Scale formation and accumulation is a major concern for Russian production companies. In Western Siberia, most wells produce fluids via Electric Submersible Pumps (ESP), and it is believed that up to 30% of the ESP failures result from scale damage. Despite that scaling is commonly first recognized at the ESPs, it can ultimately affect the whole production system. The most efficient treatment strategy to prevent scale induced damage in the tubular, including ESP, is scale inhibition. Traditionally, this involves an inhibitor squeeze treatment which is a localized inhibitor placement covering the near-wellbore area or the continuous injection of the inhibitor via a capillary tube. However, these techniques are designed to protect the production system. Squeeze treatments in hydraulically fractured formations are not always effective. Scale inhibitors together with compatible borate fracturing fluids can be used for a more effective scale inhibitor placement throughout the created hydraulic fracture to prevent scale formation from the reservoir level to the production system. This technique combines hydraulic fracturing and scale inhibition into one treatment resulting in operational simplicity. Since 2008, the combined fracturing/scale treatments have been successfully applied in the Krasnoleninskoe oil field in Western Siberia. This paper outlines the learning procedure and presents designs, testing and monitoring results from the campaign conducted at Krasnoleninskoe oil field (including Talinskaya and Em-Egovskaya sections).
Hydraulic fracturing effectiveness depends on the cost and properties of the selected propping agent. The methods and fluids that create fracture width and transport the proppant along the fracture width also have a significant impact. Recent advancements related to channel fracturing design, execution, and evaluation addressing all these components have enabled proper modeling and further treatment optimization. This work provides a detailed overview of several years of laboratory experiments, research, modeling, and global field testing of enhanced channel fracturing methods. Channel fracturing is well known for breaking the link between fracture conductivity and proppant permeability by replacing a continuous proppant pack with open channels inside the fracture using intermittent proppant feeding. To prevent proppant settling during fracture closure, degradable fibers have been effectively utilized within the fracturing fluid for over 10 years. This technique achieves maximum fracture conductivity while minimizing proppant cost. Decoupling proppant performance and fracture conductivity enables replacing ceramics by natural sand, thereby significantly improving field development economics in many areas of the world. Furthermore, extensive laboratory research has qualified new fibers for application of channel fracturing across a wider reservoir temperature range. Research and laboratory experiments were conducted to construct a workflow to model and optimize sand transport and the resulting channel geometry. Fiber and proppant transport modeling results compare extremely well with experimental results and provide excellent resolution and accuracy. This work also demonstrates that intermittent pulses of proppant with fiber effectively creates reliable channels in the fracture. Also, improved software and equipment enhancements allowed accurate fiber and proppant synchronization, making the placement of fiber-free channels possible. Recently developed advanced modeling tools have improved understanding of channel formation in the fracture, thereby enabling treatment design optimization. The enhanced models further enable evaluation of different materials selection, for instance, replacing ceramic proppant with natural sand in the channeled area of the fracture. A comprehensive case study of channel fracturing implementation in Saudi Arabia proved the method to be effective for improving proppant placement and fracture geometry to yield improved incremental production. Another field case in the region demonstrated the ability to replace ceramic proppant with natural sand without sacrificing any channel conductivity. The study breaks new ground in the stimulation of extreme low temperature and high temperature formations by extending the channel fracturing technique, enabled by the introduction of a new solids transport concept and the development of new fiber compositions. When combined with accurate modeling, improved economic results were achieved by using locally produced sands to replace ceramic proppant while consistently delivering highly conductive fractures. The project includes laboratory testing, a detailed simulation model description, and field examples.
