Colmatation of reservair rocks in the operation of oil fields as a result of cation exchange

2019 ◽  
pp. 59-67
Author(s):  
A. V. Lehov ◽  
T. A. Kireeva
Keyword(s):  
Cation Exchange ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Hydrogeochemical Modeling ◽  
Fracture Medium ◽  
Constant Increase ◽  
Almost Everywhere ◽  
Production Wells ◽  
White Tiger ◽  
Calcium Minerals

By analyzing the changes in seawater pumped to maintain reservoir pressure (FPD), the anhydrous granitoid reservoir of the White Tiger deposit, in which the cracks are partially filled with calcium minerals (calcite and lomontite), shows that these minerals interact with the injected seawater. Hydrogeochemical modeling of this process showed that cations of seawater are first sodium and then magnesium displace calcium from the lomonite exchange complex, which leads to precipitation of anhydrite and a small amount of calcite. The incoming water dissolves the anhydrite and precipitates it downstream, forming a gradually expanding annular region with a constant increase in the amount of precipitated anhydrite. As a result, there is a decrease in the permeability of the fracture medium due to the filling of the cracks with anhydrite. A large amount of calcium in the associated waters when they rise to the surface causes the precipitation of calcite in the production wells and surface equipment. The transition of drilling to ever greater depths, where the rocks contain lomontite almost everywhere, requires taking into account the phenomena of cation exchange between the injected water and the rock in the predictions of scaling.

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

scholarly journals Studying of changes in the interaction of well during the water injection process

2019 ◽  
pp. 81-85
Author(s):  
Damir K. Sagitov
Keyword(s):  
Correlation Coefficient ◽  
Pair Correlation ◽  
Water Injection ◽  
Reservoir Pressure ◽  
Maintenance System ◽  
Displacement Front ◽  
Injection Process ◽  
Production Wells

The study of the causes of changes in the effectiveness of the reservoir pressure maintenance system in terms of the interaction of injection and production wells is an important and insufficiently studied problem, especially in terms of the causes of the attenuation of stable connections between the interacting wells. Based on the results of the calculation of the Spearman pair correlation coefficient, the reasons for the change in the interaction of wells during the flooding process at various stages were estimated. Of particular interest are identified four characteristic interactions, which are determined by the periods of formation of the displacement front.

scholarly journals Numerical modelling of the cooling effect in geothermal reservoirs induced by injection of CO2 and cooled geothermal water

2020 ◽  
Vol 75 ◽  
pp. 15
Author(s):  
Hejuan Liu ◽  
Qi Li ◽  
Yang Gou ◽  
Liwei Zhang ◽  
Wentao Feng ◽  
...  
Keyword(s):  
Injection Pressure ◽  
Geothermal Water ◽  
Geothermal Reservoir ◽  
Cooling Effect ◽  
Reservoir Pressure ◽  
Temperature Decrease ◽  
Water Production ◽  
Production Well ◽  
Production Wells ◽  
Thermal Breakthrough

The utilization of geothermal energy can reduce CO2 emissions into the atmosphere. The reinjection of cooled return water from a geothermal field by a closed loop system is an important strategy for maintaining the reservoir pressure and prolonging the depletion of the geothermal reservoir by avoiding problems, e.g., water level drawdown, ground subsidence, and thermal pollution. However, the drawdown of water injectivity affected by physical and chemical clogging may occur in sandstone aquifers, and the reservoir temperature may be strongly affected by the reinjection of large amounts of cooled geothermal water, thus resulting in early thermal breakthrough at production wells and a decrease in production efficiency. In addition to the injection of cooled geothermal water, the injection of CO2 can be used to maintain the reservoir pressure and increase the injectivity of the reservoir by enhancing water–rock interactions. However, the thermal breakthrough and cooling effect of the geothermal reservoir may become complex when both CO2 and cooled geothermal water are injected into aquifers. In this paper, a simplified small-scale multilayered geological model is established based on a low-medium geothermal reservoir in Binhai district, Tianjin. The ECO2N module of the TOUGH2MP simulator is used to numerically simulate temperature and pressure responses in the geothermal reservoir while considering different treatment strategies (e.g., injection rates, temperatures, well locations, etc.). The simulation results show that a high injection pressure of CO2 greatly shortens the CO2 and thermal breakthrough at the production well. A much lower CO2 injection pressure is helpful for prolonging hot water production by maintaining the reservoir pressure and eliminating the cooling effect surrounding the production wells. Both pilot-scale and commercial-scale cooled water reinjection rates are considered. When the water production rate is low (2 kg/s), the temperature decrease at the production well is negligible at a distance of 500 m between two wells. However, when both the production and reinjection rates of cooled return water are increased to 100 m3/h, the temperature decrease in the production well exceeds 10 °C after 50 years of operation.

scholarly journals MATHEMATICAL MODELLING OF SCALING IN A RESERVOIR WHICH CONTAINS IMPERMEABLE LAYERS

2002 ◽  
Vol 1 (2) ◽  
pp. 15
Author(s):  
P. Bedrikovetsky ◽  
F. Rosario ◽  
M. Bezerra ◽  
M. Silva ◽  
R. Lopes Jr.
Keyword(s):  
High Velocity ◽  
Oil Fields ◽  
Formation Damage ◽  
Low Velocity ◽  
Tracer Concentration ◽  
Reservoir Water ◽  
Production Wells ◽  
Permeability Distribution ◽  
Impermeable Layer ◽  
Water Cut

Several different scenario of injected and reservoir water mixing have been proposed: mixing at high velocity near to injectors, mixing at low velocity inside reservoirs, mixing by diffusion via boundaries of layers with different permeabilities, mixing of injected, connate and aquifer waters at high velocity near to producers. Just the latter mechanism results in the accumulation of formation damage, while other mechanisms cause precipitation near to moving concentration front. In the current paper a new mechanism of oilfield scaling by diffusion of Barium from impermeable layer into the reservoir is proposed. The mechanism results in accumulation of precipitant and of formation damage. Viscous dominant regime of waterflooding takes place in the majority of oil fields. The Welge´s method allows calculating the permeability distribution from water cut history. The proposed extension to Welge´s method determines the partition of permeable layers in a reservoir from tracer concentration in production wells. Knowledge of this partition is important for modelling of oilfield scaling accounting for Barium supply from impermeable layers.

scholarly journals A Study on the CO2-Enhanced Water Recovery Efficiency and Reservoir Pressure Control Strategies

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-17 ◽  
Author(s):  
Zhijie Yang ◽  
Tianfu Xu ◽  
Fugang Wang ◽  
Yujie Diao ◽  
Xufeng Li ◽  
...  
Keyword(s):  
Saline Water ◽  
Control Strategies ◽  
Production Capacity ◽  
Junggar Basin ◽  
Pressure Control ◽  
Reservoir Pressure ◽  
Water Recovery ◽  
Water Production ◽  
Well Spacing ◽  
Production Wells

CO2 geological storage (CGS) proved to be an effective way to mitigate greenhouse gas emissions, and CO2-enhanced water recovery (CO2-EWR) technology may improve the efficiency of CO2 injection and saline water production with potential economic value as a means of storing CO2 and supplying cooling water to power plants. Moreover, the continuous injection of CO2 may cause a sharp increase for pressure in the reservoir system, so it is important to determine reasonable reservoir pressure control strategies to ensure the safety of the CGS project. Based upon the typical formation parameters of the China Geological Survey CO2-EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of the number of production wells and the well spacing on the enhanced efficiency of CO2 storage and saline production. The optimal key parameters that control reservoir pressure evolution over time are determined. The numerical results show that a smaller spacing between injection and production wells and a larger number of production wells can enhance not only the CO2 injection capacity but also the saline water production capacity. The effect of the number of production wells on the injection capacity and production capacity is more significant than that of well spacing, and the simulation scenario with 2 production wells, one injection well, and a well spacing of 2 km is more reasonable in the demonstration project of Junggar Basin. CO2-EWR technology can effectively control the evolution of the reservoir pressure and offset the sharp increase in reservoir pressure caused by CO2 injection and the sharp decrease of reservoir pressure caused by saline production. The main controlling factors of pressure evolution at a certain spatial point in a reservoir change with time. The monitoring pressure drops at the beginning and is controlled by the extraction of water. Subsequently, the injection of CO2 plays a dominant role in the increase of reservoir pressure. Overall, the results of analysis provide a guide and reference for the CO2-EWR site selection, as well as the practical placement of wells.

scholarly journals Design and Implementation of the Array Logging Tool on Horizontal Production Logging

2020 ◽  
Vol 2020 ◽  
pp. 1-7
Author(s):  
Wenguang Song ◽  
Haiyu Chen ◽  
Qiujuan Zhang ◽  
Jiahao Zhang
Keyword(s):  
Horizontal Wells ◽  
High Water ◽  
Oil Fields ◽  
Measuring Instruments ◽  
Conventional Production ◽  
Production Wells ◽  
Specific Retention ◽  
High Water Cut ◽  
Water Cut ◽  
Logging Tool

The measuring instruments have some errors in the measurement of high water cut production wells, and many domestic oil fields are also in high water cut state. The measured data from the conventional production logging instrument are all almost inaccurate. This project has designed a staggered probe array flow meter well logging apparatus based on the characteristic of electromagnetic wave specific retention meter that can fully cover the wellbore fluid and improve flow measurement accuracy. According to the application in horizontal wells, the accuracy of this measuring instrument now has been proved to be more than 90% and can meet the requirements of production logging interpretation in horizontal wells.

USE OF SUCKER-ROD PUMPING UNITS IN THE SYSTEM OF RESERVOIR PRESSURE MAINTENANCE AT THE LATEST STAGE OF OIL FIELDS DEVELOPMENT

2019 ◽  
pp. 62-69
Author(s):  
V.M. Valovsky ◽  
◽  
K.V. Valovsky ◽  
I.G. Shamsutdinov ◽  
G.Yu. Basos ◽  
...  
Keyword(s):  
Oil Fields ◽  
Reservoir Pressure ◽  
Sucker Rod ◽  
Pumping Units
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