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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."
Gazprom and partner RusGazDobycha have begun construction of a massive gas processing complex near the port of Ust-Luga on the Baltic Sea. Poised to become Russia's largest gas processing plant and one of the world's largest by volume, the new facility is part of Gazprom's strategy shift toward processing and will combine a gas processing plant with a gas chemical and natural gas liquefaction complex Russian Deputy Prime Minister Alexander Novak, speaking during the televised ceremony to mark the start of construction, said the complex will help Russia gain a greater share of the global market for LNG and gas processing. Russia plans to triple LNG production to some 140 million tonnes annually by 2035 and raise its global LNG market share to 20%. "Here in the northwestern part of Russia, in the Leningrad Region, we have launched the construction of a fundamentally new and high-tech industrial cluster," said Alexei Miller, chairman and chief executive of Gazprom, speaking at the dedication ceremony. "It is essential for the region and the country at large. Advanced processing is the most efficient way to maximize the potential of the immense reserves of ethane-containing gas in Russia."
Zhang, D. Leslie (CNPC USA Corp.) | Qi, Chunyan (Beijing Huamei Century International Technology Co.) | Shi, Xiaodong (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Zhan, Jianfei (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Han, Xue (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Li, Xiangyun (Beijing Huamei Century International Technology Co. Ltd.) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper the protocol and results of water/oil, surfactant /oil, CO2/oil, and N2/oil relative permeability are presented, and compared to the digital core analysis results where wettability was set to water-wet or mixed-wet, as well as the Brooks-Corey model. Amott-Harvey wettability index was measured to explain the differences. The target formation is a sandstone tight oil formation located in Songliao Basin, China. Its permeability is mostly in the 0.01-5mD range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Amott-Harvey wettability index results show that the restored wettability ranged from water-wet to oil-wet, with most samples being mixed-wt. The addition of non-ionic surfactant promoted wettability change toward more water-wetness. However, anionic surfactant had little effect on reversing wettability. Oil relative permeability (Kro) results obtained from the digital rock analysis (DRA) assuming uniform water-wetness are consistent with relative permeability calculated from mercury injection capillary pressure using Brooks-Corey model. When wettability of the digital rock model was set to mixed-wet, the resulted Kro matches the measured Kro of a sister plug to the sample used to build the digital rock model, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 flood left high residual oil saturation compared with water floods. N2 flood left even more oil behind compared with CO2 flood. Relative permeability provides key input parameters for formation evaluation and the subsequent EOR processes such as huff-n-puff operations. There are very little published relative permeability data for tight oil reservoirs. This work extends the relative permeability database, and is a starting point for future EOR work.
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.
Summary A new classification of gas-hydrate deposits is proposed that takes into account their location (marine vs. permafrost), porosity type (matrix vs. fracture), and gas origin (biogenic, thermogenic, or mixed). Furthermore, by incorporating currently used Classes 1 through 4, which describe the nature of adjacent strata, a total of 16 classes of hydrate deposits have been identified. This new classification provides detailed information on the properties of the hydrate-bearing layer and adjacent strata that can be used for both scientific research and ranking of field-development potential. Using this new classification system, a qualitative ranking of field-development potential for different classes of hydrate deposits according to likely productivity, capital, and operating costs can be conducted. Finally, we demonstrate the usefulness of this new classification by applying it to 11 well-knowngas-hydrate deposits worldwide.
Wartenberg, Nicolas (Solvay-The EOR Alliance) | Kerdraon, Margaux (Solvay-The EOR Alliance) | Salaun, Mathieu (Solvay-The EOR Alliance) | Brunet-Errard, Lena (IFPEN-The EOR Alliance) | Fejean, Christophe (IFPEN-The EOR Alliance) | Rousseau, David (IFPEN-The EOR Alliance)
Abstract This paper is dedicated to the selection of the most effective way of mitigating surfactant adsorption in chemical EOR flooding. Mitigation strategies based on either water treatment or adsorption inhibitors were benchmarked for a sea water injection brine, on both performances and economics aspects. Performances in surfactant adsorption reduction were evaluated by applying salinity and/or hardness gradient strategies through dedicated water softening techniques, such as reverse osmosis or nanofiltration. Adsorption inhibitor addition, which does not require any water treatment, was also assessed and optimized for comparison. For each scenario, a suitable surfactant formulation was designed and evaluated through phase diagrams, static adsorption and diphasic coreflood experiments. Then the real benefit of surfactant adsorption reduction on the overall EOR process economics (including the costs of chemicals and water treatment) was assessed depending on the selected strategy. Sea water was considered as the injection brine for this study as it is widely used in chemical EOR process and often suffers high surfactant adsorption level. It was found that residual oil saturation after chemical flooding (SORc) dropped from 29% to 7% by applying a hardness gradient through nanofiltration process while 4% was reached with reverse osmosis. Regarding costs and footprint however, nanofiltration was found to be more advantageous. Adsorption inhibitors addition met similar performances to nanofiltration-based process (SORc=7%) and could be a valuable option depending on injected volume (pilot or small deployment) or field location (off-shore) as they do not require water treatment plant investment. Overall, this study provides useful practical insights on both performances and economics for selecting the most adapted strategy depending on the considered field case.
Glotov, A. V. (TomskNIPIneft JSC) | Michailov, N. N. (Oil and Gas Research Institute of RAS) | Molokov, P. B. (National Research Nuclear University MEPhI) | Lopushyak, Yu. M. (Mayskoye Gold Mining Company LLC) | Shaldybin, M. V. (TomskNIPIneft JSC)
Evaluating of core saturation in case of oil source rocks of the Bazhenov formation by standard methods is not trivial task that hinders systematic measurements. An example is the existing method of distilling water in the Zaks (or Dean-Stark) apparatus, which does not allow to determine small amounts of water with high accuracy, in addition, the method is not "in-line" - it takes up to a week for one measurement. This leads to use for reserve calculation and planning mining values of oil saturation, which are not confirmed by actual data or determined on single core samples. The method was offered authors, based on combination of thermal and spectrometric techniques, let allowed measuring water saturation and oil saturation for core 12 oil fields. The results obtained indicate about significant variation in saturation by cross section of the Bazhenov formation, and the modal values of water saturation exceed those, that are usually used for reserve calculation. «Scale» factor significantly influences on the core properties, and actual values of water saturation may be higher. The degree of mobility of water in open porous space is important value. Established opinion that all water in the Bazhenov formation is associated with clays minerals is not confirmed by specially conducted researches. The dependence of water content and clayiness is linear with a high dispersion. The lowest values of water content tend to highly siliceous and carbonate rock, and the water in open voids is rather capillary-bound. The obtained values of chemically bound water released in process decomposition of minerals and transformation organic matter during heating, indicate high water content in closed pores. Studying of the features of water release in the temperature range corresponding to the decomposition (pyrolysis) of organic matter and minerals showed the presence of a large amount of water in closed pores.
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.