Successful hydraulic fracturing in various "risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin, as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This can be achieved using low-viscosity fluids, such as viscoelastic systems, oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enhances fracture placement success. As the treatments significantly differ from the regular fiber assisted application in tight gas formations, a series of experiments had to be performed to ensure full compatibility with formation fluid, resin-coated proppants, and treating fluids. Characteristics such as leakoff behavior, viscosity development, settling rate for large-sized proppants, and fiber degradation in static and dynamic conditions were determined in various laboratory tests. This engineering work allowed fiber based fluids technology to be extended to moderate permeable oil reservoirs (1-20 md) and relatively cool formations (76-95ºC), where fracturing treatments are regularly designed for tip-screenout treatments requiring fracture geometry control maximizing proppant pack permeability by increasing mesh size and proppant concentration. The first five treatments performed have pushed the limits of the technology in regard to proppant size, type, concentration, and fracture fluid gel loading. Combining this solution with the use of advanced HGC materials offers unprecedented results in regard to fracture-height containment, where positive net pressures were obtained the first time. These operational results were confirmed by production measurements where the average water cut is 50% lower compared to the conventional treatments. Increases in productivity allowed up to a 37% increase in oil flow rate.
The hydraulic channel fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, which provides for highly conductive paths for the flow of fluids from the reservoir to the wellbore. These channels are created through a process that combines fit-for-purpose geo-mechanical modeling, surface equipment controls and fluid and fiber technologies. This paper reports the first implementation of the channel fracturing technique in horizontal wellbores. A section of the Eagle Ford formation (TVD 10,900 - 11,500 ft) in the Hawkville field near Cotulla, Texas was selected for this study. This section comprises mainly limestone with 100 to 600 nD permeability and 7 to 10 % total porosity. The formation requires horizontal laterals with multi-stage hydraulic fracturing for economic production. The channel fracturing technique was evaluated in twelve horizontal wells. Results from thirty eight offset wells treated with conventional techniques (slickwater or hybrid-type treatments) are also reported to compare performance. Non-normalized data from this sample of fifty wells showed hydrocarbon production increases ranging between 32% and 68% in favor of the channel fracturing technique. The Hawkville field comprises a gas-rich section and a condensate-rich section. Reservoir simulations were performed on a sample of four wells located in the gas-rich section and two wells located in the condensate-rich section of the field to generate sets of normalized production data. These simulations accounted for variations in completion strategy, bottom hole flowing pressures and reservoir quality. Normalized production data for the sample of wells located in the gas-rich section of the field showed that the channel fracturing technique increased gas production by 51%. Normalized production data for the sample of wells located in the condensate-rich section of the field indicates increase in condensate production by 46%. Results from these history matches are consistent with the hypothesis that the channel fracturing technique enabled higher production by two concomitant mechanisms: increased area of contact with the reservoir and enhanced connectivity between the reservoir and the wellbore through highly conductive channels. Positive features that were also observed during this campaign such as the elimination of near-wellbore screen-outs and significant reductions in proppant and water consumption are also summarized and discussed.
Degradable diverters are commonly used in multistage fracturing to increase the number of fractures along the wellbore and provide temporary isolation. Still, interpreting the effects of a diverter downhole remains challenging. In this paper, a nonintrusive monitoring technique is presented, which enables interpreting the effects of the diverter on multistage fracturing treatments. This technique relies on the processing of pressure data acquired at high frequency. Unlike other monitoring techniques, its deployment is straightforward and relies only on surface acquisition and interpretation algorithms. It does not necessitate any change or additional steps in operations by utilizing events which are part of fracturing treatments. Data are interpreted on-site and in real time, and the results lead to an improved understanding about the performance of the diverter downhole, the evolutions of the wellbore connectivity with the formation, and the degradation process of the diverter. The high-frequency pressure monitoring (HFPM) technique was used during several multistage fracturing operations. We present a case where the degradable diverter was used to effectively plug a leak during the fracturing treatment. The leak had inadvertently developed in a region of the well toward the heel, threatening the fracture stimulation stage aimed at the toe of the well. The HFPM technique was used to locate the leak, confirm its successful plugging with a degradable diverter, and monitor the degradation of the diverter. The HFPM provided control of the leak and data on when to pump additional diverter and the effects of the operation. The example demonstrates in a compelling manner that the HFPM technique enables real-time decisions that ultimately improve multistage fracturing treatments and operations relying on effective isolation and diversion. The HFPM presented herein is a novel, nonintrusive method for monitoring multistage operations and enabling real-time decisions. The technique is particularly valuable for monitoring treatments that rely on diversion and zonal isolation. HFPM is enabled by state-of-the-art signal processing and interpretation algorithms. It has the potential to become a ubiquitous technique that is part of each and every multistage fracturing treatment.
