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Saifullin, Emil (Kazan Federal University (Corresponding author)) | Zhanbossynova, Shinar (Kazan Federal University) | Zharkov, Dmitrii (Kazan Federal University) | Yuan, Chengdong (Kazan Federal University (Corresponding author)) | Varfolomeev, Mikhail (Kazan Federal University (Corresponding author)) | Zvada, Maiia (Gazpromneft STC)
Summary This paper highlights the difference between foam injection for gas blocking in production well and injection well and emphasizes the use of polymer enhanced foam. Moreover, this paper shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering different factors, which provides a guide regarding what kinds of foaming agents and polymer stabilizers should be used and how to evaluate them for designing a pilot application. The target in this work is the Vostochno-Messoyakhskoye field, operated by Gazpromneft, which is currently experiencing gas channeling from the gas cap in production wells because of strong heterogeneity. Foam has long been considered as a good candidate for gas blocking. However, foam injection for gas blocking in production wells is different from that in injection wells, which requires a long-term impact on gas-saturated highly permeable areas without significantly affecting the phase permeability of oil in the reservoir. Therefore, for gas blocking in production well, a long half-life time of foam is required to sustain stable foam because a continuous shear of surfactant solution/gas cannot be achieved as in injection wells. Thus, reinforced foam by polymer (polymer-foam) is chosen. Four polyacrylamide polymer stabilizers and five anionic surfactants were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system with optimal concentrations of reagents. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor. Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of the solution, which not only decreases the foam rate but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15–0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in the core first increased and then decreased with foam quality (the volumetric ratio of gas to total liquid/gas flow). The optimal injection mode is coinjection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that the gas-blocking ability of polymer-foam is better in high-permeability cores, which is beneficial for blocking high-permeability zone. It should also be noted that under a certain ratio of oil-to-foam solution (about lower than 1 to 1), the presence of high-viscosity crude oil slowly decreased the foam rate with increasing oil volume, but significantly increased the half-life time (i.e., foam stability which is favorable for foam treatment in production well).
Chen, Ye (Offshore Oil Engineering Co. Ltd / China University of Petroleum) | He, Ning (Offshore Oil Engineering Co. Ltd) | Wang, Hui (Offshore Oil Engineering Co. Ltd) | Li, Xu (Offshore Oil Engineering Co. Ltd) | Yao, Yuan (Offshore Oil Engineering Co. Ltd) | Gao, Yonghai (China University of Petroleum)
ABSTRACT In this research, the variations of critical physical fields in marine NGH-bearing layers during depressurization are numerical simulated. Considering the mutual effects, a set of coupled model is established to describe the heat and mass transfer in layers, and a trial-calculation case is carried out using COMSOL Multiphysics. The results show that the mass transfer in the porous medium may be always faster than the heat transfer due to depressurization. It is also found that the phase transitions closer to wellbore may have a negative impact on pressure transfer. These findings have reference value for promoting hydrate commercial exploitation. INTRODUCTION Natural gas hydrate (NGH) is an alternative green energy attracting attentions all over the world (Makogon, 1982, 2007). When the ambient conditions are appropriate, especially within the high enough pressure and the low enough temperature, water molecules can be connected to each other by hydrogen bonds, constructing cages to capture large amounts of small molecular gas such as methane (dominate component with proportion of 98% or more), ethane and etc (Khurana, 2017). Then gas hydrate is generated. Besides the ambient conditions, the normal formation of NGH-bearing reservoirs in nature also requires sufficient hydrocarbon generation and trap geological structure (Paull, 2001). According to these formation requirements, it is speculated that gas hydrate can exist under the surface of both 30% land and 70% sea, mainly concentrated in polar tundra and submarine continental slope (Michael, 2003). Up to now, hundreds of NGH-bearing layers have been explored through various NGH Exploration and Development Research Programs, and the scientific evaluation indicates that the potential reserve of this clean energy resource can afford human society utilization for more than 1000 years (Zhang, 2012). Series of development methods, including depressurization (DEP), thermal stimulation (TS), chemical inhibitor injection (CI), CO2 replacement (CR) and solid fluidization (SF) have been gradually proposed to extract hydrate buried underground (Makogon, 1966, Li, 2019). The merits of each method are listed in Tab.1. Using one or more of them, Russia, America, Canada, Japan and China have already carried out several trial-production projects at Messoyakha gas field (Shao, 2016), Mallik tundra (Dallimore, 2002), Nankai Through (Takahashi & Tsuji, 2005) and South China Sea (Ye, 2020), obtaining the flammable gas fixed in crystal cages and confirming the feasibility of hydrate extraction.
