The focus of our research is on a remote oilfield in western Siberia, currently in the initial stages of development. There are two producing horizons of Jurassic age with a shale barrier in between them and variable oil/water contact (OWC). Each new well of the field is a candidate for a hydraulic fracturing treatment. Depending on well location, there is an option to perform the fracturing treatment on the lower formation only, the upper formation only, or to conduct two separate fracturing operations. Fracture breakthrough on any of the jobs can lead to significant production underperformance. With a goal to calibrate fracture modeling and identify the most critical parameters for fracture treatments, the decision was made to implement an independent measurement of frac geometry for an ongoing fracturing campaign. A total of 11 fracturing treatments are described in detail where differential cased-hole sonic anisotropy (DCHSA) measurements as well as bottomhole pressure gauges (BHPG) were implemented to enable precise modeling and to determine reliable fracture geometry. DCHSA, using a dipole shear sonic imager tools, allows for direct measurement of propped fracture height and fracture orientation azimuth. Provided with fracture height and using bottomhole pressure data, it was possible to accurately model resulting fracture half-length and propped width. In addition to DCHSA measurements, a study to describe the geomechanical properties of the formations was also undertaken to further enhance the understanding of fracture height growth in the reservoirs. Advanced open-hole logging was performed on four wells, which served as the basis for creating a geomechanical model for other wells in the field. The methodology used to model stress distribution from acoustic logging was developed using a correlation created from density logs run on offset wells. This tool allowed for reliable fracture modeling at the design stage, and enabled optimization of fracture treatments. By coupling the enhanced geological understanding obtained from the fracturing campaign with advanced geometry measurement technology, an effective geomechanical modeling method was successfully applied for future field development and production optimization. This research's technical workflow can be used as a comprehensive guideline in any field where precise placement of hydraulic fracture makes a significant difference in the overall development of a field. Introduction Kinyaminskoe oilfield is a remote field in western Siberia, located in the middle of forests and bogs, about 200 kilometers from the nearest town. Because access to the field is difficult, exploration and development of Kinyaminskoe started considerably later in time than development of closer fields, despite relatively better formation properties and production potential. Eventually, operators managed to build roads to the remote fields through the very tight Siberian taiga forests. Many of these fields are accessible only by winter roads when bogs become frozen at temperatures below -30 °C.
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.
The Volga-Urals basin is one of the largest oil-producing regions in western Russia. The most prolific wells are producing from Devonian formations characterized by light crude oil with high bubblepoint pressure. Today, most of the Devonian reservoirs are depleted and produce at bottomhole flowing pressure below bubblepoint pressure, which yields multiphase and non-Darcy flow in hydraulic fractures, drastically decreasing production. As a result, conventional hydraulic fracturing treatments are less effective. To regain fracturing treatment efficiency, the restrictions to hydrocarbon flow inside the fracture must be minimized. To account for this, a new method of fracture conductivity generation was introduced. Channel fracturing creates open pathways inside the fracture, enabling infinite fracture conductivity. Channels are created by discontinuous proppant feeding at surface into viscous fracturing fluid. Dissolvable fibers are added to the slurry to separate proppant structures and prevent them from settling during treatment. Proppant structures act as bridges inside fractures; voids between them are essentially stable channels connected along the entire length of the fracture. While channel fracturing has already been implemented successfully in many places around the world, the fracturing conditions of Volga-Urals Devonian formations were still new for this technology. The Volga-Urals region is well known for high tectonic stresses and low fracturing-fluid efficiency. While channel fracturing treatments are being designed and pumped in a regime without tip-screenout (TSO) in other locations, channel fracturing treatments in Devonian formations often showed significant TSO. Production analyses showed consistent productivity increases, and in most cases, 2 folds higher compared with offset wells where conventional fracturing technology was used. After the success of the pilot campaign, proppant flowback was resolved by incorporating a rod-shaped proppant as a tail-in stage of channel fracturing schedules. The nonspherical shape of the proppant increases internal friction between the particles and mechanically holds them in place. In addition to improving proppant flowback control, the combination of technologies maximized conductivity of the near-wellbore area which connects channels and the wellbore. The success of more than 30 of such fracturing treatments expanded the pool of candidates for channel fracturing with rod-shaped proppant to meet the challenges of similar complex geological conditions.