Problems related to inorganic scale precipitation are common in oil fields across Russia. The predominantly calcium carbonate scale rapidly precipitates from the produced water and causes reduction in reservoir permeability, restricts fluid flow in tubing and perforation, fails electric submersible and rod pumps, and plugs surface equipment. Local industry offers a number of inhibitors to prevent scale deposition. Although regular and planned injection of inhibitors into producing and injector wells is the most common method of scale precipitation prevention, no successful attempt to enhance scale prevention in conjunction with a stimulation treatment has been documented. This paper describes the first application of a combined scale inhibitor and hydraulic fracturing treatment in Western Siberia. It allowed the operator to place significant amount of scale inhibitor within the propped fracture and into the adjacent formation. The case history delineates the detailed sampling and pretreatment analysis of several oil fields with high-water-cut wells. In some of the fields, as many as 26% of the production wells experience scale-related problems. Up to 33% of electrical submersible pumps (ESP) failures are related to inorganic scales. Further, the candidate selection process provided ground for detailed lab testing to optimize the inhibitor type and volumes required for the first scale-inhibited hydraulic fracturing application in the Novogodnee field. The pilot project wells that were hydraulically fractured with the addition of scale inhibitor yielded a threefold increase in productivity and similar initial fluid production rates. The scale-inhibited wells did though provide sustained rates over a 3month monitoring period compared to rapid decline in production on the non-inhibited wells. At the same time, the wells treated with scale inhibitor have provided not only sustained production but also a fourfold reduction in operating cost, confirming the success of the pilot project.
This paper describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and higher with only 3.0 kg/m3 (25lb/1000gal) guar polymer loading, a feat previously only achievable with 3.6–4.2 kg/m3 (30–35 lb/1000gal) gel loading in similar geological conditions. In addition to reducing damage with lower polymer concentrations, other advantages of degradable fiber usage were anticipated to be proven after proppant fractures geometries and production parameters (including PI and Jd) evaluation. Analyses of the fracturing treatments have been performed based on bottomhole pressure gauges data and well-supported with direct fracture geometry estimation obtained by using differential cased hole sonic anisotropy measurements. As it is common for most formations in Western Siberia to have high degree of lamination and multiple shaly layers inside producing zone, pilot well-candidates for the project were specifically selected to have complex geology including several layers of sandstones and shaly strikes. This requires the fracture to intersect layers of sandstone and provide optimum connection for hydrocarbons flow to the wellbore, by evenly distributing proppant throughout the height of the fracture. Thus, degradable fiber-assisted fluid must be utilized, as conventional fracturing fluids may not suspend proppant for required time period and proppant settling during fracture closure results in considerable part of net pay being under stimulated. The laboratory testing on large size ISP proppant suspension by degradable fiber in viscous fluids was performed for this project and described in the paper. Western Siberia field and degradable fiber-laden fluid provided a good example of how one solution may be applied for various challenges of hydraulic fracturing optimization. This research will present a comprehensive story supported by technical analyses. Introduction and Background Fibers, in various forms or compositions, have been utilized in the oilfield business for decades, whether to promote structural integrity of a cement system, and more recently to combat lost circulation issues, and to prevent proppant flowback in hydraulic fracture stimulation1. Most recently however, the scope of fiber application has vastly expanded, with additional benefits of degradable fiber-laden slurries being realized as application expands to new areas. Since 2000, fiber-laden slurries2 have been used to improve fracture geometry and enhance production from propped fracture treatments. These particular degradable fibers are continually gaining a favorable reputation worldwide as the technology has evolved and the scope of relevant well-types has expanded.
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