scholarly journals Investigation of the influence of the heterogeneous permeability distribution on the oil phase displacement processes

2021 ◽  
Vol 5 (1(61)) ◽  
pp. 33-40
Author(s):  
Miсhail Lubkov ◽  
Oksana Zakharchuk ◽  
Viktoriia Dmytrenko ◽  
Oleksandr Petrash
Keyword(s):  
Finite Element ◽  
Difference Method ◽  
High Reliability ◽  
Oil Field ◽  
Injection Well ◽  
Shear Direction ◽  
Reservoir Pressure ◽  
Filtration Process ◽  
Injection Wells ◽  
The Impact

The object of research is the filtration processes of displacement of the oil phase under the influence of an injection well in a heterogeneous porous medium. It is possible to evaluate and take into account the effect of reservoir heterogeneity on the distribution of reservoir pressure (and, consequently, on the intensity of the filtration process) using numerical modeling of filtration processes based on the piezoelectric equation. To solve the non-stationary anisotropic problem of piezoconductivity, it is proposed to apply the combined finite-element-difference method of M. Lubkov, which makes it possible to take into account the inhomogeneous distribution of permeability inside the anisotropic oil-bearing formation and at its boundaries, and to adequately calculate the distribution of reservoir pressure. The use of the combined finite-element-difference method allows to combine the advantages of the finite-element method and the finite difference method: to model geometrically complex areas, to find the value at any point of the object under study. At the same time, the use of an implicit difference scheme when finding the nodal values of the grid provides high reliability and convergence of the results. The simulation results show that the distribution of the pressure field between the production and injection wells significantly depends on their location, both in the isotropic landslide and in the anisotropic oil-bearing reservoir. It is shown that the distance between the wells of more than 1 km levels out the effectiveness of the impact of the injection well on the oil filtration process. The influence of the permeability of the oil phase in the shear direction dominates the influence of the permeability in the axial directions (affects the pressure decrease by 4–9.5 %). In the case of a landslide-isotropic reservoir, the wells should be located in the shear (diagonal) direction, which will provide the lowest level of drop in the average reservoir pressure (by 4 %). Based on the information obtained, for the effective use of anisotropic low-permeability formations, it is necessary to place production and injection wells in areas with relatively low anisotropy of the formation permeability, especially to avoid places with the presence of landslide permeability of the formation. The location of the wells is important so that, on the one hand, there is no blockage of oil from the side of reduced permeability, and on the other hand, rapid depletion of the formation from the side of increased permeability does not occur. And also the mutual exchange between the production and injection wells did not stop. When placing a system of production and injection wells in anisotropic formations of an oil field, it is necessary to carry out a systematic analysis of the surrounding anisotropy of the formations in order to place them in such a way that would ensure effective dynamics of filtration processes around these wells. Using the method used, it is possible to predict the impact of an injection well on the distribution of reservoir pressure in the reservoir.

scholarly journals MODELING OF PRODUCING PRESSURE IN HETEROGENEOUS OIL-BEARING RESERVOIRS

2021 ◽  
pp. 72-79
Author(s):  
Mikhail Lubkov ◽  
Oksana Zakharchuk ◽  
Viktoriia Dmytrenko ◽  
Oleksandr Petrash
Keyword(s):  
Finite Element ◽  
Difference Method ◽  
Stationary Problem ◽  
Injection Well ◽  
Practical Significance ◽  
The Finite Element Method ◽  
Oil Viscosity ◽  
Injection Wells ◽  
Remote Zone ◽  
Close Relationship

Numerical modeling of the distribution of the reservoir pressure drop in the vicinity of an operating well was carried out taking into account the inhomogeneous distribution of filtration characteristics (permeability and oil viscosity) in the near and distant zones of the well operation in order to study the practical aspects of filtration in heterogeneous oil-bearing formations based on a combined finite-element-difference method for non-stationary problem of piezoconductivity. The use of the combined finite-element-difference method enables to combine the advantages of the finite-element method and the finite difference method: to model geometrically complex areas, to find the value at any point of the object under study, while the implicit difference scheme. It is shown that the intensity of filtration processes in the vicinity of the operating well depends mainly on the permeability, and, to a lesser extent, on the viscosity of the oil. Moreover, the influence of the permeability of the oil phase in the remote zone (Rd < 5 m) is greater than the effect in the close zone (Rd > 5 m) of the operating well. In the case of low permeability of the oil phase in the vicinity of the existing well, to maintain stable oil production, it is necessary to place an injection well near the production well. Using the method suggested, it is possible to predict the effect of the injection well on the formation pressure distribution in the formation. The scientific novelty of the work lies in the study of the influence of the heterogeneous permeability and oil viscosity distribution on the reservoir pressures distribution around the wells by modeling filtration processes based on a combined finite-element-difference method. The practical significance of the research results comes down to confirming the close relationship between the heterogeneity of the porous medium and the reservoir pressures distribution around an operating producing well. The combined finite-element-difference method used in this work can be used to solve other filtration problems (for example, to calculate the gas saturation of a reservoir, create a method for calculating well flow rates, assess the effect of injection wells on filtration processes).