The experience of two successful pilot projects at the East-Messoyakhskoye field made it possible to systematize the information and develop unified system – guidelines for design and implementation of polymer flooding pilot project. The developed system is implemented in the form of practical engineering guidelines for the application of polymer flooding technology in poorly consolidated reservoirs of viscous oil reservoirs. The system consists of step-by-step algorithm for planning, efficiency estimation and implementation of polymer flooding pilot project; activity matrix; and checklist. The main stages of planning, efficiency evaluation and implementation of polymer flooding pilot are identified; their sequential passage is systematized in the form of an algorithm consisting of 7 steps from preliminary EOR screening to analysis of pilot results. The matrix of activities covers key research areas in design and implementation of pilot project: analogues, polymer selection, polymer solution rheology, polymer retention, simulation, technological parameters of injection, monitoring and control of polymer flooding process, engineering solutions for the preparation and injection of polymer solution, a comprehensive assessment of the economic efficiency of the project. The matrix allows to assess the level of effort and cost required at each stage of the project. A detailed checklist has been developed to monitor the implementation of measures and make a decision on the transition to the next stage. The implementation of the guidelines will make it possible to increase efficiency and reduce the timing of design and implementation of pilot polymer flooding projects.
Shakhova, Anna (Schlumberger) | Lisyutina, Natalia (Schlumberger) | Lebedeva, Irina (Schlumberger) | Valshin, Oleg (Schlumberger) | Savinov, Roman (Schlumberger) | Famiev, Robert (Schlumberger) | Dementyev, Alexander (Schlumberger) | Marushkin, Dmitry (Schlumberger) | Bochkarev, Vladimir (Rosneft) | Surmin, Vladimir (Rosneft) | Bolychev, Evgeny (Rosneft)
Abstract This paper provides the results that were achieved and shares the drilling unique practices that were implemented to deliver the first complex bilateral extended reach drilling (ERD) well in Odoptu-more field (North Dome). Well design driven by geological objectives considered drilling 215.9mm main and pilot holes (PH). Well complexity was governed by the type of a profile having ERD ratio of 5.22 (main hole) / 4.60 (PH) and trajectory's 3D nature (turn in azimuth of 90 degrees) compared to previous wells in the project drilled mainly with 2D profiles. Apart from the problems connected with drilling and casing upper sections key challenges comprised kicking off in 215.9mm open hole at 5955m MD and 1512m TVD with rotary steerable system, setting cement plugs at shallow true vertical depth (TVD) at 89 degrees of inclination to abandon laterally drilled PH, delivering 168.3mm production liner to bottom with a risk of entering a lateral while running in hole. An effective collaboration between integrated engineering team and customer departments went far beyond ERD standard set of operations already existing in the project thus allowing to break its own records and to set new achievements due to integrated technological approach. The longest 444.5mm section (2975 m) was drilled in one run achieving the record daily drilling rate and rate of penetration (ROP). Cementing of 244.5mm floated liner resulted in the highest good cement bond integrity percentage ever achieved among other wells in project due to new ways of casing standoff and fluid rheology hierarchy modeling. For the first time in the project 215.9mm main horizontal hole in extreme reach ERD well has been drilled by kicking off in open hole from the pilot horizontal one with push-the-bit rotary steerable system without a kickoff plug with pilot hole being abandoned by setting cement plugs. Project-specific risk assessment conducted by team allowed successful deployment of 168.3mm liner into the main hole. Moreover, due to thorough engineering planning electrical submersible pump (ESP) was run without extending 244.5mm liner to surface by tie-back thus saving additional 7 days. Drilling first bilateral ERD well unlocked opportunities for the operator to reach, explore and develop different extended geological targets thus eliminating well construction process of additional wells on drilling upper sections.
Saifullin, Emil Rinatovich (Kazan Federal University) | Yuan, Chengdong (Kazan Federal University) | Zvada, Maiia Vladimirovna (Gazpromneft STC) | Varfolomeev, Mikhail Alekseevich (Kazan Federal University) | Shanbosinova, Shinar Kayratovna (Kazan Federal University) | Zharkov, Dmitrii Andreevich (Kazan Federal University) | Nazarychev, Sergei Aleksandrovich (Kazan Federal University) | Malakhov, Aleksei Olegovich (Kazan Federal University) | Sagirov, Rustam Nailevich (Kazan Federal University)
Abstract Messoyakhskoye field, operated by Gazprom Neft, is currently experiencing gas channeling from gas cap in production wells because of strong heterogeneity. Foam for a long has been considered as a good candidate for gas blocking, (Svorstol I. et al., 1996), (Hanssen, J. E., & Dalland, M. 1994), (Aarra, M. G. et al., 1996). However, foam injection for gas blocking in injection well is different from that in production well, where it is necessary to selectively and long-term impact on gas-saturated highly permeable areas without affecting the phase permeability of oil in the reservoir. This paper provides detailed laboratory studies that show how to determine suitable foam systems for gas blocking in production well. For gas blocking in production well, a long half-life time is required to sustain stable foam because a continuous shear of surfactant solution/gas can't be achieved like in injection well. Therefore, reinforced foam by polymer is chosen. Four polymer stabilizers and five foam agents were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor. Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of solution, which not only decreases the foam rate, but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15-0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in core first increased and then deceased with foam quality (the ratio of gas volume to foam volume (gas + liquid). The optimal injection mode is co-injection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that gas-blocking ability of polymer reinforced foam is better in high-permeability cores, which is beneficial for blocking high permeability zone. It should be also noted that under a certain ratio of oil to foam solution (about lower than 1 to 1), the presence of oil slowly decreased foam rate with increasing oil volume, but significantly increased half -life time, which is favorable for foam treatment in production well. This work highlights the difference between foam injection for gas blocking in production well and injection well, and emphasizes the use of polymer reinforced foam. Moreover, this work shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering different factors, which provides a guide regarding what kinds of foaming agents and polymer stabilizers should be used and how to evaluate them for designing a pilot application.