Historically, coiled tubing (CT) services were positioned as highly tailored services in Russian Federation. Main operations for CT application were post-frac cleanouts (CO) and kick-off (KO) of vertical and slightly deviated wells. Lately, with increasing of horizontal wells quantity, CT application scope became wider: logging, perforating, fishing jobs, CO, milling and other operations. With increasing interest to multi-stage hydraulic fracturing technology, Coiled Tubing application has to grow to meet client demands. In wells with horizontal section 1000 m long, milling of different sizes balls and seats became the most challenging and efficient technical solution. Located in Khanty-Mansiysk District of Western Siberia, Priobskoe field is one of the world’s largest oilfields. Due to low permeability almost 80% of reserves are hardly recoverable. Oilfield development plan include post drill fracturing of all new completed wells. In order to maximize the hydrocarbon recovery field-proven technology enabling multi-stage hydraulic fracturing of an uncemented completion in one pumping treatment became a consistent decision for well treatment. For the first job following workflow was applied: multi-stage hydraulic fracturing completion was installed and 7 zones were fractured one by one. Technology implies that during pumping, at specified stage time, balls are dropped (one at time) from the surface to open the Frac Ports (FP). After the treatment, the most efficient technical solution to remove the balls is to mill them using CT. Following milling operations the well was cleaned out and kicked off with nitrogen. In designing a Coiled Tubing job the critical part is BHA and string selection. Selected mill should be strong enough for milling Frac Port iron and long enough to prevent damage of FP, by side tracking from it to reservoir. As per project program 4 wells have been completed with technology described above. Current production rates show high efficiency of multi-stage hydraulic fracturing technology over traditional well completions. This article describes technical and operational details of the project, candidate selection process, job planning and determines a way to find an optimum technique to meet client demands. Analysis of 4 wells completed with multi-stage fracturing liner is shown in comparison with standard completion in the article.
The channel fracturing technique changes the concept of proppant fracture conductivity generation by enabling hydrocarbons to flow through open channels instead of through the proppant pack. The new technique is based on four main components: proppant pulsing at surface with fracturing equipment and software, a customized perforation strategy, a fibrous material to deliver stable channels, and a set of models to optimize channel geometry. The Taylakovskoe oil field is located in western Siberia—430 km away from the nearest settlements. The Jurassic reservoir in Taylakovskoe field is a sandstone formation with significant net pay (average 25 m) and middle-range permeability (3 to 20 mD). Bottomhole temperatures range between 85°C and 90°C. Fracturing gradient is typically 14 kPa/m. The majority of the wells are stimulated immediately after drilling. Sufficient fracture conductivity and effective fracture length are essential for adequate well performance. The optimization of hydraulic fracturing treatments conducted in recent years was based on improved fluid chemistry and pumping "aggressive" fracture designs; this yielded high-quality results. The new channel fracturing stimulation technique, which allows significant increases in fracture conductivity, became the next technological progression. With channels inside the fracture, fluid and polymer residue flow back faster than with a conventional proppant pack, improving cleanup and increasing effective fracture half-length. One of the most important advantages of the new technology is a very low risk of screenout events. The fibers make fluid more stable, while the presence of clean pulses around proppant structures promotes bridging-free flow. Reduced risk of premature treatment termination is even more important in remote operations such as in the Taylakovskoe field because of the higher costs of nonproductive time and deferred oil production. Candidate selection criteria were developed specifically for local conditions. Ten channel fracturing treatments performed in Taylakovskoe wells have already showed significant increases in incremental oil production—average 44% beyond expected production as shown by well performance analyses. We describe the performance evaluation of wells completed with this technology and future plans for applying channel fracturing methods in the Taylakovskoe field.
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