Formations with a bottomhole static temperature below 70 degC are very common for quite a number of Russian oil provences such as Komi, Samara Area, Orenburg, Tatarstan Bashkiria, and Eastern Siberia. Many of these formations are now being developed with proppant fracturing which incorporates a lot of flow back issues due to the various reasons including high viscosity oil, aggressive TSO designs and cycle loads on a proppant pack due to ESP change regime. There are a number of solutions to prevent proppant flow back and the most common one is usage of resin-coated proppants. At temperatures below 70degC RCP needs chemical activation in order to achieve a solid proppant pack consolidation. Depending on temperature range and coating structure various types of activators can be used. Traditionally commercial activators were used at very high concentrations that may compromise proppant pack conductivity and performance fracturing fluid. Alternative techniques are based on using fiber technologies and unconventionally shaped proppants.The majority of flowback control techniques have been tested in Volga-Urals region of Russia, Orenburg, Samara and Bashkiria areas. Novel additives that accelerate curing, RCP was successfully implemented and pumped during hydraulic fracturing on the most oil fields of Samara area. Flow back problems were observed only at extremely low temperature reservoir (Ͻ30 degrees Celcius) with highviscous (ϳ100ϩ cP) oil. Paper uncovers the details of activation process with detailed laboratory investigation for several RCPs and activators, proposes decision matrix for low temperature flow back control techniques, its applicability and design. Problem: Proppant Flow backProppant flow back is the term used to describe the problem of proppant being produced out of a hydraulically created fracture during well cleanup or reservoir production. This phenomenon can create several problems. Once removed from the fracture, proppant cannot contribute to fracture conductivity or reservoir production, moreover, productivity of the remaining fracture is severely affected. Proppant flowing back from the fracture may cause mechanical problems with downhole equipment, especially for the wells equipped with an electrical submersible pump (ESP).
A new method of nonintrusive fracturing process monitoring in real time has been developed. The method is a combination of advanced signal processing algorithms and a tube wave velocity model based on Bayesian statistics and, thus, does not require complex hardware. This enables cost-effective and timely decisions at the wellsite. The technique was validated in the field in several fracturing and refracturing jobs.
Scale deposits are a common problem in oil and gas wells and can have detrimental effects on well production. Depending on the severity, scaling can stop production entirely as scale forms anywhere in the well production system, including the formation, perforations, casing or tubular, and in or on the artificial lift equipment. There are several chemical and mechanical methods for removing scale deposits. However, to prevent scale deposition, the only solution is chemical inhibitors injected into the formation. The typical production system includes artificially lifted, stimulated wells (propped hydraulic fractures) placed in reservoirs where pressure maintenance is achieved by water flooding. The artificial lifting is typically accomplished through use of electric submersible pumps (ESPs). In reservoirs where produced fluids exhibit scaling tendencies, ESP run life is significantly shortened by scale formation on the pump elements restricting rotation. By treating the formation with chemical inhibitors, the life of the ESP can be extended. In this paper we provide approaches for improving a compatibility of a novel hydraulic fracturing fluid (used in Russia) and scale inhibitor. A 3-year campaign to combine scale inhibition with the hydraulic propped fracture effectively increased the average run life of ESPs in the Mayskoe and Snezhnoe oil fields.
Hydraulic fracturing de-facto is the most common stimulation technique that is employed worldwide. Russia is following the same trend and most of the new and old wells are considered for hydraulic fracturing. However, eventually as more and more reservoirs become depleted operators are looking forward to formations with so called "hard-to-recover" deposits in order to sustain hydrocarbon production.These "hard-to-recover" deposits include:• Unconventional shale pays similar to US -Bazhenov and Domanik formations.• Caspian, Arctic, and Sakhalin offshore • Eastern Siberia green fields • Mature fields and formations where conventional stimulation is not as effective as expected due to variety of reasons.
Traditionally, surface pressure is the primary tool for onsite decision making during well stimulation treatments. In multi-stage wells with multiple injection points (perforation clusters) there are several available methods for diversion efficiency evaluation: differences in pumping pressure caused by pill pumping (also referred to as diversion pressure), instantaneous shut-in pressures (ISIPs) difference, and friction pressure difference. However, these techniques rely on interpretation of friction pressure or net pressure with uncertainties related to indirect measurements of the respective parameters. A high-frequency pressure monitoring (HFPM) service uses specially designed hardware and proprietary signal processing algorithms to determine the true location of downhole events. Bayesian algorithms are used to calculate probabilities of the interval’s stimulation. Effectiveness and applicability of the method were tested on several wells across major US shale plays. It was demonstrated that the industry standard surface pressure techniques are not always the best approach for the on-site decision making. Even when diversion is not clearly visible, it still may occur downhole. Conversely, a significant diversion pressure response does not necessarily mean adequate diversion. The effective application of the HFPM technique makes engineered decisions more confident during stimulation and diversion operations.
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