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Parkhonyuk, Sergey (Schlumberger Oleg Sosenko) | Levanyuk, Olesya (Schlumberger Oleg Sosenko) | Oparin, Maxim (Schlumberger Oleg Sosenko) | Sadykov, Almaz (Schlumberger Oleg Sosenko) | Mullen, Kevin (Schlumberger Oleg Sosenko) | Lungwitz, Bernhard (Schlumberger Oleg Sosenko) | Enkababian, Philippe (Schlumberger Oleg Sosenko) | Mauth, Kevin (Schlumberger Oleg Sosenko) | Alexander, Karpukhin (TNK-BP.)
Abstract 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.
Levanyuk, Olesya (Schlumberger) | Overin, Alexander (Schlumberger) | Sadykov, Almaz (Schlumberger) | Parkhonyuk, Sergey (Schlumberger) | Lungwitz, Bernhard (Schlumberger) | Enkababian, Philippe (Schlumberger) | Klimov, Alexander (Imperial Energy) | Energy, Imperial (Imperial Energy) | Legeza, Sergey (Imperial Energy)
Abstract 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.
Summary This paper describes the main issues and challenges complicated the full-field development of the Jurassic deposits of the Tyumen Formation (JK2-9), Krasnoleninskoye Field. The paper summarizes the conclusions of actual wells operation, as well as substantiates the development strategy for heterogeneous low-permeable reservoirs. The results obtained were used as a base for HW+MSF technology piloting on Em-Egovskaya area, the most promising area in terms of reserves of the Tyumen Formation, Krasnoleninskoye field. At the time of paper generation, the pilot project moved to the next stage – rolling-out of engineering solutions on contingent areas (drilling of additional well clusters). However, the main focus of this paper is placed on the first stage of the pilot project including development strategy definition.
Abstract Petroleum companies nowadays tend to increase oil production from low-permeability heterogeneous reservoirs. Commercial development of such difficult objects is possible with all modern stimulation methods involved including hydrofracturing. Decrease in flow friction near the wellbore and increase in filtration area as a result of fracturing lead to multiple increase in production well rates and injection well capacities. Besides recovery factor increases because of oil production from poor-drained zones and layers. The purpose of this work was to estimate hydraulic fracturing efficiency by estimation of after fracturing well rate increase, by comparative analysis of well logging held before and after frac operation and by analyzing the well test. The task was to investigate factors of fracturing effectiveness. Also the principle of well selection for fracturing and their order in FDP was examined. Data on Priobskoe and Krasnoleninskoe (Em-Egovskaya area) fields located in Western Siberia were used in this work. 1. Hydraulic fracturing application in oil and gas fields development 1.1. Basic principles of hydraulic fracturing Hydraulic fracturing is a method of reservoir stimulation which represents fracturing of formation in the minimum stress direction under excess pressure of pumped fracturing fluid (fig.1). Fracturing fluids are the fluids which transfer the energy for fracturing from the surface to the wellbore. The fracture grows up under fracturing fluid pressure and becomes connected with system of natural fractures which are not penetrated by the well and with zones of higher permeability. Therefore well drainage area becomes larger. Fracture is kept open with the proppant which is transported with the fracturing fluid. The results of hydrofracturing lead to multiple increase in production well rates and injection well capacities because of decrease in flow friction near the wellbore and increase in area of filtration. Recovery factor also becomes higher because of additional production from poor-drained zones and reservoirs. Hydrofracturing has lots of technological decisions for different development objects and project purposes. Technologies differ mainly on fracturing fluid and proppant volumes and hence on sizes of created fractures. The most widely used method of wellbore region stimulation is local fracturing. Creation of fractures with 10–20 m length and tens cubic meters of fracturing fluids with unity tons of proppant is pretty enough. In that case well rate increases in 2–3 times. Technology of creation of high-conductive short fractures in high-permeability formations has been developed lately. Long fracture creation results in increase in wellbore region permeability, drainage area and oil recovery factor. Also watercut may decrease. Optimal well length in 10–50 mD formation is about 40–60 m and injection volume is between tens and hundreds cubic meters. Also selective fracturing is used which allows to involve in production and increase the productivity of low-permeability layers. 1.2. Fracturing experience A great experience has been gathered in the world oil industry nowadays. Each frac operation gets an increasing attention and preparation. Data management and analysis of input information represents a large part of this preparation. Data required for fracturing operation planning can be divided into three groups:–geological formation properties (permeability, porosity, saturation, reservoir pressure, gas-oil contact, oil-water contact, etc); –geometry and orientation of the fracture (minimum horizontal stress, Young's modulus, Poisson's ratio, formation compressibility, etc); –fracturing fluid and proppant properties. Principal information is derived from geological, petrophysical and geophysical investigations, laboratory core tests and field experiments (micro- and mini-fracs). Lately technology of integrated approach has been developing. This approach takes into account a lot of factors such as reservoir permeability, well patterns, fracture mechanics, fracturing fluid and proppant characteristics, technological and economical limits. According to this the following stages of fracturing optimization can be emphasized: 1. Selection of wells for stimulation taking into account the existing or project development system which can guarantee maximum oil and gas production and minimum expences.
Summary North Dakota Bakken oil recovery has increased nearly 100-fold over the last 5 years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft, with horizontal laterals up to 10,000 ft, and are produced by means of multizone hydraulic fracturing. The operator initially conducted a typical scale-prediction study to reduce well failures and maintain oil production. However, the scale-prediction study was challenging to perform for these Bakken wells because of the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historical field conditions. A “post-mortem” of data collected from all failed wells because of scale was conducted, considering the failure type, date, type of hydraulic-fracturing procedure, pump-intake pressure, scale-inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure. Results showed that 82% of the wells failed during early production (defined as less than 20,000 bbls of water produced and 2 years' production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing-fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale-inhibitor residuals because of high deposition potentials. This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, the results obtained, and the implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids.