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Toropetsky, Konstantin Victorovich (NovosibirskNIPIneft, LLC) | Borisov, Gleb Alexandrovich (NovosibirskNIPIneft, LLC) | Samoilov, Mikhail Ivanovich (RN - Peer Review and Technical Development Center, LLC) | Zharkov, Artem Vladimirovich (RN-Nyaganneftegaz, JSC)
Abstract This paper considers methodology aspects for constructing one-dimensional (1D) geomechanical models and stability calculations for the case of viscoplastic behavior of rock under stress with a case study of the Vikulovskaya sandstone from the Em-Egovskoe Field in West Siberia.
Abstract To provide designed oil production and to minimize non-productive time new approaches in hydraulic fracturing have been tried and introduced for several years in Uvat project. During this optimization process, several new technologies were pilot tested including fiber-laden fluid, rod-shaped proppant and channel fracturing technique. The main goal was to improve fracturing fluid reliability and to decrease the risk of premature screen-outs in combination with more aggressive fracturing design to maximize oil production. Uvat project oil field is located in Western Siberia. Jurassic formation is the main oil producer from the field, presented by significant net height (up to 45 m), relatively high permeability which varies in wide range from 2 md to more than 50 mD. The formation temperature is 80-90°C. The requirements to fracture geometry is gradually increase in these conditions. The greater fracture width must be accompanied with sufficient effective fracture half-length. This goal cannot be achieved with standard hydraulic fracturing techniques because of limitations in proppant pack conductivity. Besides, the more aggressive design is associated with the higher risk of premature job screen-out that consequently results in non-productive time. Paper describes the results of pilot projects for the following new technologies introduction: fibers that allow better proppant distribution in the fracture and decrease polymer concentration without sacrificing proppant transportation ability of the fluid (the new generation of fibers was implemented which is for low temperature formation); rod-shaped proppant to prevent particles flowback and to increase fracture conductivity; channel fracturing technology that allows to decrease treatment costs and risk of premature screen-out while keeping or even increasing the flow capacity of the fracture. In channel fracturing application a proppant is added in short pulses alternated with clean fluid pulses. This becomes even more vital in remote locations as the same stimulation result can be achieved with less proppant amount replaced by clean fluid pulses that leads to decrease in spending on logistics and time optimization for fracturing job. The manuscript describes the candidate selection methods for re-fracturing jobs and states the main success criteria (such as presence of formation energy and current skin calculation). The authors represent comparative analysis of horizontal wells and multistage fracturing effectiveness in low productive regions resulted in high incremental oil rate when compared to vertical wells with a single fracture.
Kaluder, Zdenko (OJSC Rosneft Oil Company, Andrey Platunov (Ex-TNK-BP)) | Nikolaev, Maxim (OJSC Rosneft Oil Company, Andrey Platunov (Ex-TNK-BP)) | Davidenko, Igor (OJSC Rosneft Oil Company, Andrey Platunov (Ex-TNK-BP)) | Leskin, Fedor (OJSC Rosneft Oil Company, Andrey Platunov (Ex-TNK-BP)) | Martynov, Mikhail (OJSC Rosneft Oil Company, Andrey Platunov (Ex-TNK-BP)) | Chong, K. K. (Halliburton) | Prokhorov, Alexey (Halliburton) | Shnitko, Andrey (Halliburton) | Fedorenko, Evgeny (Halliburton)
Abstract Application of horizontal multiple-stage fracturing is becoming the standard completion technique for oil and gas developments both in shale and tight sands. This technology has proven to be a game-changer within the US oil and gas industry to the point of creating an oversupply of gas in the US. Predictions indicate that the supply of oil related to this technology could allow the US to become self-sufficient within the decade. Globally, shale and tight-sand exploration activities are also increasing. This concept was successfully suited for and applied within a Russian tight-oil play in the Em-Egovskoe license area in western Siberia. This paper provides the case history of how a horizontal multiple-fracturing completion methodology helped unlock the potential reserves in the western Siberian Em-Egovskoe tight oil field. This very heterogeneous and lenticular sand oil play was known for years for its complexity and arduous nature. The completion technique employed a proven North America multiple-stage fracturing technique using a combination of swellable packers and sliding-sleeve frac ports. The fracturing design for the Em-Egovskoe field is discussed. This design is an adaptation of an alternating hybrid fluid system composed of proppant slugs during the pad stage and a high-concentration proppant ramp in the main frac stage. The well is currently flowing at commercial rates synonymous with early production in a typical North American oil shale well. The various monitoring techniques for measuring fracturing efficiency are also discussed. A production curve fit analysis using early production data allowed the operator to evaluate how the project was being commercially realized. Results and recommendations are presented.
