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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."
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.
Kazak, Ekaterina S. (Lomonosov Moscow State University) | Kazak, Andrey V. (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Bilek, Felix (Dresden Groundwater Research Centre)
Summary In this study, we aim to develop a new integrated solution for determining the formation water content and salinity for petrophysical characterization. The workflow includes three core components: the evaporation method (EM) with isotopic analysis, analysis of aqueous extracts, and cation exchange capacity (CEC) study. The EM serves to quickly and accurately measure the contents of both free and loosely clay-bound water. The isotopic composition confirms the origin and genesis of the formation water. Chemical analysis of aqueous extracts gives the lower limit of sodium chloride (NaCl) salinity. The CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks. A representative collection of rock samples is formed based on the petrophysical interpretation of well logs from a complex source rock of the Bazhenov Formation (BF; Western Siberia, Russia). The EM employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, and X-ray diffraction (XRD) analysis. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δO and δH. A modified alcoholic ammonium chloride [(NH4Cl)Alc] method provides the CEC and exchangeable cation concentration of the rock samples with low carbonate content. The studied rock samples had residual formation water up to 4.3 wt%, including free up to 3.9 wt% and loosely clay-bound water up to 0.96 wt%. The latter correlates well to the clay content. The estimated formation water salinity reached tens of grams per liter. At the same time, the isotopic composition confirmed the formation genesis at high depth and generally matched with that of the region's deep stratal waters. The content of chemically bound water reached 6.40 wt% and exceeded both free and loosely bound water contents. The analysis of isotopic composition proved the formation water origin. The CEC fell in the range of 1.5 to 4.73 cmol/kg and depended on the clay content. In this study, we take a qualitative step toward quantifying formation water in shale reservoirs. The research effort delivered an integrated workflow for reliable determination of formation water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs and general reservoir characterization and reserve estimation. The research novelty uses a unique suite of laboratory methods adapted for tight shale rocks holding less than 1 wt% of water.
Currently, the share of low-permeability oil and gas reservoirs among newly discovered fields is steadily growing and even becoming decisive. In this regard, analytical studies of nonlinear filtering processes are of particular importance. As shown in the paper, the nonlinearity of this equation fundamentally changes the form of analytical dependencies describing the form of pressure curves during well-test analysis and this means that the use of currently accepted methods for processing field research data will inevitably lead to erroneous conclusions regarding the characteristics of low-permeability productive layers. Based on the analysis of the properties of generalized self-similar solutions, the dependence of the well production rate with time at a constant value of depression is obtained, as well as the time dependence of the pressure in the wellbore when it is put into operation with a constant production rate. It is shown that under the Darcy law with a power-law dependence of the filtration rate on the pressure gradient, the flow rate of the well with constant depression, and the pressure in the wellbore with constant selection of the reservoir liquids are represented by power functions of time. Compared to the logarithmic functions of time, power-law functions are characterized by faster rates of change over time, which means that in low-permeability reservoirs, quasi-stationary well operation modes are almost impossible. Such features of the operation of production wells in low-permeability reservoirs may be erroneously evaluated as evidence of the existence of limited-sized oil-saturated lenses around these wells. From the physical point of view, this feature is due to the fact that the size of the depression funnel around the borehole with a power-law form of the Darcy law grows very slowly with time and, moreover, there is a moving boundary separating the region of the perturbed filtration flow around the borehole from resting reservoir fluid away from the well. The analytical dependences presented in the work were compared with the results of the numerical solution of the corresponding problems, and such a comparison confirmed the validity of the obtained dependencies. Thus, the analytical results obtained in the work allow to explain some features of low-permeability reservoirs development, and more correctly interpret the results of well-test analysis in such reservoirs.
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.
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.