scholarly journals Gas Lift Performance of Some Horizontal Wells in Ahdeb Oil Field

2021 ◽  
Vol 7 (3) ◽  
pp. 66-74
Author(s):  
Dr. Kareem A. Alwan ◽  
Dr. Maha R. Abdulameer ◽  
Mohammed Falih
Keyword(s):  
Water Injection ◽  
Injection Pressure ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Injection Wells ◽  
Artificial Lift ◽  
Electrical Submersible Pumps ◽  
Optimal Injection ◽  
Water Cut ◽  
The Impact

Ahdeb is one of the Iraqi oil fields, its crude characterized by medium API (22.5-28.9) and highly reservoir pressure depletion from Khasib formation due to lack of water drive. This makes it difficult to produce economic oil rates. Therefore, many water injection wells were drilled by the operators to maintain the reservoir pressure during production. In addition to that, electrical submersible pumps (ESP) were used in some productive wells. This study suggests exploitation of gas associated with oil production to be recycled to lift oil as a substitute for the ESP .The work in this study includes using PIPSIM software to build a model of four studied productive wells (AD1-11-2H, AD2-15-2H, AD4-13-3H, A4-19-1H) after choosing the suited correlation for each well. According to the statistical results, Mukherjee & Brill correlation is the best option for all wells. The use of PIPESIM software include determining artificial lift performance to determine the optimum amount of gas injected, optimum injection pressure as well as the optimum injection depth and knowing the impact of these factors on production, as well as the determination of the optimal injection conditions when water cut changes. According to the current circumstances of the wells, the depth optimized for injection is the maximum allowable depth of injection which is deeper than the packer by 100 ft and the amount of injection gas is (1.5, 1, 1, and 1) MMscf/day for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially and injection pressure (2050, 2050, 2050, and 2000) psi for wells (AD2-11-2H, AD2-15-2H, AD4-13-3H, and AD4-19-2H) sequentially.  

Online Modeling of CO2 Storage Systems

2021 ◽  
Author(s):  
Dale Douglas Erickson ◽  
Greg Metcalf
Keyword(s):  
Co2 Storage ◽  
Free Water ◽  
Oil Field ◽  
Management Tool ◽  
Carbon Dioxide Injection ◽  
Injection Wells ◽  
Internal Corrosion ◽  
Injection Process ◽  
Corrosion Risk ◽  
The Impact

Abstract This paper discusses the development and deployment of a specialized online and offline integrated model to simulate the CO2 (Carbon Dioxide) Injection process. There is a very high level of CO2 in an LNG development and the CO2 must be removed in order to prepare the gas to be processed into LNG. To mitigate the global warming effects of this CO2, a large portion of the CO2 Rich Stream (98% purity) is injected back into a depleted oil field. To reduce costs, carbon steel flowlines are used but this introduces a risk of internal corrosion. The presence of free water increases the internal corrosion risk, and for this reason, a predictive model discussed in this paper is designed to help operations prevent free water dropout in the network in real time. A flow management tool (FMT) is used to monitor the current state of the system and helps look at the impact of future events (startup, shutdowns etc.). The tool models the flow of the CO2 rich stream from the outlet of the compressor trains, through the network pipeline and manifolds and then into the injection wells. System behavior during steady state and transient operation is captured and analyzed to check water content and the balance of trace chemicals along with temperature and pressure throughout the network helping operators estimate corrosion rates and monitor the overall integrity of the system. The system has been running online for 24/7 for 2 years. The model has been able to match events like startup/shutdown, cooldowns and blowdowns. During these events the prediction of temperature/pressure at several locations in the field matches measured data. The model is then able to forecasts events into the future to help operations plan how they will operate the field. The tool uses a specialized thermodynamic model to predict the dropout of water in the near critical region of CO2 mixtures which includes various impurities. The model is designed to model startup and shutdown as the CO2 mixture moves across the phase boundary from liquid to gas or gas to liquid during these operations.

Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

SPE Journal ◽  
2022 ◽  
pp. 1-18
Author(s):  
Marat Sagyndikov ◽  
Randall Seright ◽  
Sarkyt Kudaibergenov ◽  
Evgeni Ogay
Keyword(s):  
Polymer Solutions ◽  
Mechanical Stability ◽  
Field Operator ◽  
Oil Field ◽  
Low Flow ◽  
Mechanical Degradation ◽  
Injection Wells ◽  
Polymer Injection ◽  
Step Rate ◽  
The Impact

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

scholarly journals Numerical Simulation of the Influence of Geological CO2 Storage on the Hydrodynamic Field of a Reservoir

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-21
Author(s):  
Zhaoxu Mi ◽  
Fugang Wang ◽  
Zhijie Yang ◽  
Xufeng Li ◽  
Yujie Diao ◽  
...  
Keyword(s):  
Pressure Field ◽  
Co2 Storage ◽  
Shallow Groundwater ◽  
Shallow Aquifer ◽  
Reservoir Pressure ◽  
Geological Storage ◽  
Injection Wells ◽  
Geological Conditions ◽  
Deep Reservoir ◽  
The Impact

CO2 geological storage in deep saline aquifers is an effective way to reduce CO2 emissions. The injection of CO2 inevitably causes a significant pressure increase in reservoirs. When there exist faults which cut through a deep reservoir and shallow aquifer system, there is a risk of the shallow aquifer being impacted by the changes in reservoir hydrodynamic fields. In this paper, a radial model and a 3D model are established by TOUGH2-ECO2N for the reservoir system in the CO2 geological storage demonstration site in the Junggar Basin to analyze the impact of the CO2 injection on the deep reservoir pressure field and the possible influence on the surrounding shallow groundwater sources. According to the results, the influence of CO2 injection on the reservoir pressure field in different periods and different numbers of well is analyzed. The result shows that the number of injection wells has a significant impact on the reservoir pressure field changes. The greater the number of injection wells is, the greater the pressure field changes. However, after the cessation of CO2 injection, the number of injection wells has little impact on the reservoir pressure recovery time. Under the geological conditions of the site and the constant injection pressure, although the CO2 injection has a significant influence on the pressure field in the deep reservoir, the impact on the shallow groundwater source area is minimal and can be neglected and the existing shallow groundwater sources are safe in the given project scenarios.

scholarly journals Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

2021 ◽  
Author(s):  
Tongchun Hao ◽  
Liguo Zhong ◽  
Jianbin Liu ◽  
Xiaodong Han ◽  
Tianyin Zhu ◽  
...  
Keyword(s):  
Production Efficiency ◽  
Design Method ◽  
Water Injection ◽  
Oil Field ◽  
Productivity Index ◽  
Injection Wells ◽  
Wellhead Pressure ◽  
Production Wells ◽  
Drilling Operations ◽  
The Impact

AbstractAffected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

Evaluation of the Influence of the Facies Genesis of the Reservoir Unit of the Fainsk Oil Field YUS1 Facility on the Effectiveness of Integrated Processing of the Injection Wells Bottomhole Formation Zone with the Application of Acid Compositions

2018 ◽  
Vol 785 ◽  
pp. 1-10
Author(s):  
Vadim Aleksandrov ◽  
Marsel Kadyrov ◽  
Andrey Ponomarev ◽  
Denis Drugov ◽  
Evgeniya Neelova
Keyword(s):  
Acid Composition ◽  
Process Parameters ◽  
Development Process ◽  
Geological Structure ◽  
Oil Field ◽  
Injection Wells ◽  
Formation Zone ◽  
Integrated Processing ◽  
The Impact ◽  
Practical Recommendations

One of the main problems with the bottomhole formation zone processing is the choice of an acid composition adapted to the peculiarities of the geological structure of the facility. The highest technological effect of the geological and technical interventions using physicochemical formation stimulation techniques is achieved when the genesis of processed deposits is taken into account during the process of treatment planning. The research objective is to assess the impact of the reservoir units formation (genesis) characteristics on the effectiveness of integrated processing of the bottomhole formation zone of injection wells with the application of acid compositions. Using the geological and routine analysis of the development process parameters for deposits located in various facies zones, the operational benefits of the bottomhole formation zone integrated treatments in injection wells were evaluated and practical recommendations were provided.

scholarly journals Geothermal heat use to eliminate hydrate formations in oil deposit injection wells

