horizontal completion techniques on one of two primary types: plug-and-perf or ball-and-seat liner systems. The introduction of ball-and-seat technology in the middle of the last decade was a breakthrough in the horizontal stimulation completion process and significantly impacted the ability of operators to economically develop shale and tight oil reservoirs.
Most current completion systems require post-fracturing milling interventions to restore full wellbore access and remove flow restrictions. To address the challenges associated with plug milling or opening ball seats up to the full liner drift diameter, fully retrievable single-trip systems have been developed. These next generation systems require no post-stimulation milling or drilling while maintaining the benefits of both the plug-and-perf and the ball-and-sleeve completion methods through the use of retrievable isolation plugs and ball seats. Workover time can be decreased over 40%, eliminating costly milling operations. The uncertainty in both milling efficiency and the removal of debris is replaced with a simple set-down and release mechanism which leaves the wellbore unobstructed for any future well interventions. The retrievable seat system has the added advantage of leaving behind a shiftable sleeve which can be activated numerous times.
Over 600 stages of the retrievable seat system have been successfully installed and retrieved within the last 12 months while providing operators the future ability to shut off zones which may unfavorably affect production by water or gas break through. This paper will address sleeve and plug retrieval versus milling, comparing job times, cost, operating efficiencies and equipment requirements.