Western Siberia has a long and successful history of channel hydraulic fracturing technology implementation. However, there is an urgent need to further reduce the cost of hydraulic fracturing. As a solution, it was proposed to use local suppliers of quartz sand to replace a substantial proportion of the more expensive ceramic proppant. Based on the principles of the classical channel fracturing, fracture permeability is provided by creating open channels in the intervals between proppant clusters. Open channels are created by feeding proppant in pulses simultaneously with a continuous supply of fiber, which subsequently dissolves under the action of reservoir temperature. The use of quartz sand during hydraulic fracturing in reservoirs with high stresses is thus possible only with the channel fracture method of proppant placement and is justified by the fact that the fracture conductivity in this case does not depend on the permeability of the proppant itself. Open channels play a key role. Thus, the need to reduce the cost of service is justified not only economically, but also technologically. The first step in the implementation of the technology was the successful application of traditional channel fracturing using ceramic and resin-coated proppant at the fields in the Uvat region, more than 60 operations in total. The best results on productivity were obtained in multi-stage hydraulic fracturing operations in horizontal wells, where additional effects of up to 20% relative to the standard method were obtained. Advantages in the form of accelerated operations (up to 15%) were also confirmed by reducing the duration of the preparatory work; minimize workover cleanouts after premature screen-out due to minimized risks since fibers and pulses of pure liquid ensure better proppant admittance. Significantly reduced costs for logistics and storage of proppaant, which is most relevant in the conditions of autonomous fields. As a result of a successful pilot campaign, it was decided to test injection of quartz sand during channel fracturing operations. Laboratory tests have been carried out and a risk analysis has been formalized, which described in detail in following sections. The first candidates during the pilot campaign were injection wells followed by a testing plan at a producing well stock. The experience of using quartz sand during hydraulic fracturing is innovative for sandstones after numerous attempts at the hydraulic fracturing dawn decades ago that revealed insufficient sand conductivity and required a switch to expensive ceramic proppant. The reincarnation of the perspectives of quartz sand in medium permeability reservoirs was provided by the channel fracturing method, which removes the connection between proppant permeability and fracture conductivity due to the presence of open channels. The experience in the Uvat region will be the first published in Russia and will allow further developments in this direction.
Novoportovskoe field is one of the largest oil, gas and condensate fields on the Yamal Peninsula. The Jurassic reservoir is the main productive horizon at that field. It contains 50 % of oil reserves and it is described by a 45-meter deposit with a gas cap and bottom water. The main risk during hydraulic fracturing, in the absence of barriers, is the proximity of gas- and water-bearing formations. The hydraulic fracture breakthrough into gas and water zones leads to a significant decrease of oil production rate. The main objective of the described project was a selection of fracturing technologies, which would minimize the indicated risk. A number of technologies was introduced to control the vertical growth of the hydraulic fracture: polymer-free fracturing fluid to reduce the viscosity and enhance the hydraulic fracture cleaning. The technology of enzyme fluid breaker that enables to significantly improve the retained conductivity of the hydraulic fracture compared to standard oxidative breakers. The efficiency of enzyme breaker does not directly depend on the concentration but advantages of the enzyme breaker increase at low formation temperatures. The safe ball launcher allows minimizing the amount of fluid injected during hydraulic fracturing. A series of studies was conducted to analyze the hydraulic fracture geometry: Microseismic Monitoring at Multistage Hydraulic Fracturing; Long-Spaced Cross-Dipole Sonic Log, which allows determining the hydraulic fracture height. Production logging tests were performed to assess the productivity and identification of ports with a breakthrough into water- and gas-bearing horizons. The implementation of various technologies and methods of hydraulic fracturing ensured to significantly enhance the well productivity and influenced the field development plan. The obtaining of a low gas ratio and water encroachment percentage was a key criterion for success of the performed operations. As a result, in most of the wells, the gas ratio does not exceed 500m3/t and water encroachment is not more than 40%. Currently, the enzyme breaker and ball launcher are the preferred methods for multistage hydraulic fracturing in the Jurassic formations of Novoportovskoe field. The well treated with polymer-free fracturing fluid has one of the lowest gas ratio (387 m3/t) and oil production rate of 100 t/day. The ball launcher made it possible to reduce the volume of the injected fluid during hydraulic fracturing by 30% and to decrease the operation time from 5 days to less than 2 days. The approach developed and technologies selected showed a stable growth of productivity and complete applicability of hydraulic fracturing under Jurassic horizon conditions of this unique field. Stimulation operations under complicated geographic and geological conditions give some opportunities for the oil industry in the Arctic.