Abstract The Urnenskoe field is located in the Tyumen region, Western Siberia. The main production target is the J1 formation belonging to the upper Jurassic Vasyugansk suite. Subsurface geology of the Urnenskoe field features the lithological heterogeneity of the J1 formation with high- and low-permeability interlayers and considerable petroleum reserves in upper low-permeability formation intervals. Oil and water have highly different viscosities permitting rapid water breakthrough into the formation. The first hydraulic fracturing operations were carried out at the Urnenskoe field in 2010. Because there are rich oil saturated zones in the low-permeability upper zone of the reservoir, the properties of the fracturing fluid to transport proppant and its ability to prevent settling during both the pumping and when the fracture is closing are decisive for the well productivity after the fracturing operation. Fracturing fluid with degradable fibers was selected to achieve these properties during hydraulic fracturing. The fibers create a reinforcing net within the fracturing fluid with proppant and mechanically assist the transportation and suspension of the proppant grains. The temperature decomposes the fibers when the fracture is closed. In addition, the fibers allow lowering the polymer concentration in the fracturing fluid, thus enabling control of the fracture vertical growth and decreasing proppant pack damage. Since there are no all-season roads and it is difficult to approach the Urnenskoe field in the summer, there was no fracturing fleet capable of performing an operation utilizing the fluid with degradable fibers in July 2011. Therefore, 7 conventional fracturing operations were performed; these can be used to compare the effectiveness of conventional fracturing with another 23 operations in which the fibers were used. These operations revealed that the wells in which the fibers were used had a dimensionless productivity index that was 33% higher, and this effect remained stable. Also, for the wells with the fiber application, the average cumulative oil production for 5 months was 2,245tons higher (recalculated for one well). These results confirm the effectiveness of hydraulic fracturing with degradable fibers in the Urnenskoe field. The successful experience of using hydraulic fracturing with degradable fibers at the Urnenskoe field, laboratory tests of the fiber-laden fluid, analysis of well productivity, and particular applications of the technology provide information to guide further optimization. In addition, the technology has been applied in the Jurassic formations of the neighboring Ust-Tegusskoe field, where a considerable productivity gain was achieved compared with the conventional fracturing operations.
Platunov, Andrey (TNK-BP) | Nikolaev, Maxim (TNK-BP) | Leskin, Fedor (TNK-BP) | Kaluder, Zdenko (TNK-BP) | Masalkin, Yuri (TNK-BP) | Davidenko, Igor (TNK-BP) | Fedotov, Vladimir (TNK-BP) | Murzinov, Alexey (Trican Well Services)
Abstract For the first time in horizons of Tumenskoe formations of Em-Egovskoe oilfield in Krasnoleninsky play of Western Siberia to achieve the maximum wellbore contact with heterogeneous multilayered formations the technology of multistage fracturing in horizontal well was used. It was a three staged fracturing job with use of coiled tubing to prepare well in between stages followed by well kick off and production start up. Paper describes the experience of challenges overcoming during the different stages of horizontal well architecture, principles of equipment selection and fracturing design. This particular work was in 2010 and originated the first brief into the time of multifracturing horizontal wells of Tumenskoe formations in Em-Egovskoe field, Western Siberia. Multistage fracturing in horizontally drilled well is one of the effective technological solutions for Tumenskoe formations in Em-Egovskoe field. Remoteness and not yet confident knowledge of pay zones at current stage of described field wittingly made the preconditions for selecting the cost effective well design to suit the productivity of the well. That pilot multistage fracturing project presented itself as practical and reliable method to stimulate the production in horizontal well in Tumenskoe formations of Em-Egovskoe field Krasnoleninsky play. With more experience in further use of this technology will allow keeping this drilling and completion method as economically effective in field of this subject. This paper showed the problems occurred during the well drilling stage those also some affect on the followed completion and fracturing operations. Technological solutions have been offered based on study in this paper for future wells. As result of the analysis and gained experience the recommendations are made to ease the construction of well as for example to use the liner wellbore design. A number of recommendations are made for fracturing and coiled tubing design, preparation, equipment availability and technological processes. Presented work preforms the hot topic of glimmering entry into massive multistage fracturing in formations of Bazhen-Abalak and Tumenskoe horizons in Western Siberia. The specifics of drilling and completion in horizontal wells are brought out based on described in paper geological conditions. Some trends and backgrounds were determined in study to achieve better efficiency in fracturing and coiled tubing operations for targeted formations.