2021 ◽  
Vol 230 ◽  
pp. 01019
Author(s):  
Мykhailo Fyk ◽  
Volodymyr Biletskyi ◽  
Madjid Аbbood ◽  
Fabris Аnzian
Keyword(s):  
Heat Exchanger ◽  
Heat Exchange ◽  
Oil Field ◽  
Injection Well ◽  
Mathematical Apparatus ◽  
Joint Work ◽  
Injection Wells ◽  
Geothermal Heat ◽  
Heat Exchange Surface ◽  
Exchange Surface

The article is devoted to an actual issue: the development of internal downhole heat exchangers technology to combat hydration in injection wells. Purpose: development of conceptual solutions for the use of geothermal coolant in the internal well heat exchanger of the injection well. A scheme of an internal downhole heat exchanger with a geothermal heat carrier has been developed, and includes a supply line of a geothermal carrier through the heat exchange surface of the injection well into the productive reservoir of the oil field. The scheme provides targeted utilization of thermobaric energy of a geothermal source to combat hydration in the injection well. A mathematical apparatus for describing the process of heat utilization and heat exchange in injection well is proposed. It is established that the capacity of one geothermal well discovered at the oil depths in the Dnipro-Donetsk basin is sufficient to eliminate hydration in 1-3 injection wells, and determines the feasibility of their joint work.

scholarly journals ANALYSIS OF THE TRACER STUDIES RESULTS: A STUDY OF AS1-3 FORMATION OF THE SEVERO-OREKHOVSKOYE OIL FIELD

2018 ◽  
pp. 44-51
Author(s):  
V. F. Dyagilev ◽  
S. T. Polischuk ◽  
S. A. Leontev ◽  
V. M. Spasibov
Keyword(s):  
Mathematical Analysis ◽  
Analysis Data ◽  
Oil Field ◽  
Tracer Studies ◽  
Injection Wells ◽  
Field Development ◽  
Field Practice ◽  
Production Wells ◽  
The Impact ◽  
State Of Field

In oil field practice tracer (indicator) studies are an effective and efficient method of monitoring the state of field development. Using the multifactor mathematical analysis, the nature and intensity of the impact of injection wells on production wells have been compared with the results of injection of indicator liquids. Injection of indicator liquids was carried out along the AS1-3 formation at the Severo-Orekhovskoye oil field through the wellheads of the injection wells. The technique provides for correlation of injection in all potentially possible directions within a given range of action (usually no more than 2 rows), excluding one or more of the wells and more from the analysis. There is a direct positive correlation between evaluation data on indicator downloads and multivariate mathematical analysis data. The convergence of the results is 65%.

A new approach to water cut forecasting based on results of capacitance resistance modeling

2020 ◽  
Vol 6 (1) ◽  
pp. 192-207 ◽  
Author(s):  
Alexander D. Bekman ◽  
Tatiana A. Pospelova ◽  
Dmitry V. Zelenin
Keyword(s):  
Mathematical Model ◽  
Injection Well ◽  
Adaptation Algorithm ◽  
Injection Wells ◽  
Operational Analysis ◽  
Operating Modes ◽  
Advantages And Disadvantages ◽  
Stage Of Development ◽  
Water Cut ◽  
The Impact

For oil fields that are at a late stage of development, urgent tasks are the operational analysis of the development and optimization of the operating modes of injection wells. The demand for responsiveness often forces one to abandon the use of three-dimensional hydrodynamic models in favor of analytical ones such as CRMP. Using CRMP models allows you to quickly assess the trends in the impact of injection wells on producing wells and build reliable short-term forecasts for fluid production. Supplementing the traditional (single-phase) CRMP model with a water cut model also allows predicting oil production rates for producing wells and expands the capabilities of an operational analysis of the existing development system. In addition, an adequate water cut model allows using the CRMP model to solve the problem of optimizing the operating modes of the injection well stock. This article discusses the main known water cut models used in conjunction with the CRMP model, provides a brief analysis of their advantages and disadvantages. A new authorial mathematical model of water cut (“multi-characteristic model”) is proposed, which allows to establish the role of each injection well in changing the water content of the considered producer. An adaptation algorithm is also described, that is, the selection of unknown model coefficients implemented in Ariadna software (developed by Tyumen Petroleum Research Center LLC). The low computational complexity of the algorithm allows you to quickly simulate areas containing up to several hundred wells. The results of experiments on the use of a new mathematical model on a synthetic model of an oil reservoir are presented. The results of predicting water cut are compared with the results of previously known methods. The restrictions for using the new model, as well as directions for its development are indicated.

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