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Russia has taken its first steps toward regulating carbon emissions since joining the Paris climate accords in 2019 with President Vladimir Putin's signing of legislation in early July requiring the country's largest greenhouse-gas emitters (GHG) to report carbon data to a new government agency. The new law makes carbon reporting mandatory as of January 2023 for companies emitting 150,000 tons of carbon or more, and January 2025 for carbon emitters in the 50,000 to 150,000 range, according to the Russian news agency TASS. "An accounting system is being introduced, carbon dioxide is becoming a substance subject to government regulation," Greenpeace spokesman Vladimir Chuprov told Reuters. "An emissions accounting and reduction system is emerging. This is a prerequisite for a greenhouse-gas emissions trading system."
Shareholders of Russia's second-largest gas producer, Novatek, have approved $11 billion in external financing for the Arctic LNG 2 project on which Novatek has pledged its 60% equity stake in the project as collateral. The approval came 23 April at the company's annual shareholders' meeting. In making the announcement, Novatek CEO Leonid Mikhelson said that responsibility for fundraising will be split three ways between Russia, China, and the tandem of Japan and Europe acting together. The $21-billion project, which received final investment approval in 2019, is expected to launch production in 2023 as Novatek expands its LNG exports east and west along Russia's now navigable Arctic coast. Arctic LNG 2 will reach full capacity of almost 20 mtpa in 2026, according to the company.
Gazprom Neft and Shell announced they have closed on a joint venture (JV) to study and develop the Arctic onshore Leskinsky and Pukhutsyayakhsky license blocks on Russia's Gydan Peninsula. The Gydan Peninsula lies east of the Yamal Peninsula where Russia's largest independent gas producer Novatek currently exports from its Yamal LNG facility. Novotek is expanding its operations by siting its Arctic LNG-2 project in Gydan, heightening interest in developing commercial reserves on both sides of the Ob River estuary that flows to the Kara Sea and export markets east and west. Gazprom Neft and Shell will each hold a 50% interest in the JV's charter capital. The partners will manage the venture equally with intent to develop a promising exploration cluster in the northeastern part of Gydan, Gazprom Neft noted in a press release.
Arzhilovsky, A. V. (Tyumen Petroleum Research Center LLC) | Grischenko, A. S. (RN-Uvatneftegas LLC) | Smirnov, D. S. (Tyumen Petroleum Research Center LLC) | Kornienko, S. A. (Tyumen Petroleum Research Center LLC) | Baisov, R. R. (Tyumen Petroleum Research Center LLC) | Ovcharov, V. V. (Tyumen Petroleum Research Center LLC) | Ziazev, R. R. (Tyumen Petroleum Research Center LLC)
The major volume (62 %) of the current recoverable reserves at the RN-Uvatneftegas fields is confined to the Tyumen formation, while a significant portion is concentrated in areas with poor reservoir properties. Thus, at the Severo-Tyamkinskoye field, when developing oil reservoirs with permeability of less than 2·10 μm by directional wells with hydraulic fracturing, low startup rates and high decline rates were observed, as well as lack of any effect from applying a waterflooding system with directional wells used as injectors. Horizontal well patterns in combination with multi-stage hydraulic fracturing are an economic technology for the development of hard-to-recover reserves. The feasibility of drilling horizontal wells with multistage hydraulic fracturing in low-permeable reservoirs at the fields of RN-Uvatneftegas has been confirmed by pilot projects and results of a detailed sector flow simulation model runs (over 300 feasibility runs) which reproduced the typical properties of low-permeable reservoirs of the Tyumen formation. The flow simulation model runs and the pilot operations are used to roll out the HW systems with multistage hydraulic fracturing within the Tyumen formation reservoirs. As of January 1, 2020, 53 horizontal well with multi-stage hydraulic fracturing were drilled in the Tyumen formation reservoirs (J2, J3, J4, J4) at the fields of RN-Uvatneftegas with permeability ranging from 0.2·10 to 2·10 μm. The actual well operation confirmed the theoretical conclusions: the average startup parameters of horizontal wells are more than twice as high, while horizontal wells are, on average, started up at lower drawdowns. The decline rates of horizontal and directional wells are comparable, an increase in the length of a horizontal section and the number of frac jobs leads to an increase in the startup rates and overall productivity of horizontal wells. With comparable decline rates and high start-up oil rates, the expected oil production from horizontal wells significantly exceeds that of directional wells.