Abstract The paper reviews practical applications of geosteering to horizontal well drilling and evaluates its efficiency for horizontal drilling. On Ust-Tegusskoye filed more then 30 horizontal wells were steered using 3D geological model. One of key problems in geosteering process is limited ability to understand the location of the wellbore relative to the target object (productive layer, sand interval). The traditional set of data – structural maps build from seismic and pilot wells does not allow building fine structural capable to ensure successful drilling. But building the modeling workflow allows to simulate many possible locations of horizontal wellbore between top and bottom of reservoir, find the most probable location and minimize risk of unsuccessful drilling. Local update of the geomodels in the relatively small regions containing newly drilled wells helps getting production forecasts from flow simulator in reasonable time. Recently large attention is paid to developing innovative approaches to the steering of horizontal wells. The key requirement to the geosteering process today is landing well trajectory not only into pay part of productive layer, but into most efficient part of reservoir with minimal penetration of dense sub layers. For that the whole set of technological solutions exists ranging from optimization of pilot wellbore locations and finding best possible well profiles on geological and flow simulation models to the real time geosteering. On Ust-Tegusskoye field the number of drilled horizontal wells grows every year: in 2009 there were 3 wells, in 2010 - 5 and in 2011 - 15. At the first half of 2012 9 horizontal wells were drilled (Figure 1). Minimal thickness of target layer for horizontal wells is 2.5 m. Maximum length of horizontal part is 832 m. In spite of continuous improvements in drilling technology the problem of finding borehole position within top and bottom of target layer is still actual. Standard set of G&G information – seismic based structural surfaces and pilot wells does not allow building geomodel with reliability required for successful steering of horizontal well. Wrong positioning of well trajectory make cause it to deviate from target layer – so effective length of the well will be significantly reduced.
Abstract Cyclic water injection belongs to the group of EOR methods but the incremental recovery from its impact is poor and is comparable with accuracy of the total production measurement. So application of such treatment we call advanced waterflood. Physical mechanism of oil recovery increase by cyclic water injection is a well-established phenomenon although the theory does not define the location of wells with periodical injection, amplitudes of injection variation and duration of cycles. In this paper the authors describe the framework of investigation for determination of the unknown parameters on the basis of streamline reservoir simulation. The streamline calculation gives comprehensive visualization and quantitative description of the process and makes apparent the search of effective variant of the technology. The calculations were performed on the South-Usanovskoe formation of Urnenskoe oil field.
Samarskiy, Alexey (Halliburton) | Munger, Robert (TNK-BP) | Terentiev, Alexander Gennadievich (TNK-BP) | Gasparov, Sergey Albertovich (TNK-BP) | Zalogin, Boris Pavlovich (TNK-BP) | Samyshkin, Sergey Yurievich (TNK-BP)
Abstract The traditional drilling fluid of choice in West Siberia is a potassium chloride (KCl) low-solids nondispersed polymer system. The use of KCl has been justified by the need to inhibit smectite-rich clays in the Tertiary and Cretaceous formations. KCl inhibits clay swelling and coagulates dispersive clays and does not impair the rheological and filtration characteristics of a polymer water-based drilling fluid. However, there are a number of concerns about the use of KCl in drilling operations. KCl is used in relatively high concentrations (up to 210 kg/m), requiring significant logistical resources for delivery and handling of the material, especially on remote ice-road locations. High potassium and chloride ion concentrations can also be considered to be hazardous to the environment. In recent years, regulators and operators have searched for a more environmentally, operationally, and logistically acceptable water-based mud (WBM). This has resulted in the introduction of a new generation of freshwater-based high-performance drilling fluids (Stawaisz et al. 2002). These fluids rely on polymers for clay flocculation instead of KCl. The use of a flocculating high-performance water-based fluid (HPWBF) in the Uvat Field has allowed significant reduction in fluid volumes, fluid cost, and drilling time, as well as helped to reduce logistical costs and control problems such as downhole losses, hole instability, and drilled solids contamination. Introduction In West Siberia, the choice of water-based fluid (WBF) is determined by the requirements of tight environmental and waste disposal controls, as well as by the need for cost-efficient drilling of extended-reach wells. At Uvat, drilling is performed in 311.1-mm (12¼-in.) and 215.9-mm (8½-in.) hole sizes with 