Channel fracturing technology has been a key enabler to unlocking hydrocarbon production from low-permeability formations in Russia for 10 years, by minimizing treatment costs and improving operational efficiency. However, an intrinsic limitation existed for candidate selection because the technique requires post-job dissolution of the fiber that is a principal component of the success of achieving efficient channel fracturing behavior. This set a lower temperature limitation of 60°C, such that formations with temperatures below this value were not recognized as potential candidates. This project was aimed at eliminating the temperature limitation and thereby enhancing the potential candidate pool for application. The channel fracturing technique creates infinite-conductivity channels within a fracture, using a proppant-pulsing technique delivered by the surface equipment. Proppant structures are consolidated and transported along the fracture by means of fibrous material, which then degrades in the channels and proppant pillars within days after the treatment, conventionally because of the high formation temperature. Expanding hydraulic fracturing into new low-temperature oil provinces such as Eastern Siberia and the Turonian formation in the Yamal region called for adjustment in the channel fracturing technique. Specifically, surface equipment was used in a modified mode to alter the pumping schedule of the fiber additive to add fiber in pulses that are synchronized with proppant pulses. The new channel fracturing methodology was designed and tested under laboratory conditions initially and then subsequently applied in several low-temperature (20 to 30°C) oil and gas fields/wells in Russia. The first campaign yielded positive results. New software and equipment adjustments allowed for precise and accurate synchronization that resulted in fiber-free channels. The first productivity results also illustrated the potential of the technology to match or exceed the planned hydrocarbon production. The main advantages of the channel fracturing technique remained unchanged—improved barrels/dollar ratio by up to 10% compared with conventional methods and fracturing cycle operational efficiency reduction of up to 25% as compared with standard techniques. Thus, the temperature limitation was removed, leaving one major criterion for channel fracturing applicability: rock competency to hold channels open and stable throughout the life of the fracture. The study breaks new ground in the stimulation of low-temperature formations by extending the channel fracturing technique, well-recognized in the traditional basins of Russia. The project includes laboratory testing and real field examples from two regions of Russia—the first campaigns.
Urengoyskoe oil and gas condensate field is second large conventional reserve of gas condensate in the world. Active development of Achimov deposits of this field is in progress now. Specific features of Achimov layers are low permeability, extremely high reservoir pressure and 15-90 meters of Net Pay. Increase of hydraulic fracture frac half-length is main strategy for such environment to optimize well productivity and reservoir fluid recovery. Logistic in tough arctic conditions is challenge here. Method to increase volume of hydraulic fracturing treatment and its effect on well productivity is described in this article. Some technological tasks were solved to optimize hydraulic fracturing process of Achimov deposits. Pumped proppant volume was a main one. Treatment design was modified to be more aggressive step by step to decrease used slurry volume and enhance fracture geometry. Full laboratory support was provided for this project. Fracturing fluid composition was optimized to provide fluid stability during approx. 7 hours fracturing job as well as fluid friction decrease to meet surface limitations of treatment pressure. Using open channel fracturing technology allowed to optimize logistics in limited space well pads without additional pad construction works and increase job efficiency. The technology provides required size of hydraulic fracture due to proppant pulsing method with proppant consumption decrease. Before 2014, fracturing treatment size was in a range from 50 to 300 tons of proppant. It did not provide parameters of optimal fracture geometry for pay zones having average Net Pays of 76 m. Increase of frac tanks amount and special frac fleet equipment units combined with permanent technological and laboratory support allowed increasing pumped proppant volume per job up to 400 tons providing high quality of operations. Implementation of open channel fracturing technology was next step in direction of frac job volume increase (up to equivalent of 700 tons of proppant) keeping the same resources and from the same size of well pad. Analysis of efficiency of open channel fracturing technology in comparison with conventional fracturing treatment in wells having similar geological conditions and stimulated with the same slurry volumes was done. It confirmed success of channel fracturing technology using results of the conducted well tests. Implemented hydraulic fracturing optimization workflow was effective to increase well productivity in turbidite reservoir. To date, sizes of hydraulic fractures created in Urengoyskoe field are one of the largest worldwide. Experience accumulated in Achimov deposits development could be successfully used in other hydrocarbon fields having similar geological challenges.
Tsarichanskoe is one of the largest oil fields in the Volga-Ural region of Russia with proven reserves oven 25 million tons of oil equivalent. An ambitious goal to produce up to 2 million tons over the next 5 years was set to achieve. The target formation to produce from is a Devonian reservoir also known as DKT. It is represented by alternation of sandstone, mudstone and siltstone and has challenging properties to deal with such as low permeability and low temperature (60–70C). Economic production from these reservoirs requires an effective stimulation. Conventional hydraulic fracturing in vertical and horizontal wells has been intensively utilized in the field with varying success since the beginning of its development. In some cases, wells completed with conventional fracturing underperform expectations and demonstrate rapid production decline. In other, complex geological conditions restrict treatment size with fracture conductivity being compromised. Therefore, the need exists for a novel stimulation technique capable to perform in the given environment and unlock the reservoir to its full potential. Channel fracturing technique has been successfully deployed in Russia with more than 170 treatments pumped in different fields. The channel fracturing technique creates highly conductive open pathways within the proppant pack by combining specific pumping protocols with fluid and fiber technologies. It is aimed at maximizing fracture conductivity and establishes unrestricted flow of fluids from the reservoir to the wellbore through the network for channels formed by heterogeneous proppant placement. To ensure stability of the channels network, the use of appropriate degradable fiber materials is imperative. The fiber additive has to be chosen based upon specific reservoir temperature. Several treatments were pumped with unique low-temperature fiber among the first trials worldwide. Successful application of low-temperature fiber enabled channel fracturing technology for Tsarichanskoe. Field campaign was supported by extensive laboratory analysis of the fiber to prove its mechanical properties and required functionality for channel fracturing in low temperature reservoirs. Initial production analysis indicates that application of channel fracturing in conjunction with the unique degradable fiber resulted in a sustainable oil rate increase up to 30% in comparison with conventional fracturing. The step change in production was achieved with noticeable reduction in proppant and water consumption by 40% and 15% respectively. Successful deployment of the channel fracturing in Tsarichanskoe field offers new opportunities for effective stimulation of low temperature formations in Russia.
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