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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.
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.
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.
Abstract Injection Fall-Off (IFO) testing is one of the most important methods to help monitor injector performance over time in waterfloods, water disposal operations, polymer floods, etc. IFO tests provide information about, amongst others, k*h, skin, reservoir transmissibility, and mobility contrasts. Analysis of the early-time period of such tests also can yield estimates of length and height of fractures that are induced during injection. There is however, one important parameter that cannot be estimated from IFO tests, which is the Fracture Closure Pressure (FCP) which is generally considered to be a measure for minimum principal in-situ stress. In this work, we present exact 3D simulations of hydraulic fracture propagation, followed by fracture closure as a result of shut-in and after-closure reservoir flow. The simulations focus on the details of valve closure at the wellhead followed by propagation and (repeated) reflection of the closure-induced pressure pulse (‘water hammer’) whilst at the same time the fracture is gradually closing. The simulated post shut-in pressure decline trends which are the combined result of water hammer, fracture closure and reservoir fluid flow have been compared with field data. The main result that consistently emerged from our simulations and their comparison with field data is that the water hammer disappears as soon as the fracture is completely closed. This can be explained by the fact that the magnitude of a water hammer following injector shut-in strongly increases with the total ‘system’ (wellbore plus fracture) compliance (storage), as is evidenced from our simulations. Since often, the system compliance for an open fracture is an order of magnitude higher than for a closed fracture, fracture closure itself results in a practical disappearance of water hammer. Thus, identification of the point of water hammer disappearance after shut-in allows one to estimate FCP.
Chemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR.
Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age.
The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa.
It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood.
The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go.
This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
Chaplygin, Dmitry (Company Salym Petroleum) | Azamatov, Marat (Company Salym Petroleum) | Khamadaliev, Damir (Company Salym Petroleum) | Yashnev, Viktor (Company Salym Petroleum) | Novikov, Igor (Geosplit LLC) | Drobot, Albina (Geosplit LLC) | Buyanov, Anton (Geosplit LLC) | Ovchinnikov, Kirill (Geosplit LLC) | Husein, Nadir (Geosplit LLC)
The paper describes the use of new generation of inflow chemical tracer application at Salym Petroleum Development Upper-Salym oilfield as a part of Smart Field project. This kind of well surveying using indicators that allow the evaluation of the inflow composition for each hydraulic fracturing port in horizontal wells remotely, without any additional risky and costly downhole activities.
The new inflow chemical tracer technology is based on the use of nano-particle quantum dots, which give a level of high accuracy in quantitative analysis of fluid inflow. Markers, which are micromillimeter in size, are inserted into the polymer coating of the proppant. The technology involves the injection of marked polymer-coated proppant in the process of MHF (multi-stage hydraulic fracturing). Once the MHF is done, and the well is producing, the fluid samples are taken at surface and tested in a laboratory using machine learning software. Once the obtained data is interpreted, a flow profile of oil and water can be generated for each frac stage.
One of the main advantages of marker technologies is that they provide data over a long period of time, with a significant reduction in operating cost. It opens the door for new opportunities in terms of more accurate reservoir characterization and better hydrocarbon recovery. The key element of the technology is the use of specialized intelligent machine-learning software based on Random Forest algorithm to produce production flow profile.
The described methodology was used during the multi-stage hydraulic fracturing operation on oil wells 8105 and 8064 of Upper-Salym field. The volume of proppant injection at each stage was 20 tons, out of which 15 tons were of marked proppant containing a unique code for each stage. As soon as marked proppant has a contact with well fluid markers are emitted into fluid and sampling at the wellhead can be done any time when information required. The results of samples analysis are reports with graph showing quantitative distribution of water and oil production of each fracturing interval.
The new generation of inflow markers allows for continuous production, surveillance and quantitative analysis of oil and water phase from each fracturing stage. This enables better decision making to optimize the production and make better decisions for water conformance interventions. This surveillance method does not require complex and risky well interventions or production shutdowns, making it substantially more cost effective than the existing conventional methods.
Optimization of oil production, remote monitoring for risks minimization, reduction of operating costs - all these are the results of the introduction of Smart Fields technology systems in the Salym group of oilfields.
Mirsayanova, Elina (Skolkovo Institute of Science and Technology) | Ilyasov, Ilnur (JSC, Messoyakhaneftegaz) | Cheremisin, Alexander (Skolkovo Institute of Science and Technology) | Evseeva, Margarita (Skolkovo Institute of Science and Technology) | Cheremisin, Alexey (Skolkovo Institute of Science and Technology)
Abstract Many factors affect the efficiency of polymer flooding, but the key is polymer adsorption on the rock. The analysis of the main methods of experimental elaboration of uncertainties associated with the estimation of adsorption on micromodels is carried out in this article. As part of this work, the following studies were carried out: review of existing research methods and measurement of adsorption parameter; analysis of relevant uncertainties (adsorption, core, model) and methods for their reduction; carrying out subtle approaches in the study of adsorption on core samples using a filtration unit and measuring the polymer concentration by spectrophotometry; reproduction of the performed experiments on the core on the scale of the micromodel. The main problems, which are reflected in detail in the course of the experiments, are the complexity of measuring the concentration spectra in the presence of the hydrocarbon phase. This problem was solved by extracting core samples followed by pumping 4 pore volumes of polymer solution of hydrolyzed polyacrylamide Flopaam 3630S. The main results of the experiments made it possible to clarify the value of dynamic adsorption in the range of permeabilities 450 - 1100 mD for the PK1-3 layers of the East-Messoyakhskoye field. Thus, it was found that the average adsorption value is 338 μg / kg of rock. The results of filtration experiments were modeled in a commercial hydrodynamic simulator, which will allow in the future to assess the effectiveness of polymer flooding for a geological object of field development, to assess polymer losses during its filtration, and to clarify the economic risks associated with the project.
Ipatov, Andrey Ivanovich (Scientific and Technical Center of Gazprom Neft) | Zhukovskaia, Elena Anatolievna (Scientific and Technical Center of Gazprom Neft) | Lazutkin, Dmitriy Mikhailovich (Bazhen Technical Center)
Abstract Modern technology of drilling and construction of horizontal wells allows for effective development of complex oil fields hard-to-recover oil reserves includes off low-permeability (less than 1-2 mD) and hyper-low-permeable (0.01-0.0001mD) fields. The latter in Russia include Bazhen, Domanic and Achimov fields. Their development provides for the mandatory completion of HW with Multiple-Fractured Horizontal Wells (MFHW). Experience in the development of layers of the specified type for Gazpromneft PJSC shows that the highest oil production rate is achieved if the MFHW system reveals not only the low-permeability rock matrix, but also captures the highly conductive (typically fractured) streaks — "strata-conveyors" (the latter may also be located in neighboring geological and stratigraphic differences). The difference in the permeability of such highly conductive layers and the hyper-low-permeable matrix of the host rocks can be very significant (up to 10!). In addition to the positive aspects of the presence of highly conductive layers in the section associated with the achievement of high initial oil flow rates in new wells, in the process of further development, negative consequences may arise as a result of premature (even unpredictable) gas and water breakthroughs through narrow fractured layers. Is it possible to take into account the risks of loss of well productivity as a consequence of the pronounced geological heterogeneity of these fields, even if the scale of the impact of this heterogeneity is still difficult to assess by modern research methods? In this paper analyzes some of the results of core, logging, well testing and indicator studies with the allocation of characteristic features indicating the presence of local highly conductive fractured layers in the section of the oil the Bazhen-Abalak complex (BAC).