Summary In this study, unique field data analysis and modeling of operating wells with an extended horizontal wellbore (HW) and multistage hydraulic fracturing (MHF) in the Bazhenov formation were conducted. Moreover, a large amount of long horizontal well data obtained from the Bazhenov formation field was used. Wells with extended HW drilling and MHF are necessary for commercial oil production in the Bazhenov formation. Problems can occur in such wells when operating in the flowing mode and using an artificial lift at low flow rates. This study aimed to describe the field experiences of low-rate wells with extended HWs and MHF and the uniqueness of well operations and complexities. It was also focused on modeling various operation modes of such wells using specialized software and accordingly selecting the optimal downhole parameters and analyzing the sensitivity of fluid properties and well parameters to the well flow. The flow rates in wells with extended HW and MHF decrease in the first year by 70–80% when oil is produced from ultralow-permeability formations. Drainage occurs in a nonstationary mode in the entire life of a well, leading to complexities in operation. A comprehensive analysis of field data [downhole and wellhead pressure gauges, electric submersible pump (ESP) operation parameters, and phases’ flow rate measurements] and fluid sample laboratory studies was conducted to identify the difficulties in various operating modes. For an accurate description of the physical processes, various approaches were used for the numerical simulation of multiphase flows in a wellbore, considering the change in the inflow from the reservoir. The complexities that may arise during the operation of wells were demonstrated by analyzing the field data and the numerical simulation results. The formation of a slug flow in low flow rates in a wellbore was caused by a rapid decline in the production rate, a decrease in the water cut, and an increase in the gas/oil ratio (GOR) over time. Based on the results, proppant particles can be carried into the HW and thereby reduce the effective section of the well in case of high drawdowns in the initial period of well operation. Consequently, the pressure drops along the wellbore increased, and the drawdown on the formation decreased. Other difficulties were determined to be associated with the consequences and technologies of hydraulic fracturing (HF). These effects were shown based on the field data and the numerical simulation results of the flow processes in wells. In addition, corrective measures were established to address various complexities, and the applications of these recommendations in the field were conducted.
The article provides an analysis of shale oil production and artificial lift equipment world market for choosing the optimal method for oil production from the Bazhenov formation. The result of the analysis is the identification of prospective complexes of artificial lift (wellhead and downhole) equipment that meet the following conditions: • artificial lift equipment is used in operating conditions that are similar to those, which planned for the Bazhenov formation development: for wells with a long horizontal wellbore and multi-stage hydraulic fracturing; conditions similar to the Bazhenov formation in terms of the depth of the deposit, production volumes (production curve, initial flow rates, gas-oil ratio (GOR), reservoir temperature, etc ).; • the properties of the produced fluid are similar to the Bazhenov formation reservoir fluid (light oil, GOR increase over production time, water cut drop over time, etc. Analysis includes wellhead equipment, downhole equipment, and control stations for wellhead and downhole equipment. Based on the analysis results, the main selection criteria are given, a comparative analysis of the main types of artificial lift equipment is carried out, and promising types of artificial lift for oil production from the Bazhenov formation are identified.
Wells with extended horizontal wellbore (HW) drilling with multistage hydraulic fracturing (MHF) is necessary for commercial oil production from Bazhenov formation (Vashkevich et al., 2015; Strizhnev, 2019). Today the maximum HW length for Bazhenov formation wells is 1500 m (Strizhnev, 2019, Korobitsyn et al., 2020). In international practice the maximum HW length for shale oil production is around 3000-400 m (Rodionova et al., 2019). Pump Down Perforator (PDP) technology is used for MHF: a liner is run in hole and cemented, then perforation and hydraulic fracturing (HF) are successively performed by stages at equal distances from the end to the beginning of HW to create a branched system of fractures in Bazhenov formation. Performed HF stages are isolated with special packer plugs (insoluble blind, dissolvable blind, insoluble with seat for dissolvable ball or dissolvable with seat for dissolvable ball)) (Mingazov et al., 2020). Consequently, the fluid inflow into the well is occurred along whole HW and the flow rate increases from monotonically from the end to the beginning of HW and has maximum value at last HF stage. The numbers of HF stages are about 24-30 (number of perforating clusters - 100) at one well in Russia and 50 in the world (Alzahabi et al., 2019). One of important parameter during HF is the speed of HF fluid injection into the formation. Tubing outer diameters 114-140 mm. are used in HW to increase the injection rate and reduce friction losses in the well. The flow rate of HF fluid in this case reach to 14-16 m3/min (Ogneva et al., 2020; Astafiev et al., 2015). Monobore wells construction is planned to use with outer diameter 140 mm. A stinger is used as sealing element between tubing and liner to minimizing risk of HF liquids leaks into the annulus (Astafiev et al., 2015). As a result, the inner well diameter from wellhead to bottomhole is around constant in the process of MHF. The pressure in the hydraulic fractures and the collector near fractures after MHF is highly exceeded the initial reservoir pressure. Hence wellhead pressure after MHF in water filled well is about 100-150 bar (Jing Wang et al., 2021). This fact significantly limits downhole well operations because of requires killing (tubing change, let down ESP, etc.). These works are required heavy well killing fluid because of high overpressure. It is undesirable because of it can reduce the fracture conductivity, worse well bottom zone properties and reduce well productivity. Therefore, the well is working at flowing mode in initial period usually until the reservoir pressure in the drainage area is decreased at the hydrostatic level or below (Jing Wang et al., 2021). After that the well can be killing using technical water with a density of 1.01 – 1.07 g/sm3 (the use of well-killing fluid with a density higher than 1.1 g/sm3 is undesirable). The possibility of well flowing working depends on properties of collector and reservoir fluid: High gas-oil ratio (GOR) and reservoir conductivity help well flowing until reservoir pressure drop off hydrostatic pressure.
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