127-mm (5-in.) OD drillpipe. Typical wells drilled from each pad have an S-shape profile and three casing string design, with an average depth of ~ 2400 mTVD and a maximum horizontal displacement in excess of 3000 m (Fig. 1). Initial wells in the field were drilled using KCl-polymer WBF. The traditional mud system used during the past decade has been KCl- polymer WBF, which offers several benefits including:Easy conversion of the mud system when drilling different intervals Hole stability in reactive or dispersive claystone sections Inhibition and control of low-gravity solids (LGS) when drilling long deviated sections of smectite clays in Tertiary and Cretaceous formations Improved hole cleaning by the use of shear-thinning and thixotropic biopolymers Reduced equivalent circulating density (ECD) and mitigation of fracturing in depleted sandstone sections Use of the same mud system for most of the well Reduced formation damage by adding specifically sized acid-soluble bridging agents and biodegradable and acid-soluble polymers and controlling drilled solids in the drilling fluid However, the use of KCl is no longer considered to be environmentally acceptable by some operators in terms of waste management and dilution practices. This particular operation is located in the environmentally sensitive and remote Uvat Field, Tyumen Province, West Siberia (Fig. 2). Environmental issues include: water protection zones, protection of aquifers and the permafrost zone, limited waste storage facilities on the drilling pad, and annual re-supply of chemical to the rig site by winter ice road.
Abstract The paper reviews tectonic influence on pore pressure distribution in overpressured sealing zones, and their recognition on logs. Based on materials from West Siberia (Russia) and Gulf-of-Mexico (Texas and Louisiana) a study of tectonic and diagenetic impact on transitional zones forming and associated drilling problems is performed. Faults play an important role in overpressure forming, but they can also cause partial or total damage of the seal. A fault can enhance sealing properties of shale cap or partially destroy them, allow "escape" of formation fluids and pressures from down-dip formations, forming a shallow overpressure zone (Matagorda Island 622/623 and East Cameroon). Various stages of shale diagenesis are related to water expulsion and can aid to abnormally height formation pressure forming. A nature of Bazenov abnormal pressure is related to TOC (total organic carbon) alteration, specifically to hydrocarbon generation. This overpressure was "translated" into Abalak shaly formation with complex fractured-cavernous reservoirs (Severo-Demyanskoe, Em-Egovskoe fields). Both events are causing drilling problems and could be recognized on NMR (nuclear-magnetic resonance) and conventional (resistivity, gamma-ray) log diagrams. By incorporating such information into the drilling model one can characterize complex formations and avoid them when possible from penetrating. Introduction Abnormal formation pressure may result from faulting, folding, lateral sliding, diapiric shale or salt movements, etc. . In the Caspian Sea area there was a direct connection established by P.P. Avdusin between mud volcanoes and overpressured zones; small-scale mud-volcano events are also observed at the mouth of Mississippi River . The features we have to account for, while drilling into a overpressured zones are the decrease of shale density, consequent increase of shale porosity and lower associated water salinity in contrast to shales that had been buried under hydropressured regime . Various tectonic events are responsible for compaction, pressure migration from depth (underground blowout), and temperature changes. Faulting is an important mechanism for forming the overpressured section, but it can also entirely or partially destroy sealing properties . Individual faults may allow fluid to leak from deep abnormally pressured compartments, and thus produce overpressure in rocks at shallower depths, also called "fluid migration" . Pore pressure and fracture gradient are two parameters that impose main influence on completion cots and drilling safety. For well to be in control at all time the mud weight should be in-between these two. The scope of our work was to analyze drilling results from abnormally pressured sections, and provide recommendations for their future exploration. We were particularly interested in understanding the role of diagenetic changes and tectonic activities that control (enhance/damage) the shaly caps. Main objective was to assess the influence of various faults on shaly sealing properties and well bore stability in transitional (from overpressured to hydropressured) zones. Description Based on materials (thin-sections, XRD and SEM's) from West Siberia and Gulf-of-Mexico (Texas) fields a comparison of key diagenetic changes in transitional zones was performed. Althought overpressured formations were quite different: Upper Jurassic hot shales, that recognized as a main sourse rock from West Siberia Basin, and gas-bearing Miocene semi-consolidated section from Gulf-of-Mexico, certain similarites were found (results are summarized in Table 1).