The system-forming project of the Southern industrial zone of the Yamal Peninsula "Novoportovskoye oilfield" of Gazprom Neft was analyzed. In its structure, 4 mineral resource centers (MRC) are allocated, differing in resource base, transport system and consumers (export - the current Novoportovsk oil maritime MRC and the Novoportovsky gas pipeline MRC under construction, providing local consumption - the current Kamennomyssky gas local MRC and the Novoportovsky gas local MRC under construction). An analysis of the availability of reserves and resources for the production of Novoportovsk oil MRC was carried out, groups of pools that make the greatest contribution to the development of the oil production base were identified, and program for its development were identified. The structure of the current logistics scheme for the export of MRC crude oil (characteristics of groups of ships solving various tasks for the export of commodity products - shipping, cabotage transportation, transshipment, and export transportation) is given. Based on the approved production levels, the need for tankers was estimated, the period of need to attract an additional fleet on freight terms and the time for the release of project vessels that could be directed to the implementation of other company projects were determined. Characteristics of commercial product of MRC - crude oil grade "Novy Port" - are given. For Novoportovsk gas pipeline MRC transportation safety is estimated, based on the approved production levels, gas consumption for own needs and capacity of the gas pipeline.
On the edge of the Arabian Desert, a megaproject located above the Arctic Circle was given the IPTC Excellence in Project Integration Award. Taking home the top honor was Moscow-based Gazprom Neft, which is the current operator of the Novoportovskoye oil and gas condensate field that was discovered in 1964 but left undeveloped for decades due to its remote location on the Yamal Peninsula in Siberia. For the past 5 years, Gazprom Neft has maintained year-round delivery of oil via an offshore loading terminal known as the "Arctic Gate." The project has also required the Russian oil and gas sector to build a new fleet of super-spec icebreakers and ice-class oil tankers designed for the harsh environments of the Arctic. The remoteness of the Novoportovskoye field has demanded that Gazprom Neft invest in remote surveillance and production technologies.
Gazprom Neft will develop its Meretoyakhaneftegaz project in Russia independently after Shell pulled out of a planned joint venture (JV) citing the negative impact of external factors. Gazprom Neft said the assets being developed are within the perimeter of the JV at the Meretoyakhinskoye field, Tazovsky, Severo-Samburgsky, and two West Jubilee sites in the Yamalo-Nenets Autonomous Area in accordance with a previously approved work plan. Operations are expected to start before the end of 2020 with industrial development of the Tazovsky field. Gazprom Neft and Shell remain involved with the Salym Petroleum Development (SPD) JV, which closed a deal in March to expand activity developing the Salym group of fields in Russia's Khanty-Mansi Autonomous Okrug. The deal includes a new license for the right to geological exploration, and exploration and production of traditional hydrocarbon reserves at the Salymsky-2 site in the Khanty-Mansi area.
Despite the ongoing impact from the COVID-19 pandemic, NOVATEK said its $21.3-billion Arctic LNG 2 project in Russia is on schedule, with expectations that it will start on time. Following a first joint meeting with the chief executives of project partners Total, CNPC, CNOOC, Mitsui, and JOGMEC, NOVATEK said overall progress for the project is estimated at 19%, with concrete casting of the first gravity-based structure (GBS) platform estimated at 37% completion. The company said the module fabrication yards are working at full capacity, and contractors for procurement, and construction are fully mobilized, alongside supply contracts that are being fulfilled. Nine production wells have been drilled at the Utrenneye field in Russia's Ob Bay with three drilling rigs in operation. NOVATEK said significant progress has been made in contracting LNG volumes from the 19.8-mtpa project.
Load engineering firm Mammoet is the latest company to be awarded a contract for the Arctic LNG 2 project being developed in the Gydan Peninsula in the norther part of Siberia, Russia. TechnipFMC-led joint venture NovArctic in cooperation with Saipem and NIPIgas brought on Mammoet as an unloading, transportation, and installation contractor for the project. Over the course of 4 years, Mammoet will install 42 large modules onto three concrete gravity-based structures in Murmansk. The project is expected to use around 2,000 self-propelled modular transporter axles, several mega-jack lifting systems, a crane fleet spearheaded by a CC8800-1 crane with a boom booster, and around 120 workers at peak times. Each module will weigh between 8,000 to 17,000 tons; over the project's lifespan the total weight of lifting operations will reach some 500,000 tons.
This paper presents the results of a 3-year project aimed at mass field implementation of ultrahigh-speed (UHS) electric submersible pump (ESP) systems in western Siberia. The project had a successful outcome, with more than 200 installations performed. The project was aimed at increasing the efficiency and safety of oil and gas production and reduction of total cost of ownership (TCO). The authors discuss the project as an endeavor of a joint venture developing the Salym group of oil fields. Since the beginning of asset development in 2003, ESP technology has been used as the primary artificial-lift method.