Multilateral drilling technology offers a highly effective method of enhanced oil recovery in fields characterized by complicated geological structures. This paper describes the analysis of sidetracks drilled in an open hole by an annular ledge formation method with a downhole motor in multilateral wells. Currently, industry growth requires development of fields with complicated geology. Drilling single-bore horizontal holes for these fields is insufficient, to say nothing of drilling vertical or directional wells. Multilateral wells with multiple horizontal sidetracks are drilled with increasing frequency.
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.
Abstract A concept has been developed for gas, gas-condensate and oil fields exploitation planning in the Arctic region, taking into account the limitations of the existing external and internal infrastructure. The work was carried out as part of an integrated project management system to determine business opportunities and initiate the transition of field development projects to the pre - project development phase (Pre - FEDD). The paper considers the formations and geological structures of the Bolshekhetskaya Depression in the license areas: License area "Nakhodkinskiy" Licensed area "Pyakyakhinsky" License area "South Messoyakhsky" License area "Halmerpayutinsky" License area "Salekaptsky" Licensed area "West Tazovsky" License area "Vareisky" The choice of the profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure of the formation during the well construction, as well as include all productive layers in the development, reduce the risk of complications during operation. Usage of longer horizontal wells will reduce drill footage; to increase the flow rate and profitability of wells; it is more rational to use formation energy due to lower values of depression on the formation and correspondingly reduced losses of condensate in the formation.
Sabirov, Denis Galievich (Gazpromneft STC) | Demenev, Roman Aleksandrovich (Gazpromneft STC) | Isakov, Kirill Dmitrievich (Gazpromneft STC) | Ilyasov, Ilnur Rustamovich (Messoyakhaneftegaz) | Orlov, Alexander Gennadievich (Messoyakhaneftegaz) | Glushchenko, Nikolay Aleksandrovich (Messoyakhaneftegaz)
Abstract Most of the Russian oil fields consist of the complex reservoirs and it is required to apply secondary reservoir development methods, such as waterflooding, in order to increase reservoir development efficiency. However, for highly heterogeneous reservoir with viscous oil, "classical" waterflooding is not enough and there is a need to use enhanced oil recovery methods, one of which is polymer flooding. The prospects polymer solutions injection have been proved in different fields worldwide, including the East-Messoyakhskoye field at the PK1-3 reservoir with high-viscosity oil. At this field, polymer flooding pilots were carried out and taking into account the obtained field data, the geological and dynamic model were updated, which helped to improve the process physics understanding and evaluate the possibility of sweep efficiency increase during project implementation. This paper describes the challenges, difficulties, applied approaches, results and experience obtained in reservoir simulation of polymer flooding.
There are situations where one needs to solve a hard problem, but have limited time, lack of material resources and the necessary information. In that case we have to rely on one's own experience and all the available resources. The Vostochnoye - Messoyakhskoye oilfield was put into operation and maintenance phase in September 2016, and from that point on the oil treatment facility is associated with the oil emulsion destruction problem and consequently the quality decrease of the crude oil. The main objects of the Vostochno - Messoyakhskoye field development are reservoirs that are complex in their geological structure and unique in oil reserves. The relatively not deep oil occurrence of 800 - 900 meters, that actively underlies water-bearing horizon and low temperatures of 15 C are considered to be the reservoir feature. Studies results of the inlet fluid to the oil preparation unit revealed the key factors affecting the stability of the oil emulsion: high dynamic viscosity of 2700 mPa * s, low temperature of 15 C, extensive gas factor of 298 m3 / t. According to the data given from the dependence of dynamic viscosity on water cut at a temperature of 15 C diagram, it can be seen that the most difficult demulsification contains water in the quantity of 40 to 65%. 2 SPE-201875-MS