Located in northern Russian, the Timano-Pechora province covers a large variety of oil and gas fields with different formation properties and characteristics. These include formation temperatures (BHST) ranging from ~ 40°C to ~100°C, permeability of 20 to 400 mD, and the presence of 1 to 3% H2S. Many wells have long, perforated intervals of up to 80 to 100 m and produce heavy oil with high-wax-appearance. Stimulation treatments in the region also face such operational challenges as harsh surface weather conditions, difficulty in flowback from low formation pressure, and long shut-in times. Because most of the wells have electric submersible pumps (ESPs) in place, well interventions are often limited to straddle packer or coiled-tubing operations. Some wells are remotely located, with only 2 to 3 months of road accessibility. In addition, there is limited information available for wells to be treated. The supply and purity of acids, as well as inhibitors added by the manufacturer, can also present potential problems, such as incompatibility with other additives and formation of emulsions. To address the challenges of acidizing in the Timano-Pechora region, a comprehensive laboratory and field approach was applied. To achieve better zonal coverage in these heterogeneous carbonate reservoirs, a viscoelastic surfactant (VES)-based self-diverting acid system was deployed. It consists of a VES and HCl. The new system self-diverts triggered by the increases in viscosity as the acid dissolves calcite and dolomite. The viscosity of spent fluid is reduced by produced hydrocarbon, leaving no solid residue to cause formation damage. Field results demonstrate the effectiveness of the new acid system. The simplicity of the system makes it the fluid of choice, especially in sour environments. The absence of metallic crosslinkers in this system eliminates problems associated with sulfide precipitation in sour wells. Introduction Timano-Pechora oil and gas province is located in Northern Russia spanning across Komi republic, Arkhangelsk and Nenets regions (see regional map in Fig. 1). This remote region covers a large variety of oil and gas fields with different formation properties and characteristics, formations and challenges. Although exploration drilling was started as early as1890, the first light oil field (Chibyuskoe field) was only discovered 40 years later in 1930, which was followed with heavy oil field (Yaregskoe field) in 1932. The region currently has more than 75 fields representing over 230 different carbonate and sandstone formations. Those oilfields, both brown and green, are owned by several government and private E&P companies. While the brown fields are mostly on third development stage, the green fields are located extremely remotely with almost no road accessibility.
Excess water production is a major concern for Russian oil companies. Maturing fields are producing at ever-increasing water cut resulting in problems such as the cost of disposal and environmental issues. In recent years, operators have shown a rising interest in Relative Permeability Modifiers (RPMs) as a potential solution to reduce water production. RPMs are designed to disproportionately reduce the relative permeability to one phase (water) over the oil phase. RPMs are a preventive approach to reduce water production. Ideally, they should completely block water flow without affecting oil flow. While RPMs are used worldwide, they must be adjusted to the reservoir conditions. This becomes even more important in the case of hydraulic fracturing of formations with nearby water-saturated layers. Commonly, service companies recommend one type of RPM which fits all reservoirs. This paper demonstrates how RPM selection on reservoir cores is critical for successful application in the field. We describe laboratory testing and review field trial results of RPMs in a low permeability (2 to 14 mD), highly laminated formation. Because RPMs are typically used only in high-permeability reservoirs, this application is unique. We evaluated chemically different RPMs on actual core material and found strong performance variations of the tested RPMs. We selected a suitable RPM following both core flow testing and compatibility testing. For the field test, wells in the Krasnoleninskoe oilfield were selected for RPM treatments. Oil production was increased in most cases while the water cut was reduced or only slightly increased by up to 5% during 6 months following the treatment. These results show that with proper evaluation, RPMs can also be successfully used in low-permeability reservoirs. We demonstrated also that otherwise proven successful RPMs may not fit every reservoir and proper evaluation and monitoring is critical for success.
Borate-based fluids have been widely used as fracturing fluids for hydraulic fracturing treatments for several decades. Although the fluid system had been studied extensively and the importance of shear recovery was fairlywell understood, the rate of shear recovery for different pumping conditions was still an issue in question. It was commonly believed that fluids crosslinked with borate had reversible shear recovery after exposure to pumping through tubing and perforations. As a consequence, fluids with inadequate shear recovery have been used, resulting in premature screenouts and unnecessary high polymer loadings. We will show that the shear recovery rate is influenced by several physical and chemical factors, such as temperature and pH. Based on the understanding, we have developed a novel fracturing fluid with much-improved shear recovery and simplified operational requirements.We present the laboratory development of the novel fracturing fluid based on guar and a novel borate crosslinker. The crosslinker is a solid borate material, which allows controllable crosslinking through slow dissolution and instant shear recovery. We used a simple experimental method to study shear recovery behavior in the laboratory and field environment. The new fluid shows excellent compatibility with water sources used for fracturing treatments in western Siberia. The use of dry crosslinker also results in the reduction of polymer loading from 4.2 kg/m 3 to 3.0 kg/m 3 leading to higher proppant pack conductivity. We also describe the field cases of the new fracturing fluid.The new fluid has significant advantages over the existing technology because of better shear recovery, lower polymer loading, and operational simplicity. It is well suited for operational, logistical, and reservoir conditions in Russia.
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